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Attachment 1

Comments of Environmental Law & Policy Center, Sierra Club and Valley Watch Inc.

TheFuture ofCoal

AN INTERDISCIPLINARY MIT STUDY

Coal-Based Electricity Generation 17

Chapter 3 — Coal-Based Electricity Generation

INTRODUCTION

In the U.S., coal-based power generation is

expanding again; in China, it is expanding

very rapidly; and in India, it appears on the

verge of rapid expansion. In all these coun-

tries and worldwide, the primary generating

technology is pulverized coal (PC) combus-

tion. PC combustion technology continues

to undergo technological improvements that

increase effi ciency and reduce emissions.

However, technologies favored for today’s

conditions may not be optimum under future

conditions. In particular, carbon dioxide cap-

ture and sequestration in coal-based power

generation is an important emerging option

for managing carbon dioxide emissions while

meeting growing electricity demand, but this

would add further complexity to the choice

of generating technology.

Th e distribution of coal-based generating

plants for the U. S. is shown in Figure 3.1.

Most of the coal-based generating units in

the U. S. are between 20 and 55 years old; the

average age of the fl eet is over 35 years[1].

Coal-based generating units less than 35

years old average about 550 MWe; older gen-

erating units are typically smaller. With cur-

rent life-extension capabilities, many of these

units could, on-average, operate another 30+

years. Units that are less than about 50 years

old are essentially all air-blown, PC combus-

tion units. Th e U.S. coal fl eet average gener-

ating effi ciency is about 33%, although a few,

newer generating units exceed 36% effi ciency

[2][3]. Increased generating effi ciency is im-

portant, since it translates directly into lower

criteria pollutant emissions (at a given re-

moval effi ciency) and lower carbon dioxide

emissions per kWe-h of electricity generated.

GENERATING TECHNOLOGIES — OVERVIEW

Th is chapter evaluates the technologies that

are either currently commercial or will be

commercially viable in the near term for

electricity generation from coal. It focuses

primarily on the U. S., although the analysis

is more broadly applicable. We analyze these

generating technologies in terms of the cost

of electricity produced by each, without and

with carbon dioxide (CO2) capture, and their

applicability, effi ciency, availability and reli-

ability. Power generation from coal is subject

to a large number of variables which impact

technology choice, operating effi ciency, and

cost of electricity (COE) produced [4]. Our

approach here was to pick a point set of condi-

tions at which to compare each of the generat-

ing technologies, using a given generating unit

design model to provide consistency. We then

consider how changes from this point set of

conditions, such as changing coal type, impact

the design, operation, and cost of electricity

(COE) for each technology. We also consider

emissions control and retrofi ts for CO2 cap-

ture for each technology. Appendix 3.A sum-

marizes coal type and quality issues, and their

impact.

For the technology comparisons in this chap-

ter, each of the generating units considered

was a green-fi eld unit which contained all the

emissions control equipment required to op-

erate slightly below current, low, best-demon-

strated criteria emissions performance levels.

18 MIT STUDY ON THE FUTURE OF COAL

To evaluate the technologies on a consistent

basis, the design performance and operating

parameters for these generating technologies

were based on the Carnegie Mellon Integrated

Environmental Control Model, version 5.0

(IECM) [5] which is a modeling tool specifi c

to coal-based power generation [6] [7]. Th e

units all use a standard Illinois # 6 bituminous

coal, a high-sulfur, Eastern U.S. coal with a

moderately high heating value (3.25 wt% sul-

fur & 25,350 kJ/kg (HHV)). Detailed analysis

is given in Table A-3.B.1 [5] (Appendix 3.B).

GENERATING EFFICIENCY Th e fraction of the

thermal energy in the fuel that ends up in the net

electricity produced is the generating effi ciency

of the unit [8]. Typical modern coal units range

in thermal effi ciency from 33% to 43% (HHV).

Generating effi ciency depends on a number of

unit design and operating parameters, includ-

ing coal type, steam temperature and pressure,

and condenser cooling water temperature [9].

For example, a unit in Florida will generally

have a lower operating effi ciency than a unit in

northern New England or in northern Europe

due to the higher cooling water temperature in

Florida. Th e diff erence in generating effi ciency

could be 2 to 3 percentage points. Typically,

units operated at near capacity exhibit their

highest effi ciency; unit cycling and operating

below capacity result in lower effi ciency.

LEVELIZED COST OF ELECTRICITY

Th e levelized cost of electricity (COE) is the

constant dollar electricity price that would be

required over the life of the plant to cover all

operating expenses, payment of debt and ac-

crued interest on initial project expenses, and

the payment of an acceptable return to in-

vestors. Levelized COE is comprised of three

components: capital charge, operation and

maintenance costs, and fuel costs. Capital cost

is generally the largest component of COE.

Th is study calculated the capital cost compo-

nent of COE by applying a carrying charge

factor of 15.1% to the total plant cost (TPC).

Appendix 3.C provides the basis for the eco-

nomics discussed in this chapter.

AIR-BLOWN COAL COMBUSTION GENERATING TECHNOLOGIES

In the next section we consider the four pri-

mary air-blown coal generating technologies

that compose essentially all the coal-based

power generation units in operation today

and being built. Th ese include PC combustion

using subcritical, supercritical, or ultra-super-

critical steam cycles designed for Illinois #6

coal and circulating fl uid-bed (CFB) combus-

tion designed for lignite. Table 3.1 summariz-

Figure 3.1 Distribution of U. S. Coal-Based Power Plants. Data from 2002 USEPA eGRID database; Size Of Circles Indicate Power Plant Capacity.


es representative operating performance and

economics for these air-blown coal combus-

tion generating technologies. Appendix 3.C

provides the basis for the economics. PC com-

bustion or PC generation will be used to mean

air-blown pulverized coal combustion for the

rest of this report, unless explicitly stated to be

oxy-fuel PC combustion for oxygen-blown PC

combustion.

PULVERIZED COAL COMBUSTION POWER GEN-ERATION: WITHOUT CO2 CAPTURE

SUBCRITICAL OPERATION In a pulverized coal

unit, the coal is ground to talcum-powder

fi neness, and injected through burners into

the furnace with combustion air [10-12]. Th e

fi ne coal particles heat up rapidly, undergo py-

rolysis and ignite. Th e bulk of the combustion

air is then mixed into the fl ame to completely

burn the coal char. Th e fl ue gas from the boiler

passes through the fl ue gas clean-up units to

remove particulates, SOx, and NOx. Th e fl ue

gas exiting the clean-up section meets criteria

Table 3.1 Representative Performance And Economics For Air-Blown PC Generating Technologies

SUBCRITICAL PC SUPERCRITICAL PC ULTRA-SUPERCRITICAL PC SUBCRITICAL CFB6

W/OCAPTURE

W/CAPTURE

W/OCAPTURE

W/CAPTURE

W/OCAPTURE

W/CAPTURE

W/OCAPTURE

W/CAPTURE

PERFORMANCE

Heat rate (1), Btu/kWe-h 9,950 13,600 8,870 11,700 7,880 10,000 9,810 13,400

Generating effi ciency (HHV) 34.3% 25.1% 38.5% 29.3% 43.3% 34.1% 34.8% 25.5%

Coal feed, kg/h 208,000 284,000 185,000 243,000 164,000 209,000 297,000 406,000

CO2 emitted, kg/h 466,000 63,600 415,000 54,500 369,000 46,800 517,000 70,700

CO2 captured at 90%, kg/h (2) 0 573,000 0 491,000 0 422,000 0 36,000

CO2 emitted, g/kWe-h 931 127 830 109 738 94 1030 141

COSTS

Total Plant Cost, $/kWe (3) 1,280 2,230 1,330 2,140 1,360 2,090 1,330 2,270

Inv. Charge, ¢/kWe-h @ 15.1% (4) 2.60 4.52 2.70 4.34 2.76 4.24 2.70 4.60

Fuel, ¢/kWe-h @ $1.50/MMBtu 1.49 2.04 1.33 1.75 1.18 1.50 0.98 1.34

O&M, ¢/kWe-h 0.75 1.60 0.75 1.60 0.75 1.60 1.00 1.85

COE, ¢/kWe-h 4.84 8.16 4.78 7.69 4.69 7.34 4.68 7.79

Cost of CO2 avoided5 vs. same technology w/o capture, $/tonne

41.3 40.4 41.1 39.7

Cost of CO2 avoided5 vs. supercritical w/o capture, $/tonne

48.2 40.4 34.8 42.8

Basis: 500 MWe net output. Illinois # 6 coal (61.2% wt C, HHV = 25,350 kJ/kg), 85% capacity factor

(1) effi ciency = 3414 Btu/kWe-h/(heat rate); (2) 90% removal used for all capture cases(3) Based on design studies and estimates done between 2000 & 2004, a period of cost stability, updated to 2005$ using CPI infl ation rate. 2007 cost would be higher because of recent rapid increases in engineering and construction costs, up 25 to 30% since 2004.(4) Annual carrying charge of 15.1% from EPRI-TAG methodology for a U.S. utility investing in U.S. capital markets; based on 55% debt @ 6.5%, 45% equity @ 11.5%, 38% tax rate, 2% infl ation rate, 3 year construction period, 20 year book life, applied to total plant cost to calculate invest-ment charge(5) Does not include costs associated with transportation and injection/storage(6) CFB burning lignite with HHV = 17,400 kJ/kg and costing $1.00/million Btu


pollutant permit requirements, typically con-

tains 10–15% CO2 and is essentially at atmo-

spheric pressure. A block diagram of a subcrit-

ical PC generating unit is shown in Figure 3.2.

Dry, saturated steam is generated in the fur-

nace boiler tubes and is heated further in the

superheater section of the furnace. Th is high-

pressure, superheated steam drives the steam

turbine coupled to an electric generator. Th e

low-pressure steam exiting the steam turbine

is condensed, and the condensate pumped

back to the boiler for conversion into steam.

Subcritical operation refers to steam pressure

and temperature below 22.0 MPa (~3200 psi)

and about 550° C (1025° F) respectively. Sub-

critical PC units have generating effi ciencies

between 33 to 37% (HHV), dependent on coal

quality, operations and design parameters,

and location.

Key material fl ows and conditions for a 500

MWe subcritical PC unit are given in Figure

3.2 [5, 13]. Th e unit burns 208,000 kg/h (208

tonnes/h [14]) of coal and requires about 2.5

million kg/h of combustion air. Emissions

control was designed for 99.9% PM and 99+%

SOx reductions and greater than about 90%

NOx reduction. Typical subcritical steam cy-

cle conditions are 16.5 MPa (~2400 psi) and

540° C (1000° F) superheated steam. Under

these operating conditions (Figure 3.2), IECM

projects an effi ciency of 34.3% (HHV) [15].

More detailed material fl ows and operating

conditions are given in Appendix 3.B, Figure

A-3.B.2, and Table 3.1 summarizes the CO2

emissions.

Th e coal mineral matter produces about 22,800

kg/h (23 tonnes/h) of fl y and bottom ash. Th is

can be used in cement and/or brick manufac-

ture. Desulfurization of the fl ue gas produces

about 41,000 kg/h (41 tonnes/h) of wet solids

that may be used in wallboard manufacture or

disposed of in an environmentally safe way.

SUPERCRITICAL AND ULTRA-SUPERCRITICAL OPERATION Generating effi ciency is in-

creased by designing the unit for operation at

higher steam temperature and pressure. Th is

represents a movement from subcritical to

supercritical to ultra-supercritical steam pa-

rameters [16]. Supercritical steam cycles were

not commercialized until the late 1960s, aft er

the necessary materials technologies had been

developed. A number of supercritical units

were built in the U.S. through the 1970’s and

early 80’s, but they were at the limit of the

then-available materials and fabrication capa-

bilities, and some problems were encountered

[17]. Th ese problems have been overcome for

supercritical operating conditions, and super-

critical units are now highly reliable. Under

supercritical conditions, the supercritical fl uid

is expanded through the high-pressure stages

of a steam turbine, generating electricity. To

recharge the steam properties and increase the

amount of power generated, aft er expansion

through the high-pressure turbine stages, the


steam is sent back to the boiler to be reheated.

Reheat, single or double, increases the cycle

effi ciency by raising the mean temperature of

heat addition to the cycle.

Supercritical electricity generating effi ciencies

range from 37 to 40% (HHV), depending on

design, operating parameters, and coal type.

Current state-of-the-art supercritical PC gen-

eration involves 24.3 MPa (~3530 psi) and 565°

C (1050° F), resulting in a generating effi ciency

of about 38% (HHV) for Illinois #6 coal.

Meanwhile, new materials capabilities have

been further expanding the potential oper-

ating range. To take advantage of these de-

velopments, the power industry, particularly

in Europe and Japan, continues to move to

higher steam pressure and temperature, pri-

marily higher temperatures. Operating steam

cycle conditions above 565° C (>1050° F) are

referred to as ultra-supercritical. A number

of ultra-supercritical units operating at pres-

sures to 32 MPa (~4640 psi) and temperatures

to 600/610° C (1112-1130° F) have been con-

structed in Europe and Japan [18]. Opera-

tional availability of these units to date has

been comparable to that of subcritical plants.

Current materials research and development

is targeting steam cycle operating conditions

of 36.5 to 38.5 MPa (~5300-5600 psi) and tem-

peratures of 700-720° C (1290-1330° F)[19].

Th ese conditions should increase generating

effi ciency to the 44 to 46% (HHV) range for

bituminous coal, but require further materi-

als advances, particularly for manufacturing,

fi eld construction, and repair.

Figure 3.3 is a block diagram of a 500 MWe

ultra-supercritical PC generating unit show-

ing key fl ows. Th e coal/combustion side of the

boiler and the fl ue gas treatment are the same

as for a subcritical boiler. Coal required to

generate a given amount of electricity is about

21% lower than for subcritical generation,

which means that CO2 emissions per MWe-h

are reduced by 21%. Th e effi ciency projected

for these design operating conditions is 43.3%

(HHV) (Figure 3.3) vs. 34.3% for subcritical

conditions. More detailed material and oper-

ating information is given in Appendix 3.B.

Table 3.1 summarizes the performance for

subcritical, supercritical, and ultra-supercriti-

cal operation.

FLUID-BED COMBUSTION A variation on PC

combustion is fl uid-bed combustion in which

coal is burned with air in a fl uid bed, typically

a circulating fl uid bed (CFB)[20-22]. CFBs are

best suited to low-cost waste fuels and low-

quality or low heating value coals. Crushed coal

and limestone are fed into the bed, where the

limestone undergoes calcination to produce

lime (CaO). Th e fl uid bed consists mainly of

lime, with a few percent coal, and recirculated

coal char. Th e bed operates at signifi cantly low-

er temperatures, about 427° C (800° F), which

thermodynamically favors low NOx formation


and SO2 capture by reaction with CaO to form

CaSO4. Th e steam cycle can be subcritical and

potentially supercritical, as with PC combus-

tion, and generating effi ciencies are similar.

Th e primary advantage of CFB technology is

its capability to capture SO2 in the bed, and

its fl exibility to a wide range of coal proper-

ties, including coals with low heating value,

high-ash coals and low-volatile coals, and to

changes in coal type during operation. Several

new lignite-burning CFB units have been con-

structed recently, and CFBs are well suited to

co-fi ring biomass [23].

Th e performance data for the CFB unit in

Table 3.1 is based on lignite rather than Illi-

nois # 6 coal. Th e lignite has a heating value

of 17,400 kJ/kg and low sulfur. Th e coal feed

rate is higher than for the other technologies

because of the lower heating value of the lig-

nite. Appendix 3.B gives a detailed process

schematic for CFB generation.

COAL TYPE AND QUALITY EFFECTS

Coal type and quality impact generating unit

technology choice and design, generating ef-

fi ciency, capital cost, performance, and COE

(Appendix 3.A). Boiler designs today usually

encompass a broader range of typical coals

than initially intended to provide future fl ex-

ibility. Single coal designs are mostly limited

to mine-mouth plants, which today are usu-

ally only lignite, subbituminous, or brown

coal plants. Th e energy, carbon, moisture, ash,

and sulfur contents, as well as ash characteris-

tics, all play an important role in the value and

selection of coal, in its transportation cost,

and in the technology choice for power gen-

eration. For illustration, Table 3.2 gives typical

values and ranges for various coal properties

as a function of coal type. Although most of

the studies available are based on bituminous

coals, a large fraction of the power generated

in the U.S. involves Western subbituminous

coals (>35%), such as Powder River Basin, be-

cause of its low sulfur content.

Each of these coal properties interacts in a sig-

nifi cant way with generation technology to af-

fect performance. For example, higher sulfur

content reduces PC generating effi ciency due

to the added energy consumption and oper-

ating costs to remove SOx from the fl ue gas.

High ash content requires PC design changes

to manage erosion. High ash is a particular

problem with Indian coals. Fluid-bed com-

bustion is well suited to high-ash coals, low-

carbon coal waste, and lignite. Several high-

effi ciency, ultra-supercritical and supercritical

PC generating units have recently been com-

missioned in Germany burning brown coal or

lignite, and several new CFB units have been

constructed in Eastern Europe, the U.S., Tur-

key and India burning lignite and in Ireland

burning peat[23, 24].

Coal types with lower energy content and

higher moisture content signifi cantly aff ect

capital cost and generating effi ciency. About

50% of U.S. coal is sub-bituminous or lignite.

Using bituminous Pittsburgh #8 as the refer-

ence, PC units designed for Powder River Ba-

sin (PRB) coal and for Texas lignite have an

estimated 14% and 24% higher capital cost

respectively. Generating effi ciency decreases

but by a smaller percentage (Appendix 3.A,

Figure A-3.A.3) [25]. However, the lower cost

of coal types with lower heating value can off -

set the impact of this increased capital cost

and decreased effi ciency, thus, resulting in

very little impact on COE. Using average 2004

mine-mouth coal prices and PC generation,

the COE for Illinois #6, PRB, and Texas lignite

is equal to or less than that for Pittsburgh #8

(Appendix 3.A, Figure A-3.A.4).

U.S. CRITERIA POLLUTANT IMPACTS

Although coal-based power generation has a

negative environmental image, advanced PC

plants have very low emissions; and PC emis-

sions control technology continues to improve

and will improve further (Appendix 3.D). It is

not clear when and where the ultimate limits

of fl ue gas control will be reached. In the U.S.,

particulate removal, via electrostatic precipita-


tors (ESP) or fabric fi lters, is universally prac-

ticed with very high levels of removal (99.9%).

Flue gas desulfurization has been added to

less than one-third of U.S. coal-based gener-

ating capacity [2], and post-combustion NOx

control is practiced on about 10% of the coal-

based generating capacity.

Th e Clean Air Act (1990) set up a cap and

trade system for SOx [26] and established

emissions reductions guidelines for NOx. Th is

has helped produce a 38% reduction in total

SOx emissions over the last 30 years, while

coal-based power generation grew by 90%.

Total NOx emissions have been reduced by

25% over this period. Recent regulations, in-

cluding NAAQS[27], the Clean Air Interstate

Rule (CAIR) [28], and the Clean Air Mercury

Rule (CAMR) [29] will require an additional

60% reduction in total SOx emissions and an

additional 45% reduction in total NOx emis-

sions nationally by 2020. During this period,

coal-based generation is projected to grow

about 35%. Mercury reduction initially comes

with SOx abatement; additional, mandated re-

ductions come aft er 2009. NAAQS have pro-

duced a situation in which permitting a new

coal generating unit requires extremely low

emissions of particulate matter (PM), SOx,

and NOx, driven by the need to meet strin-

gent, local air quality requirements, essentially

independent of national emissions caps.

Newly permitted coal-fi red PC units routinely

achieve greater than 99.5% particulate control,

and removal effi ciencies greater than 99.9% are

achievable at little additional cost. Wet fl ue-

gas desulfurization (FGD) can achieve 95%

SOx removal without additives and 99% SOx

removal with additives [30]. Selective catalytic

reduction (SCR), combined with low-NOx

combustion technology, routinely achieves

90+% NOx reduction over non-controlled

emissions levels. New, advanced PC units in

the U.S. are currently achieving criteria pollut-

ant emissions reductions consistent with the

performance outlined above and have emis-

sions levels that are at or below the emissions

levels achieved by the best PC units in Japan

and Europe (Appendix 3.D).

Today, about 25% of the mercury in the coal

burned is removed by the existing fl ue gas treat-

ment technologies in place, primarily with the

fl y ash via electrostatic precipitators (ESP) or

fabric fi lters. Wet FGD achieves 40-60% mercu-

ry removal; and when it is combined with SCR,

mercury removal could approach 95% for bi-

tuminous coals [31]. For subbituminous coals,

mercury removal is typically less than 40%, and

may be signifi cantly less for lignite, even when

the fl ue gas clean-up technologies outlined

above are in use. However, with activated car-

bon or brominated activated carbon injection

removal rates can be increased to ~90% [31].

Optimization of existing technologies and new

technology innovations can be expected to

achieve > 90% mercury removal on most if not

all coals within the next 10-15 years.

Table 3.3 gives the estimated incremental

impact on the COE of the fl ue gas treatment

technologies to meet the low emissions levels

that are the design basis of this study, vs. a PC

unit without controls. Th e impact of achiev-

ing these levels of control is about 1.0 ¢/kWe-h

Table 3.2 Typical Properties of Characteristic Coal Types

COAL TYPEENERGY CONTENT, kJ/kg

[CARBON CONTENT, wt %] MOISTURE, wt % SULFUR, wt % ASH, wt %

Bituminous* 27,900 (ave. consumed in U.S.) [67 %] 3 – 13 2 – 4 7 - 14

Sub-bituminous* (Powder River Basin) 20,000 (ave. consumed in U.S.) [49 %] 28 - 30 0.3–0.5 5 - 6

Lignite* 15,000 (ave. consumed in U.S.) [40 %] 30 - 34 0.6 - 1.6 7 - 16

Average Chinese Coal 19,000 - 25,000 [48 – 61 %] 3 - 23 0.4 – 3.7 28 - 33

Average Indian Coal 13,000 – 21,000 [30 – 50 %] 4 - 15 0.2 – 0.7 30 - 50

* U.S coal reserves are ~ 48 % anthracite & bituminous, ~37 % subbituminous, and ~ 15 % lignite (See Appendix 3-A, Figure A.2 for more details.)


or about 20% of the total COE from a highly-

controlled PC unit. Although mercury con-

trol is not explicitly addressed here, removal

should be in the 60-80% range for bituminous

coals, including Illinois #6 coal, and less for

subbituminous coals and lignite. We estimate

that the incremental costs to meet CAIR and

CAMR requirements and for decreasing the

PM, SOx, and NOx emissions levels by a fac-

tor of 2 from the current best demonstrated

emissions performance levels used for Table

3.3 would increase the cost of electricity by

about an additional 0.22 ¢/kWe-h (Appendix

3.D, Table A-3D.4). Th e total cost of emis-

sions control is still less than 25% of the cost

of the electricity produced. Meeting the Fed-

eral 2015 emissions levels is not a question of

control technology capabilities but of uniform

application of current technology. Meeting lo-

cal emissions requirements may be a diff erent

matter.

PULVERIZED COAL COMBUSTION GENERATING TECHNOLOGY: WITH CO2 CAPTURE

CO2 capture with PC combustion generation

involves CO2 separation and recovery from

the fl ue gas, at low concentration and low par-

tial pressure. Of the possible approaches to

separation [32], chemical absorption with

amines, such as monoethanolamine (MEA) or

hindered amines, is the commercial process

of choice [33, 34]. Chemical absorption off ers

high capture effi ciency and selectivity for air-

blown units and can be used with sub-, super-,

and ultra-supercritical generation as illustrat-

ed in Figure 3.4 for a subcritical PC unit. Th e

CO2 is fi rst captured from the fl ue gas stream

by absorption into an amine solution in an ab-

sorption tower. Th e absorbed CO2 must then

be stripped from the amine solution via a tem-

perature increase, regenerating the solution

for recycle to the absorption tower. Th e recov-

ered CO2 is cooled, dried, and compressed to a

supercritical fl uid. It is then ready to be piped

to storage.

CO2 removal from fl ue gas requires energy,

primarily in the form of low-pressure steam

for the regeneration of the amine solution.

Th is reduces steam to the turbine and the net

power output of the generating plant. Th us, to

maintain constant net power generation the

coal input must be increased, as well as the size

of the boiler, the steam turbine/generator, and

the equipment for fl ue gas clean-up, etc. Ab-

sorption solutions that have high CO2 binding

energy are required by the low concentration

of CO2 in the fl ue gas, and the energy require-

ments for regeneration are high.

