1

The Economics of CO2 and Mixed Gas Geo-

sequestration of Flue Gas Using Gas Separation

Membranes

Minh T. Ho1, 3, Dianne E. Wiley1, 3*, Guy Allinson2, 3 and Greg Leamon2, 3

1.UNESCO Centre for Membrane Science and Technology, The University of New South Wales,

Australia

2.School of Petroleum Engineering, The University of New South Wales, Australia

3.Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC)

* D.Wiley@unsw.edu.au

ABSTRACT

Greenhouse gas emission sources generally produce mixed gases. Previous studies of CO2 capture and

storage have typically examined only sequestration of pure CO2. This paper analyses the cost of

separating a gas mixture from a power station flue gas stream and injecting it into an offshore sub-

surface reservoir. The costs of separating and storing various gas mixtures were analysed at two

extremes. One extreme in which the entire flue gas stream containing both CO2 and N2 is stored. The

other extreme in which as much CO2 is separated as is technically possible using gas membrane capture

coupled with chemical absorption. The results indicate that for the gases investigated, using a gas

2

membrane capture system, the lowest sequestration cost per tonne of CO2 avoided occurs when a mixed

gas with a CO2 content of about 60% is sequestered. Lower costs and higher tonnages of CO2 avoided

can be achieved using an amine based absorption capture system. At the lowest cost point, and for most

of the range of cases studied, the cost of capture is significantly greater than the cost of storage.

However, this depends on the source of the CO2, the distance between the source and the injection site

and the reservoir into which CO2 is injected.

KEYWORDS: CO2 capture, CO2 storage, Economics, Membranes, Mix gases

INTRODUCTION

Growing international concerns over the rising levels of atmospheric CO2 emissions and the resulting

environmental and economic impacts present a challenge to industrial point sources of CO2 to stabilise

these emission levels. One mitigation approach proposed is to capture the CO2 emissions and sequester

the CO2 into geological formations1. Since 1992, there have been several international studies

investigating the cost of CO2 capture and subsequent storage 2-11. These studies examined the cost of

separating the CO2 from a range of power plant flue gases using CO2 separation technologies such as

chemical and physical absorption. The objective of these studies was to examine the economic

feasibility and cost implications of sequestering CO2 in geological formations as a greenhouse gas

mitigation option. Of the nine studies, only two examined the recovery of CO2 from flue gas using gas

separation membranes 5-6 and these studies focused on the capture and sub-surface storage of a pure

stream of CO2. However, the stream of CO2 recovered using gas separation membranes is generally not

pure CO2 but rather a stream of mixed gases enriched with CO2.

Only a few studies12-14 have investigated the costs of storing other gases in conjunction with CO2. The

objective of these studies however was to explore if geological storage of CO2 could also include other

environmentally toxic gases such as NOx and SO2 rather than the component gases of the flue gas

3

stream such as nitrogen or oxygen. In our previous work, it was demonstrated that storage of mixed

gases is more expensive than storage of pure CO2. This is because larger volumes for mixed gases

require larger pipelines and larger compressors14.

The aim of this study is to investigate if there exists an optimum gas mixture for recovered CO2 using

gas separation membranes, for which the combined cost of capture and storage is the lowest. This study

reports the results of a conceptual study investigating the recovery of CO2 from a flue gas stream of a

typical Australian pulverised black coal fired power station and then injecting it into an offshore

geological storage site. The cost estimates rely on computerised engineering and economic models for

CO2 capture and storage developed especially for Australian conditions14. These models enable

estimation of the costs of CO2 and mixed gas capture and storage given any stationary source and sink

combination in Australia.

CONCEPT

Throughout this paper ‘ CO2 capture’ is defined as the extraction of one or more gases from a mixed

feed gas stream, and ‘storage’ encompasses the initial compression, transport and injection of one or

more gases into a sub-surface reservoir. Depending on the location of the selected injection site, several

additional compression stages may be required for transport. The whole process is defined as CO2

capture and storage (CCS) as shown in Figure 1.

