Global carbon dioxide storage potential and costs - Ecofys · PDF fileGlobal carbon dioxide storage potential and costs ... Wina Graus TNO-NITG Frank van ... GLOBAL CARBON DIOXIDE

our mission: a sustainable energy supply for everyone

Global carbon dioxide storage potential and costsBy Ecofys in cooperation with TNO


Ecofys bv P.O. Box 8408 NL-3503 RK Utrecht Kanaalweg 16-G NL-3526 KL Utrecht The Netherlands www.ecofys.nl tel +31 (0)30 280 83 00 fax +31 (0)30 280 83 01 e-mail [email protected]

Ecofys Chris Hendriks Wina Graus TNO-NITG Frank van Bergen

2004 EEP-02001

by order of the: Rijksinstituut voor Volksgezondheid en Milieu

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS I

Executive Summary

Ecofys in co-operation with TNO-NITG present in this report an estimate of the worldwide CO2 storage potential. The potential is given by region and for five types of underground storage reservoirs. The report also presents an estimate of costs for capture and storage of carbon dioxide.

Cost o f carbon d iox ide capture and storage

Cost for capture and storage of carbon dioxide can conveniently be divided into costs for capture, compression, transport and storage. For each of these categories we will give an indication of the costs and discuss the main issues underlying the cost indication. Capture of carbon dioxide Carbon dioxide capture processes can be divided into four main categories: • Precombustion processes.

The fossil fuel is converted to a hydrogen rich stream and a carbon rich stream. This is an option for integrated coal-fired combined cycle systems (IGCC) or natural gas-fired combined cycle systems (NGCC).

• Post combustion processes. Carbon dioxide is recovered from flue gases.

• Denitrogenation processes. A concentrated carbon dioxide stream can be produced by the exclusion of nitrogen in the combustion process.

• Processes where pure streams of carbon dioxide are produced. Some industrial processes produce pure carbon dioxide, e.g. ammonia and hydrogen production.

These processes can be applied in power plants and in various large industrial process. In Table 1 (power plants) and Table 2 (large industries) we present typical cost for CO2 capture.

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS II

Table 1. Costs and plant character ist ics for power p lants with capture

of carbon dioxide

Type of capture technology Pre-comb. Pre-comb. Post-comb. Post-comb. Post-comb.

Type of plant Natural gas

(NGCC)

Coal

(IGCC)

Natural gas

(NGCC)

Natural gas

fired (steam)

Coal

(Pulverized)

Without capture

Plant efficiency (%LHV) 58.0% 47.0% 58.0% 42.0% 42.0%

Emission factor (kgCO2/kWh) 0.35 0.72 0.35 0.48 0.81

Power costs (€/kWh) 3.1 4.8 3.1 3.8 4.0

With capture



Loss of plant efficiency 6.5% 4.8% 6.0% 5.6% 8.3%

Power costs (€/kWh) 4.6 6.4 4.1 5.0 6.0

Power cost increase (%)

CO2 avoided (%) 85% 88% 85% 85% 85%

Costs (€/tCO2) 43 26 37 30 29

Table 2. Typica l costs of CO2 capture for industr ia l p lants

Facility €/tCO2 Facility €/tCO2

Cement plants 28 Refineries 29-42

Iron and steel plants 29 Hydrogen (flue gas) 36

Ammonia plants (flue gas) 36 Hydrogen (pure CO2) 3

Ammonia plants (pure CO2) 3 Petrochemical plants 32-36

Capture costs for power plants range from about 26 € per tonne of CO2 avoided for integrated gasifier combined cycles to about 43 € per tonne of CO2 avoided for natural gas-fired combined cycles equipped with pre-combustion capture. Implementation of capture increases power production costs by 35 to 40 percent (IGCC, and natural gas-fired plants) to about 50 percent for pulverised coal-fired plants. Costs for industrial sources are in the range of 28 to 42 € per tonne of CO2 avoided. Costs depend on the level of concentration of carbon dioxide in the flue gas and the availability of surplus heat at or nearby the plant site. The reported costs concern full-scale plants and do not reflects costs for demonstration plants and pilot plants. Costs to compress the captured carbon dioxide range roughly from 6 to 10 € per tonne CO2. When obtained from the plant with capture, efficiency will decrease by 2 to 3.5 percent for natural-gas and coal-fired plants, respectively. Transport of carbon dioxide Transport of large amounts of carbon dioxide is usually most conveniently done by pipelines. In case of large distances over sea, sometimes tanker transport might be more attractive. Transport costs over 100 km range from 1 to 6 € per tonne of CO2 depending on the capacity of the pipeline. A larger flow size reduces costs. More than 50 percent of the costs are formed by depreciation of investment costs. The costs for transport consist furthermore of construction costs (material costs, labor,