A subcritical PC unit with CO2 capture (Fig-

ure 3.4), that produces 500 MWe net power,

requires a 37% increase in plant size and in

coal feed rate (76,000 kg/h more coal) vs. a

Table 3.3 Estimated Incremental Costs for a Pulverized Coal Unit to Meet Today’s Best Dem-onstrated Criteria Emissions Control Performance Vs. No Control

CAPITAL COSTa [$/kWe] O&Mb [¢/kWe-h] COEc [¢/kWe-h]

PM Controld 40 0.18 0.26

NOx 25 (50 – 90)e 0.10 (0.05 – 0.15) 0.15 (0.15 – 0.33)

SO2 150 (100 – 200)e 0.22 (0.20 – 0.25) 0.52 (0.40 – 0.65)

Incremental control cost 215 0.50 0.93f

a. Incremental capital costs for a typical, new-build plant to meet today’s low emissions levels. Costs for low heating value coals will be somewhat higher

b . O&M costs are for typical plant meeting today’s low emissions levels. Costs will be somewhat higher for high-sulfur and low heating value coals.

c. Incremental COE impact, bituminous coal

d. Particulate control by ESP or fabric fi lter included in the base unit costs

e. Range is for retrofi ts and depends on coal type, properties, control level and local factors

f. When added to the “no-control” COE for SC PC, the total COE is 4.78 ¢/kWe-h


500 MWe unit without CO2 capture (Figure

3.2). Th e generating effi ciency is reduced from

34.3% to 25.1% (Table 3.1). Th e primary fac-

tors in effi ciency reduction associated with ad-

dition of CO2 capture are illustrated in Figure

3.5. Th e thermal energy required to recover

CO2 from the amine solution reduces the ef-

fi ciency by 5 percentage points. Th e energy

required to compress the CO2 from 0.1 MPa

to about 15 MPa ( to a supercritical fl uid) is

the next largest factor, reducing the effi ciency

by 3.5 percentage points. All other energy re-

quirements amount to less than one percent-

age point.

An ultra-supercritical PC unit with CO2 cap-

ture (Figure 3.6) that produces the same net

power output as an ultra-supercritical PC unit

without CO2 capture (Figure 3.3) requires a

27% increase in unit size and in coal feed rate

(44,000 kg/h more coal). Figure 3.7 illustrates

the main factors in effi ciency reduction asso-

ciated with addition of CO2 capture to an ul-

tra-supercritical PC unit. Th e overall effi cien-

cy reduction is 9.2 percentage points in both

cases, but the ultra-supercritical, non-capture

unit starts at a suffi ciently high effi ciency that

with CO2 capture, its effi ciency is essentially

the same as that of the subcritical unit without

CO2 capture.

COST OF ELECTRICITY FOR AIR-BLOWN PULVER-IZED COAL COMBUSTION

Th e cost of electricity (COE), without and with

CO2 capture, was developed for the competing

technologies analyzed in this report through

a detailed evaluation of recent design studies,

combined with expert validation. Appendix

3.C lists the studies that formed the basis for

our report (Table A-3.C.2), provides more de-

tail on each, and details the approach used. Th e

largest and most variable component of COE

among the studies is the capital charge, which

is dependent on the total plant (or unit) cost

(TPC) and the cost of capital. Figure 3.8 shows


the min, max, and mean of the estimated TPC

for each technology expressed in 2005 dollars.

Costs are for a 500 MWe plant and are given in

$/kWe net generating capacity.

In addition to the variation in TPC, each of

these studies used diff erent economic and op-

erating parameter assumptions resulting in a

range in the capital carrying cost, in the O&M

cost, and in the fuel cost. Th e diff erences in

these assumptions among the studies account

for much of the variability in the reported

COE. Th e COE from these studies is shown in

Figure 3.9, where the “as-reported” bars show

the min, max, and mean in the COE for the

diff erent technologies as reported in the stud-

ies in the dollars of the study year. Appendix

3.C provides more detail.

To compare the studies on a more consistent

basis, we recalculated the COE for each of the

studies using the normalized economic and

operating parameters listed in Table 3.4. O&M

costs are generally considered to be technology

and report-specifi c and were not changed in

this analysis. Other factors that contribute to

variation include regional material and labor

costs, and coal quality impacts. Th e “normal-

ized” bars in Figure 3.9 summarize the results

of this analysis of these design studies.

Th e variation in “as-reported” COE for non-

capture PC combustion is small because of

the broad experience base for this technology.

Signifi cant variation in COE exists for the CO2

capture cases due to the lack of commercial

data. Th e normalized COE values are higher

for most of the cases because we used a higher

fuel price and put all cost components in 2005

dollars.

To develop the COE values for this report, we

took the TPC numbers from the design stud-

ies (Figure 3.8), adjusted them to achieve in-

ternal consistency (e.g. SubC PC<SC PC<USC

PC), then compared our TPC numbers with

industry consensus group numbers [35] and

made secondary adjustments based on ratios

and deltas from these numbers. Th is produced

the TPC values in Table 3.1. Using these TPC


numbers, the parameters in Table 3.4, and es-

timated O&M costs, we calculated the COE

for each technology, and these are given in

Table 3.1.

Total plant costs shown above and in Table

3.1 were developed during a period of price

stability [2000-2004] and were incremented

by CPI infl ation to 2005$. Th ese costs and the

deltas among them were well vetted, broadly

accepted, and remain valid in comparing costs

of diff erent generating technologies. However,

signifi cant cost infl ation from 2004 levels due

to increases in engineering and construction

costs including labor, steel, concrete and other

consumables used for power plant construc-

tion, has been between 25 and 30%. Th us, a

SCPC unit with an estimated capital cost of

$1330 (Table 3.1) is now projected at $1660 to

$1730/ kWe in 2007$. Because we have no fi rm

data on how these cost increases will aff ect the

cost of the other technologies evaluated in this

report, the discussion that follows is based on

the cost numbers in Table 3.1, which for rela-

tive comparison purposes remain valid.

For PC generation without CO2 capture, the

COE decreases from 4.84 to 4.69 ¢/kWe-h

from subcritical to ultra-supercritical technol-

ogy because effi ciency gains outweigh the ad-

ditional capital cost (fuel cost component de-

creases faster than the capital cost component

increases). Historically, coal cost in the U.S.

has been low enough that the economic choice

has been subcritical PC. Th e higher coal costs

in Europe and Japan have driven the choice

of higher-effi ciency generating technologies,

supercritical and more recently ultra-super-

critical. For the CFB case, the COE is similar

to that for the PC cases, but this is because

cheaper lignite is the feed, and emissions con-

trol is less costly. Th e CFB design used here

does not achieve the very low criteria emis-

sions achieved by our PC design. For Illinois

#6 and comparable emissions limits, the COE

for the CFB would be signifi cantly higher.

Th e increase in COE in going from no-capture

to CO2 capture ranges from 3.3 ¢/kWe-h for

subcritical generation to 2.7 ¢/kWe-h for ultra-

supercritical generation (Table 3.1). Over half

of this increase is due to higher capital carrying

charge resulting from the increased boiler and

steam turbine size and the added CO2 capture,

recovery, and compression equipment. About

two thirds of the rest is due to higher O&M

costs associated with the increased operational

scale per kWe and with CO2 capture and recov-

ery. For air-blown PC combustion technolo-

gies, the cost of avoided CO2 is about $41 per

tonne. Th ese costs are for capture, compression

and drying, and do not include the pipeline,

transportation and sequestration costs.

Th e largest cause of the effi ciency reduction

observed with CO2 capture for air-blown PC

generation (Figure 3.5 and 3.7) is the energy

Table 3.4 Economic and Operating Parameters

PARAMETER VALUE

Capacity factor 85%

Carrying charge factor 15.1%

Fuel cost $1.50 / MMBtu (HHV)

Total capital requirement (TCR) 12% higher than total plant cost

Life of plant 20 years

Cost year basis 2005

Tax rate 39.2%


required to regenerate the amine solution

(recovering the CO2), which produces a 5

percentage point effi ciency reduction. If this

component could be reduced by 50% with

an effi cient, lower-energy capture technol-

ogy, the COE for supercritical capture would

be reduced by about 0.5 ¢/kWe-h to about 7.2

¢/kWe-h and by about 0.4 ¢/kWe-h for ultra-

supercritical generation. Th is would reduce

the CO2 avoided cost to about $30 per tonne,

a reduction of over 25%.

RETROFITS FOR CO2 CAPTURE

Because of the large coal-based PC generating

fl eet in place and the additional capacity that

will be constructed in the next two decades, the

issue of retrofi tting for CO2 capture is impor-

tant to the future management of CO2 emis-

sions. For air-blown PC combustion units, ret-

rofi t includes the addition of a process unit to

the back end of the fl ue-gas system to separate

and capture CO2 from the fl ue gas, and to dry

and compress the CO2 to a supercritical fl uid,

ready for transport and sequestration. Since

the existing coal fl eet consists of primarily

subcritical units, another option is to rebuild

the boiler/steam system, replacing it with high

effi ciency supercritical or ultra-supercritical

technology, including post-combustion CO2

capture. Appendix 3.E provides a more-de-

tailed analysis of retrofi ts and rebuilds.

For an MEA retrofi t of an existing subcriti-

cal PC unit, the net electrical output can be

derated by over 40%, e.g., from 500 MWe to

294 MWe [36]. In this case, the effi ciency de-

crease is about 14.5 percentage points (Ap-

pendix 3.E) compared to about 9.2 percentage

points for purpose-built subcritical PC units,

one no-capture and the other capture (Table

3.1). With the retrofi t, the steam required to

regenerate the absorbing solution to recover

the CO2 (Figure 3.4), unbalances the rest of

the plant so severely that the effi ciency is re-

duced another 4 to 5 percentage points. In the

retrofi t case, the original boiler is running at

full design capacity, but the original steam tur-

bine is operating at about 60% design rating,

which is well off its effi ciency optimum. Due

to the large power output reduction (41% de-

rating), the retrofi t capital cost is estimated to

be $1600 per kWe [36]. Th is was for a specifi c


unit with adequate space; however, retrofi t

costs are expected to be highly dependent on

location and unit specifi cs. If the original unit

is considered fully paid off , we estimate the

COE aft er retrofi t could be slightly less than

that for a new purpose-built PC unit with CO2

capture. However, an operating plant will usu-

ally have some residual value, and the reduc-

tion in unit effi ciency and output, increased

on-site space requirements and unit downtime

are all complex factors not fully accounted for

in this analysis. Based on our analysis, we con-

clude that retrofi ts seem unlikely.

Another approach, though not a retrofi t, is

to rebuild the core of a subcritical PC unit,

installing supercritical or ultra-supercritical

technology along with post-combustion CO2

capture. Although the total capital cost for

this approach is higher, the cost/kWe is about

the same as for a subcritical retrofi t. Th e re-

sultant plant effi ciency is higher, consistent

with that of a purpose-built unit with capture;

the net power output can essentially be main-

tained; and the COE is about the same due to

the overall higher effi ciency. We estimate that

an ultra-supercritical rebuild with MEA cap-

ture will have an effi ciency of 34% and pro-

duce electricity for 6.91 ¢/kWe-h (Appendix

3.E). We conclude that rebuilds including CO2

capture appear more attractive than retrofi ts,

particularly if they upgrade low-effi ciency PC

units with high-effi ciency technology, includ-

ing CO2 capture.

CAPTURE-READY A unit can be considered

capture-ready if, at some point in the future,

it can be retrofi tted for CO2 capture and se-

questration and still be economical to operate

[37]. Th us, capture-ready design refers to de-

signing a new unit to reduce the cost of and to

facilitate adding CO2 capture later or at least

to not preclude addition of capture later. Cap-

ture-ready has elements of ambiguity associ-

ated with it because it is not a specifi c design,

but includes a range of investment and design

decisions that might be undertaken during

unit design and construction. Further, with an

uncertain future policy environment, signifi -

cant pre-investment for CO2 capture is typi-

cally not economically justifi ed [38]. However,

some actions make sense. Future PC plants

should employ the highest economically ef-

fi cient technology and leave space for future

capture equipment if possible, because this

makes retrofi ts more attractive. Siting should

consider proximity to geologic storage.

OXYGEN-BLOWN COAL-BASED POWER GENERA-TION

Th e major problems with CO2 capture from

air-blown PC combustion are due to the need

to capture CO2 from fl ue gas at low concentra-

tion and low partial pressure. Th is is mainly

due to the large amount of nitrogen in the fl ue

gas, introduced with the combustion air. An-

other approach to CO2 capture is to substitute

oxygen for air, essentially removing most of the

nitrogen. We refer to this as oxy-fuel PC com-

bustion. A diff erent approach is to gasify the

coal and remove the CO2 prior to combustion.

Each of these approaches has advantages and

disadvantages, but each off ers opportunities

for electricity generation with reduced CO2-

capture costs. We consider these approaches

next in the form of oxy-fuel PC combustion

and Integrated Gasifi cation Combined Cycle

(IGCC) power generation.

Table 3.5 summarizes representative perfor-

mance and economics for oxygen-blown coal-

based power generation technologies. Oxy-

fuel combustion and IGCC were evaluated

using the same bases and assumptions used for

the PC combustion technologies (Table 3.1).

In this case the estimates are for the Nth unit

or plant where N is a relatively small number,

< 10. In this report, we use gasifi cation and

IGCC to mean oxygen-blown gasifi cation or

oxygen-blown IGCC. If we mean air-blown

gasifi cation, it will be explicitly stated.

OXY-FUEL PULVERIZED COAL (PC) COMBUS-TION

Th is approach to capturing CO2 from PC

units involves burning the coal with ~95%


pure oxygen instead of air as the oxidant[39-

41]. Th e fl ue gas then consists mainly of car-

bon dioxide and water vapor. Because of the

low concentration of nitrogen in the oxidant

gas (95% oxygen), large quantities of fl ue gas

are recycled to maintain design temperatures

and required heat fl uxes in the boiler, and dry

coal-ash conditions. Oxy-fuel enables capture

of CO2 by direct compression of the fl ue gas

but requires an air-separation unit (ASU) to

supply the oxygen. Th e ASU energy consump-

tion is the major factor in reducing the effi -

ciency of oxy-fuel PC combustion. Th ere are

no practical reasons for applying oxy-fuel ex-

cept for CO2 capture.

A block diagram of a 500 MWe oxy-fuel gen-

erating unit is shown in Figure 3.10 with key

material fl ows shown. Boiler and steam cycle

are supercritical. Th e coal feed rate is higher

than that for supercritical PC without capture

because of the power consumption of the air

separation unit but lower than that for a super-

critical PC with MEA CO2 capture (Table 3.1).

In this design, wet FGD is used prior to recycle

to remove 95% of the SOx to avoid boiler cor-

rosion problems and high SOx concentration

in the downstream compression/separation

equipment. Non-condensables are removed

from the compressed fl ue gas via a two-stage

fl ash. Th e composition requirements (purity)

of the CO2 stream for transport and geologi-

cal injection are yet to be established. Th e

Table 3.5 Representative Performance and Economics for Oxy-Fuel Pulverized Coal and IGCC Power Generation Technologies, Compared with Supercritical Pulverized Coal

SUPERCRITICAL PC SC PC-OXY IGCC

W/O CAPTURE W/ CAPTURE W/CAPTURE W/O CAPTUREQ W/CAPTURE

PERFORMANCE

Heat rate (1), Btu/kWe-h 8,868 11,652 11,157 8,891 10,942

Generating effi ciency (HHV) 38.5% 29.3% 30.6% 38.4% 31.2%

Coal feed, kg/h 184,894 242,950 232,628 185,376 28,155

CO2 emitted, kg/h 414,903 54,518 52,202 415,983 51,198

CO2 captured at 90%, kg/h (2) 0 490,662 469,817 0 460,782

CO2 emitted, g/kWe-h (2) 830 109 104 832 102

COSTS

Total Plant Cost (3), $/kWe 1,330 2,140 1,900 1,430 1,890

Inv. Charge, ¢/kWe-h @ 15.1% (4) 2.70 4.34 3.85 2.90 3.83

Fuel, ¢/kWe-h @ $1.50/MMBtu 1.33 1.75 1.67 1.33 1.64

O&M, ¢/kWe-h 0.75 1.60 1.45 0.90 1.05

COE, ¢/kWe-h 4.78 7.69 6.98 5.13 6.52

Cost of CO2 avoided vs. same technology w/o capture (5), $/tonne 40.4 30.3 19.3

Cost of CO2 avoided vs. supercritical technology w/o capture (5), $/tonne 40.4 30.3 24.0

Basis: 500 MWe plant net output, Illinois # 6 coal (61.2 wt % C, HHV = 25,350 kJ/kg), & 85% capacity factor; for oxy-fuel SC PC CO2 for sequestration is high purity; for IGCC, GE radiant cooled gasifi er for no-capture case and GE full-quench gasifi er for capture case.

(1) effi ciency = (3414 Btu/kWe-h)/(heat rate)

(2) 90% removal used for all capture cases

(3) Based on design studies done between 2000 & 2004, a period of cost stability, updated to 2005$ using CPI infl ation rate. Refers to the Nth plant where N is less than 10. 2007 cost would be higher because of recent rapid increases of engineering and construction costs, up to 30% since 2004.

(4) Annual carrying charge of 15.1% from EPRI-TAG methodology, based on 55% debt @ 6.5%, 45% equity @ 11.5%, 39.2% tax rate, 2% infl ation rate, 3 year construction period, 20 year book life, applied to total plant cost to calculate investment charge

(5) Does not include costs associated with transportation and injection/storage


generating effi ciency is 30.6% (HHV), which

is about 1 percentage point higher than super-

critical PC with MEA CO2 capture. Current

design work suggests that the process can be

further simplifi ed with SOx and NOx removal

occurring in the downstream compression &

separation stage at reduced cost [42]. Further

work is needed.

Figure 3.11 shows the parasitic energy re-

quirements for oxy-fuel PC generation with

CO2 capture. Since the steam cycle is super-

critical for the oxy-fuel case, supercritical PC

is used as the comparison base. Th e oxy-fuel

PC unit has a gain over the air-driven PC case

due to improved boiler effi ciency and reduced

emissions control energy requirements, but

the energy requirement of the ASU, which

produces a 6.4 percentage point reduction,

outweighs this effi ciency improvement. Th e

overall effi ciency reduction is 8.3 percentage

points from supercritical PC. More effi cient

oxygen separation technology would have a

signifi cant impact.

A key unresolved issue is the purity require-

ments of the supercritical CO2 stream for geo-

logical injection (sequestration). Our design

produces a highly-pure CO2 stream, similar

to that from the PC capture cases, but incurs

additional cost to achieve this purity level. If

this additional purifi cation were not required

for transport and geologic sequestration of the

CO2, oxy-fuel PC combustion could gain up

to one percentage point in effi ciency, and the

COE could be reduced by up to 0.4 ¢/kWe-h.

Oxy-fuel PC combustion is in early commer-

cial development but appears to have consid-

erable potential. It is under active pilot-scale

development [43, 44]; Vattenfall plans a 30

MWth CO2-free coal combustion plant for

2008 start-up[43]; Hamilton, Ontario is de-

veloping a 24 MWe oxy-fuel electricity gen-

eration project [45]; and other projects can be

expected to be announced.

ECONOMICS Because there is no commercial

experience with oxy-fuel combustion and lack

of specifi city on CO2 purity requirements for

transport and sequestration in a future regu-

latory regime, the TPC in the limited design

studies ranged broadly [13, 39, 41, 46] (Ap-

pendix 3.C, Table A-3.C.2, Figure A-3.C.1).


Only the Parsons study estimated the COE

[13]. As with PC combustion, we reviewed the

available design studies (Appendix 3.C), our

plant component estimate of costs, and ex-

ternal opinion of TPC to arrive at a projected

TPC (Table 3.5). We estimated generating ef-

fi ciency to be 30.6% from the Integrated Envi-

ronmental Control Model[5]. We applied our

normalization economic and operating pa-

rameters (Table 3.4) to calculate a COE of 6.98

¢/kWe-h (Table 3.5). Th ere may be some up-

side potential in these numbers if supercritical

CO2 stream purity can be relaxed and design

effi ciencies gained, but more data are needed.

RETROFITS Oxy-fuel is a good option for ret-

rofi tting PC and FBC units for capture since

the boiler and steam cycle are less aff ected by

an oxy-fuel retrofi t; the major impact being an

increased electricity requirement for the aux-

iliaries, particularly the ASU. Bozzuto estimat-

ed a 36% derating for an oxy-fuel retrofi t vs.

a 41% derating for MEA capture on the same

unit [36]. In summary, the oxy-fuel retrofi t op-

tion costs about 40% less on a $/kWe basis, is

projected to produce electricity at 10% to 15%

less than an MEA retrofi t, and has a signifi -

cantly lower CO2 avoidance cost (Appendix

3.E). Oxy-fuel rebuild to improve effi ciency is

another option and appears to be competitive

with a high-effi ciency MEA rebuild [47].

INTEGRATED GASIFICATION COMBINED CYCLE (IGCC)

Integrated gasifi cation combined cycle (IGCC)

technology produces electricity by fi rst gasify-

ing coal to produce syngas, a mixture of hy-

drogen and carbon monoxide[48, 49]. Th e

syngas, aft er clean-up, is burned in a gas tur-

bine which drives a generator. Turbine ex-

haust goes to a heat recovery generator to raise

steam which drives a steam turbine generator.

Th is combined cycle technology is similar to

the technology used in modern natural gas

fi red combined-cycle power plants. Appendix

3.B provides more detail on gasifi cation.

Th e key component in IGCC is the gasifi er, for

which a number of diff erent technologies have

been developed and are classifi ed and summa-

rized in Table 3.6.

Gasifi er operating temperature depends on

whether the ash is to be removed as a solid,

dry ash or as a high-temperature liquid (slag).

Outlet temperature depends on the fl ow re-

gime and extent of mixing in the gasifi er. For

the current IGCC plants, oxygen-blown, en-

trained-fl ow gasifi ers are the technology of

choice, although other confi gurations are be-

ing evaluated.

Four 275 to 300 MWe coal-based IGCC dem-

onstration plants, which are all in commercial

operation, have been built in the U.S. and in

Europe, each with government fi nancial sup-

port [50][33]. Five large IGCC units (250 to

550 MWe) are operating in refi neries gasifying

asphalt and refi nery wastes [51, 52]; a smaller

one (180 MWe) is operating on petroleum coke.

Th e motivation for pursuing IGCC is the po-

tential for better environmental performance

at a lower marginal cost, easier CO2 capture

for sequestration, and higher effi ciency. How-

ever, the projected capital cost (discussed be-

low) and operational availability of today’s

IGCC technology make it diffi cult to compete

with conventional PC units at this time.


IGCC: WITHOUT CO2 CAPTURE

Th ere are several commercial gasifi ers which

can be employed with IGCC [53] (see Ap-

pendix 3.B for details). A block diagram of a

500 MWe IGCC unit using a radiant cooling/

quench gasifi er is shown in Figure 3.12. Finely

ground coal, either dry or slurried with water,

is introduced into the gasifi er, which is operat-

ed at pressures between 3.0 and 7.1 MPa (440

to 1050 psi), along with oxygen and water.

Oxygen is supplied by an air separation unit

(ASU). Th e coal is partially oxidized raising

the temperature to between 1340 and 1400 oC.

Th is assures complete carbon conversion by

rapid reaction with steam to form an equilib-

rium gas mixture that is largely hydrogen and

carbon monoxide (syngas). At this tempera-

ture, the coal mineral matter melts to form

a free-fl owing slag. Th e raw syngas exits the

gasifi cation unit at pressure and relatively high

temperature, with radiative heat recovery rais-

ing high-pressure steam. Adequate technol-

ogy does not exist to clean-up the raw syngas

at high temperature. Instead, proven technol-

ogies for gas clean-up require near-ambient

temperature. Th us, the raw syngas leaving the

gasifi er can be quenched by injecting water, or

a radiant cooler, and/or a fi re-tube (convec-

tive) heat exchanger may be used to cool it to

the required temperature for removal of par-

ticulate matter and sulfur.

Th e clean syngas is then burned in the com-

bustion turbine. Th e hot turbine exhaust gas

is used to raise additional steam which is sent

to the steam turbine in the combined-cycle

power block for electricity production. For

the confi guration shown (See Box 3.1), the

overall generating effi ciency is 38.4% (HHV),

but coal and gasifi er type will impact this

number.