The conceptual basis for the analysis in this study is shown in Figure 2. The first option shown in

Figure 2 (‘Option A’), assumes that all of the flue gas (CO2 plus other gases) emitted from the source is

stored. The feed gas, is compressed, transported and then injected into the sub-surface. Thus, there is

no separation of the flue gas. This is one extreme of the range of options examined. ‘Option B’ in

Figure 2 shows the other extreme, where 95% of the CO2 from the inlet feed gas is recovered and a gas

4

stream of pure CO2 is compressed, transported and injected. Other options between the two extremes

are also examined in which varying portions of CO2 and other gases are separated and stored.

In this study, it was assumed that the power requirement needed for the CO2 separation process and

compression stages is provided from a supplementary power supply. This approach was taken rather

than assuming that the base power plant and source of CO2 parasitically provided energy for the capture

and storage process. This was done to ensure that the output from the power plant was maintained to

the grid, and that alternative sources of energy could be investigated as a power source to the capture

and storage process.

A standard assumption made purely for the purposes of this study is that the “auxiliary” energy will

come from a new natural gas combined cycle power plant (‘NGCC’). This is because an NGCC plant

has lower CO2 emissions than fossil fuel energy sources such as black or brown coal. The CO2

emissions from the NGCC power plant are fixed at 0.4 kg CO2 per kWh15. In practice, whether a new or

existing power plant is used for supplementary power and what type of energy it uses will depend on

the particular circumstances and location of the actual CCS scheme. While the choice of the auxiliary

energy source will change the absolute costs of CCS, it does not affect significantly the relative costs of

the different options considered here.

Because the concentrations of CO2 in NGCC flue gases are lower, we assume that such CO2

emissions are vented to the atmosphere and not captured. Therefore, they contribute to the total CO2

emissions of the system. The net tonnes of CO2 avoided is the difference between the tonnes of CO2

stored and the tonnes of CO2 emitted after capture. The percent CO2 avoided is calculated as:

2 22

2

CO captured - CO emitted from supplementary power% CO avoided =

CO original emission from source (1)

5

The amount of recovered CO2 is the same as that stored in the subsurface.

THE CASE STUDY

We base our analysis on a 14-mole/volume % CO2 and 86 mole/volume % N2 feed gas mixture. This

is close to the typical flue gas composition of 14% CO2, 81% N2 and 5% O2 for an Australian black

coal fired power plant assuming that the gas has been dehydrated and that all of the SOx and NOx has

been removed 6. For simplicity, we ignore the small amount of O2. The feed gas flow rate is taken as 5

million tonnes per year, containing 1 million tonnes per year of CO2 and 4 million tonnes of N2 on a

mass basis. The inlet feed gas pressure is assumed to be atmospheric with an inlet temperature of 93oC

5.

CO2 CAPTURE USING GAS SEPARATION MEMBRANES AND CHEMICAL ABSORPTION

For the CO2 capture process, we investigate the use of gas separation membrane technology, coupled

in some instances with chemical absorption. This allows us to model the capture of a wide range of gas

mixtures with varying proportions of CO2 and other gases. The performance of gas separation

membranes relies on the fact that different components in the gas mixture interact differently with the

membrane material. One component in the flue gas (for instance, CO2) dissolves preferentially into the

membrane and diffuses through it, giving the "product stream" or the "permeate". Other gases also

diffuse through the membrane and become part of the permeate, but they do so to a lesser extent. The

portion of CO2 in the permeate is referred to as its "purity".

The gases that do not diffuse through the membrane are considered waste gases in this study and are

emitted to the atmosphere. These include the CO2 that does not permeate through the membrane. The

waste gases therefore contain both CO2 and other gases.

6

The extent of capture of the different components is governed partly by the selectivity of the

membrane. A high selectivity for CO2 gives a higher concentration of CO2 in the permeate. However,

as selectivity increases, the permeability usually becomes lower and the rate of flow through the

membrane decreases6. A compromise between producing a high purity stream and sufficient flow rate

is required.

To enable us to estimate the cost of storage for a range of CO2 gas mixtures, we use both a one-stage

membrane layout and a two-stage membrane layout for the separation process16.

The single one-stage membrane layout (Single Membrane System - "SMS") shown in Figure 3 is the

simplest. It comprises of only the flue (feed) gas compressor and the membrane, which incorporates

both the membrane housing pipe work and the membrane fibres. The permeate from this layout is the

mixed gas stream to be compressed for pipeline transport and geological storage. In practice, SMS

layouts consist of many physical membrane modules operating in parallel. Conceptually, however,

these modules operate as a single unit or stage and are modelled and costed as a single stage.