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS III

maintenance, assurances and licenses). The costs are depending on length of the route, number of highways and water crossings. Specific terrain conditions, like mountainous areas (higer construction costs) and populated areas (higher safety requirements), might increase costs of transport significantly. Storage costs The costs for the injection of carbon dioxide are mainly caused by the drilling of wells and operational costs. These costs range from 1 to 8 € per tonne of carbon dioxide, depending on the depth and permeability of the storage reservoir and the type of reservoir. The costs for enhanced oil recovery are between –10 (i.e. net benefits) and 20 € per tonne of carbon dioxide. Onshore storage is generally less expensive than offshore storage. Extra produced oil or extra produced natural gas recovery may reduce costs for storage. The costs will range considerably from project to project and, in the case of EOR, are also very dependent on the actual oil and gas price. In some cases it could be economically beneficial to apply enhanced oil recovery. Storage combined with enhanced coal bed methane is currently often more expensive because of the large amounts of wells required. Table 3 shows storage costs for several depths.

Table 3. Storage costs by depth ( in €/tCO2)

Depth of storage (m)

1000 2000 3000

Aquifer onshore 2 3 6

Aquifer offshore 5 7 11

Natural gas field onshore 1 2 4

Natural gas field offshore 4 6 8

Empty oil field onshore 1 2 4

Empty oil field offshore 4 6 8

Low Medium High EOR onshore -10 0 10

EOR offshore -10 3 20

ECBM 0 10 30

Potent ia l o f carbon d iox ide storage

Carbon dioxide can be stored in underground layers. The following types of storage reservoirs are distinguished:

• Empty natural gas fields • Empty oil fields • Remaining oil fields to explore with enhanced oil recovery (EOR) • Unmineable coal layers to which enhanced coal bed methane recovery can

be applied (ECBM) • Aquifers (water containing underground layers)

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS IV

We developed a serie of methodologies to calculate the underground storage potential for each type of reservoir. For all the storage options a low, best and high estimate is presented of the total amount of carbon dioxide that can be stored. The ‘best’ estimate for total storage potential worldwide is 1700 GtCO2. This equals about 80 years of current worldwide annual net emission of carbon dioxide to the atmosphere. The calculated storage potential ranges from 500 Gtonne CO2 (equivalent to 20 years of current CO2 emissions) to 6000 Gtonne of CO2 (equivalent to 265 years). The low, best and high estimates are based on a number of assumptions, like the uncertainty of the amount of undiscovered natural gas reservoirs, the exchange ratio of CO2 and methane for ECBM (2-3), and the space that can be used to store CO2 in oil reservoirs (40-80%). The potential for aquifers is estimated to range from 30 to 1100 Gtonne of CO2. However, when requirements for a closed structure of an aquifer are less severe, the potential in aquifers might be manifold. Figure 1 and Figure 2 shows the carbon dioxide storage potential by type of reservoir and by region, respectively. Not all storage capacity is currently available for carbon dioxide storage. Hydrocarbon fields may not already be exploit or are not yet empty. There may also be a conflict of interest, e.g. the field is needed for natural gas storage. Enhanced oil recovery is applied most economically before the field is abandoned and infrastructure is still in place. Re-installation of equipment might turn out very expensive.

Figure 1. CO2 storage per type of underground reservoirs.