Table 3.6 Classifi cation and Characteristics of Gasifi ers

MOVING BED FLUID BED ENTRAINED FLOW

Outlet temperature Low (425-600 °C) Moderate (900-1050 °C) High (1250-1600 °C)

Oxidant demand Low Moderate High

Ash conditions Dry ash or slagging Dry ash or agglomerating Slagging

Size of coal feed 6-50 mm 6-10 mm < 100 µm

Acceptability of fi nes Limited Good Unlimited

Other characteristics Methane, tars and oils present in syngas

Low carbon conversion Pure syngas, high carbon conversion


IGCC: WITH PRE-COMBUSTION CO2 CAPTURE

Applying CO2 capture to IGCC requires three

additional process units: shift reactors, an ad-

ditional CO2 separation process, and CO2

compression and drying. In the shift reactors,

CO in the syngas is reacted with steam over

a catalyst to produce CO2 and hydrogen. Be-

cause the gas stream is at high pressure and

has a high CO2 concentration, a weakly CO2-

binding physical solvent, such as the glymes in

Selexol, can be used to separate out the CO2.

Reducing the pressure releases the CO2 and

regenerates the solvent, greatly reducing the

energy requirements for CO2 capture and re-

covery compared to the MEA system. Higher

pressure in the gasifi er improves the energy ef-

fi ciency of both the separation and CO2 com-

pression steps. Th e gas stream to the turbine is

now predominantly hydrogen, which requires

turbine modifi cations for effi cient operation.

Th e block diagram with key material fl ows for

a 500 MWe IGCC unit designed for CO2 cap-

ture is shown in Figure 3.13. For CO2 capture, a

full-quench gasifi er is currently considered the

optimum confi guration. Th e overall generating

effi ciency is 31.2% which is a 7.2 percentage

point reduction from the IGCC system with-

out CO2 capture. Adding CO2 capture requires

a 23% increase in the coal feed rate. Th is com-

pares with coal feed rate increases of 27% for

ultra-supercritical PC and 37% for subcritical

PC when MEA CO2 capture is used.

Figure 3.14 illustrates the major impacts on ef-

fi ciency of adding CO2 capture to IGCC. CO2

compression and water gas shift each have

BOX 3.1 IGCC DEMONSTRATIONS

The Cool Water Project sponsored by Southern Cali-fornia Edison in cooperation with GE and Texaco pio-neered IGCC with support from the Synthetic Fuels Corporation. This plant demonstrated the feasibility of using IGCC to generate electricity. The plant op-erated periodically from 1984–1989, and cost over $2000 /kWe. The project was eventually abandoned, but it provided the basis for the Tampa Electric Polk Power Station. The DOE supported the 250 MWe Polk Station commercial IGCC demonstration unit, using a Texaco gasifi er, which started up in 1996. The total plant cost was about $1800/kWe. Since it was the fi rst commercial-scale IGCC plant, several optional systems were added, such as a hot-gas clean-up sys-tem, which were never used, and were later simpli-fi ed or removed. When these changes are taken into accounted, the adjusted total plant cost has been estimated at $1650/kWe (2001$). This experience has led to some optimism that costs will come down signifi cantly with economies of scale, component standardization, and technical and design advances. However, price increases will raise the nominal cost of plant capital signifi cantly.

The availability of these early IGCC plants was low for the fi rst sev-eral years of operation due to a range of problems, as shown in the fi gure. Many of the problems were design and materials related

which were corrected and are unlikely to reappear; others are pro-cess related, much like running a refi nery, but all eventually proved to be manageable. Gasifi er availability is now 82+% and operating effi ciency is ~35.4%. DOE also supported the Wabash River Gasifi ca-tion Repowering Project, an IGCC demonstration project using the Dow E-gas gasifi er. This demonstration started up in late 1995, has 262 MWe capacity, and an effi ciency of ~38.4%. Start-up history was similar to that of the Polk unit. LGTI provided the basis for Wabash.


signifi cant impacts. CO2 compression is about

two-thirds that for the PC cases because the

CO2 is recovered at an elevated pressure. En-

ergy is required in the form of steam for shift

reaction. Th e energy required for CO2 recov-

ery is lower than for the PC case because of the

higher pressures and higher CO2 concentra-

tions, resulting in less energy intensive separa-

tion processes. Th e total effi ciency reduction

for IGCC is 7.2 percentage points as compared

with 9.2 percentage points for the PC cases.

Th is smaller delta between the no-capture and

the capture cases is one of the attractive fea-

tures of IGCC for application to CO2 capture.

COST OF ELECTRICITY We analyzed the avail-

able IGCC design studies, without and with

CO2 capture, just as we did for PC genera-

tion, to arrive at a TPC and our estimate of the

COE (Appendix 3.C). Th ere was considerable

variation (~$400/kWe from min to max) in

the TPC from the design studies for both no-

capture and capture cases as shown in Figure

A-3.C.2 (Appendix 3.C). Each estimate is for a

500 MWe plant and includes the cost of a spare

gasifi er. Th is variation is not surprising in that

the studies involved two gasifi er types, and

there is little commercial experience against

which to benchmark costs. Th ere is a variation

(min to max) of 0.8 ¢/kWe-h for no capture

and 0.9 ¢/kWe-h for CO2 capture in the “as-

reported” COE in the studies (Figure A-3.C.4,

Appendix 3.C).

We used the same approach to estimate the

COE for IGCC as for air-blown PC [54]. For

IGCC w/o capture, the COE is about 0.4 cent/

kWe-h higher than for supercritical PC genera-

tion, driven by somewhat higher capital and

operating costs. Th e increase in COE for IGCC

when CO2 capture is added is about 1.4 ¢/kWe-

h. Th is is about half the increase projected for

amine capture with supercritical PC. Th e cost

of avoided CO2 is about $ 20 per tonne which

is about half that for air-blown PC technology.

Oxy-fuel PC is in between air-blown PC with

amine capture and IGCC with CO2 capture,

based on currently available data.

Th e COE values developed for this report

compare well with the “normalized” values


from the design studies evaluated (Figure A-

3.C.3 and A-3.C.4). Our values are close to the

mean values for super-critical PC without and

with capture. For IGCC, our values are at the

high end of the range of the other design stud-

ies. Our COE for oxy-fuel PC is slightly higher

than the “as-reported” values, although it is

important to note that oxy-fuel data are based

on only two published studies [44, 55].

To further validate the fi ndings in this sec-

tion, we compared our results with the COE

estimates from several sources and summa-

rize these results in Table 3.7. Supercritical

PC without capture is set as the reference at

1.0. Th is suggests that without CO2 capture,

the cost of electricity from IGCC will be from

5 to 11% higher than from supercritical PC.

When CO2 capture is considered, the cost of

electricity produced by IGCC would be in-

creased by 30 to 50% over that of supercritical

PC without capture, or 25 to 40% over that of

IGCC without capture (Table 3.7). However,

for supercritical PC with CO2 capture, the cost

of electricity is expected to increase by 60 to

85% over the cost for supercritical PC with-

out capture. Th ese numbers are for green-fi eld

plants; they are also for the Nth plant where

N is less than 10; and they are based on cost

estimates from the relatively stable 2000–2004

cost period.

COAL TYPE AND QUALITY EFFECTS Although

gasifi cation can handle almost any carbon-

containing material, coal type and quality can

have a larger eff ect on IGCC than on PC gen-

eration. IGCC units operate most eff ectively

and effi ciently on dry, high-carbon fuels such

as bituminous coals and coke. Sulfur content,

which aff ects PC operation, has little eff ect on

IGCC cost or effi ciency, although it may im-

pact the size of the sulfur clean-up process.

For IGCC plants, coal ash consumes heat en-

ergy to melt it, requires more water per unit

carbon in the slurry, increases the size of the

ASU, and ultimately results in reduced overall

effi ciency. Th is is more problematic for slurry-

feed gasifi ers, and therefore, high-ash coals are

more suited to dry-feed systems (Shell), fl uid-

bed gasifi ers (BHEL), or moving-bed gasifi ers

(Lurgi)[25]. Slurry-fed gasifi ers have similar

problems with high-moisture coals and coal

types with low heating values, such as lignite.

Th ese coal types decrease the energy density

of the slurry, increase the oxygen demand, and

decrease effi ciency. Dry-feed gasifi ers are fa-

vored for high-moisture content feeds.

Coal quality and heating value impact IGCC

capital cost and generating effi ciency more

strongly than they aff ect these parameters

for PC generation (see Figure A-3.A.3, Ap-

pendix 3.A) [25]. However, the lower cost of

coals with low heating value can off set much

of the impact of increased capital cost and re-

duced effi ciency. To illustrate, the capital cost

per kWe and the generating effi ciency for an

E-Gas IGCC plant designed for Texas lignite

are estimated to be 37% higher and 24% lower

respectively than if the unit were designed for

Pittsburgh #8 coal [25]. For PC combustion

the impact is signifi cantly less: 24% higher

and 10% lower respectively. As a result, we es-

timate that the COE for Texas lignite genera-

tion is about 20% higher (Figure A-3.A.4) than

for Pittsburgh #8 coal because lower coal cost

is not suffi cient to off set the other increases.

Table 3.7 Relative Cost of Electricity from PC and IGCC Units, without and with CO2 Capture*

MIT GTC AEP GE

PC no-capture, reference 1.0 1.0 1.0 1.0

IGCC no-capture 1.05 1.11 1.08 1.06

IGCC capture 1.35 1.39 1.52 1.33

PC capture 1.60 1.69 1.84 1.58

*Included are: the MIT Coal Study results (MIT), the Gasifi cation Technology Council (GTC) [56], General Electric (GE) [57], and American Electric Power (AEP) [58].


Texas lignite has a high-moisture content and

a low-carbon content, which is particularly

bad for a slurry-feed gasifi er. For a dry-feed

gasifi er, such as the Shell gasifi er, the lignite

would compare more favorably. Optimum

gasifi er type and confi guration are infl uenced

by coal type and quality, but there are limited

data on these issues.

Th e available data illustrate several important

trends and gaps. First, there is a lack of data

and design studies for IGCC with low-heat-

ing value, low-quality coals and particularly

for gasifi ers other than water-slurry fed, en-

trained-fl ow systems. Second, PC generation

without CO2 capture is slightly favored over

IGCC (lower COE) for high heating value,

bituminous coals, but this gap increases as

PC steam cycle effi ciency increases and as

coal heating value decreases. Th e COE gap is

substantially widened (favoring PC) for coals

with low heating values, such as lignite. Th ird,

for CO2 capture, the COE gap for high-heat-

ing value bituminous coals is reversed and is

substantial (IGCC now being favored); but as

coal heating value decreases, the COE gap is

substantially narrowed. It appears that ultra-

supercritical PC combustion and lower energy

consuming CO2 capture technology, when de-

veloped, could have a lower COE than water-

slurry fed IGCC with CO2 capture. Th is area

needs additional study.

U.S. CRITERIA POLLUTANT IMPACTS – ENVIRON-MENTAL PERFORMANCE IGCC has inherent

advantages with respect to emissions control.

Th e overall environmental footprint of IGCC

is smaller than that of PC because of reduced

volume and lower leachability of the fused

slag, reduced water usage and the potential for

signifi cantly lower levels of criteria pollutant

emissions. Criteria emissions control is easier

because most clean-up occurs in the syngas

which is contained at high pressure and has

not been diluted by combustion air, i.e. nitro-

gen. Th us, removal can be more eff ective and

economical than cleaning up large volumes of

low-pressure fl ue gas.

Th e two operating IGCC units in the U.S. are

meeting their permitted levels of emissions,

which are similar to those of PC units. How-

ever, IGCC units that have been designed to

do so can achieve almost order-of-magnitude

lower criteria emissions levels than typical

current U.S. permit levels and 95+% mercury

removal with small cost increases. Appendix

3.D details the environmental performance

demonstrated and expected.

Our point COE estimates suggest that al-

though improvements in PC emissions con-

trol technology, including mercury control,

will increase the COE from PC units, the lev-

els of increased control needed to meet fed-

eral emissions levels for 2015 should not make

the COE from a PC higher than that from an

IGCC. We estimate that the increased emis-

sions control to meet the U.S. 2015 regula-

tions, including mercury, will increase the PC

COE by about 0.22 ¢/kWe-h to 5.00 ¢/kWe-h

and the COE for IGCC to 5.16 ¢/kWe-h (Ap-

pendix 3.D). Th is does not include the cost of

emissions allowances or major, unanticipated

regulatory or technological changes. Although

the COE numbers for PC and IGCC are ex-

pected to approach one another, the cost of

meeting criteria pollutant and mercury emis-

sions regulations should not force a change in

technology preference from PC to IGCC with-

out CO2 capture.

However, evaluation and comparison of gen-

erating technologies for future construction

need to incorporate the eff ect of uncertainty

in the key variables into the economic evalu-

ation. Th is includes uncertainty in technology

performance, including availability and ability

to cycle, and cost, in regulatory changes, in-

cluding timing and cost, and in energy costs

and electricity demand/dispatch. Forward

estimates for each variable are set, values,

bounds and probabilities are established; and

a Monte Carlo simulation is done producing a

sensitivity analysis of how changes in the vari-

ables aff ect the economics for a given plant.

Th is analysis shows that as permitted future

pollutant emissions levels are reduced and the

cost of emissions control increases, the NPV


cost gap between PC and IGCC will narrow;

and at some point, increased emissions con-

trol can be expected to lead to IGCC having

the lower NPV cost. Th is, of course, depends

on when and the extent to which these chang-

es occur and on how emissions control tech-

nology costs change with time and increasing

reduction requirements. Th is type of analysis

is used widely in evaluating the commercial

economics of large capital projects, of which

generation is a set, but is outside the scope of

this report.

Th e same analysis applies to consideration of

future CO2 regulations. Th e introduction of a

CO2 tax at a future date (dependent on date

of imposition, CO2 tax rate, rate of increase,

potential grandfathering and retrofi t costs)

will drive IGCC to be the lowest NPV cost

alternative at some reasonable set of assump-

tions, and assuming today’s technology per-

formance. Substantial technology innovation

could change the outcome, as could changing

the feed from bituminous coal to lignite.

In light of all these considerations, it is clear

that there is no technology today that is an ob-

vious silver bullet.

RETROFITS FOR CO2 CAPTURE Retrofi tting

an IGCC for CO2 capture involves changes

in the core of the gasifi cation/combustion/

power generation train that are diff erent than

the type of changes involved in retrofi tting a

PC plant for capture. Th e choice of the gas-

ifi er (slurry feed, dry feed), gasifi er confi gura-

tion (full-quench, radiant cooling, convective

syngas coolers), acid gas clean-up, operating

pressure, and gas turbine are dependent on

whether a no-capture or a capture plant is be-

ing built. Appendix 3.E treats IGCC retrofi t-

ting in more detail.

No-capture designs tend to favor lower pres-

sure [2.8 to 4.1 MPa (400–600 psi)] and in-

creased heat recovery from the gasifi er train

(radiant coolers and even syngas coolers) to

raise more steam for the steam turbine, result-

ing in a higher net generating effi ciency. Dry

feed (Shell) provides the highest effi ciency and

is favored for coals with lower heating value,

largely because of their higher moisture con-

tent; but the capital costs are higher. On the

other hand, capture designs favor higher-pres-

sure [6.0 MPa (1000 psi)] operation, slurry

feed, and full-quench mode[59]. Full-quench

mode is the most eff ective method of adding

suffi cient steam to the raw syngas for the water

gas shift reaction without additional, expen-

sive steam raising equipment and/or robbing

steam from the steam cycle. Higher pressure

reduces the cost of CO2 capture and recovery,

and of CO2 compression. In addition, the de-

sign of a high-effi ciency combustion turbine

for high hydrogen concentration feeds is dif-

ferent from combustion turbines optimized

for syngas, requires further development, and

has very little operating experience. In sum-

mary, an optimum IGCC unit design for no

CO2 capture is quite diff erent from an opti-

mum unit design for CO2 capture.

Although retrofi tting an IGCC unit for cap-

ture would involve signifi cant changes in most

components of the unit if it is to result in an

optimum CO2-capture unit, it appears that an

IGCC unit could be successfully retrofi t by ad-

dressing the key needed changes (adding shift

reactors, an additional Selexol unit, and CO2

compression/drying). In this case, retrofi tting

an IGCC unit would appear to be less expen-

sive than retrofi tting a PC unit, although it

would not be an optimum CO2-capture unit.

Pre-investment for later retrofi t will generally

be unattractive and will be unlikely for a tech-

nology that is trying to establish a competi-

tive position. However, for IGCC, additional

space could be set aside to facilitate future

retrofi t potential. In addition, planning for a

possible retrofi t for capture could infl uence

initial design choices (e.g., radiant quench vs.

full quench).

IGCC OPERATIONAL HISTORY In addition

to cost, IGCC has to overcome the percep-

tion of poor availability and operability. Ap-

pendix 3.B provides more detail, beyond

that discussed below. For each of the current

IGCC demonstration plants, 3 to 5 years was

required to reach 70 to 80% availability aft er


commercial operation was initiated. Because

of the complexity of the IGCC process, no

single process unit or component of the to-

tal system is responsible for the majority of

the unplanned shutdowns that these units

have experienced, reducing IGCC unit avail-

ability. However, the gasifi cation complex or

block has been the largest factor in reducing

IGCC availability and operability. Even aft er

reaching 70 to 80% availability, operational

performance has not typically exceeded 80%

consistently. A detailed analysis of the operat-

ing history of the Polk Power Station over the

last few years suggests that it is very similar to

operating a petroleum refi nery, requiring con-

tinuous attention to avert, solve and prevent

mechanical, equipment and process problems

that periodically arise. In this sense, the opera-

tion of an IGCC unit is signifi cantly diff erent

from the operation of a PC unit, and requires a

diff erent operational philosophy and strategy.

Th e Eastman Chemical Coal Gasifi cation Plant

uses a Texaco full-quench gasifi er and a back-

up gasifi er (a spare) and has achieved less than

2% forced outage from the gasifi cation/syngas

system over almost 20 years operation. Spar-

ing is one approach to achieving better on-

line performance, and a vigorous equipment

health maintenance and monitoring program

is another. Th ere are fi ve operating in-refi n-

ery IGCC units based on petroleum residu-

als and/or coke; two are over 500 MWe each.

Several other refi nery-based gasifi cation units

produce steam, hydrogen, synthesis gas, and

power. Th ey have typically achieved better op-

erating performance, more quickly than the

coal-based IGCC units. Th ree more are under

construction. It is fair to say that IGCC is well

established commercially in the refi nery set-

ting. IGCC can also be considered commer-

cial in the coal-based electricity generation

setting, but in this setting it is neither well

established nor mature. As such, it is likely to

undergo signifi cant change as it matures.

Our analysis assumes that IGCC plants, with

or without capture, can “cycle” to follow load

requirements. However, there is relatively

little experience with cycling of IGCC plants

(although the 250 MWe Shell IGCC at Bug-

genum operated for 2 years in a load follow-

ing mode under grid dispatch in the general

range 50–100% load, and the Negishi IGCC

unit routinely cycles between 100 to 75% load,

both up and down, in 30 min) so considerable

uncertainty exists for these performance fea-

tures. Because an IGCC plant is “integrated”

in its operation any shortfall in this perfor-

mance could cause considerable increase in

both variable and capital cost.

COAL TO FUELS AND CHEMICALS

Rather than burning the syngas produced by

coal gasifi cation in a combustion turbine, it

can be converted to synthetic fuels and chemi-

cals. Th e syngas is fi rst cleaned of particulates

and sulfur compounds and undergoes water

gas shift to obtain the desired hydrogen to

CO ratio. Fischer-Tropsch technology can be

used to convert this syngas or “synthesis gas”

into predominantly high-quality diesel fuel,

along with naphtha and LPG. Fischer-Tropsch

technology involves the catalytic conversion

of the hydrogen and carbon monoxide in the

synthesis gas into fuel range hydrocarbons.

Th is technology has been used in South Africa

since the 1950’s, and 195,000 barrels per day

of liquid fuels are currently being produced

in that country by Fischer-Tropsch. Synthesis

gas can also be converted to methanol which

can be used directly or be upgraded into high-

octane gasoline. For gaseous fuels production,

the synthesis gas can be converted into meth-

ane, creating synthetic natural gas (SNG).

Figure 3.15 illustrates three potential coal to

fuels or chemicals process options. Th is type

of process confi guration could be called a coal

refi nery. More details are presented in Appen-

dix 3.F.

Methanol production from coal-based syn-

thesis gas is also a route into a broad range

of chemicals. Th e naphtha and lighter hydro-

carbons produced by Fischer-Tropsch are an-

other route to produce a range of chemicals,

in addition to the diesel fuel produced. Th e

largest commodity chemical produced from


synthesis gas today is ammonia. Although

most U.S. ammonia plants were designed to

produce their syngas by reforming natural

gas, world wide there are a signifi cant number

of ammonia plants that use syngas from coal

gasifi cation and more are under construction.

Th ese routes to chemicals are easily integrated

into a coal refi nery, as is power generation.

Commercially, these processes will be applied

to the extent that they make economic sense

and are in the business portfolio of the operat-

ing company.

For such a coal refi nery, all the carbon enter-

ing in the coal exits as carbon in the fuels or

chemicals produced, or as CO2 in concentrat-

ed gas form that could easily be compressed

for sequestration. In this case, of order 50%

to 70% of the carbon in the coal would be in

the form of CO2 ready for sequestration. If the

gasifi cation product were hydrogen, then es-

sentially all the carbon entering the refi nery

in the coal would appear in concentrated CO2

streams that could be purifi ed and compressed

for sequestration. Without carbon capture

and sequestration (CCS), we estimate that the

Fischer-Tropsch fuels route produces about

150% more CO2 as compared with the use

of the petroleum-derived fuel products. For

SNG, up to 175% more CO2 is emitted than if

regular natural gas is burned. With CCS, the

full fuel-cycle CO2 emissions for both liquid

fuel and SNG are comparable with traditional

production and utilization methods. Fortu-

nately, CCS does not require major changes to

the process, large amounts of additional capi-

tal, or signifi cant energy penalties because the

CO2 is a relatively pure byproduct of the pro-

cess at intermediate pressure. CCS requires

drying and compressing to supercritical pres-

sure. As a result of this the CO2 avoided cost

for CCS in conjunction with fuels and chemi-

cals manufacture from coal is about one third

of the CO2 avoided cost for IGCC.

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3. Average generating effi ciency of the U.S. coal fl eet was determined from the EIA Electric Power Annual Review (2003) by dividing the total MWe-h of coal-based elec-tricity generated by the coal consumed in generating that power. This effi ciency has been invarient from 1992 to 2003. NETL (2002) gives coal fl eet plant effi cency as a function of plant age.

4. In the U.S., the generating technology choice depends upon a number of issues, including: cost, criteria pollut-ant limits, coal type, effi ciency, plant availability require-ments, plant location (elevation and temperature) and potential for carbon dioxide regulations.

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7. Other modeling tools could have been used. Each would have given somewhat diff erent results because of the myriad of design and parameter choices, and engineer-ing approximations included in each. Model results are consistent with other models when operational diff er-ences are accounted for (Appendix 3-B).


8. U.S. engineering pracitce is to use the higher heating val-ue (HHV) of the fuel in calculating generating effi ciency, and electrical generating effi ciencies are expressed on an HHV basis. Fuel prices are also normally quoted on an HHV basis. The HHV of a fuel includes the heat recovered in condensing the water formed in combustion to liquid water. If the water is not condensed, less heat is recov-ered; and the value is the Lower Heating Value (LHV) of the fuel.

9. Of these variables, steam cycle severity (steam tempera-ture and pressure) is the most important. Steam cycle se-verity increases from subcritical to supercritical to ultra-supercritical. Increasing severity means that the steam carries more available energy to the steam turbine, re-sulting in higher generating effi ciency.

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15. Changes in operating parameters, excluding emissions control levels, can shift the generating effi ciency by up-wards to one percentage point. Large changes in emis-sions control levels can have a similarly large eff ect. A conservative set of parameters was used in this study, giving a generating effi ciency somewhat below the mid-point of the range. See Appendix 3-B and Appendix 3-D for more detail.

16. As steam pressure and temperature are increased above 218 atm (3200 psi) and 375° C (706° F), respectively, the water-steam system becomes supercritical. Under these conditions the two-phase mixture of liquid water and gaseous steam disappears. Instead with increasing temperature the fl uid phase undergoes gradual transi-tion from a single dense liquid-like phase to a less dense vapor-like phase, characterized by its own unique set of physical properties.