One of the consequences of using gas separation membranes is that the permeate stream contains

other component gases such as N2 as well as the desired CO2. To increase the concentration of CO2 in

the gas stream sent to storage, the rich CO2 stream from the first membrane can be recompressed and

then passed through a second membrane. This layout is referred to as a two-stage cascade membrane

system (TCMS) as shown in Figure 4. The TCMS layout incorporates a feed gas compressor, an

intermediate compressor and two membrane stages. The permeate from the second membrane is the

mixed gas stream to be compressed for transport and storage.

The TCMS yields low volumes of high purity CO2 while the SMS yields high volumes of low purity

CO2. With these two membrane layouts, and using a polymer-based membrane, a mixed gas stream

7

with a CO2 content ranging from 30% to 95% can be obtained. Higher concentrations of CO2 (almost

100% CO2) can be achieved using chemical absorption as a stand-alone system or in combination with

gas separation membranes.

The capture of CO2 by gas separation membranes is modelled using the numeric cross flow

permeation model described by Shindo et al17. For this study, the properties of a polymer based

polyphenyleneoxide hollow fibre membrane with a CO2/N2 selectivity of 20 and a CO2 permeability of

72 Barrer, and a membrane thickness of 0.125 µm were used. The operating conditions for the

membrane systems are listed in Table 14-5.

In this paper we also compare the costs of the membrane systems with a monoethanolamine (MEA)

chemical absorption process. The MEA system typically removes 75-90% of the CO2 from the feed gas

and produces a near pure (>99%) CO2 product stream [9]. The capture of CO2 by chemical absorption

is modelled using fundamental mass and energy balances as well as empirical relationships as described

by Mariz18-20. The key conditions assumed for the amine chemical absorption process are listed in Table

2.

TRANSPORT AND STORAGE

Earlier work by Geoscience Australia has shown that over 60 geological sites in Australia are suitable

for geological storage of CO2 20. For the purposes of this study, we assume that the storage site is

located offshore and transport of the gas to the site will be by both land and seabed pipelines, as well as

offshore platforms hosting injection wells and ancillary equipment. As part of the process scheme, the

gas stream is first compressed to between 1,250 and 2,500 psi (86 to 172 bar). At these pressures, the

CO2 is in a supercritical state, giving a reduced volume ready for transport. In our example,

recompression is required at the junction of the onshore and offshore pipelines. The gas is then piped

8

to an offshore platform in 60 m of water, from where the gas is injected into a sandstone reservoir at a

depth of some 2,000 m below sea level. Table 3 lists our main assumptions for the storage operation.

The cost outputs of the economic model for Australian CO2 storage depend on both the conditions of

the selected reservoir and distance between the CO2 source and storage site. This storage site was

selected due to its proximity to nearby Eastern Australian CO2 sources such as power generators and

industrial plants and its large capacity. Details of the processing assumptions and calculations for the

storage economic model are presented in Allinson et al 22.

COST ESTIMATES

Estimates of the cost of equipment items were obtained mainly from equipment vendors, publications

and industry contacts10, 19-20, 24. The breakdown of total capital costs, and operating costs is based on

chemical engineering estimating procedures25. The membrane costs are based on the procedure

described by van der Sluijs et al.26. All cost estimates are in US$ in the year 2004.

Other economic assumptions are consistent with those of Allinson & Nguyen14 and Hendriks6 and are

listed in Table 4.

The real cost of CO2 capture and storage in US$ per tonne of CO2 avoided is estimated as:

ni i

ii = 1

2 n2 i

ii = 1

K O(1 )

Cost of CO avoided = (CO avoided)

(1 )

d

d

++

+

∑

∑

(2)

where Ki and Oi are the real capital and operating costs (US$ million) in ith year, d is the discount

rate (% pa) and CO2 avoided is the annual amount of CO2 avoided in million tonnes.

9

We assume that storage operating costs for storage are sufficient to cover the costs of monitoring the

CO2 storage system. Monitoring activities involve seismic surveys, well logging and reservoir analysis.