Oil fields onshore9%

Oil fields offshore6%

Natural Gas fields onshore

37%

Natural Gas fields offshore

18%

Coal beds16%

Aquifers14%

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS V

F igure 2. CO2 storage potent ia l per region

Exper ience curves

Carbon dioxide capture and storage systems are in an early stage of development. The reported costs concern full-scale plants (thus not demonstration, pilot or plants built in the initial phase of implementation of the technology) and the costs should be regarded as indicative only. Actual costs could differ ± 30% from the reported costs. Large-scale deployment of the carbon dioxide sequestration systems will most certainly lead to systems with lower energy penalties and lower costs than systems put into operation in the first years of implementation. Costs for storage are likely to reduce when storing CO2 underground is increasingly deployed. The possibilities to reduce costs for storage in depleted fields and aquifers will probably be less than for EOR and ECBM. Costs for depleted reservoirs are mainly related to drilling wells, a current mature technology. Nevertheless, reductions may be obtained by a better understanding of the storage process. This may lead to less required monitoring and observation wells and improved design of the storage location. Little information is available for EOR and ECBM. Better understanding of the ‘underground processes’ of these options might lead to considerable cost reduction. For these options, however, the price of the oil and natural gas is of large influence on the storage costs. High energy prices may even lead to benefits for CO2 storage.

World cost curve for carbon d iox ide s torage

Figure 3 shows a world cost curve for CO2 storage. For the calculation of the average transport costs, for each type of underground storage a weighted average transport distance between source and storage reservoir is used. For the calculation of the storage costs, typical storage costs are used for each type of reservoir.

U.S.A.6%

Former S.U.21%

Middle East20%

Southern Asia3%

Eastern Asia16%

South East. Asia4%

Japan0%

Oceania4%

Greenland0%

Canada3%

Central America

South America

Northern Africa

Western Africa

Eastern Africa

Southern Africa

Western Europe

Eastern Europe

Fig

ure

3.

Wo

rld

co

st

cu

rve

CO

2 s

tora

ge

. C

osts

are

ca

lcu

late

d b

y:

(1)

av

era

ge

ca

ptu

re a

nd

co

mp

ressio

n c

osts

of

38

.5 €

/tC

O2,

(2)

we

igh

ted

wo

rld

av

era

ge

of

tra

nsp

ort

dis

tan

ce

pe

r ty

pe

of

rese

rvo

ir a

nd

(3

) ty

pic

al

sto

rag

e c

osts

pe

r ty

pe

of

rese

rvo

ir.

Wo

rld

CO

2-st

ora

ge

cost

cu

rve

35404550556065

020

040

060

080

010

0012

0014

0016

0018

00

Sto

rag

e p

ote

nti

al (

Pg

CO

2)

Total cost (euro/Mg CO2)

Dep

lete

d oi

l and

N

atur

al g

as fi

elds

of

fsho

re

EO

R o

ffsho

reD

eple

ted

oil f

ield

s on

shor

e

EO

R o

nsho

re

Enh

ance

d N

atur

al

gas

reco

very

on

shor

e

Enh

ance

d N

atur

al

gas

reco

very

of

fsho

re

EC

BM

Aqu

ifers

Dep

lete

d N

atur

al

gas

field

s on

shor

e

Table of contents

1 Introduction 1

2 CO2 capture and storage costs 3

2.1 Carbon dioxide capture 3 2.1.1 Economic analyses framework 4 2.1.2 Pre-combustion capture from power plants 5 2.1.3 Post-combustion capture from power plants 6 2.1.4 Post-combustion capture from large industry 7 2.2 Carbon dioxide compression costs 9 2.3 Carbon dioxide transport costs 10 2.4 Carbon dioxide storage costs 12

3 Potential of carbon dioxide storage 14

3.1 Type of reservoirs 14 3.2 Oil and Gas reservoirs 14 3.2.1 Oil reservoir: storage in EOR operations 15 3.2.2 Oil reservoir:storage in depleted oil fields 19 3.2.3 Gas reservoir: storage in operational gas fields 20 3.2.4 Gas reservoir: storage in depleted gas fields 23 3.3 Coal basins 23 3.3.1 Coal basin: in storage in ECBM operations 23 3.4 Aquifers 24 3.5 Results of the calculations 26 3.6 Cost curves for storage of carbon dioxide 29