17. However, due to materials-related boiler tube fatigue and creep stress in headers, steamlines, and in the turbines, the utility industry moved back to subcritical technology for new U. S. coal power plants. Even after the materials problems were resolved there was not a move back to supercritical PC because at the very cheap price of U. S. coal, the added plant cost could not be justifi ed on coal feed rate savings.

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46. NETL, NETL Coal Power Database, NETL, Editor. 2002, U.S. DOE.

47. Simbeck, D., Existing Power Plants - CO2 Mitigation Costs, Personal communication to J.R. Katzer, 2005: Cambridge, MA.

48. Higman, C., and M. vanderBurgt, Gasifi cation. 2003, New York: Elsevier.

49. Holt, N., Integrated Gasifi cation Combined Cycle Power Plants, in Encyclopedia of Physical Science and Technology. 2001, Academic Press: New York.

50. Nuon Power Buggenum, The Netherlands, Shell gasifi er (253 MWe, 1994): Wabash River IGCC, Terre Haute, IN, U.S. E-gas(262MW, 1995)`; Polk Power Station, Tampa, Flori-da, U.S., Texaco/GE gasifi er(250 MW, 1996)`; Puertollana, Spain, Prenfl o/Shell gasifi er (298 MW, 1998)

51. Ono, T., NPRC Negishi IGCC Startup and Operation, in Gas-ifi cation Technologies 2003. 2003: San Francisco, Califor-nia.

52. Collodi, G., and R. M. Jones, The Sarlux IGCC Project, an Outline of the Construction and Commissioning Activities, in 1999 Gasifi cation Technologies Conference. 2003: San Francisco, California.

53. Holt, N., IGCC Technology Status, Economics and Needs, in International Energy Agency Zero Emission Technologies Technology Workshop. 2004a: Gold Coast, Queensland, Australia.

54. To estimate the COE for IGCC, without and with CO2 capture, we developed a consistent set of TPC numbers from the design studies and then compared these and our cost deltas with industry concensus group numbers to arrive at the TPC numbers given in Table 3.5. We esti-mated the O&M costs and calculated the COE using the parameters in Table 3.4. These are the COE numbers in Table 3.5.

55. Parsons Infrastructure & Technology Group, Inc., Updated Cost and Performance Estimates for Fossil Fuel Power Plants with CO2 Removal. 2002: Pittsburgh, PA & Palo Alto, Calif.

56. Childress, J., Coal Gasifi catioon & IGCC/Polygen Perfor-mance & Prospects for the U.S., in (2005) Platts IGCC Sym-posium. 2005: Pittsburgh, PA.

57. Lowe, E., GE’s Gasifi cation Development, in Gasifi cation Technologies Council. 2005: San Francisco, CA.

58. AEP, American Electric Power, Ohio Public Utilities Commis-sion Filing for Meigs IGCC Power Plant, O. PUC, 2005.

59. Holt, N., Gasifi cation & IGCC - Status, Challenges, Design Issues & Opportunities, in Reaction Engineering Interna-tional. 2005: Salt Lake City, Utah.

60. Bechtel, Gasifi cation Plant Cost and Performance Opti-mization, Final Report. 2003, Global Energy, Nexant: San Francisco.

61. Gray, D., and Glen Tomlinson, Coproduction of Ultra Clean Transportation Fuels, Hydrogen, and Electric Power from Coal. 2001, Mitretek.

Attachment 2

Comments of Environmental Law & Policy Center, Sierra Club and Valley Watch Inc.

17 Technical Summary

Technical Summary

Coordinating Lead AuthorsEdward Rubin (United States), Leo Meyer (Netherlands), Heleen de Coninck (Netherlands)

Lead AuthorsJuan Carlos Abanades (Spain), Makoto Akai (Japan), Sally Benson (United States), Ken Caldeira (United States), Peter Cook (Australia), Ogunlade Davidson (Sierra Leone), Richard Doctor (United States), James Dooley (United States), Paul Freund (United Kingdom), John Gale (United Kingdom), Wolfgang Heidug (Germany), Howard Herzog (United States), David Keith (Canada), Marco Mazzotti (Italy and Switzerland), Bert Metz (Netherlands), Balgis Osman-Elasha (Sudan), Andrew Palmer (United Kingdom), Riitta Pipatti (Finland), Koen Smekens (Belgium), Mohammad Soltanieh (Iran), Kelly (Kailai) Thambimuthu (Australia and Canada), Bob van der Zwaan (Netherlands)

Review EditorIsmail El Gizouli (Sudan)

IPCC Special Report

Carbon Dioxide Capture and Storage


Contents1. Introduction and framework of this report ...........................................................................................................................19

2. Sources of CO2 . .....................................................................................................................................................................22

3. Capture of CO2 .................................................................................................................................................................. ....24

4. Transport of CO2 ................................................................................................................................................................ ...29

5. Geological storage ............................................................................................................................................................... .31

6. Ocean storage ................................................................................................................................................................... ....37

7. Mineral carbonation and industrial uses .............................................................................................................................. 39

8. Costs and economic potential .............................................................................................................................................. 41

9. Emission inventories and accounting ............................................................................................................................... ....46

10. Gaps in knowledge ........................................................................................................................................................... ....48


1. Introduction and framework of this report

Carbon dioxide capture and storage (CCS), the subject of this Special Report, is considered as one of the options for reducing atmospheric emissions of CO2 from human activities. The purpose of this Special Report is to assess the current state of knowledge regarding the technical, scientific, environmental, economic and societal dimensions of CCS and to place CCS in the context of other options in the portfolio of potential climate change mitigation measures. The structure of this Technical Summary follows that of the Special Report. This introductory section presents the general framework for the assessment together with a brief overview of CCS systems. Section 2 then describes the major sources of CO2, a step needed to assess the feasibility of CCS on a global scale. Technological options for CO2 capture are then discussed in Section 3, while Section 4 focuses on methods of CO2 transport. Following this, each of the storage options is addressed. Section 5 focuses on geological storage, Section 6 on ocean storage, and Section 7 on mineral carbonation and industrial uses of CO2. The overall costs and economic potential of CCS are then discussed in Section 8, followed by an examination in Section 9 of the implications of CCS for greenhouse gas emissions inventories and accounting. The Technical Summary concludes with a discussion of gaps in knowledge, especially those critical for policy considerations.

Overview of CO2 capture and storage

CO2 is emitted principally from the burning of fossil fuels, both in large combustion units such as those used for electric power generation and in smaller, distributed sources such as automobile engines and furnaces used in residential and commercial buildings. CO2 emissions also result from some industrial and resource extraction processes, as well as from the burning of forests during land clearance. CCS would most likely be applied to large point sources of CO2, such as power plants or large industrial processes. Some of these sources could supply decarbonized fuel such as hydrogen to the transportation, industrial and building sectors, and thus reduce emissions from those distributed sources. CCS involves the use of technology, first to collect and concentrate the CO2 produced in industrial and energy-related sources, transport it to a suitable storage location, and then store it away from the atmosphere for a long period of time. CCS would thus allow fossil fuels to be used with low emissions of greenhouse gases. Application of CCS to biomass energy sources could result in the net removal of CO2 from the atmosphere (often referred to as ‘negative

emissions’) by capturing and storing the atmospheric CO2 taken up by the biomass, provided the biomass is not harvested at an unsustainable rate.

Figure TS.1 illustrates the three main components of the CCS process: capture, transport and storage. All three components are found in industrial operations today, although mostly not for the purpose of CO2 storage. The capture step involves separating CO2 from other gaseous products. For fuel-burning processes such as those in power plants, separation technologies can be used to capture CO2 after combustion or to decarbonize the fuel before combustion. The transport step may be required to carry captured CO2 to a suitable storage site located at a distance from the CO2 source. To facilitate both transport and storage, the captured CO2 gas is typically compressed to a high density at the capture facility. Potential storage methods include injection into underground geological formations, injection into the deep ocean, or industrial fixation in inorganic carbonates. Some industrial processes also might utilize and store small amounts of captured CO2 in manufactured products. The technical maturity of specific CCS system components varies greatly. Some technologies are extensively deployed in mature markets, primarily in the oil and gas industry, while others are still in the research, development or demonstration phase. Table TS.1 provides an overview of the current status of all CCS components. As of mid-2005, there have been three commercial projects linking CO2 capture and geological storage: the offshore Sleipner natural gas processing project in Norway, the Weyburn Enhanced Oil Recovery (EOR)1 project in Canada (which stores CO2 captured in the United States) and the In Salah natural gas project in Algeria. Each captures and stores 1–2 MtCO2 per year. It should be noted, however, that CCS has not yet been applied at a large (e.g., 500 MW) fossil-fuel power plant, and that the overall system may not be as mature as some of its components.

.1 In this report, EOR means enhanced oil recovery using CO2


Why the interest in CO2 capture and storage?

In 1992, international concern about climate change led to the United Nations Framework Convention on Climate Change (UNFCCC). The ultimate objective of that Convention is the “stabilization of greenhouse gas concentrations in the atmosphere at a level that prevents dangerous anthropogenic interference with the climate system”. From this perspective, the context for considering CCS (and other mitigation options) is that of a world constrained in CO2 emissions, consistent with the international goal of stabilizing atmospheric greenhouse gas concentrations. Most scenarios for global energy use project a substantial increase of CO2 emissions throughout this century in the absence of specific actions to mitigate climate change. They also suggest that the supply of primary energy will continue to be dominated by fossil fuels until at least the middle of the century (see Section 8). The magnitude of the emissions reduction needed to stabilize the atmospheric concentration of CO2 will depend on both the level of future emissions (the baseline) and the

desired target for long-term CO2 concentration: the lower the stabilization target and the higher the baseline emissions, the larger the required reduction in CO2 emissions. IPCC’s Third Assessment Report (TAR) states that, depending on the scenario considered, cumulative emissions of hundreds or even thousands of gigatonnes of CO2 would need to be prevented during this century to stabilize the CO2 concentration at 450 to 750 ppmv2. The TAR also finds that, “most model results indicate that known technological options3 could achieve a broad range of atmospheric CO2 stabilization levels”, but that “no single technology option will provide all of the emissions reductions needed”. Rather, a combination of mitigation measures will be needed to achieve stabilization. These known technological options are available for stabilization, although the TAR cautions that, “implementation would require associated socio-economic and institutional changes”.

Figure TS.1. Schematic diagram of possible CCS systems. It shows the sources for which CCS might be relevant, as well as CO2 transport and storage options (Courtesy CO2CRC).

2 ppmv is parts per million by volume.3 “Known technological options” refer to technologies that are currently at the operation or pilot-plant stages, as referred to in the mitigation scenarios discussed

in IPCC’s Third Assessment Report. The term does not include any new technologies that will require drastic technological breakthroughs. It can be considered to represent a conservative estimate given the length of the scenario period.


In this context, the availability of CCS in the portfolio of options for reducing greenhouse gas emissions could facilitate the achievement of stabilization goals. Other technological options, which have been examined more extensively in previous IPCC assessments, include: (1) reducing energy demand by increasing the efficiency of energy conversion and/or utilization devices; (2) decarbonizing energy supplies (either by switching to less carbon-intensive fuels (coal to natural gas, for example), and/or by increasing the use of renewable energy sources and/or nuclear energy (each of which, on balance, emit little or no CO2); (3) sequestering CO2 through the enhancement of natural sinks by biological fixation; and (4) reducing non-CO2 greenhouse gases.

Model results presented later in this report suggest that use of CCS in conjunction with other measures could significantly reduce the cost of achieving stabilization and would increase flexibility in achieving these reductions . The heavy worldwide reliance on fossil fuels today (approximately 80% of global energy use), the potential for CCS to reduce CO2 emissions over the next century, and the compatibility of CCS systems with current energy infrastructures explain the interest in this technology.

Table TS.1. Current maturity of CCS system components. An X indicates the highest level of maturity for each component. There are also less mature technologies for most components.

CCS component CCS technology

Res

earc

h ph

ase

a

Dem

onst

ratio

n ph

ase

b

Econ

omic

ally

feas

ible

un

der

spec

ific

cond

ition

s c

Mat

ure

mar

ket d

Capture Post-combustion XPre-combustion X

Oxyfuel combustion XIndustrial separation (natural gas processing, ammonia production) X

Transportation Pipeline XShipping X

Geological storage Enhanced Oil Recovery (EOR) Xe Gas or oil fields X

Saline formations XEnhanced Coal Bed Methane recovery (ECBM)f X

Ocean storage Direct injection (dissolution type) XDirect injection (lake type) X

Mineral carbonation Natural silicate minerals XWaste materials X

Industrial uses of CO2 X

a Research phase means that the basic science is understood, but the technology is currently in the stage of conceptual design or testing at the laboratory or bench scale, and has not been demonstrated in a pilot plant.

b Demonstration phase means that the technology has been built and operated at the scale of a pilot plant, but further development is required before the technology is required before the technology is ready for the design and construction of a full-scale system.

c Economically feasible under specific conditions means that the technology is well understood and used in selected commercial applications, for instance if there is a favourable tax regime or a niche market, or processing on in the order of 0.1 MtCO2 yr-1, with few (less than 5) replications of the technology.

d Mature market means that the technology is now in operation with multiple replications of the technology worldwide.e CO2 injection for EOR is a mature market technology, but when used for CO2 storage, it is only economically feasible under specific conditions.f ECBM is the use of CO2 to enhance the recovery of the methane present in unminable coal beds through the preferential adsorption of CO2 on coal.

Unminable coal beds are unlikely to ever be mined, because they are too deep or too thin. If subsequently mined, the stored CO2 would be released.


Major issues for this assessment

There are a number of issues that need to be addressed in trying to understand the role that CCS could play in mitigating climate change. Questions that arise, and that are addressed in different sections of this Technical Summary, include the following: • What is the current status of CCS technology?• What is the potential for capturing and storing CO2?• What are the costs of implementation?• How long should CO2 be stored in order to achieve

significant climate change mitigation?• What are the health, safety and environment risks of

CCS?• What can be said about the public perception of CCS?• What are the legal issues for implementing CO2 storage?• What are the implications for emission inventories and

accounting?• What is the potential for the diffusion and transfer of CCS

technology?

When analyzing CCS as an option for climate change mitigation, it is of central importance that all resulting emissions from the system, especially emissions of CO2, be identified and assessed in a transparent way. The importance of taking a “systems” view of CCS is therefore stressed, as the selection of an appropriate system boundary is essential for proper analysis. Given the energy requirements associated with capture and some storage and utilization options, and the possibility of leaking storage reservoirs, it is vital to assess the CCS chain as a whole. From the perspectives of both atmospheric stabilization and long-term sustainable development, CO2 storage must extend over time scales that are long enough to contribute significantly to climate change mitigation. This report expresses the duration of CO2 storage in terms of the‘fraction retained’, defined as the fraction of the cumulative mass of CO2 injected that is retained in a storage reservoir over a specified period of time. Estimates of such fractions for different time periods and storage options are presented later. Questions arise not only about how long CO2 will remain stored, but also what constitutes acceptable amounts of slow, continuous leakage4 from storage. Different approaches to this question are discussed in Section 8. CCS would be an option for countries that have significant sources of CO2 suitable for capture, that have access to storage sites and experience with oil or gas operations, and that need to satisfy their development aspirations in a carbon-constrained environment. Literature assessed in the IPCC Special Report ‘Methodological and Technological Issues and Technology

Transfer’ indicates that there are many potential barriers that could inhibit deployment in developing countries, even of technologies that are mature in industrialized countries. Addressing these barriers and creating conditions that would facilitate diffusion of the technology to developing countries would be a major issue for the adoption of CCS worldwide.

2. Sources of CO2

This section describes the major current anthropogenic sources of CO2 emissions and their relation to potential storage sites. As noted earlier, CO2 emissions from human activity arise from a number of different sources, mainly from the combustion of fossil fuels used in power generation, transportation, industrial processes, and residential and commercial buildings. CO2 is also emitted during certain industrial processes like cement manufacture or hydrogen production and during the combustion of biomass. Future emissions are also discussed in this section.

Current CO2 sources and characteristics

To assess the potential of CCS as an option for reducing global CO2 emissions, the current global geographical relationship between large stationary CO2 emission sources and their proximity to potential storage sites has been examined. CO2 emissions in the residential, commerical and transportation sectors have not been considered in this analysis because these emission sources are individually small and often mobile, and therefore unsuitable for capture and storage. The discussion here also includes an analysis of potential future sources of CO2 based on several scenarios of future global energy use and emissions over the next century. Globally, emissions of CO2 from fossil-fuel use in the year 2000 totalled about 23.5 GtCO2 yr-1 (6 GtC yr-1). Of this, close to 60% was attributed to large (>0.1 MtCO2 yr-1) stationary emission sources (see Table TS.2). However, not all of these sources are amenable to CO2 capture. Although the sources evaluated are distributed throughout the world, the database reveals four particular clusters of emissions: North America (midwest and eastern USA), Europe (northwest region), East Asia (eastern coast of China) and South Asia (Indian subcontinent). By contrast, large-scale biomass sources are much smaller in number and less globally distributed. Currently, the vast majority of large emission sources have CO2 concentrations of less than 15% (in some cases, substantially less). However, a small portion (less than 2%) of the fossil fuel-based industrial sources have CO2 concentrations in excess of 95%. The high-concentration sources are potential candidates for the early implementation

4 With respect to CO2 storage, leakage is defined as the escape of injected fluid from storage. This is the most common meaning used in this Summary. If used in the context of trading of carbon dioxide emission reductions, it may signify the change in anthropogenic emissions by sources or removals by sinks which occurs outside the project boundary.


of CCS because only dehydration and compression would be required at the capture stage (see Section 3). An analysis of these high-purity sources that are within 50 km of storage formations and that have the potential to generate revenues (via the use of CO2 for enhanced hydrocarbon production through ECBM or EOR) indicates that such sources currently emit approximately 360 MtCO2 per year. Some biomass sources like bioethanol production also generate high-concentration CO2 sources which could also be used in similar applications. The distance between an emission location and a storage site can have a significant bearing on whether or not CCS can play a significant role in reducing CO2 emissions. Figure

TS.2a depicts the major CO2 emission sources (indicated by dots), and Figure TS.2b shows the sedimentary basins with geological storage prospectivity (shown in different shades of grey). In broad terms, these figures indicate that there is potentially good correlation between major sources and prospective sedimentary basins, with many sources lying either directly above, or within reasonable distances (less than 300 km) from areas with potential for geological storage. The basins shown in Figure TS.2b have not been identified or evaluated as suitable storage reservoirs; more detailed geological analysis on a regional level is required to confirm the suitability of these potential storage sites.

Table TS.2. Profile by process or industrial activity of worldwide large stationary CO2 sources with emissions of more than 0.1 MtCO2 per year.

Process Number of sources Emissions (MtCO2 yr-1)

Fossil fuelsPower 4,942 10,539Cement production 1,175 932Refineries 638 798Iron and steel industry 269 646Petrochemical industry 470 379Oil and gas processing N/A 50Other sources 90 33

Biomass Bioethanol and bioenergy 303 91

Total 7,887 13,466

Figure TS.2a. Global distribution of large stationary sources of CO2 (based on a compilation of publicly available information on global emission sources, IEA GHG 2002)


Future emission sources

In the IPCC Special Report on Emission Scenarios (SRES), the future emissions of CO2 are projected on the basis of six illustrative scenarios in which global CO2 emissions range from 29 to 44 GtCO2 (8–12 GtC) per year in 2020, and from 23 to 84 GtCO2 (6–23 GtC) per year in 2050. It is projected that the number of CO2 emission sources from the electric power and industrial sectors will increase significantly until 2050, mainly in South and East Asia. By contrast, the number of such sources in Europe may decrease slightly. The proportion of sources with high and low CO2 content will be a function of the size and rate of introduction of plants employing gasification or liquefaction of fossil fuels to produce hydrogen, or other liquid and gaseous products. The greater the number of these plants, the greater the number of sources with high CO2 concentrations technically suitable for capture. The projected potential of CO2 capture associated with the above emission ranges has been estimated at an annual 2.6 to 4.9 GtCO2 by 2020 (0.7–1.3 GtC) and 4.7 to 37.5 GtCO2 by 2050 (1.3–10 GtC). These numbers correspond to 9–12%, and 21–45% of global CO2 emissions in 2020 and 2050, respectively. The emission and capture ranges reflect the inherent uncertainties of scenario and modelling analyses, and the technical limitations of applying CCS. These scenarios only take into account CO2 capture from fossil fuels, and not from biomass sources. However, emissions from large-

scale biomass conversion facilities could also be technically suitable for capture. The potential development of low-carbon energy carriers is relevant to the future number and size of large, stationary CO2 sources with high concentrations. Scenarios also suggest that large-scale production of low-carbon energy carriers such as electricity or hydrogen could, within several decades, begin displacing the fossil fuels currently used by small, distributed sources in residential and commercial buildings and in the transportation sector (see Section 8). These energy carriers could be produced from fossil fuels and/or biomass in large plants that would generate large point sources of CO2 (power plants or plants similar to current plants producing hydrogen from natural gas). These sources would be suitable for CO2 capture. Such applications of CCS could reduce dispersed CO2 emissions from transport and from distributed energy supply systems. At present, however, it is difficult to project the likely number, size, or geographical distribution of the sources associated with such developments.

3. Capture of CO2

This section examines CCS capture technology. As shown in Section 2, power plants and other large-scale industrial processes are the primary candidates for capture and the main focus of this section.

Figure TS.2b. Prospective areas in sedimentary basins where suitable saline formations, oil or gas fields, or coal beds may be found. Locations for storage in coal beds are only partly included. Prospectivity is a qualitative assessment of the likelihood that a suitable storage location is present in a given area based on the available information. This figure should be taken as a guide only, because it is based on partial data, the quality of which may vary from region to region, and which may change over time and with new information (Courtesy of Geoscience Australia).


Capture technology options and applications

The purpose of CO2 capture is to produce a concentrated stream of CO2 at high pressure that can readily be transported to a storage site. Although, in principle, the entire gas stream containing low concentrations of CO2 could be transported and injected underground, energy costs and other associated costs generally make this approach impractical. It is therefore necessary to produce a nearly pure CO2 stream for transport and storage. Applications separating CO2 in large industrial plants, including natural gas treatment plants and ammonia production facilities, are already in operation today. Currently, CO2 is typically removed to purify other industrial gas streams. Removal has been used for storage purposes in only a few cases; in most cases, the CO2 is emitted to the atmosphere. Capture processes also have been used to obtain commercially useful amounts of CO2 from flue gas streams generated by the combustion of coal or natural gas. To date, however, there have been no applications of CO2 capture at large (e.g., 500 MW) power plants. Depending on the process or power plant application in question, there are three main approaches to capturing the CO2 generated from a primary fossil fuel (coal, natural gas or oil), biomass, or mixtures of these fuels: Post-combustion systems separate CO2 from the flue gases produced by the combustion of the primary fuel in air. These systems normally use a liquid solvent to capture the small fraction of CO2 (typically 3–15% by volume) present in a flue gas stream in which the main constituent is nitrogen (from air). For a modern pulverized coal (PC) power plant or a natural gas combined cycle (NGCC) power plant, current post-combustion capture systems would typically employ an organic solvent such as monoethanolamine (MEA). Pre-combustion systems process the primary fuel in a reactor with steam and air or oxygen to produce a mixture consisting mainly of carbon monoxide and hydrogen (“synthesis gas”). Additional hydrogen, together with CO2, is produced by reacting the carbon monoxide with steam in a second reactor (a “shift reactor”). The resulting mixture of hydrogen and CO2 can then be separated into a CO2 gas stream, and a stream of hydrogen. If the CO2 is stored, the hydrogen is a carbon-free energy carrier that can be combusted to generate power and/or heat. Although the initial fuel conversion steps are more elaborate and costly than in post-combustion systems, the high concentrations of CO2 produced by the shift reactor (typically 15 to 60% by volume on a dry basis) and the high pressures often encountered in these applications are more favourable for CO2 separation. Pre-combustion would be used at power plants that employ integrated gasification combined cycle (IGCC) technology. Oxyfuel combustion systems use oxygen instead of air for combustion of the primary fuel to produce a flue gas that is mainly water vapour and CO2. This results in a flue gas with

high CO2 concentrations (greater than 80% by volume). The water vapour is then removed by cooling and compressing the gas stream. Oxyfuel combustion requires the upstream separation of oxygen from air, with a purity of 95–99% oxygen assumed in most current designs. Further treatment of the flue gas may be needed to remove air pollutants and non-condensed gases (such as nitrogen) from the flue gas before the CO2 is sent to storage. As a method of CO2 capture in boilers, oxyfuel combustion systems are in the demonstration phase (see Table TS.1). Oxyfuel systems are also being studied in gas turbine systems, but conceptual designs for such applications are still in the research phase. Figure TS.3 shows a schematic diagram of the main capture processes and systems. All require a step involving the separation of CO2, H2 or O2 from a bulk gas stream (such as flue gas, synthesis gas, air or raw natural gas). These separation steps can be accomplished by means of physical or chemical solvents, membranes, solid sorbents, or by cryogenic separation. The choice of a specific capture technology is determined largely by the process conditions under which it must operate. Current post-combustion and pre-combustion systems for power plants could capture 85–95% of the CO2 that is produced. Higher capture efficiencies are possible, although separation devices become considerably larger, more energy intensive and more costly. Capture and compression need roughly 10–40% more energy than the equivalent plant without capture, depending on the type of system. Due to the associated CO2 emissions, the net amount of CO2 captured is approximately 80–90%. Oxyfuel combustion systems are, in principle, able to capture nearly all of the CO2 produced. However, the need for additional gas treatment systems to remove pollutants such as sulphur and nitrogen oxides lowers the level of CO2 captured to slightly more than 90%. As noted in Section 1, CO2 capture is already used in several industrial applications (see Figure TS.4). The same technologies as would be used for pre-combustion capture are employed for the large-scale production of hydrogen (which is used mainly for ammonia and fertilizer manufacture, and for petroleum refinery operations). The separation of CO2 from raw natural gas (which typically contains significant amounts of CO2) is also practised on a large scale, using technologies similar to those used for post-combustion capture. Although commercial systems are also available for large-scale oxygen separation, oxyfuel combustion for CO2 capture is currently in the demonstration phase. In addition, research is being conducted to achieve higher levels of system integration, increased efficiency and reduced cost for all types of capture systems.