RESULTS

The costs shown in this paper are for a hypothetical mixed gas stream comprising 1 MM tonnes of

CO2 and 4 MM tonnes of other gases. Scaling these volumes up or down would yield different absolute

costs. In particular, because of economies of scale, larger volumes would, in general, lower the cost per

tonne avoided for both capture and storage. For instance, the costs of storage would fall significantly

compared to the costs shown here. However, this feature of the analysis does not alter our main

conclusions, which are based on the relative movements in costs per tonne avoided as we change the

gas composition of the output of the capture process.

Purity

The relationships between the rate of CO2 recovered from the feed gas, the total amount of CO2

avoided and purity of the product obtained using the SMS and TCMS layouts for gas separation

membranes is shown in Figure 5. The results show that the different layouts produce vastly different

product purities (around 30%) at similar levels of CO2 recovery and CO2 avoided. The TCMS layout is

more suited to applications where a high product purity of CO2 is required. Using the TCMS layout,

CO2 purities of greater than 65% are obtained with CO2 recoveries of 60% – 90%. However, to achieve

even higher levels of CO2 purity in the permeate (greater than 90%), the corresponding CO2 recovery

from the feed gas would be less than 75%. In contrast, the SMS layout yields higher removal

efficiencies, but lower product purity. To recover 70% – 90% of the CO2 from the feed gas using the

SMS layout, the purity of the enriched CO2 permeate is only 30% to 60%.

Costs of SMS and TCMS compared

10

Figure 6 shows the capture, storage and total costs of sequestering streams of CO2 enriched mixed

gases. The capture costs are shown for both gas separation membrane layouts, SMS and TCMS.

Because the two layouts generate permeates with vastly different CO2 purity levels there is a difference

in the costs for both storage and capture for the two systems. Although the total costs for both layouts

are similar, the results in Figure 6 show that the SMS has a lower capture cost than the TCMS layout.

Feron5 also showed in his work on CO2 capture from flue gas that the SMS layout has the lowest

compression costs, membrane area requirement, and operating costs of different membrane layouts.

From Figures 3 and 4, the TCMS layout contains an additional compressor compared to that of the

SMS, as well as an extra membrane stage. These extra equipment components add to the total capital

costs and hence the capture cost for the TCMS layout.

However, the storage cost for the SMS layout is higher than for the TCMS layout at all rates of CO2

recovery and CO2 avoided studied. This occurs because the product stream contains a lower volume

percentage of CO2 than for the TCMS layout. Figure 5 shows that at equivalent amounts of CO2

avoided, the quantity of N2 to be stored along with the CO2 is also considerably higher in the SMS

layout than in the TCMS layout. The larger volume to be stored increases the size of the transport

pipeline and storage compressors required, resulting in higher capital and hence storage costs.

Interestingly, for both membrane systems the total capture plus storage cost is similar, regardless of

the differences in the capture and storage costs. The total costs are influenced by many factors

including the properties of the site selected for storage, the distance between the source and storage, and

the processing and economic assumptions. Further study investigating the total end-to-end costs using

different membranes, with different processing and economic assumptions, needs to be undertaken to

confirm the effect of the layouts on the total capture and storage cost.

Economies of scale

11

The results in Figure 6 show that, for low amounts of CO2 avoided and hence low CO2 removal rates

(below 0.5 million tonnes), the total cost is dominated by the capture component. With increasing CO2

recovery rates and CO2 avoided, the capital cost increases due to an increase in the membrane area

required for separation. For membrane capture systems, the cost of the compressors needed for feed gas

compression dominates the capital costs, which can account for up to 80% of the total capital cost6.

This is confirmed in Figure 7 where the capital and operational breakdown using a SMS for 80% CO2

recovery is shown. The dominant capital cost components are the compressor and expanders (60%),

with the membrane cost making up less than 10% of the total. Since the membrane cost is only a small

proportion of the total capital cost, and the tonnage of CO2 sequestered changes by significantly more

than the change in capital cost, the overall capture cost per tonne of CO2 avoided decreases as the

amount of CO2 avoided increases. In other words, there are economies of scale, which result in a

decrease in the cost of capture per tonne of CO2 avoided.