4 Experience curves 32

5 Conclusions 34

References 36

Appendices 40

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS VIII

GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS 1

1 Introduction

Until so far only limited effort has been made to estimate CO2 regional storage po-tential worldwide. Hendriks [1994] developed a method for a worldwide potential estimate for natural gas, oil and aquifer reservoirs by region. On regional scale con-siderable more effort has been undertaken. In the GESTCO project2 a validated es-timate is carried out for European countries. In addition, the IEA GHG R&D programme carried out a number of studies, which provides information for storage capacity. However, none of them gives a comprehensive worldwide overview of storage capacity by region and type of storage reservoir. In this study we develop a methodology to assess storage potential in various types of underground reservoirs for 18 regions (comprising the whole world except Ant-arctica) in a consistent way. This study also provides costs estimates for capture technologies, transport and storage activities. It should be noted that carbon dioxide sequestration technology is still in an early stage of implementation. Reported costs should therefore be regarded as indicative values only. Chapter 2 describes the results of the costs estimate study. The methodology to es-timate storage potential is presented in chapter 3. It should be understood that the results could only be regarded as an indication of storage potential rather than an exact estimate. This is mainly due to lack of data, large regional differences in res-ervoir characterisation and limited knowledge about the ‘real’ potential of a reser-voir.

2 GESTCO (geological storage of carbon dioxide) is a project carried out for the European Commission by 8 European geological survey s and Ecofys. The project assesses storage of carbon dioxide in underground reservoirs in eight European countries.



2 CO2 capture and storage costs

This chapter discusses the costs to capture (par. 2.1), compression (par. 2.2), trans-port (par. 2.3) and storage of carbon dioxide underground (par. 2.4).

2.1 Carbon d iox ide capture

The goal of CO2 capture is to isolate carbon from the energy carrier in a form suit-able for transport and storage. It is generally believed that a relatively pure stream of carbon dioxide must be produced. This improves the economics for compres-sion, transport and storage. Also sink capacity is better utilised by injecting pure CO2. For ease of transport, carbon dioxide is generally liquefied and compressed to about 8 to 12 MPa for onshore transport and up to 20 MPa for offshore transport. Sources that appear to lend themselves best to capture include large-point sources of CO2 such as conventional pulverised steam power plants, coal or natural gas-fired combined cycles, and fuel cells. In addition to power plants, industrial sources are being considered for application of capture technologies, like cement plants, oil refineries, iron and steel plants, ammonia and hydrogen production plants, and natural gas processing sites. Capture from disperse sources of CO2 emissions like residential buildings and transport vehicles need a different approach. Possible op-portunity is the introduction of fuel cells for vehicular propulsion combined with central production of hydrogen including CO2 capture. There are numerous ways to capture carbon dioxide from energy conversion proc-esses. These CO2 capture processes can conveniently be divided into four main categories:

1. Pre-combustion processes. The fossil fuel is converted to a hydrogen-rich stream and a carbon-rich stream.

2. Post-combustion processes. Carbon dioxide is recovered from a flue gas. 3. Denitrogenation processes. A concentrated CO2 stream can be produced by

the exclusion of N2 before or during the combustion/conversion process. 4. Pure streams of CO2. Some industrial processes produce pure CO2.

It should be mentioned that together with carbon dioxide capture, often other emis-sions of pollutants like SOx, NOx and particulates also will be reduced. This is ei-ther a pre-requisite for the capture process (e.g. otherwise the pollutants hinders the capture process in post-combustion processes) or it is a direct consequence of the capture process (e.g. in denitrogenation processes in which all flue gases are cap-tured). In this chapter the capture technologies for power production (pre-combustion and post-combustion), and for industrial sources (post-combustion and CO2-rich streams) are shortly described and the costs are presented (in €/Mg CO2-avoided and in specific investment costs (€/kW)). In this study we did not evaluate proc-esses, as they are still in an early stage of development and they can be applied


principally to the same kind of processes for which also alternative processes are available.