Figure TS.4. (a) CO2 post-combustion capture at a plant in Malaysia. This plant employs a chemical absorption process to separate 0.2 MtCO2 per year from the flue gas stream of a gas-fired power plant for urea production (Courtesy of Mitsubishi Heavy Industries). (b) CO2 pre-combustion capture at a coal gasification plant in North Dakota, USA. This plant employs a physical solvent process to separate 3.3 MtCO2 per year from a gas stream to produce synthetic natural gas. Part of the captured CO2 is used for an EOR project in Canada.

Figure TS.3. Overview of CO2 capture processes and systems.


CO2 capture: risks, energy and the environment

The monitoring, risk and legal implications of CO2 capture systems do not appear to present fundamentally new challenges, as they are all elements of regular health, safety and environmental control practices in industry. However, CO2 capture systems require significant amounts of energy for their operation. This reduces net plant efficiency, so power plants require more fuel to generate each kilowatt-hour of electricity produced. Based on a review of the literature, the increase in fuel consumption per kWh for plants capturing 90% CO2 using best current technology ranges from 24–40% for new supercritical PC plants, 11–22% for NGCC plants, and 14–25% for coal-based IGCC systems compared to similar plants without CCS. The increased fuel requirement results in an increase in most other environmental emissions per kWh generated relative to new state-of-the-art plants without CO2 capture and, in the case of coal, proportionally larger amounts of solid wastes. In addition, there is an increase in the consumption of chemicals such as ammonia and limestone used by PC plants for nitrogen oxide and sulphur dioxide emissions control. Advanced plant designs that further reduce CCS energy requirements will also reduce overall environmental impacts as well as cost. Compared to many older existing plants, more efficient new or rebuilt plants with CCS may actually yield net reductions in plant-level environmental emissions.

Costs of CO2 capture

The estimated costs of CO2 capture at large power plants are based on engineering design studies of technologies in commercial use today (though often in different applications and/or at smaller scales than those assumed in the literature), as well as on design studies for concepts currently in the research and development (R&D) stage. Table TS.3 summarizes the results for new supercritical PC, NGCC and IGCC plants based on current technology with and without CO2 capture. Capture systems for all three designs reduce CO2 emissions per kWh by approximately 80–90%, taking into account the energy requirements for capture. All data for PC and IGCC plants in Table TS.3 are for bituminous coals only. The capture costs include the cost of compressing CO2 (typically to about 11–14 MPa) but do not include the additional costs of CO2 transport and storage (see Sections 4–7). The cost ranges for each of the three systems reflect differences in the technical, economic and operating assumptions employed in different studies. While some differences in reported costs can be attributed to differences in the design of CO2 capture systems, the major sources of

variability are differences in the assumed design, operation and financing of the reference plant to which the capture technology is applied (factors such as plant size, location, efficiency, fuel type, fuel cost, capacity factor and cost of capital). No single set of assumptions applies to all situations or all parts of the world, so a range of costs is given. For the studies listed in Table TS.3, CO2 capture increases the cost of electricity production5 by 35–70% (0.01 to 0.02 US$/kWh) for an NGCC plant, 40–85% (0.02 to 0.03 US$/kWh) for a supercritical PC plant, and 20–55% (0.01 to 0.02 US$/kWh) for an IGCC plant. Overall, the electricity production costs for fossil fuel plants with capture (excluding CO2 transport and storage costs) ranges from 0.04–0.09 US$/kWh, as compared to 0.03–0.06 US$/kWh for similar plants without capture. In most studies to date, NGCC systems have typically been found to have lower electricity production costs than new PC and IGCC plants (with or without capture) in the case of large base-load plants with high capacity factors (75% or more) and natural gas prices between 2.6 and 4.4 US$ GJ-1 over the life of the plant. However, in the case of higher gas prices and/or lower capacity factors, NGCC plants often have higher electricity production costs than coal-based plants, with or without capture. Recent studies also found that IGCC plants were on average slightly more costly without capture and slightly less costly with capture than similarly-sized PC plants. However, the difference in cost between PC and IGCC plants with or without CO2 capture can vary significantly according to coal type and other local factors, such as the cost of capital for each plant type. Since full-scale NGCC, PC and IGCC systems have not yet been built with CCS, the absolute or relative costs of these systems cannot be stated with a high degree of confidence at this time. The costs of retrofitting existing power plants with CO2 capture have not been extensively studied. A limited number of reports indicate that retrofitting an amine scrubber to an existing plant results in greater efficiency loss and higher costs than those shown in Table TS.3. Limited studies also indicate that a more cost-effective option is to combine a capture system retrofit with rebuilding the boiler and turbine to increase plant efficiency and output. For some existing plants, studies indicate that similar benefits could be achieved by repowering with an IGCC system that includes CO2 capture technology. The feasibility and cost of all these options is highly dependent on site-specific factors, including the size, age and efficiency of the plant, and the availability of additional space.

5 The cost of electricity production should not be confused with the price of electricity to customers.


Table TS.4 illustrates the cost of CO2 capture in the production of hydrogen. Here, the cost of CO2 capture is mainly due to the cost of CO2 drying and compression, since CO2 separation is already carried out as part of the hydrogen production process. The cost of CO2 capture adds approximately 5% to 30% to the cost of the hydrogen produced. CCS also can be applied to systems that use biomass fuels or feedstock, either alone or in combination with fossil fuels. A limited number of studies have looked at the costs of such systems combining capture, transport and storage. The capturing of 0.19 MtCO2 yr-1 in a 24 MWe biomass IGCC plant is estimated to be about 80 US$/tCO2 net captured (300

US$/tC), which corresponds to an increase in electricity production costs of about 0.08 US$/kWh. There are relatively few studies of CO2 capture for other industrial processes using fossil fuels and they are typically limited to capture costs reported only as a cost per tonne of CO2 captured or avoided. In general, the CO2 produced in different processes varies widely in pressure and concentration (see Section 2). As a result, the cost of capture in different processes (cement and steel plants, refineries), ranges widely from about 25–115 US$/tCO2 net captured. The unit cost of capture is generally lower for processes where a relatively pure CO2 stream is produced (e.g. natural gas processing, hydrogen production and ammonia production), as seen for the hydrogen plants

Table TS.3. Summary of CO2 capture costs for new power plants based on current technology. Because these costs do not include the costs (or credits) for CO2 transport and storage, this table should not be used to assess or compare total plant costs for different systems with capture. The full costs of CCS plants are reported in Section 8.

Performance and cost measures New NGCC plant New PC plant New IGCC plant Range Rep. Range Rep. Range Rep.

Low High value Low High value Low High valueEmission rate without capture (kgCO2/kWh) 0.344 - 0.379 0.367 0.736 - 0.811 0.762 0.682 - 0.846 0.773Emission rate with capture (kgCO2/kWh) 0.040 - 0.066 0.052 0.092 - 0.145 0.112 0.065 - 0.152 0.108Percentage CO2 reduction per kWh (%) 83 - 88 86 81 - 88 85 81 - 91 86Plant efficiency with capture, LHV basis (% ) 47 - 50 48 30 - 35 33 31 - 40 35

Capture energy requirement (% increase input/kWh)

11 - 22 16 24 - 40 31 14 - 25 19

Total capital requirement without capture (US$/kW)

515 - 724 568 1161 - 1486 1286 1169 - 1565 1326

Total capital requirement with capture (US$/kW)

909 - 1261 998 1894 - 2578 2096 1414 - 2270 1825

Percent increase in capital cost with capture (%)

64 - 100 76 44 - 74 63 19 - 66 37

COE without capture (US$/kWh) 0.031 - 0.050 0.037 0.043 - 0.052 0.046 0.041 - 0.061 0.047COE with capture only (US$/kWh) 0.043 - 0.072 0.054 0.062 - 0.086 0.073 0.054 - 0.079 0.062Increase in COE with capture (US$/kWh) 0.012 - 0.024 0.017 0.018 - 0.034 0.027 0.009 - 0.022 0.016Percent increase in COE with capture (%) 37 - 69 46 42 - 66 57 20 - 55 33Cost of net CO2 captured (US$/tCO2) 37 - 74 53 29 - 51 41 13 - 37 23Capture cost confidence level (see Table 3.6) moderate moderate moderate

Abbreviations: Representative value is based on the average of the values in the different studies. COE=cost of electricity production; LHV=lower heating value. See Section 3.6.1 for calculation of energy requirement for capture plants. Notes: Ranges and representative values are based on data from Special Report Tables 3.7, 3.9 and 3.10. All PC and IGCC data are for bituminous coals only at costs of 1.0-1.5 US$ GJ-1 (LHV); all PC plants are supercritical units. NGCC data based on natural gas prices of 2.8-4.4 US$ GJ-1 (LHV basis). Cost are stated in constant US$2002. Power plant sizes range from approximately 400-800 MW without capture and 300-700 MW with capture. Capacity factors vary from 65-85% for coal plants and 50-95% for gas plants (average for each=80%). Fixed charge factors vary from 11-16%. All costs include CO2 compression but not additional CO2 transport and storage costs.


in Table TS.4, where costs vary from 2–56 US$/tCO2 net captured. New or improved methods of CO2 capture, combined with advanced power systems and industrial process designs, could reduce CO2 capture costs and energy requirements. While costs for first-of-a-kind commercial plants often exceed initial cost estimates, the cost of subsequent plants typically declines as a result of learning-by-doing and other factors. Although there is considerable uncertainty about the magnitude and timing of future cost reductions, the literature suggests that, provided R&D efforts are sustained, improvements to commercial technologies can reduce current CO2 capture costs by at least 20–30% over approximately the next ten years, while new technologies under development could achieve more substantial cost reductions. Future cost reductions will depend on the deployment and adoption of commercial technologies in the marketplace as well as sustained R&D.

4. Transport of CO2

Except when plants are located directly above a geological storage site, captured CO2 must be transported from the point of capture to a storage site. This section reviews the principal

methods of CO2 transport and assesses the health, safety and environment aspects, and costs.

Methods of CO2 transport

Pipelines today operate as a mature market technology and are the most common method for transporting CO2. Gaseous CO2 is typically compressed to a pressure above 8 MPa in order to avoid two-phase flow regimes and increase the density of the CO2, thereby making it easier and less costly to transport. CO2 also can be transported as a liquid in ships, road or rail tankers that carry CO2 in insulated tanks at a temperature well below ambient, and at much lower pressures. The first long-distance CO2 pipeline came into operation in the early 1970s. In the United States, over 2,500 km of pipeline transports more than 40 MtCO2 per year from natural and anthropogenic sources, mainly to sites in Texas, where the CO2 is used for EOR.These pipelines operate in the ‘dense phase’ mode (in which there is a continuous progression from gas to liquid, without a distinct phase change), and at ambient temperature and high pressure. In most of these pipelines, the flow is driven by compressors at the upstream end, although some pipelines have intermediate (booster) compressor stations.

Table TS.4. Summary of CO2 capture costs for new hydrogen plants based on current technology

Performance and cost measuresNew hydrogen plant

RangeRepresentative value

Low HighEmission rate without capture (kgCO2 GJ-1) 78 - 174 137Emission rate with capture (kgCO2 GJ-1) 7 - 28 17Percent CO2 reduction per GJ (%) 72 - 96 86Plant efficiency with capture, LHV basis (%) 52 - 68 60Capture energy requirement (% more input GJ-1) 4 - 22 8Cost of hydrogen without capture (US$ GJ-1) 6.5 - 10.0 7.8Cost of hydrogen with capture (US$ GJ-1) 7.5 - 13.3 9.1Increase in H2 cost with capture (US$ GJ-1) 0.3 - 3.3 1.3Percent increase in H2 cost with capture (%) 5 - 33 15Cost of net CO2 captured (US$/tCO2) 2 - 56 15Capture cost confidence level moderate to high

Notes: Ranges and representative values are based on data from Table 3.11. All costs in this table are for capture only and do not include the costs of CO2 transport and storage. Costs are in constant US$2002. Hydrogen plant feedstocks are natural gas (4.7-5.3 US$ GJ-1) or coal (0.9-1.3 US$ GJ-1); some plants in dataset produce electricity in addition to hydrogen. Fixed charge factors vary from 13-20%. All costs include CO2 compression but not additional CO2 transport and storage costs (see Section 8 for full CCS costs).


In some situations or locations, transport of CO2 by ship may be economically more attractive, particularly when the CO2 has to be moved over large distances or overseas. Liquefied petroleum gases (LPG, principally propane and butane) are transported on a large commercial scale by marine tankers. CO2 can be transported by ship in much the same way (typically at 0.7 MPa pressure), but this currently takes place on a small scale because of limited demand. The properties of liquefied CO2 are similar to those of LPG, and the technology could be scaled up to large CO2 carriers if a demand for such systems were to materialize. Road and rail tankers also are technically feasible options. These systems transport CO2 at a temperature of -20ºC and at 2 MPa pressure. However, they are uneconomical compared to pipelines and ships, except on a very small scale, and are unlikely to be relevant to large-scale CCS.

Environment, safety and risk aspects

Just as there are standards for natural gas admitted to pipelines, so minimum standards for ‘pipeline quality’ CO2 should emerge as the CO2 pipeline infrastructure develops further. Current standards, developed largely in the context of EOR applications, are not necessarily identical to what would be required for CCS. A low-nitrogen content is important for EOR, but would not be so significant for CCS. However, a CO2 pipeline through populated areas might need a lower specified maximum H2S content. Pipeline transport of CO2 through populated areas also requires detailed route selection, over-pressure protection, leak detection and other design factors. However, no major obstacles to pipeline design for CCS are foreseen. CO2 could leak to the atmosphere during transport, although leakage losses from pipelines are very small. Dry (moisture-free) CO2 is not corrosive to the carbon-manganese steels customarily used for pipelines, even if the CO2 contains contaminants such as oxygen, hydrogen sulphide, and sulphur or nitrogen oxides. Moisture-laden CO2, on the other hand, is highly corrosive, so a CO2 pipeline in this case would have to be made from a corrosion-resistant alloy, or be internally clad with an alloy or a continuous polymer coating. Some pipelines are made from corrosion-resistant alloys, although the cost of materials is several times larger than carbon-manganese steels. For ships, the total loss to the atmosphere is between 3 and 4% per 1000 km, counting both boil-off and the exhaust from ship engines. Boil-off could be reduced by capture and liquefaction, and recapture would reduce the loss to 1 to 2% per 1000 km. Accidents can also occur. In the case of existing CO2 pipelines, which are mostly in areas of low population density, there have been fewer than one reported incident per year (0.0003 per km-year) and no injuries or fatalities. This is consistent with experience with hydrocarbon pipelines,

and the impact would probably not be more severe than for natural gas accidents. In marine transportation, hydrocarbon gas tankers are potentially dangerous, but the recognized hazard has led to standards for design, construction and operation, and serious incidents are rare.

Cost of CO2 transport

Costs have been estimated for both pipeline and marine transportation of CO2. In every case the costs depend strongly on the distance and the quantity transported. In the case of pipelines, the costs depend on whether the pipeline is onshore or offshore, whether the area is heavily congested, and whether there are mountains, large rivers, or frozen ground on the route. All these factors could double the cost per unit length, with even larger increases for pipelines in populated areas. Any additional costs for recompression (booster pump stations) that may be needed for longer pipelines would be counted as part of transport costs. Such costs are relatively small and not included in the estimates presented here. Figure TS.5 shows the cost of pipeline transport for a nominal distance of 250 km. This is typically 1–8 US$/tCO2 (4–30 US$/tC). The figure also shows how pipeline cost depends on the CO2 mass flow rate. Steel cost accounts for a significant fraction of the cost of a pipeline, so fluctuations in such cost (such as the doubling in the years from 2003 to 2005) could affect overall pipeline economics. In ship transport, the tanker volume and the characteristics of the loading and unloading systems are some of the key factors determining the overall transport cost.

offshore

Cos

ts (U

S$/tC

O2/2

50km

)

0.0

1.0

2.0

3.0

4.0

5.0

6.0

0 5 10 15 20 25 30 35

onshore

Figuur 4.5

Mass flow rate (MtCO2 yr-1)

Figure TS.5. Transport costs for onshore pipelines and offshore pipelines, in US$ per tCO2 per 250 km as a function of the CO2 mass flow rate. The graph shows high estimates (dotted lines) and low estimates (solid lines).


The costs associated with CO2 compression and liquefaction are accounted for in the capture costs presented earlier. Figure TS.6 compares pipeline and marine transportation costs, and shows the break-even distance. If the marine option is available, it is typically cheaper than pipelines for distances greater than approximately 1000 km and for amounts smaller than a few million tonnes of CO2 per year. In ocean storage the most suitable transport system depends on the injection method: from a stationary floating vessel, a moving ship, or a pipeline from shore.

5. Geological storage

This section examines three types of geological formations that have received extensive consideration for the geological storage of CO2: oil and gas reservoirs, deep saline formations and unminable coal beds (Figure TS.7). In each case, geological storage of CO2 is accomplished by injecting it in dense form into a rock formation below the earth’s surface. Porous rock formations that hold or (as in the case of depleted oil and gas reservoirs) have previously held fluids, such as natural gas, oil or brines, are potential candidates for CO2 storage. Suitable storage formations can occur in both onshore and offshore sedimentary basins (natural large-scale depressions in the earth’s crust that are filled with sediments). Coal beds also may be used for storage of CO2 (see Figure TS.7) where it is unlikely that the coal will later be mined and provided that permeability is sufficient. The option of storing CO2 in coal beds and enhancing methane production is still in the demonstration phase (see Table TS.1).

Existing CO2 storage projects

Geological storage of CO2 is ongoing in three industrial-scale projects (projects in the order of 1 MtCO2 yr-1 or more): the Sleipner project in the North Sea, the Weyburn project in Canada and the In Salah project in Algeria. About 3–4 MtCO2 that would otherwise be released to the atmosphere is captured and stored annually in geological formations. Additional projects are listed in Table TS.5. In addition to the CCS projects currently in place, 30 MtCO2 is injected annually for EOR, mostly in Texas, USA, where EOR commenced in the early 1970s. Most of this CO2 is obtained from natural CO2 reservoirs found in western regions of the US, with some coming from anthropogenic sources such as natural gas processing. Much of the CO2 injected for EOR is produced with the oil, from which it is separated and then reinjected. At the end of the oil recovery, the CO2 can be retained for the purpose of climate change mitigation, rather than vented to the atmosphere. This is planned for the Weyburn project.

Storage technology and mechanisms

The injection of CO2 in deep geological formations involves many of the same technologies that have been developed in the oil and gas exploration and production industry. Well-drilling technology, injection technology, computer simulation of storage reservoir dynamics and monitoring methods from existing applications are being developed further for design and operation of geological storage. Other underground injection practices also provide relevant operational experience. In particular, natural gas storage, the deep injection of liquid wastes, and acid gas disposal (mixtures of CO2 and H2S) have been conducted in Canada and the U.S. since 1990, also at the megatonne scale. CO2 storage in hydrocarbon reservoirs or deep saline formations is generally expected to take place at depths below 800 m, where the ambient pressures and temperatures will usually result in CO2 being in a liquid or supercritical state. Under these conditions, the density of CO2 will range from 50 to 80% of the density of water. This is close to the density of some crude oils, resulting in buoyant forces that tend to drive CO2 upwards. Consequently, a well-sealed cap rock over the selected storage reservoir is important to ensure that CO2 remains trapped underground. When injected underground, the CO2 compresses and fills the pore space by partially displacing the fluids that are already present (the ‘in situ fluids’). In oil and gas reservoirs, the displacement of in situ fluids by injected CO2 can result in most of the pore volume being available for CO2 storage. In saline formations, estimates of potential storage volume are lower, ranging from as low as a few percent to over 30% of the total rock volume.

Tran

spor

t cos

ts (U

S$/tC

O2)

offshore pipelineonshore pipeline

ship costs

Figuur 4.6Figure TS.6. Costs, plotted as US$/tCO2 transported against distance, for onshore pipelines, offshore pipelines and ship transport. Pipeline costs are given for a mass flow of 6 MtCO2 yr-1. Ship costs include intermediate storage facilities, harbour fees, fuel costs, and loading and unloading activities. Costs include also additional costs for liquefaction compared to compression.


Once injected into the storage formation, the fraction retained depends on a combination of physical and geochemical trapping mechanisms. Physical trapping to block upward migration of CO2 is provided by a layer of shale and clay rock above the storage formation. This impermeable layer is known as the “cap rock”. Additional physical trapping can be provided by capillary forces that retain CO2 in the pore spaces of the formation. In many cases, however, one or more sides of the formation remain open, allowing for lateral migration of CO2 beneath the cap rock. In these cases, additional mechanisms are important for the long-term entrapment of the injected CO2. The mechanism known as geochemical trapping occurs as the CO2 reacts with the in situ fluids and host rock. First, CO2 dissolves in the in situ water. Once this occurs (over time scales of hundreds of years to thousands of years), the CO2-laden water becomes more dense and therefore sinks down into the formation (rather than rising toward the surface).

Next, chemical reactions between the dissolved CO2 and rock minerals form ionic species, so that a fraction of the injected CO2 will be converted to solid carbonate minerals over millions of years. Yet another type of trapping occurs when CO2 is preferentially adsorbed onto coal or organic-rich shales replacing gases such as methane. In these cases, CO2 will remain trapped as long as pressures and temperatures remain stable. These processes would normally take place at shallower depths than CO2 storage in hydrocarbon reservoirs and saline formations.

Geographical distribution and capacity of storage sites

As shown earlier in Section 2 (Figure TS.2b), regions with sedimentary basins that are potentially suitable for CO2 storage exist around the globe, both onshore and offshore. This report focuses on oil and gas reservoirs, deep saline

Figure TS.7. Methods for storing CO2 in deep underground geological formations. Two methods may be combined with the recovery of hydrocarbons: EOR (2) and ECBM (4). See text for explanation of these methods (Courtesy CO2CRC).


formations and unminable coal beds. Other possible geological formations or structures (such as basalts, oil or gas shales, salt caverns and abandoned mines) represent niche opportunities, or have been insufficiently studied at this time to assess their potential. The estimates of the technical potential6 for different geological storage options are summarized in Table TS.6. The estimates and levels of confidence are based on an assessment of the literature, both of regional bottom-up, and global top-down estimates. No probabilistic approach to assessing capacity estimates exists in the literature, and this would be required to quantify levels of uncertainty reliably. Overall estimates, particularly of the upper limit of the potential, vary widely and involve a high degree of uncertainty, reflecting conflicting methodologies in the literature and the fact that our knowledge of saline formations is quite limited in most parts of the world. For oil and gas reservoirs, better estimates are available which are based on the replacement of hydrocarbon volumes with CO2 volumes. It should be noted that, with the exception of EOR, these reservoirs will not be available for CO2 storage until the hydrocarbons are depleted, and that pressure changes and geomechanical effects due to hydrocarbon production in the reservoir may reduce actual capacity. Another way of looking at storage potential, however, is to ask whether it is likely to be adequate for the amounts of CO2 that would need to be avoided using CCS under different

greenhouse gas stabilization scenarios and assumptions about the deployment of other mitigation options. As discussed later in Section 8, the estimated range of economic potential7 for CCS over the next century is roughly 200 to 2,000 GtCO2. The lower limits in Table TS.6 suggest that, worldwide, it is virtually certain8 that there is 200 GtCO2 of geological storage capacity, and likely9 that there is at least about 2,000 GtCO2.