Costs of storage

At low values of CO2 avoided, less than 0.5 million tonnes of CO2 avoided, the cost of storage

remains relatively low and constant. This is because as seen in Figure 5, at these rates of CO2 avoided

the percentage of CO2 in the product stream is relatively high. The purity of CO2 in the enriched stream

to be stored is greater than 55% in the SMS and greater than 80% in the TCMS. For the SMS layout,

the storage cost increases by 10% at 0.55 million tonnes CO2 avoided compared to the cost at 0.5

million tonnes of CO2 avoided. This is because at a CO2 avoided of 0.55 million tonnes, the purity of

the CO2 is less than 50% in the permeate. The larger gas volume of the stream requires significantly

more compression adding to both the capital and operating costs. Therefore, for mixed gases

containing less than 50% of CO2 by volume, the high cost of compression and storage makes

geosequestration costly.

Costs of capture and storage - the extremes

12

Figure 8 shows how the total costs of capture and storage vary as the mass of CO2 avoided increases

for the SMS gas separation membranes, chemical absorption, no capture (option A in Figure 2) and for

95% recovery of CO2 as in Option B of Figure 2.

The "no capture" option sequesters the entire flue gas stream – 1 million tonnes of CO2 plus 4 million

tonnes of N2. However, the power required to compress and transport such large volumes of gas

generates a large amount of CO2 (approximately 0.5 million tonnes). Therefore, the total CO2 avoided is

only 0.5 million tonnes per annum (50% of the CO2 in the flue gas). In sum, the "no capture" process is

able to store very large volumes of CO2 but only a modest level of CO2 avoided is achieved and the cost

per tonne of CO2 avoided is also very high12.

At the other end of the spectrum, with “95% recovery”, almost all of the CO2 is separated using a

combination of membranes and MEA chemical absorption prior to storage. In this option, 0.95 million

tonnes of CO2 and no N2 is sequestered. However, again large amounts of CO2 are generated: - 0.55

million tonnes of CO2 per annum from the multi-unit capture system and 0.05 million tonnes from the

storage system. Therefore, the amount of CO2 avoided is only of the order of 0.4 million tonnes (40%

CO2 avoided) and the costs per tonne of CO2 avoided are high.

Thus, both of the ‘extremes’ where all the CO2 in the flue gas stream is geologically stored are very

costly and yield very low rates of CO2 avoided. The two extremes store a large amount of CO2, but

with significant disadvantages.

Costs of capture and storage - the optimum

In Figure 8, the lowest total cost using a membrane capture system occurs at 0.55-0.6 million tonnes

CO2 avoided. As shown in Figure 5, at this point the amount of CO2 sequestered is also at a maximum;

for this study - 90% of the feed gas CO2 is recovered storing 0.9 million tonnes of CO2 per year. To

13

power the capture and storage facilities, 0.3 million tonnes of CO2 is emitted from the auxiliary power

supplies for capture and storage. This gives a maximum CO2 avoided of 0.6 million tonnes (60% of the

CO2 in the flue gas stream). For the membrane system considered in this study, to be able to increase

the avoidance value beyond 60% would require using an auxiliary power supply with lower emission

rates, and/or processing equipment with higher operating efficiency.

Membranes vs MEA

The costs of CO2 mitigation utilising MEA is also shown in Figure 8. In comparison to the membrane

system, this process yields approximately 0.75 million tonnes of CO2 avoided (75% of the CO2 in the

flue gas stream) at a maximum CO2 recovery of 90%. This compares with 0.60 million tonnes of CO2

avoided for the optimum membrane system.

The capture cost of the amine based chemical absorption system is lower than for the membrane

system for most CO2 avoided rates. This is because the large costs of the compressors in the membrane

system make it the capital and operating costs greater than the MEA system. In this study, the cost to

power the compressors is approximately 40% of the total operating cost (Figure 7). Other investigations

have reported energy consumption of MEA systems to be between 20-30% of the operating costs [9-

11].

In addition, the storage costs for the MEA system are substantially lower than for the membrane

system. This is because the stored gas produced by the absorption system is a small volume of highly

purified CO2. Allinson and Nguyen14 showed previously that the storage of pure CO2 is considerably

less than mixed gas storage. The effect is that the total cost of sequestering a relatively pure stream of

CO2 generated by MEA chemical absorption is less costly than sequestration of a mixed gas product

stream produced using gas separation membranes.

14

COMPARISON WITH OTHER STUDIES

Though there are numerous published studies examining the economics of capture and storage of

post-combustion CO2 from coal-fired power plants, very few studies have examined the total costs of

end-to-end capture and storage costs for specific cases. The study by Dave et al3 is the only specific

study of CO2 capture and storage for Australian conditions. The capture costs from this paper using gas

separation membranes and MEA chemical absorption will be compared to those of Hendriks6 and the

International Energy Agency’s5 as these studies have investigated capture cost using both membranes

and chemical absorption.

Figure 9 compares the capture costs in terms of US $/tonne CO2 avoided for a CO2 recovery rate of

80%. For the gas separation membranes, the results show that the reported capture cost for the IEA

study of $45/tonne CO2 avoided is lower than this study, even though similar conditions were used.

This difference is because the IEA study only considered the change in CO2 emissions at the power

plant without including any additional power losses that may be incurred for the transportation and

storage. In this study, for a CO2 recovery rate of 80%, the CO2 avoided due to power losses in the

capture plant is approximately 76% for the SMS and 70% for the MEA system, the rest of the power

loss being for compression, transportation and storage. If this additional power loss is taken into

account, the amount of CO2 avoided is much lower than for the capture plant alone. If transport and

storage power losses were taken into account for the IEA study, the capture cost would increase to

$53/tonne CO2 avoided for the membrane system. Alternatively, if the power losses for transport and

storage were neglected in this study, the capture cost decreases to $47/tonne CO2 avoided. The rest of

the difference is the result of differences in economic assumptions such as operating capacity, and cost

for power.

In comparison, the capture costs for the membrane system studied by Hendriks6 includes some of the

costs for CO2 transport and compression to 80 bar and accounts for the additional power consumption

15

due to the compression. This compression cost however does not take into account the full

transportation and associated storage costs.

These three studies have been conducted at different levels of complexity, and due to the different

economic assumptions used such as discount rates, plant capacity and choice of transport costs, the

absolute costs are not directly comparable. Further study into the effect of different accounting

methodologies, and the effect of processing and economic assumptions on the capture and storage costs

is required.

CONCLUSION

Sequestration of CO2 from stationary source emitters can be applied either with no capture of any

gases from the feed gas stream), or it can include varying degrees of CO2 capture. The results in this

paper indicate that storage of an entire flue gas stream, where CO2 comprises only a small proportion of

the total mass/volume is not as economically attractive as some form of separation to increase the

concentration of CO2 in the gas prior to storage. Similarly, at the other extreme for 95% CO2 recovery,

the cost for capture is also prohibitive.

For the gas separation membrane cases studied, the lowest cost of capture and storage occurs when

approximately 60% of the CO2 is avoided. In comparison, an amine based absorption capture system is

able to achieve a higher rate of 70% CO2 avoided at an even lower cost. The results suggest that at the

lowest cost point and over most of the range of cases studied here, the cost of capture is significantly

greater than the cost of storage. However, in practice this would depend on the source of the CO2, the

distance between the source and the injection site and the reservoir into which the CO2 is injected.

ACKNOWLEDGMENTS. This research was supported by the Australian Cooperation Research

Centre for Greenhouse Gas Technologies (CO2CRC).

16

17

LIST OF FIGURES AND TABLES

- Figure 1 Process scheme for CO2 capture and storage (CCS).

- Figure 2 Capture and storage options for CO2 mitigation.

- Figure 3 Single-stage membrane system (SMS).

- Figure 4 Two-stage cascade membrane system (TCMS).

- Figure 5 CO2 avoided as a function of the percentage of CO2 in the product for both the

SMS and TCMS layouts.

- Figure 6 The capture, storage and total cost using gas separation membranes, SMS and

TCMS.

- Figure 7 The total capital and annualised operating costs for a SMS recovering 80% CO2.

- Figure 8 The behaviour of cost for capture and storage, as a function of CO2 avoided for gas

separation membranes, MEA absorption, no ‘capture’, and maximum capture (95% CO2

recovered).

- Figure 9 Comparison of CO2 capture costs for gas separation membranes and MEA

• Table 1 The operating conditions for both SMS and TCMS layouts.

• Table 2 The operating conditions for MEA chemical absorption system.

• Table 3 Summary of inputs for the storage model.

• Table 4 Summary of economic inputs for the capture and storage models.

18

Capture Unit

Onshore pipeline

Offshore pipeline

Source

Compression

Injection

Figure 1 Process scheme for CO2 capture and storage (CCS).