Site selection criteria and methods

Site characterization, selection and performance prediction are crucial for successful geological storage. Before selecting a site, the geological setting must be characterized to determine if the overlying cap rock will provide an effective seal, if there is a sufficiently voluminous and permeable storage formation, and whether any abandoned or active wells will compromise the integrity of the seal. Techniques developed for the exploration of oil and gas reservoirs, natural gas storage sites and liquid waste disposal sites are suitable for characterizing geological storage sites for CO2. Examples include seismic imaging, pumping tests for evaluating storage formations and seals, and cement integrity logs. Computer programmes that model underground CO2 movement are used to support site characterization and selection activities. These programmes were initially developed for applications such as oil and

Table TS.5. Sites where CO2 storage has been done, is currently in progress or is planned, varying from small pilots to large-scale commercial applications.

Project name Country Injection start (year)

Approximate average daily injection rate

(tCO2 day-1)

Total (planned) storage (tCO2)

Storage reservoir type

Weyburn Canada 2000 3,000-5,000 20,000,000 EORIn Salah Algeria 2004 3,000-4,000 17,000,000 Gas fieldSleipner Norway 1996 3,000 20,000,000 Saline formationK12B Netherlands 2004 100

(1,000 planned for 2006+)8,000,000 Enhanced gas

recoveryFrio U.S.A 2004 177 1600 Saline formationFenn Big Valley Canada 1998 50 200 ECBMQinshui Basin China 2003 30 150 ECBMYubari Japan 2004 10 200 ECBMRecopol Poland 2003 1 10 ECBMGorgon (planned) Australia ~2009 10,000 unknown Saline formationSnøhvit (planned) Norway 2006 2,000 unknown Saline formation

6 Technical potential is the amount by which it is possible to reduce greenhouse gas emissions by implementing a technology or practice that already has been demonstrated.

7 Economic potential is the amount of greenhouse gas emissions reductions from a specific option that could be achieved cost-effectively, given prevailing circumstances (the price of CO2 reductions and costs of other options).

8 “Virtually certain” is a probability of 99% or more.9 “Likely” is a probability of 66 to 90%.


gas reservoir engineering and groundwater resources investigations. Although they include many of the physical, chemical and geomechanical processes needed to predict both short-term and long-term performance of CO2 storage, more experience is needed to establish confidence in their effectiveness in predicting long-term performance when adapted for CO2 storage. Moreover, the availability of good site characterization data is critical for the reliability of models.

Risk assessment and environmental impact

The risks due to leakage from storage of CO2 in geological reservoirs fall into two broad categories: global risks and local risks. Global risks involve the release of CO2 that may contribute significantly to climate change if some fraction leaks from the storage formation to the atmosphere. In addition, if CO2 leaks out of a storage formation, local hazards may exist for humans, ecosystems and groundwater. These are the local risks. With regard to global risks, based on observations and analysis of current CO2 storage sites, natural systems, engineering systems and models, the fraction retained in appropriately selected and managed reservoirs is very likely10 to exceed 99% over 100 years, and is likely to exceed 99% over 1000 years. Similar fractions retained are likely for even longer periods of time, as the risk of leakage is expected to decrease over time as other mechanisms provide additional trapping. The question of whether these fractions retained would be sufficient to make impermanent storage valuable for climate change mitigation is discussed in Section 8. With regard to local risks, there are two types of scenarios in which leakage may occur. In the first case, injection well failures or leakage up abandoned wells could create a sudden and rapid release of CO2. This type of release is likely to be detected quickly and stopped using techniques that are available today for containing well blow-outs. Hazards associated with this type of release primarily affect workers in the vicinity of the release at the time it occurs, or those called in to control the blow-out. A concentration of CO2 greater

than 7–10% in air would cause immediate dangers to human life and health. Containing these kinds of releases may take hours to days and the overall amount of CO2 released is likely to be very small compared to the total amount injected. These types of hazards are managed effectively on a regular basis in the oil and gas industry using engineering and administrative controls. In the second scenario, leakage could occur through undetected faults, fractures or through leaking wells where the release to the surface is more gradual and diffuse. In this case, hazards primarily affect drinking-water aquifers and ecosystems where CO2 accumulates in the zone between the surface and the top of the water table. Groundwater can be affected both by CO2 leaking directly into an aquifer and by brines that enter the aquifer as a result of being displaced by CO2 during the injection process. There may also be acidification of soils and displacement of oxygen in soils in this scenario. Additionally, if leakage to the atmosphere were to occur in low-lying areas with little wind, or in sumps and basements overlying these diffuse leaks, humans and animals would be harmed if a leak were to go undetected. Humans would be less affected by leakage from offshore storage locations than from onshore storage locations. Leakage routes can be identified by several techniques and by characterization of the reservoir. Figure TS.8 shows some of the potential leakage paths for a saline formation. When the potential leakage routes are known, the monitoring and remediation strategy can be adapted to address the potential leakage. Careful storage system design and siting, together with methods for early detection of leakage (preferably long before CO2 reaches the land surface), are effective ways of reducing hazards associated with diffuse leakage. The available monitoring methods are promising, but more experience is needed to establish detection levels and resolution. Once leakages are detected, some remediation techniques are available to stop or control them. Depending on the type of leakage, these techniques could involve standard well repair techniques, or the extraction of CO2 by intercepting its leak into a shallow groundwater aquifer (see Figure TS.8).

Table TS.6. Storage capacity for several geological storage options. The storage capacity includes storage options that are not economical.

Reservoir type Lower estimate of storage capacity (GtCO2)

Upper estimate of storage capacity (GtCO2)

Oil and gas fields 675a 900a

Unminable coal seams (ECBM) 3-15 200Deep saline formations 1,000 Uncertain, but possibly 104

a These numbers would increase by 25% if ‘undiscovered’ oil and gas fields were included in this assessment.

10 “Very likely” is a probability of 90 to 99%.


Techniques to remove CO2 from soils and groundwater are also available, but they are likely to be costly. Experience will be needed to demonstrate the effectiveness, and ascertain the costs, of these techniques for use in CO2 storage.

Monitoring and verification

Monitoring is a very important part of the overall risk management strategy for geological storage projects. Standard procedures or protocols have not been developed yet but they are expected to evolve as technology improves, depending on local risks and regulations. However, it is expected that some parameters such as injection rate and injection well pressure will be measured routinely. Repeated seismic surveys have been shown to be useful for tracking the underground migration of CO2. Newer techniques such as gravity and electrical measurements may also be useful. The sampling of groundwater and the soil between the surface and water table may be useful for directly detecting CO2 leakage. CO2 sensors with alarms can be located at the injection wells for ensuring worker safety and to detect leakage. Surface-based techniques may also be used for detecting and quantifying surface releases. High-quality baseline data improve the

reliability and resolution of all measurements and will be essential for detecting small rates of leakage. Since all of these monitoring techniques have been adapted from other applications, they need to be tested and assessed with regard to reliability, resolution and sensitivity in the context of geological storage. All of the existing industrial-scale projects and pilot projects have programmes to develop and test these and other monitoring techniques. Methods also may be necessary or desirable to monitor the amount of CO2 stored underground in the context of emission reporting and monitoring requirements in the UNFCCC (see Section 9). Given the long-term nature of CO2 storage, site monitoring may be required for very long periods.

Legal issues

At present, few countries have specifically developed legal and regulatory frameworks for onshore CO2 storage. Relevant legislation include petroleum-related legislation, drinking-water legislation and mining regulations. In many cases, there are laws applying to some, if not most, of the issues related to CO2 storage. Specifically, long-term liability issues, such as global issues associated with the

Figure TS.8. Potential leakage routes and remediation techniques for CO2 injected into saline formations. The remediation technique would depend on the potential leakage routes identified in a reservoir (Courtesy CO2CRC).


leakage of CO2 to the atmosphere, as well as local concerns about environmental impact, have not yet been addressed. Monitoring and verification regimes and risks of leakage may play an important role in determining liability, and vice-versa. There are also considerations such as the longevity of institutions, ongoing monitoring and transferability of institutional knowledge. The long-term perspective is essential to a legal framework for CCS as storage times extend over many generations as does the climate change problem. In some countries, notably the US, the property rights of all those affected must be considered in legal terms as pore space is owned by surface property owners. According to the general principles of customary international law, States can exercise their sovereignty in their territories and could therefore engage in activities such as the storage of CO2 (both geological and ocean) in those areas under their jurisdiction. However, if storage has a transboundary impact, States have the responsibility to ensure that activities within their jurisdiction or control do not cause damage to the environment of other States or of areas beyond the limits of national jurisdiction. Currently, there are several treaties (notably the UN Convention on the Law of the Sea, and the London11 and OSPAR12 Conventions) that could apply to the offshore injection of CO2 into marine environments (both into the ocean and the geological sub-seabed). All these treaties have been drafted without specific consideration of CO2 storage. An assessment undertaken by the Jurists and Linguists Group to the OSPAR Convention (relating to the northeast Atlantic region), for example, found that, depending on the method and purpose of injection, CO2 injection into the geological sub-seabed and the ocean could be compatible with the treaty in some cases, such as when the CO2 is transported via a pipeline from land. A similar assessment is now being conducted by Parties to the London Convention. Furthermore, papers by legal commentators have concluded that CO2 captured from an oil or natural gas extraction operation and stored offshore in a geological formation (like the Sleipner operation) would not be considered ‘dumping’ under, and would not therefore be prohibited by, the London Convention.

Public perception

Assessing public perception of CCS is challenging because of the relatively technical and “remote” nature of this issue at the present time. Results of the very few studies conducted to date about the public perception of CCS indicate that the public is generally not well informed about CCS. If

information is given alongside information about other climate change mitigation options, the handful of studies carried out so far indicate that CCS is generally regarded as less favourable than other options, such as improvements in energy efficiency and the use of non-fossil energy sources. Acceptance of CCS, where it occurs, is characterized as “reluctant” rather than “enthusiastic”. In some cases, this reflects the perception that CCS might be required because of a failure to reduce CO2 emissions in other ways. There are indications that geological storage could be viewed favourably if it is adopted in conjunction with more desirable measures. Although public perception is likely to change in the future, the limited research to date indicates that at least two conditions may have to be met before CO2 capture and storage is considered by the public as a credible technology, alongside other better known options: (1) anthropogenic global climate change has to be regarded as a relatively serious problem; (2) there must be acceptance of the need for large reductions in CO2 emissions to reduce the threat of global climate change.

Cost of geological storage

The technologies and equipment used for geological storage are widely used in the oil and gas industries so cost estimates for this option have a relatively high degree of confidence for storage capacity in the lower range of technical potential. However, there is a significant range and variability of costs due to site-specific factors such as onshore versus offshore, reservoir depth and geological characteristics of the storage formation (e.g., permeability and formation thickness). Representative estimates of the cost for storage in saline formations and depleted oil and gas fields are typically between 0.5–8 US$/tCO2 injected. Monitoring costs of 0.1–0.3 US$/tCO2 are additional. The lowest storage costs are for onshore, shallow, high permeability reservoirs, and/or storage sites where wells and infrastructure from existing oil and gas fields may be re-used.

When storage is combined with EOR, ECBM or (potentially) Enhanced Gas Recovery (EGR), the economic value of CO2 can reduce the total cost of CCS. Based on data and oil prices prior to 2003, enhanced oil production for onshore EOR with CO2 storage could yield net benefits of 10–16 US$/tCO2 (37–59 US$/tC) (including the costs of geological storage). For EGR and ECBM, which are still under development, there is no reliable cost information based on actual experience. In all cases, however, the economic benefit of enhanced production

11 Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (1972), and its London Protocol (1996), which has not yet entered into force.

12 Convention for the Protection of the Marine Environment of the North-East Atlantic, which was adopted in Paris (1992). OSPAR is an abbreviation of Oslo-Paris.


depends strongly on oil and gas prices. In this regard, the literature basis for this report does not take into account the rise in world oil and gas prices since 2003 and assumes oil prices of 15–20 US$ per barrel. Should higher prices be sustained over the life of a CCS project, the economic value of CO2 could be higher than that reported here.

6. Ocean storage

A potential CO2 storage option is to inject captured CO2 directly into the deep ocean (at depths greater than 1,000 m), where most of it would be isolated from the atmosphere for centuries. This can be achieved by transporting CO2 via pipelines or ships to an ocean storage site, where it is injected into the water column of the ocean or at the sea floor. The dissolved and dispersed CO2 would subsequently become part of the global carbon cycle. Figure TS.9 shows some of the main methods that could be employed. Ocean storage has not yet been deployed or demonstrated at a pilot scale, and is still in the research phase. However, there have been small-scale field experiments and 25 years of theoretical, laboratory and modelling studies of intentional ocean storage of CO2.

Storage mechanisms and technology

Oceans cover over 70% of the earth’s surface and their average depth is 3,800 m. Because carbon dioxide is soluble in water, there are natural exchanges of CO2 between the atmosphere and waters at the ocean surface that occur until equilibrium is reached. If the atmospheric concentration of CO2 increases, the ocean gradually takes up additional CO2. In this way, the oceans have taken up about 500 GtCO2 (140 GtC) of the total 1,300 GtCO2 (350 GtC) of anthropogenic emissions released to the atmosphere over the past 200 years. As a result of the increased atmospheric CO2 concentrations from human activities relative to pre-industrial levels, the oceans are currently taking up CO2 at a rate of about 7 GtCO2 yr-1 (2 GtC yr-1). Most of this carbon dioxide now resides in the upper ocean and thus far has resulted in a decrease in pH of about 0.1 at the ocean surface because of the acidic nature of CO2 in water. To date, however, there has been virtually no change in pH in the deep ocean. Models predict that over the next several centuries the oceans will eventually take up most of the CO2 released to the atmosphere as CO2 is dissolved at the ocean surface and subsequently mixed with deep ocean waters.

Dispersal ofCO2 /CaCO3mixture

CO2 lakeCO2 lake

Rising CO2 plume

Refilling ship

Flue gas

CO2 /CaCO3reactor

Captured andcompressed CO2

3 kmSinking CO2 plume

Dispersal of CO2 by ship

Figuur TS.9Figure TS.9. Methods of ocean storage.


There is no practical physical limit to the amount of anthropogenic CO2 that could be stored in the ocean. However, on a millennial time scale, the amount stored will depend on oceanic equilibration with the atmosphere. Stabilizing atmospheric CO2 concentrations between 350 ppmv and 1000 ppmv would imply that between 2,000 and 12,000 GtCO2 would eventually reside in the ocean if there is no intentional CO2 injection. This range therefore represents the upper limit for the capacity of the ocean to store CO2 through active injection. The capacity would also be affected by environmental factors, such as a maximum allowable pH change. Analysis of ocean observations and models both indicate that injected CO2 will be isolated from the atmosphere for at least several hundreds of years, and that the fraction retained tends to be higher with deeper injection (see Table TS.7). Ideas for increasing the fraction retained include forming solid CO2 hydrates and/or liquid CO2 lakes on the sea floor, and dissolving alkaline minerals such as limestone to neutralize the acidic CO2. Dissolving mineral carbonates, if practical, could extend the storage time scale to roughly 10,000 years, while minimizing changes in ocean pH and CO2 partial pressure. However, large amounts of limestone and energy for materials handling would be required for this approach (roughly the same order of magnitude as the amounts per tonne of CO2 injected that are needed for mineral carbonation; see Section 7).

Ecological and environmental impacts and risks

The injection of a few GtCO2 would produce a measurable change in ocean chemistry in the region of injection, whereas the injection of hundreds of GtCO2 would produce larger changes in the region of injection and eventually produce measurable changes over the entire ocean volume. Model simulations that assume a release from seven locations at 3,000 m depth and ocean storage providing 10% of the mitigation effort for stabilization at 550 ppmv CO2 projected acidity changes (pH changes) of more than 0.4 over approximately 1% of the ocean volume. By comparison, in

a 550 ppmv stabilization case without ocean storage, a pH change of more than 0.25 at the ocean surface was estimated due to equilibration with the elevated CO2 concentrations in the atmosphere. In either case, a pH change of 0.2 to 0.4 is significantly greater than pre-industrial variations in ocean acidity. Over centuries, ocean mixing will result in the loss of isolation of injected CO2. As more CO2 reaches the ocean surface waters, releases into the atmosphere would occur gradually from large regions of the ocean. There are no known mechanisms for sudden or catastrophic release of injected CO2 from the ocean into the atmosphere. Experiments show that adding CO2 can harm marine organisms. Effects of elevated CO2 levels have mostly been studied on time scales up to several months in individual organisms that live near the ocean surface. Observed phenomena include reduced rates of calcification, reproduction, growth, circulatory oxygen supply and mobility, as well as increased mortality over time. In some organisms these effects are seen in response to small additions of CO2. Immediate mortality is expected close to injection points or CO2 lakes. The chronic effects of direct CO2 injection into the ocean on ocean organisms or ecosystems over large ocean areas and long time scales have not yet been studied. No controlled ecosystem experiments have been performed in the deep ocean, so only a preliminary assessment of potential ecosystem effects can be given. It is expected that ecosystem consequences will increase with increasing CO2 concentrations and decreasing pH, but the nature of such consequences is currently not understood, and no environmental criteria have as yet been identified to avoid adverse effects. At present, it is also unclear how or whether species and ecosystems would adapt to the sustained chemical changes.

Costs of ocean storage

Although there is no experience with ocean storage, some attempts have been made to estimate the costs of CO2 storage projects that release CO2 on the sea floor or in the deep ocean. The costs of CO2 capture and transport to the shoreline (e.g

Table TS.7. Fraction of CO2 retained for ocean storage as simulated by seven ocean models for 100 years of continuous injection at three different depths starting in the year 2000.

Injection depthYear 800 m 1500 m 3000 m2100 0.78 ± 0.06 0.91 ± 0.05 0.99 ± 0.012200 0.50 ± 0.06 0.74 ± 0.07 0.94 ± 0.062300 0.36 ± 0.06 0.60 ± 0.08 0.87 ± 0.102400 0.28 ± 0.07 0.49 ± 0.09 0.79 ± 0.122500 0.23 ± 0.07 0.42 ± 0.09 0.71 ± 0.14


via pipelines) are not included in the cost of ocean storage. However, the costs of offshore pipelines or ships, plus any additional energy costs, are included in the ocean storage cost. The costs of ocean storage are summarized in Table TS.8. These numbers indicate that, for short distances, the fixed pipeline option would be cheaper. For larger distances, either the moving ship or the transport by ship to a platform with subsequent injection would be more attractive.

Legal aspects and public perception

The global and regional treaties on the law of the sea and marine environment, such as the OSPAR and the London Convention discussed earlier in Section 5 for geological storage sites, also affect ocean storage, as they concern the ‘maritime area’. Both Conventions distinguish between the storage method employed and the purpose of storage to determine the legal status of ocean storage of CO2. As yet, however, no decision has been made about the legal status of intentional ocean storage. The very small number of public perception studies that have looked at the ocean storage of CO2 indicate that there is very little public awareness or knowledge of this subject. In the few studies conducted thus far, however, the public has expressed greater reservations about ocean storage than geological storage. These studies also indicate that the perception of ocean storage changed when more information was provided; in one study this led to increased acceptance of ocean storage, while in another study it led to less acceptance. The literature also notes that ‘significant opposition’ developed around a proposed CO2 release experiment in the Pacific Ocean.

7. Mineral carbonation and industrial uses

This section deals with two rather different options for CO2 storage. The first is mineral carbonation, which involves converting CO2 to solid inorganic carbonates using chemical reactions. The second option is the industrial use of CO2, either directly or as feedstock for production of various carbon-containing chemicals.

Mineral carbonation: technology, impacts and costs

Mineral carbonation refers to the fixation of CO2 using alkaline and alkaline-earth oxides, such as magnesium oxide (MgO) and calcium oxide (CaO), which are present in naturally occurring silicate rocks such as serpentine and olivine. Chemical reactions between these materials and CO2 produces compounds such as magnesium carbonate (MgCO3) and calcium carbonate (CaCO3, commonly known as limestone). The quantity of metal oxides in the silicate rocks that can be found in the earth’s crust exceeds the amounts needed to fix all the CO2 that would be produced by the combustion of all available fossil fuel reserves. These oxides are also present in small quantities in some industrial wastes, such as stainless steel slags and ashes. Mineral carbonation produces silica and carbonates that are stable over long time scales and can therefore be disposed of in areas such as silicate mines, or re-used for construction purposes (see Figure TS.10), although such re-use is likely to be small relative to the amounts produced. After carbonation, CO2 would not be released to the atmosphere. As a consequence, there would be little need to monitor the disposal sites and the associated risks would be very low. The storage potential is difficult to estimate at this early phase of development. It would be limited by the fraction of silicate reserves that can be technically exploited, by environmental issues such as the volume of product disposal, and by legal and societal constraints at the storage location. The process of mineral carbonation occurs naturally, where it is known as ‘weathering’. In nature, the process occurs very slowly; it must therefore be accelerated considerably to be a viable storage method for CO2 captured from anthropogenic sources. Research in the field of mineral carbonation therefore focuses on finding process routes that can achieve reaction rates viable for industrial purposes and make the reaction more energy-efficient. Mineral carbonation technology using natural silicates is in the research phase but some processes using industrial wastes are in the demonstration phase. A commercial process would require mining, crushing and milling of the mineral-bearing ores and their transport to a processing plant receiving a concentrated CO2 stream from a capture plant (see Figure TS.10). The carbonation process

Table TS.8. Costs for ocean storage at depths deeper than 3,000 m.

Ocean storage methodCosts (US$/tCO2 net injected)

100 km offshore 500 km offshoreFixed pipeline 6 31Moving ship/platforma 12-14 13-16

a The costs for the moving ship option are for injection depths of 2,000-2,500 m.


energy required would be 30 to 50% of the capture plant output. Considering the additional energy requirements for the capture of CO2, a CCS system with mineral carbonation would require 60 to 180% more energy input per kilowatt-hour than a reference electricity plant without capture or mineral carbonation. These energy requirements raise the cost per tonne of CO2 avoided for the overall system significantly (see Section 8). The best case studied so far is the wet carbonation of natural silicate olivine. The estimated cost of this process is approximately 50–100 US$/tCO2 net mineralized (in addition to CO2 capture and transport costs, but taking into account the additional energy requirements). The mineral carbonation process would require 1.6 to 3.7 tonnes of silicates per tonne of CO2 to be mined, and produce 2.6 to 4.7 tonnes of materials to be disposed per tonne of CO2 stored as carbonates. This would therefore be a large operation, with an environmental impact similar to that of current large-scale surface mining operations. Serpentine also often contains chrysotile, a natural form of asbestos. Its presence therefore demands monitoring and mitigation measures of the kind available in the mining industry. On the other hand, the products of mineral carbonation are chrysotile-

free, since this is the most reactive component of the rock and therefore the first substance converted to carbonates. A number of issues still need to be clarified before any estimates of the storage potential of mineral carbonation can be given. The issues include assessments of the technical feasibility and corresponding energy requirements at large scales, but also the fraction of silicate reserves that can be technically and economically exploited for CO2 storage. The environmental impact of mining, waste disposal and product storage could also limit potential. The extent to which mineral carbonation may be used cannot be determined at this time, since it depends on the unknown amount of silicate reserves that can be technically exploited, and environmental issuessuch as those noted above.