19

Generate 0.5

MM tonne CO2

1 MM tonne

CO2

4 MM tonnes other gases

Source

1 MM tonne

CO2

4 MM tonnes other gases

Option A: No Capture

Capture Storage

1 MMtonne

CO2

Emit

0.05 MMtonne CO2

4 MMtonnes other gas

Generate 0.04 MM

tonne CO2

0.95 MMtonne

CO2

4 MM tonnes other gases

Option B: 95% Capture

Source

Storage

Figure 2 Capture and storage options for CO2 mitigation.

20

ExpanderFeed stream:

MembraneHeat Exchanger Compressor

Retentate waste stream:

N2, CO2

N2, CO2

Permeate:

N2, CO2

Figure 3 Single-stage membrane system (SMS).

21

Sequestered stream: CO2, N2 (permeate)

Waste stream: N2, CO2

Membrane

Compressor

Heat Exchanger Compressor

Feed stream: CO2, N2

Membrane

Expander

Figure 4Two-stage cascade membrane system (TCMS).

22

20%

40%

60%

80%

100%

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7

CO2 avoided (million tonnes/year)

CO

2 %

in p

rodu

ct

60% CO2 recovery 90%

0.04

N2 stored (million tonnes)

0.25

0.25

N2 stored (million tonnes)

0.99

60% CO2 recovery 90%

TCMS

SMS

Figure 5 CO2 avoided as a function of the percentage of CO2 in the product for both the SMS (▬) and

TCMS (- - -) layouts.

23

0

50

100

150

200

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7

CO2 avoided (million tonnes/year)

Cos

t ($/

tonn

e C

O2

avoi

ded)

30% 40% 50% 60% 70% 80% 90% 100%

CO2 recovery (%)

Storage

Capture

Total

Figure 6 The capture, storage and total cost using gas separation membranes, SMS (▬) and TCMS (- -

-).

24

Heat Exchangers1%

Compressors + Expanders

59%FGD16%

M embrane7%

General Equipment17%

General22%

Cooling3%

Membrane replacem't2%

Energy38%

Capital charges35%

A: Total Capital Breakdown

B: Annualised operating costs

Figure 7 The total capital and annualised operating costs for a SMS recovering 80% CO2

25

0

50

100

150

200

0.0 0.1 0.2 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 1.1

CO2 avoided (million tonnes/year)

Cos

t ($/

tonn

e C

O2

avoi

ded)

No capture

Total for 95% capture

Storage

Capture

TotalM

EM

BR

AN

ES

Storage

Capture

Total

ME

A

Figure 8 The behaviour of cost for capture and storage, as a function of CO2 avoided for gas separation

membranes, MEA absorption, no ‘capture’, and maximum capture (95% CO2 recovered).

26

0

10

20

30

40

50

60

70

80

Membrane

Cap

ture

Cos

t ($

/tonn

e C

O2

avoi

ded)

MEA

This study (2004)

Hendriks (1994)

IEA study (1992)

Figure 9 Comparison of CO2 capture costs for gas separation membranes and MEA

27

TABLES

Table 1 The operating conditions for both SMS and TCMS layouts.

Feed pressure 20 bar

Permeate pressure 1 bar

Membrane temperature 30 OC

Pressure of expanded waste gas 1 bar

28

Table 2 The operating conditions for MEA chemical absorption system.

Absorber pressure 1.2 bar

Absorber temperature 40 OC

CO2 rich loading 0.4 mole CO2/mole MEA

Solvent loss due to SO2

1.6 kg MEA/tonne CO2 recovered

29

Table 3 Summary of inputs for the storage model.

Reservoir Gippsland

Onshore pipe length 110 km

Offshore pipe length 60 km

Water depth 60 m

Reservoir depth 2,063 m

Reservoir thickness 120 m

Reservoir temperature 85 oC

Reservoir pressure 3,154 psia

Average reservoir permeability 1,500 mD

Reservoir radius 9.0 km

30

Table 4 Summary of economic inputs for the capture and storage models.

Discount rate 7 % pa

Cost of external power 20 $/MWh

Fixed annual operating cost 4% of total Capital Costs

Project life 20 years

Construction period 2 years

Membrane cost 150 $/m2

31

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