Industrial uses

Industrial uses of CO2 include chemical and biological processes where CO2 is a reactant, such as those used in urea and methanol production, as well as various technological applications that use CO2 directly, for example in the horticulture industry, refrigeration, food packaging, welding,

Figure TS.10. Material fluxes and process steps associated with the mineral carbonation of silicate rocks or industrial residues (Courtesy ECN).


beverages and fire extinguishers. Currently, CO2 is used at a rate of approximately 120 MtCO2 per year (30 MtC yr-1) worldwide, excluding use for EOR (discussed in Section 5). Most (two thirds of the total) is used to produce urea, which is used in the manufacture of fertilizers and other products. Some of the CO2 is extracted from natural wells, and some originates from industrial sources – mainly high-concentration sources such as ammonia and hydrogen production plants – that capture CO2 as part of the production process. Industrial uses of CO2 can, in principle, contribute to keeping CO2 out of the atmosphere by storing it in the “carbon chemical pool” (i.e., the stock of carbon-bearing manufactured products). However, as a measure for mitigating climate change, this option is meaningful only if the quantity and duration of CO2 stored are significant, and if there is a real net reduction of CO2 emissions. The typical lifetime of most of the CO2 currently used by industrial processes has storage times of only days to months. The stored carbon is then degraded to CO2 and again emitted to the atmosphere. Such short time scales do not contribute meaningfully to climate change mitigation. In addition, the total industrial use figure of 120 MtCO2 yr-1 is small compared to emissions from major anthropogenic sources (see Table TS.2). While some industrial processes store a small proportion of CO2 (totalling roughly 20 MtCO2 yr-1) for up to several decades, the total amount of long-term (century-scale) storage is presently in the order of 1 MtCO2 yr-1 or less, with no prospects for major increases. Another important question is whether industrial uses of CO2 can result in an overall net reduction of CO2 emissions by substitution for other industrial processes or products. This can be evaluated correctly only by considering proper system boundaries for the energy and material balances of the CO2 utilization processes, and by carrying out a detailed life-cycle analysis of the proposed use of CO2. The literature in this area is limited but it shows that precise figures are difficult to estimate and that in many cases industrial uses could lead to an increase in overall emissions rather than a net reduction. In view of the low fraction of CO2 retained, the small volumes used and the possibility that substitution may lead to increases in CO2 emissions, it can be concluded that the contribution of industrial uses of captured CO2 to climate change mitigation is expected to be small.

8. Costs and economic potential

The stringency of future requirements for the control of greenhouse gas emissions and the expected costs of CCS systems will determine, to a large extent, the future deployment of CCS technologies relative to other greenhouse gas mitigation options. This section first summarizes the overall cost of CCS for the main options and process applications considered in previous sections. As used in this summary

and the report, “costs” refer only to market prices but do not include external costs such as environmental damages and broader societal costs that may be associated with the use of CCS. To date, little has been done to assess and quantify such external costs. Finally CCS is examined in the context of alternative options for global greenhouse gas reductions.

Cost of CCS systems

As noted earlier, there is still relatively little experience with the combination of CO2 capture, transport and storage in a fully integrated CCS system. And while some CCS components are already deployed in mature markets for certain industrial applications, CCS has still not been used in large-scale power plants (the application with most potential). The literature reports a fairly wide range of costs for CCS components (see Sections 3–7). The range is due primarily to the variability of site-specific factors, especially the design, operating and financing characteristics of the power plants or industrial facilities in which CCS is used; the type and costs of fuel used; the required distances, terrains and quantities involved in CO2 transport; and the type and characteristics of the CO2 storage. In addition, uncertainty still remains about the performance and cost of current and future CCS technology components and integrated systems. The literature reflects a widely-held belief, however, that the cost of building and operating CO2 capture systems will decline over time as a result of learning-by-doing (from technology deployment) and sustained R&D. Historical evidence also suggests that costs for first-of-a-kind capture plants could exceed current estimates before costs subsequently decline. In most CCS systems, the cost of capture (including compression) is the largest cost component. Costs of electricity and fuel vary considerably from country to country, and these factors also influence the economic viability of CCS options. Table TS.9 summarizes the costs of CO2 capture, transport and storage reported in Sections 3 to 7. Monitoring costs are also reflected. In Table TS.10, the component costs are combined to show the total costs of CCS and electricity generation for three power systems with pipeline transport and two geological storage options. For the plants with geological storage and no EOR credit, the cost of CCS ranges from 0.02–0.05 US$/kWh for PC plants and 0.01–0.03 US$/kWh for NGCC plants (both employing post-combustion capture). For IGCC plants (using pre-combustion capture), the CCS cost ranges from 0.01–0.03 US$/kWh relative to a similar plant without CCS. For all electricity systems, the cost of CCS can be reduced by about 0.01–0.02 US$/kWh when using EOR with CO2 storage because the EOR revenues partly compensate for the CCS costs. The largest cost reductions are seen for coal-based plants, which capture the largest amounts of CO2. In a few cases, the low end of the CCS cost range can be negative,


indicating that the assumed credit for EOR over the life of the plant is greater than the lowest reported cost of CO2 capture for that system. This might also apply in a few instances of low-cost capture from industrial processes. In addition to fossil fuel-based energy conversion processes, CO2 could also be captured in power plants fueled with biomass, or fossil-fuel plants with biomass co-firing. At present, biomass plants are small in scale (less than 100 MWe). This means that the resulting costs of production with and without CCS are relatively high compared to fossil alternatives. Full CCS costs for biomass could amount to 110 US$/tCO2 avoided. Applying CCS to biomass-fuelled or co-fired conversion facilities would lead to lower or negative13 CO2 emissions, which could reduce the costs for this option, depending on the market value of CO2 emission reductions. Similarly, CO2 could be captured in biomass-fueled H2 plants. The cost is reported to be 22–25 US$/tCO2 (80–92 US$/tC) avoided in a plant producing 1 million Nm3 day-1 of H2, and corresponds to an increase in the H2 product costs of about 2.7 US$ GJ-1. Significantly larger biomass plants could potentially benefit from economies of scale, bringing down costs of the CCS systems to levels broadly similar to coal plants. However, to date, there has been little experience with large-scale biomass plants, so their feasibility has not been proven yet, and costs and potential are difficult to estimate.

The cost of CCS has not been studied in the same depth for non-power applications. Because these sources are very diverse in terms of CO2 concentration and gas stream pressure, the available cost studies show a very broad range. The lowest costs were found for processes that already separate CO2 as part of the production process, such as hydrogen production (the cost of capture for hydrogen production was reported earlier in Table TS.4). The full CCS cost, including transport and storage, raises the cost of hydrogen production by 0.4 to 4.4 US$ GJ-1 in the case of geological storage, and by -2.0 to 2.8 US$ GJ-1 in the case of EOR, based on the same cost assumptions as for Table TS.10.

Cost of CO2 avoided

Table TS.10 also shows the ranges of costs for ‘CO2 avoided’. CCS energy requirements push up the amount of fuel input (and therefore CO2 emissions) per unit of net power output. As a result, the amount of CO2 produced per unit of product (a kWh of electricity) is greater for the power plant with CCS than the reference plant, as shown in Figure TS.11. To determine the CO2 reductions one can attribute to CCS, one needs to compare CO2 emissions per kWh of the plant with capture to that of a reference plant without capture. The difference is referred to as the ‘avoided emissions’.

Table TS.9. 2002 Cost ranges for the components of a CCS system as applied to a given type of power plant or industrial source. The costs of the separate components cannot simply be summed to calculate the costs of the whole CCS system in US$/CO2 avoided. All numbers are representative of the costs for large-scale, new installations, with natural gas prices assumed to be 2.8-4.4 US$ GJ-1 and coal prices 1-1.5 US$ GJ-1.

CCS system components Cost range RemarksCapture from a coal- or gas-fired power plant

15-75 US$/tCO2 net captured Net costs of captured CO2, compared to the same plant without capture.

Capture from hydrogen and ammonia production or gas processing

5-55 US$/tCO2 net captured Applies to high-purity sources requiring simple drying and compression.

Capture from other industrial sources 25-115 US$/tCO2 net captured Range reflects use of a number of different technologies and fuels.

Transportation 1-8 US$/tCO2 transported Per 250 km pipeline or shipping for mass flow rates of 5 (high end) to 40 (low end) MtCO2 yr-1.

Geological storagea 0.5-8 US$/tCO2 net injected Excluding potential revenues from EOR or ECBM.

Geological storage: monitoring and verification

0.1-0.3 US$/tCO2 injected This covers pre-injection, injection, and post-injection monitoring, and depends on the regulatory requirements.

Ocean storage 5-30 US$/tCO2 net injected Including offshore transportation of 100-500 km, excluding monitoring and verification.

Mineral carbonation 50-100 US$/tCO2 net mineralized Range for the best case studied. Includes additional energy use for carbonation.

a Over the long term, there may be additional costs for remediation and liabilities.

13 If for example the biomass is harvested at an unsustainable rate (that is, faster than the annual re-growth), the net CO2 emissions of the activity might not be negative.


Introducing CCS to power plants may influence the decision about which type of plant to install and which fuel to use. In some situations therefore, it can be useful to calculate a cost per tonne of CO2 avoided based on a reference plant different from the CCS plant. Table TS.10 displays the cost and emission factors for the three reference plants and the corresponding CCS plants for the case of geological storage. Table TS.11 summarizes the range of estimated costs for different combinations of CCS plants and the lowest-cost reference plants of potential interest. It shows, for instance, that where a PC plant is planned initially, using CCS in that plant may lead to a higher CO2 avoidance cost than if an NGCC plant with CCS is selected, provided natural gas is available. Another option with lower avoidance cost could be to build an IGCC plant with capture instead of equipping a PC plant with capture.

Economic potential of CCS for climate change mitigation

Assessments of the economic potential of CCS are based on energy and economic models that study future CCS deployment and costs in the context of scenarios that achieve economically efficient, least-cost paths to the stabilization of atmospheric CO2 concentrations. While there are significant uncertainties in the quantitative results from these models (see discussion below), all models indicate that CCS systems are unlikely to be deployed on a large scale in the absence of an explicit policy that substantially limits greenhouse gas emissions to the atmosphere. With greenhouse gas emission limits imposed, many integrated assessments foresee the deployment of CCS systems on a large scale within a few decades from the start of any significant climate change mitigation regime. Energy and economic models indicate that CCS systems

Table TS.10. Range of total costs for CO2 capture, transport and geological storage based on current technology for new power plants using bituminous coal or natural gas

Power plant performance and cost parametersa Pulverized coal power plant

Natural gas combined cycle

power plant

Integrated coal gasification combined

cycle power plantReference plant without CCS

Cost of electricity (US$/kWh) 0.043-0.052 0.031-0.050

0.041-0.061

Power plant with captureIncreased fuel requirement (%) 24-40 11-22 14-25CO2 captured (kg/kWh) 0.82-0.97 0.36-0.41 0.67-0.94CO2 avoided (kg/kWh) 0.62-0.70 0.30-0.32 0.59-0.73% CO2 avoided 81-88 83-88 81-91

Power plant with capture and geological storageb

Cost of electricity (US$/kWh) 0.063-0.099 0.043-0.077 0.055-0.091Cost of CCS (US$/kWh) 0.019-0.047 0.012-0.029 0.010-0.032% increase in cost of electricity 43-91 37-85 21-78Mitigation cost (US$/tCO2 avoided) 30-71 38-91 14-53 (US$/tC avoided) 110-260 140-330 51-200

Power plant with capture and enhanced oil recoveryc

Cost of electricity (US$/kWh) 0.049-0.081 0.037-0.070 0.040-0.075Cost of CCS (US$/kWh) 0.005-0.029 0.006-0.022 (-0.005)-0.019% increase in cost of electricity 12-57 19-63 (-10)-46Mitigation cost (US$/tCO2 avoided) 9-44 19-68 (-7)-31 (US$/tC avoided) 31-160 71-250 (-25)-120

a All changes are relative to a similar (reference) plant without CCS. See Table TS.3 for details of assumptions underlying reported cost ranges.b Capture costs based on ranges from Table TS.3; transport costs range from 0-5 US$/tCO2; geological storage cost ranges from 0.6-8.3 US$/tCO2.c Same capture and transport costs as above; Net storage costs for EOR range from -10 to -16 US$/tCO2 (based on pre-2003 oil prices of 15-20 US$ per

barrel).


are unlikely to contribute significantly to the mitigation of climate change unless deployed in the power sector. For this

to happen, the price of carbon dioxide reductions would have to exceed 25–30 US$/tCO2, or an equivalent limit on CO2 emissions would have to be mandated. The literature and current industrial experience indicate that, in the absence of measures for limiting CO2 emissions, there are only small, niche opportunities for CCS technologies to deploy. These early opportunities involve CO2 captured from a high-purity, low-cost source, the transport of CO2 over distances of less than 50 km, coupled with CO2 storage in a value-added application such as EOR. The potential of such niche options is about 360 MtCO2 per year (see Section 2). Models also indicate that CCS systems will be competitive with other large-scale mitigation options such as nuclear power and renewable energy technologies. These studies show that including CCS in a mitigation portfolio could reduce the cost of stabilizing CO2 concentrations by 30% or more. One aspect of the cost competitiveness of CCS technologies is that they are compatible with most current energy infrastructures. In most scenarios, emissions abatement becomes progressively more constraining over time. Most analyses indicate that notwithstanding significant penetration of CCS systems by 2050, the majority of CCS deployment will occur in the second half of this century. The earliest CCS deployments are typically foreseen in the industrialized nations, with deployment eventually spreading worldwide. While results for different scenarios and models differ (often

Emitted

ReferencePlant

Plantwith CCS

CO2 produced (kg/kWh)

Captured

Figuur 8.2

CO2 avoided

CO2 captured

Figure TS.11. CO2 capture and storage from power plants. The increased CO2 production resulting from loss in overall efficiency of power plants due to the additional energy required for capture, transport and storage, and any leakage from transport result in a larger amount of “CO2 produced per unit of product” (lower bar) relative to the reference plant (upper bar) without capture.

Table TS.11. Mitigation cost ranges for different combinations of reference and CCS plants based on current technology for new power plants. Currently, in many regions, common practice would be either a PC plant or an NGCC plant14. EOR benefits are based on oil prices of 15 - 20 US$ per barrel. Gas prices are assumed to be 2.8 -4.4 US$/GJ-1, coal prices 1-1.5 US$/GJ-1 (based on Table 8.3a).

CCS plant typeNGCC reference plant PC reference plant

US$/tCO2 avoided(US$/tC avoided)

US$/tCO2 avoided(US$/tC avoided)

Power plant with capture and geological storageNGCC 40 - 90

(140 - 330)20 - 60

(80 - 220)PC 70 - 270

(260 - 980)30 - 70

(110 - 260)IGCC 40 - 220

(150 - 790)20 - 70

(80 - 260)Power plant with capture and EOR

NGCC 20 - 70 (70 - 250)

0 - 30 (0 - 120)

PC 50 - 240 (180 - 890)

10 - 40 (30 - 160)

IGCC 20 - 190 (80 - 710)

0 - 40 (0 - 160)

14 IGCC is not included as a reference power plant that would be built today since this technology is not yet widely deployed in the electricity sector and is usually slightly more costly than a PC plant.


significantly) in the specific mix and quantities of different measures needed to achieve a particular emissions constraint (see Figure TS.12), the consensus of the literature shows that CCS could be an important component of the broad portfolio of energy technologies and emission reduction approaches. The actual use of CCS is likely to be lower than the estimates of economic potential indicated by these energy and economic models. As noted earlier, the results are typically based on an optimized least-cost analysis that does

not adequately account for real-world barriers to technology development and deployment, such as environmental impact, lack of a clear legal or regulatory framework, the perceived investment risks of different technologies, and uncertainty as to how quickly the cost of CCS will be reduced through R&D and learning-by-doing. Models typically employ simplified assumptions regarding the costs of CCS for different applications and the rates at which future costs will be reduced.

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Figure TS.12. These figures are an illustrative example of the global potential contribution of CCS as part of a mitigation portfolio. They are based on two alternative integrated assessment models (MESSAGE and MiniCAM) adopting the same assumptions for the main emissions drivers. The results would vary considerably on regional scales. This example is based on a single scenario and therefore does not convey the full range of uncertainties. Panels a) and b) show global primary energy use, including the deployment of CCS. Panels c) and d) show the global CO2 emissions in grey and corresponding contributions of main emissions reduction measures in colour. Panel e) shows the calculated marginal price of CO2 reductions.


For CO2 stabilization scenarios between 450 and 750 ppmv, published estimates of the cumulative amount of CO2 potentially stored globally over the course of this century (in geological formations and/or the oceans) span a wide range, from very small contributions to thousands of gigatonnes of CO2. To a large extent, this wide range is due to the uncertainty of long-term socio-economic, demographic and, in particular, technological changes, which are the main drivers of future CO2 emissions. However, it is important to note that the majority of results for stabilization scenarios of 450–750 ppmv CO2 tend to cluster in a range of 220–2,200 GtCO2 (60–600 GtC) for the cumulative deployment of CCS. For CCS to achieve this economic potential, several hundreds or thousands of CCS systems would be required worldwide over the next century, each capturing some 1–5 MtCO2 per year. As indicated in Section 5, it is likely that the technical potential for geological storage alone is sufficient to cover the high end of the economic potential range for CCS.

Perspectives on CO2 leakage from storage

The policy implications of slow leakage from storage depend on assumptions in the analysis. Studies conducted to address the question of how to deal with impermanent storage are based on different approaches: the value of delaying emissions, cost minimization of a specified mitigation scenario, or allowable future emissions in the context of an assumed stabilization of atmospheric greenhouse gas concentrations. Some of these studies allow future releases to be compensated by additional reductions in emissions; the results depend on assumptions regarding the future cost of reductions, discount rates, the amount of CO2 stored, and the assumed level of stabilization for atmospheric concentrations. In other studies, compensation is not seen as an option because of political and institutional uncertainties and the analysis focuses on limitations set by the assumed stabilization level and the amount stored. While specific results of the range of studies vary with the methods and assumptions made, the outcomes suggest that a fraction retained on the order of 90–99% for 100 years or 60–95% for 500 years could still make such impermanent storage valuable for the mitigation of climate change. All studies imply that, if CCS is to be acceptable as a mitigation measure, there must be an upper limit to the amount of leakage that can take place.

9. Emission inventories and accounting

An important aspect of CO2 capture and storage is the development and application of methods to estimate and report the quantities in which emissions of CO2 (and associated emissions of methane or nitrous oxides) are reduced, avoided, or removed from the atmosphere. The two elements involved here are (1) the actual estimation and reporting of emissions for national greenhouse gas inventories, and (2) accounting for CCS under international agreements to limit net emissions.15

Current framework

Under the UNFCCC, national greenhouse gas emission inventories have traditionally reported emissions for a specific year, and have been prepared on an annual basis or another periodic basis. The IPCC Guidelines (IPCC 1996) and Good Practice Guidance Reports (IPCC 2000; 2003) describe detailed approaches for preparing national inventories that are complete, transparent, documented, assessed for uncertainties, consistent over time, and comparable across countries. The IPCC documents now in use do not specifically include CO2 capture and storage options. However, the IPCC Guidelines are currently undergoing revisions that should provide some guidance when the revisions are published in 2006. The framework that already has been accepted could be applied to CCS systems, although some issues might need revision or expansion.

Issues relevant to accounting and reporting

In the absence of prevailing international agreements, it is not clear whether the various forms of CO2 capture and storage will be treated as reductions in emissions or as removals from the atmosphere. In either case, CCS results in new pools of CO2 that may be subject to physical leakage at some time in the future. Currently, there are no methods available within the UNFCCC framework for monitoring, measuring or accounting for physical leakage from storage sites. However, leakage from well-managed geological storage sites is likely to be small in magnitude and distant in time. Consideration may be given to the creation of a specific category for CCS in the emissions reporting framework but this is not strictly necessary since the quantities of CO2 captured and stored could be reflected in the sector in which the CO2 was produced. CO2 storage in a given location could include CO2 from many different source categories, and even from sources in many different countries. Fugitive

15 In this context, ‘‘estimation’’ is the process of calculating greenhouse gas emissions and ‘‘reporting’’ is the process of providing the estimates to the UNFCCC. ‘‘Accounting’’ refers to the rules for comparing emissions and removals as reported with commitments (IPCC 2003).


emissions from the capture, transport and injection of CO2 to storage can largely be estimated within the existing reporting methods, and emissions associated with the added energy required to operate the CCS systems can be measured and reported within the existing inventory frameworks. Specific consideration may also be required for CCS applied to biomass systems as that application would result in reporting negative emissions, for which there is currently no provision in the reporting framework.

Issues relevant to international agreements

Quantified commitments to limit greenhouse gas emissions and the use of emissions trading, Joint Implementation (JI) or the Clean Development Mechanism (CDM) require clear rules and methods to account for emissions and removals. Because CCS has the potential to move CO2 across traditional accounting boundaries (e.g. CO2 might be captured in one country and stored in another, or captured in one year and partly released from storage in a later year), the rules and methods for accounting may be different than those used in traditional emissions inventories. To date, most of the scientific, technical and political discussions on accounting for stored CO2 have focused on sequestration in the terrestrial biosphere. The history of these negotiations may provide some guidance for the development of accounting methods for CCS. Recognizing the potential

impermanence of CO2 stored in the terrestrial biosphere, the UNFCCC accepted the idea that net emissions can be reduced through biological sinks, but has imposed complex rules for such accounting. CCS is markedly different in many ways from CO2 sequestration in the terrestrial biosphere (see Table TS.12), and the different forms of CCS are markedly different from one another. However, the main goal of accounting is to ensure that CCS activities produce real and quantifiable reductions in net emissions. One tonne of CO2 permanently stored has the same benefit in terms of atmospheric CO2 concentrations as one tonne of CO2 not emitted, but one tonne of CO2 temporarily stored has less benefit. It is generally accepted that this difference should be reflected in any system of accounting for reductions in net greenhouse gas emissions. The IPCC Guidelines (IPCC 1996) and Good Practice Guidance Reports (IPCC 2000; 2003) also contain guidelines for monitoring greenhouse gas emissions. It is not known whether the revised guidelines of the IPCC for CCS can be satisfied by using monitoring techniques, particularly for geological and ocean storage. Several techniques are available for the monitoring and verification of CO2 emissions from geological storage, but they vary in applicability, detection limits and uncertainties. Currently, monitoring for geological storage can take place quantitatively at injection and qualitatively in the reservoir and by measuring surface fluxes of CO2. Ocean storage monitoring can take place by

Table TS.12. Differences in the forms of CCS and biological sinks that might influence the way accounting is conducted.

Property Terrestrial biosphere Deep ocean Geological reservoirs

CO2 sequestered or stored Stock changes can be monitored over time.

Injected carbon can be measured.

Injected carbon can be measured.

Ownership Stocks will have a discrete location and can be associated with an identifiable owner.

Stocks will be mobile and may reside in international waters.

Stocks may reside in reservoirs that cross national or property boundaries and differ from surface boundaries.

Management decisions Storage will be subject to continuing decisions about land-use priorities.

Once injected there are no further human decisions about maintenance once injection has taken place.

Once injection has taken place, human decisions about continued storage involve minimal maintenance, unless storage interferes with resource recovery.

Monitoring Changes in stocks can be monitored.

Changes in stocks will be modelled.

Release of CO2 can be detected by physical monitoring.

Expected retention time Decades, depending on management decisions.

Centuries, depending on depth and location of injection.

Essentially permanent, barring physical disruption of the reservoir.

Physical leakage Losses might occur due to disturbance, climate change, or land-use decisions.

Losses will assuredly occur as an eventual consequence of marine circulation and equili-bration with the atmosphere.

Losses are unlikely except in the case of disruption of the reservoir or the existence of initially undetected leakage pathways.

Liability A discrete land-owner can be identified with the stock of sequestered carbon.

Multiple parties may contribute to the same stock of stored CO2 and the CO2 may reside in international waters.

Multiple parties may contribute to the same stock of stored CO2 that may lie under multiple countries.


detecting the CO2 plume, but not by measuring ocean surface release to the atmosphere. Experiences from monitoring existing CCS projects are still too limited to serve as a basis for conclusions about the physical leakage rates and associated uncertainties. The Kyoto Protocol creates different units of accounting for greenhouse gas emissions, emissions reductions, and emissions sequestered under different compliance mechanisms. ‘Assigned amount units’ (AAUs) describe emissions commitments and apply to emissions trading, ‘certified emission reductions’ (CERs) are used under the CDM, and ‘emission reduction units’ (ERUs) are employed under JI. To date, international negotiations have provided little guidance about methods for calculating and accounting for project-related CO2 reductions from CCS systems (only CERs or ERUs), and it is therefore uncertain how such reductions will be accommodated under the Kyoto Protocol. Some guidance may be given by the methodologies for biological-sink rules. Moreover, current agreements do not deal with cross-border CCS projects. This is particularly important when dealing with cross-border projects involving CO2 capture in an ‘Annex B’ country that is party to the Kyoto Protocol but stored in a country that is not in Annex B or is not bound by the Protocol. Although methods currently available for national emissions inventories can either accommodate CCS systems or be revised to do so, accounting for stored CO2 raises questions about the acceptance and transfer of responsibility for stored emissions. Such issues may be addressed through national and international political processes.

10. Gaps in knowledge

This summary of the gaps in knowledge covers aspects of CCS where increasing knowledge, experience and reducing uncertainty would be important to facilitate decision-making about the large-scale deployment of CCS.

Technologies for capture and storage

Technologies for the capture of CO2 are relatively well understood today based on industrial experience in a variety of applications. Similarly, there are no major technical or knowledge barriers to the adoption of pipeline transport, or to the adoption of geological storage of captured CO2. However, the integration of capture, transport and storage in full-scale projects is needed to gain the knowledge and experience required for a more widespread deployment of CCS technologies. R&D is also needed to improve knowledge of emerging concepts and enabling technologies for CO2 capture that have the potential to significantly reduce the costs of capture for new and existing facilities. More specifically, there are knowledge gaps relating to large coal-

based and natural gas-based power plants with CO2 capture on the order of several hundred megawatts (or several MtCO2). Demonstration of CO2 capture on this scale is needed to establish the reliability and environmental performance of different types of power systems with capture, to reduce the costs of CCS, and to improve confidence in the cost estimates. In addition, large-scale implementation is needed to obtain better estimates of the costs and performance of CCS in industrial processes, such as the cement and steel industries, that are significant sources of CO2 but have little or no experience with CO2 capture. With regard to mineral carbonation technology, a major question is how to exploit the reaction heat in practical designs that can reduce costs and net energy requirements. Experimental facilities at pilot scales are needed to address these gaps. With regard to industrial uses of captured CO2, further study of the net energy and CO2 balance of industrial processes that use the captured CO2 could help to establish a more complete picture of the potential of this option.

Geographical relationship between the sources and storage opportunities of CO2

An improved picture of the proximity of major CO2 sources to suitable storage sites (of all types), and the establishment of cost curves for the capture, transport and storage of CO2, would facilitate decision-making about large-scale deployment of CCS. In this context, detailed regional assessments are required to evaluate how well large CO2 emission sources (both current and future) match suitable storage options that can store the volumes required.

Geological storage capacity and effectiveness

There is a need for improved storage capacity estimates at the global, regional and local levels, and for a better understanding of long-term storage, migration and leakage processes. Addressing the latter issue will require an enhanced ability to monitor and verify the behaviour of geologically stored CO2. The implementation of more pilot and demonstration storage projects in a range of geological, geographical and economic settings would be important to improve our understanding of these issues.

Impacts of ocean storage

Major knowledge gaps that should be filled before the risks and potential for ocean storage can be assessed concern the ecological impact of CO2 in the deep ocean. Studies are needed of the response of biological systems in the deep sea to added CO2, including studies that are longer in duration and larger in scale than those that have been performed until


now. Coupled with this is a need to develop techniques and sensors to detect and monitor CO2 plumes and their biological and geochemical consequences.

Legal and regulatory issues

Current knowledge about the legal and regulatory requirements for implementing CCS on a larger scale is still inadequate. There is no appropriate framework to facilitate the implementation of geological storage and take into account the associated long-term liabilities. Clarification is needed regarding potential legal constraints on storage in the marine environment (ocean or sub-seabed geological storage). Other key knowledge gaps are related to the methodologies for emissions inventories and accounting.

Global contribution of CCS to mitigating climate change

There are several other issues that would help future decision-making about CCS by further improving our understanding of the potential contribution of CCS to the long-term global mitigation and stabilization of greenhouse gas concentrations. These include the potential for transfer and diffusion of CCS technologies, including opportunities for developing countries to exploit CCS, its application to biomass sources of CO2, and the potential interaction between investment in CCS and other mitigation options. Further investigation is warranted into the question of how long CO2 would need to be stored. This issue is related to stabilization pathways and intergenerational aspects.

Chapter 3: Capture of CO2 105

3Capture of CO2

Coordinating Lead AuthorsKelly (Kailai) Thambimuthu (Australia and Canada), Mohammad Soltanieh (Iran), Juan Carlos Abanades (Spain)

Lead AuthorsRodney Allam (United Kingdom), Olav Bolland (Norway), John Davison (United Kingdom), Paul Feron (The Netherlands), Fred Goede (South Africa), Alyce Herrera (Philippines), Masaki Iijima (Japan), Daniël Jansen (The Netherlands), Iosif Leites (Russian Federation), Philippe Mathieu (Belgium), Edward Rubin (United States), Dale Simbeck (United States), Krzysztof Warmuzinski (Poland), Michael Wilkinson (United Kingdom), Robert Williams (United States)

Contributing AuthorsManfred Jaschik (Poland), Anders Lyngfelt (Sweden), Roland Span (Germany), Marek Tanczyk (Poland)

Review EditorsZiad Abu-Ghararah (Saudi Arabia), Tatsuaki Yashima (Japan)

106 IPCC Special Report on Carbon dioxide Capture and Storage

Contents

ExECutivE SummARy 107

3.1 introduction 1083.1.1 The basis for CO2 capture 1083.1.2 CO2 capture systems 1083.1.3 Types of CO2 capture technologies 1093.1.4 Application of CO2 capture 110

3.2 industrial process capture systems 1113.2.1 Introduction 1113.2.2 Natural gas sweetening 1113.2.3 Steel production 1123.2.4 Cement production 1133.2.5 Ammonia production 1133.2.6 Status and outlook 113

3.3 Post-combustion capture systems 1133.3.1 Introduction 1133.3.2 Existing technologies 1143.3.3 Emerging technologies 1183.3.4 Status and outlook 121

3.4 Oxy-fuel combustion capture systems 1223.4.1 Introduction 1223.4.2 Oxy-fuel indirect heating - steam cycle 1223.4.3 Oxy-fuel direct heating - gas turbine cycle 1253.4.4 Oxy-fuel direct heating - steam turbine cycle 1263.4.5 Techniques and improvements in oxygen

production 1273.4.6 Chemical looping combustion 1293.4.7 Status and outlook 130

3.5 Pre-combustion capture systems 1303.5.1 Introduction 1303.5.2 Existing technologies 1303.5.3 Emerging technologies 1363.5.4 Enabling technologies 1383.5.5 Status and outlook 140

3.6 Environmental, monitoring, risk and legal aspects of capture systems 141

3.6.1 Emissions and resource use impacts of CO2 capture systems 141

3.6.2 Issuesrelatedtotheclassificationofcarbon dioxide as a product 145

3.6.3 Health and safety risks associated with carbon dioxide processing 145

3.6.4 Plant design principles and guidelines used by governments,industriesandfinanciers 145

3.6.5 Commissioning, good practice during operations and sound management of chemicals 146

3.6.6 Site closure and remediation 146

3.7 Cost of CO2 capture 1463.7.1 Factors affecting CO2 capture cost 1463.7.2 Measures of CO2 capture cost 1473.7.3 The context for current cost estimates 1493.7.4 Overview of technologies and systems evaluated 1503.7.5 Post-combustion CO2 capture cost for electric

power plants (current technology) 1503.7.6 Pre-combustion CO2 capture cost for electric

power plants (current technology) 1553.7.7 CO2 capture cost for hydrogen production and

multi-product plants (current technology) 1583.7.8 Capture costs for other industrial processes

(current technology) 1613.7.9 Outlook for future CO2 capture costs 1633.7.10 CO2 capture costs for electric power plants

(advanced technology) 1633.7.11 CO2 capture costs for hydrogen production and

multi-product plants (advanced technology) 1663.7.12 CO2 capture costs for other industrial processes

(advanced technology) 1683.7.13 Summary of CO2 capture cost estimates 168

3.8 Gaps in knowledge 170

References 171


ExECutivE SummARy

The purpose of CO2 capture is to produce a concentrated stream that can be readily transported to a CO2 storage site. CO2 capture and storage is most applicable to large, centralized sources like power plants and large industries. Capture technologies also open the way for large-scale production of low-carbon or carbon-free electricity and fuels for transportation, as well as for small-scale or distributed applications. The energy required to operate CO2capturesystemsreducestheoverallefficiencyofpower generation or other processes, leading to increased fuel requirements, solid wastes and environmental impacts relative to the same type of base plant without capture. However, as moreefficientplantswithcapturebecomeavailableandreplacemany of the older less efficient plants now in service, thenet impacts will be compatible with clean air emission goals for fossil fuel use. Minimization of energy requirements for capture,togetherwithimprovementsintheefficiencyofenergyconversion processes will continue to be high priorities for future technology development in order to minimize overall environmental impacts and cost. At present, CO2 is routinely separated at some large industrial plants such as natural gas processing and ammonia production facilities, although these plants remove CO2 to meet process demands and not for storage. CO2 capture also has been applied to several small power plants. However, there have been no applications at large-scale power plants of several hundred megawatts, the major source of current and projected CO2 emissions. There are three main approaches to CO2 capture, for industrial and power plant applications. Post-combustion systems separate CO2fromthefluegasesproducedby combustion of a primary fuel (coal, natural gas, oil or biomass) in air. Oxy-fuel combustion uses oxygen instead of airforcombustion,producingafluegasthatismainlyH2O and CO2 and which is readily captured. This is an option still under development. Pre-combustion systems process the primary fuel in a reactor to produce separate streams of CO2 for storage and H2 which is used as a fuel. Other industrial processes, including processes for the production of low-carbon or carbon-free fuels, employ one or more of these same basic capture methods. The monitoring, risk and legal aspects associated with CO2 capture systems appear to present no new challenges, as they are all elements of long-standing health, safety and environmental control practice in industry. For all of the aforementioned applications, we reviewed recent studies of the performance and cost of commercial or near-commercial technologies, as well as that of newer CO2 capture concepts that are the subject of intense R&D efforts worldwide. For power plants, current commercial CO2 capture systems can reduce CO2 emissions by 80-90% kWh-1 (85-95% capture efficiency). Across all plant types the cost ofelectricity production (COE) increases by 12-36 US$ MWh-1 (US$ 0.012-0.036 kWh-1) over a similar type of plant without capture, corresponding to a 40-85% increase for a supercritical pulverized coal (PC) plant, 35-70% for a natural gas combined cycle(NGCC)plantand20-55%foranintegratedgasification

combined cycle (IGCC) plant using bituminous coal. Overall the COE for fossil fuel plants with capture, ranges from 43-86 US$ MWh-1, with the cost per tonne of CO2 ranging from 11-57 US$/tCO2 captured or 13-74 US$/tCO2 avoided (depending on plant type, size, fuel type and a host of other factors). These costs include CO2 compression but not additional transport and storage costs. NGCC systems typically have a lower COE than new PC and IGCC plants (with or without capture) for gas prices below about 4 US$ GJ-1. Most studies indicate that IGCC plants are slightly more costly without capture and slightly less costly with capture than similarly sized PC plants, but the differences in cost for plants with CO2 capture can vary with coal type and other local factors. The lowest CO2 capture costs (averaging about 12 US$/t CO2 captured or 15 US$/tCO2 avoided) were found for industrial processes such as hydrogen production plants that produce concentrated CO2 streams as part of the current production process; such industrial processes may represent some of the earliest opportunities for CO2 Capture and Storage (CCS). In all cases, CO2 capture costs are highly dependent upon technical, economic and financial factorsrelated to the design and operation of the production process or power system of interest, as well as the design and operation of the CO2 capture technology employed. Thus, comparisons of alternative technologies, or the use of CCS cost estimates, requireaspecificcontexttobemeaningful. New or improved methods of CO2 capture, combined with advanced power systems and industrial process designs, can significantly reduceCO2 capture costs and associated energy requirements. While there is considerable uncertainty about the magnitude and timing of future cost reductions, this assessment suggests that improvements to commercial technologies can reduce CO2 capture costs by at least 20-30% over approximately the next decade, while new technologies under development promise more substantial cost reductions. Realization of future cost reductions, however, will require deployment and adoption of commercial technologies in the marketplace as well as sustained R&D.


3.1 introduction

3.1.1 ThebasisforCO2capture

The main application of CO2 capture is likely to be at large point sources: fossil fuel power plants, fuel processing plants and other industrial plants, particularly for the manufacture of iron, steel, cement and bulk chemicals, as discussed in Chapter 2. Capturing CO2 directly from small and mobile sources in the transportation and residential & commercial building sectors is expectedtobemoredifficultandexpensivethanfromlargepointsources. Small-scale capture is therefore not further discussed in this chapter. An alternative way of avoiding emissions of CO2 from these sources would be by use of energy carriers such as hydrogen or electricity produced in large fossil fuel-based plants with CO2 capture or by using renewable energy sources. Production of hydrogen with CO2 capture is included in this chapter. The possibility of CO2 capture from ambient air (Lackner, 2003) is not discussed in this chapter because the CO2 concentration in ambient air is around 380 ppm, a factor of 100 ormore lower than in flue gas. Capturing CO2 from air by the growth of biomass and its use in industrial plants with CO2 capture is more cost-effective based on foreseeable technologies, and is included in this chapter. In an analysis of possible future scenarios for anthropogenic greenhouse-gas emissions it is implicit that technological innovations will be one of the key factors which determines our future path (Section 2.5.3). Therefore this chapter deals not

only with application of existing technology for CO2 capture, but describes many new processes under development which may result in lower CO2 capture costs in future.

3.1.2 CO2capturesystems

There are four basic systems for capturing CO2 from use of fossil fuels and/or biomass:• Capture from industrial process streams (described in

Section 3.2);• Post-combustion capture (described in Section 3.3);• Oxy-fuel combustion capture (described in Section 3.4); • Pre-combustion capture (described in Section 3.5).

ThesesystemsareshowninsimplifiedforminFigure3.1.

3.1.2.1 Capture from industrial process streamsCO2 has been captured from industrial process streams for 80 years (Kohl and Nielsen, 1997), although most of the CO2 that is captured is vented to the atmosphere because there is no incentive or requirement to store it. Current examples of CO2 capture from process streams are purification of naturalgas and production of hydrogen-containing synthesis gas for the manufacture of ammonia, alcohols and synthetic liquid fuels. Most of the techniques employed for CO2 capture in the examples mentioned are also similar to those used in pre-combustion capture. Other industrial process streams which are a source of CO2 that is not captured include cement and steel production, and fermentation processes for food and drink production. CO2 could be captured from these streams using

Figure 3.1 CO2 capture systems (adapted from BP).


techniques that are common to post-combustion capture, oxy-fuel combustion capture and pre-combustion capture (see below and Section 3.2).

3.1.2.2 Post-combustion captureCapture of CO2 from flue gases produced by combustion offossil fuels and biomass in air is referred to as post-combustion capture. Instead of being discharged directly to the atmosphere, fluegasispassedthroughequipmentwhichseparatesmostofthe CO2. The CO2 is fed to a storage reservoir and the remaining fluegas is discharged to the atmosphere.A chemical sorbentprocess as described in Section 3.1.3.1 would normally be used for CO2 separation. Other techniques are also being considered but these are not at such an advanced stage of development. Besides industrial applications, the main systems of reference for post-combustion capture are the current installed capacity of 2261 GWe of oil, coal and natural gas power plants (IEA WEO, 2004) and in particular, 155 GWe of supercritical pulverizedcoalfiredplants(IEACCC,2005)and339GWe of natural gas combined cycle (NGCC) plants, both representing thetypesofhighefficiencypowerplanttechnologywhereCO2 capture can be best applied (see Sections 3.3 and 3.7).

3.1.2.3 Oxy-fuel combustion captureIn oxy-fuel combustion, nearly pure oxygen is used for combustioninsteadofair,resultinginafluegasthatismainlyCO2 and H2O. If fuel is burnt in pure oxygen, the flametemperature is excessively high, but CO2 and/or H2O-rich flue gas can be recycled to the combustor to moderate this.Oxygen is usually produced by low temperature (cryogenic) air separation and novel techniques to supply oxygen to the fuel, such as membranes and chemical looping cycles are being developed. The power plant systems of reference for oxy-fuel combustion capture systems are the same as those noted above for post-combustion capture systems.

3.1.2.4 Pre-combustion capturePre-combustion capture involves reacting a fuel with oxygen or air and/or steam to give mainly a ‘synthesis gas (syngas)’ or ‘fuel gas’ composed of carbon monoxide and hydrogen. The carbon monoxide is reacted with steam in a catalytic reactor, called a shift converter, to give CO2 and more hydrogen. CO2 is then separated, usually by a physical or chemical absorption process, resulting in a hydrogen-rich fuel which can be used in many applications, such as boilers, furnaces, gas turbines, engines and fuel cells. These systems are considered to be strategically important (see Section 3.5) but the power plant systems of reference today are 4 GWe of both oil and coal-based, integrated gasification combined cycles (IGCC) which arearound 0.1% of total installed capacity worldwide (3719 GWe; IEA WEO, 2004). Other reference systems for the application of pre-combustion capture include substantially more capacity thanthatidentifiedaboveforIGCCinexistingnaturalgas,oiland coal-based syngas/hydrogen production facilities and other types of industrial systems described in more detail in Sections 3.2 and 3.5.

3.1.3 TypesofCO2capturetechnologies

CO2 capture systems use many of the known technologies for gas separation which are integrated into the basic systems for CO2captureidentifiedinthelastsection.Asummaryoftheseseparation methods is given below while further details are available in standard textbooks.

3.1.3.1 Separation with sorbents/solventsThe separation is achieved by passing the CO2-containing gas in intimate contact with a liquid absorbent or solid sorbent that is capable of capturing the CO2. In the general scheme of Figure 3.2a, the sorbent loaded with the captured CO2 is transported to a different vessel, where it releases the CO2 (regeneration) after being heated, after a pressure decrease or after any other change in the conditions around the sorbent. The sorbent resulting after the regeneration step is sent back to capture more CO2 in a cyclic process. In some variants of this scheme the sorbent is a solid and does not circulate between vessels because the sorption and regeneration are achieved by cyclic changes (in pressure or temperature) in the vessel where the sorbent is contained. A make-upflowoffreshsorbentisalwaysrequiredtocompensatefor the natural decay of activity and/or sorbent losses. In some situations, the sorbent may be a solid oxide which reacts in a vessel with fossil fuel or biomass producing heat and mainly CO2 (see Section 3.4.6). The spent sorbent is then circulated to a second vessel where it is re-oxidized in air for reuse with some loss and make up of fresh sorbent. The general scheme of Figure 3.2 governs many important CO2 capture systems, including leading commercial options like chemical absorption and physical absorption and adsorption. Other emerging processes based on new liquid sorbents, or new solid regenerable sorbents are being developed with the aim of overcoming the limitations of the existing systems. One common problem of these CO2 capture systems is that theflowofsorbentbetweenthevesselsofFigure3.2aislargebecauseithastomatchthehugeflowofCO2 being processed in the power plant. Therefore, equipment sizes and the energy required for sorbent regeneration are large and tend to translate into an important efficiencypenalty and added cost.Also, insystems using expensive sorbent materials there is always a danger of escalating cost related to the purchase of the sorbent and the disposal of sorbent residues. Good sorbent performance under high CO2 loading in many repetitive cycles is obviously a necessary condition in these CO2 capture systems.

3.1.3.2 Separation with membranesMembranes (Figure 3.2b) are specially manufactured materials that allow the selective permeation of a gas through them. The selectivity of the membrane to different gases is intimately relatedtothenatureofthematerial,buttheflowofgasthroughthe membrane is usually driven by the pressure difference across the membrane. Therefore, high-pressure streams are usually preferred for membrane separation. There are many different types of membrane materials (polymeric, metallic, ceramic) thatmayfindapplication inCO2 capture systems to


preferentially separate H2 from a fuel gas stream, CO2 from a range of process streams or O2 from air with the separated O2 subsequently aiding the production of a highly concentrated CO2stream.Althoughmembraneseparationfindsmanycurrentcommercial applications in industry (some of a large scale, like CO2 separation from natural gas) they have not yet been applied for the large scale and demanding conditions in terms of reliability and low-cost required for CO2 capture systems. A large worldwide R&D effort is in progress aimed at the manufacture of more suitable membrane materials for CO2 capture in large-scale applications.

3.1.3.3 Distillationofaliquefiedgasstreamandrefrigerated separation

A gas can be made liquid by a series of compression, cooling and expansion steps. Once in liquid form, the components of the gas can be separated in a distillation column. In the case of air, this operation is currently carried out commercially on a large scale. Oxygen can be separated from air following the scheme of Figure 3.2c and be used in a range of CO2 capture systems (oxy-fuel combustion and pre-combustion capture). As in the previous paragraphs, the key issue for these systems is

thelargeflowofoxygenrequired.Refrigeratedseparationcanalso be used to separate CO2 from other gases. It can be used to separate impurities from relatively high purity CO2 streams, for example, from oxy-fuel combustion and for CO2 removal from natural gas or synthesis gas that has undergone a shift conversion of CO to CO2.

3.1.4 ApplicationofCO2capture

The CO2 capture systems shown in Figure 3.1 can be cross-referenced with the different separation technologies of Figure 3.2, resulting in a capture toolbox. Table 3.1 gives an overview of both current and emerging technologies in this toolbox. In the next sections of this chapter a more detailed description of all these technological options will be given, with more emphasis on the most developed technologies for which the CO2 capture cost can be estimated most reliably. These leading commercial options are shown in bold in Table 3.1. An overview of the diverse range of emerging options being investigated worldwide for CO2 capture applications will also be provided. All of these optionsareaimedatmoreefficientandlowercostCO2-capture systems (compared with the leading options). It is important

Figure 3.2 General schemes of the main separation processes relevant for CO2 capture. The gas removed in the separation may be CO2, H2 or O2. In Figures 3.2b and 3.2c one of the separated gas streams (A and B) is a concentrated stream of CO2, H2 or O2 and the other is a gas stream with all the remaining gases in the original gas (A+B).


to understand that this wide variety of approaches for CO2 capturewill tend to settlewith time as the expected benefits(and potential weaknesses) in the technological portfolio of Table 3.1 becomes obvious with new results from current and future research and demonstration projects. Only a few of these options will prove truly cost-effective in the medium to long term. CO2 capture may be installed in new energy utilization plantsor itmaybe retrofitted toexistingplants. Inprinciple,if CO2 capture is to be introduced rapidly, it may have to be retrofittedtosomeexistingplantsortheseplantswouldhavetobe retired prematurely and replaced by new plants with capture. Disadvantagesofretrofitsare:• There may be site constraints such as availability of land for

the capture equipment; • A long remaining plant life may be needed to justify the

large expense of installing capture equipment;• Oldplantstendtohavelowenergyefficiencies.Including

CO2 capture will have a proportionally greater impact on the netoutputthaninhighefficiencyplants.

To minimize the site constraints, new energy utilization plants could be built ‘capture-ready’, that is with the process design initially factoring in the changes necessary to add capture and with sufficient space and facilitiesmade available for simpleinstallation of CO2 capture at a later date. For some types of captureretrofit,forexamplepre-combustioncaptureandoxy-fuelcombustion,muchoftheretrofitequipmentcouldbebuilton a separate site if necessary. The other barriers could be largely overcome by upgrading or substantially rebuilding the existing plant when capture is retrofitted.Forexample,oldinefficientboilersandsteamturbinescould be replaced by modern, high-efficiency supercriticalboilers and turbines or IGCC plants. As the efficiencies ofpowergenerationtechnologiesareincreasing,theefficiencyoftheretrofittedplantwithCO2 capture could be as high as that of the original plant without capture.

3.2 industrial process capture systems

3.2.1 Introduction

There are several industrial applications involving process streams where the opportunity exists to capture CO2 in large quantities and at costs lower than from the systems described in the rest of this chapter. Capture from these sources will not be the complete answer to the needs of climate change, since the volumes of combustion-generated CO2 are much higher, butitmaywellbetheplacewherethefirstcaptureandstorageoccurs.

3.2.2 Naturalgassweetening

Natural gas contains different concentration levels of CO2, depending on its source, which must be removed. Often pipeline specificationsrequirethattheCO2 concentration be lowered to ta

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