2.1.1 Economic analyses framework

For various types of power plant (Integrated gasification Combined Cycles (IGCC), Natural gas Combined Cycles (NGCC), and Pulverised Coal-fired power plants (PC)) several studies in the literature are reviewed. For each study, two cases are analysed: the reference plant (no capture), and the capture plant, which includes carbon dioxide separation and compression up to about 10 MPa.3 All studies deal with new power plants. Retrofit of existing plants might be more expensive and might cause higher efficiency losses than newly built plants. For industrial sources the costs are based on add-on capture technology. The variables characterising the financial performance of a particular capture proc-ess depend on the following three parameters: 1. Full load hours / yearly operating hours, 2. Capital charge rate. It is used to annualise the capital investment of the plant.

This rate can be calculated from the presumed discount rate and lifetime of the capital,

3. Fuel costs (defined on lower heating value). The individual studies reviewed use different values for each three parameters. Consequently, the financial results that are obtained differ not only because of technological variations amongst the processes, but also of the economic assump-tions. To better compare the evaluations, the original studies are adjusted to a common basis, which is given in Table 4.

Table 4. Used values for compar ison capture costs f rom power p lants

Full load hours 7500 hours per year

Capital charge rate 11% (i.e. discount rate 10%; lifetime 25 years)

Coal price 2 €/GJLHV

Natural gas price 3 €/GJLHV

Based on the results from literature and own research we developed a computer programme to calculate efficiency losses and capture costs depending on size of the plant, type of fuel used, (power) production technology, and concentration of car-bon dioxide in the flue gases. We performed the calculation for the following four types of power plant and for 6 types of large industries. The calculations for power plants are done for a standard size of 500 MWe net output (for a plant without capture):

1. IGCC (Pre-combustion) 2. NGCC (Pre-combustion) 3. Pulverised coal-fired power plant (Post-combustion) 4. Conventional natural gas-fired power plant (Post-combustion) 5. Cement plants 6. Iron and steel plants

2 The costs of transport and storage are not included in this analyses, but are presented in the next sections.


7. Ammonia plants 8. Refineries 9. Hydrogen 10. Petrochemical plants

Table 5 and Table 6 give for power plants and industrial plants typical investment and O&M costs. For the power plants also efficiency loss due to the capture of car-bon dioxide and CO2 emission factors is given. Background discussion on the cap-ture technologies and capture conditions is provided in the next sections.

Table 5. Costs and plant character ist ics for power p lants with capture

of carbon dioxide.

Type of capture technology Pre-comb. Pre-comb. Post-comb. Post-comb. Post-comb.

Type of plant Natural gas

(NGCC)

Coal

(IGCC)

Natural gas

(NGCC)

Natural gas

fired (steam)

Coal

(Pulverized)

Without capture



Power costs (€/kWh) 3.1 4.8 3.1 3.8 4.0

With capture



Loss of plant efficiency 6.5% 4.8% 6.0% 5.6% 8.3%

Power costs (€/kWh) 4.6 6.4 4.1 5.0 6.0

Power cost increase (%)

CO2 avoided (%) 85% 88% 85% 85% 85%

Costs (€/Mg CO2) 43 26 37 30 29

Table 6. Typica l costs of CO2 capture for industr ia l p lants

Facility €/MgCO2 €/MgCO2

Cement plants 28 Refineries 29-42

Iron and steel plants 29 Hydrogen (flue gas) 36

Ammonia plants (flue gas) 36 Hydrogen (pure CO2) 3

Ammonia plants (pure CO2) 3 Petrochemical plants 32-36

2.1.2 Pre-combustion capture from power plants

In carbon dioxide capture using a pre-combustion process (also decarbonisation of fuel called), the carbon containing (fossil) fuel is converted to a mixture of carbon monoxide and hydrogen. In a second step the carbon monoxide is shifted further with water to carbon dioxide and an extra amount of hydrogen. In a CO2 separation unit, the carbon dioxide is separated from the hydrogen. The hydrogen is subse-quently combusted in the gas turbine of the power plant.


In principal hydrogen can be produced out of any fuel, either of fossil origin or from biomass. The carbon dioxide is normally removed from the hydrogen by a physical recovery process. The carbon dioxide is recovered in almost pure form. The most logical power technology to apply pre-combustion capture technology will be the integrated coal-fired combined cycle (IGCC). Two additional steps need to be added to this process: shift from the coal gas to a carbon dioxide rich gas stream and separation of the carbon dioxide from the hydrogen. Capture is also ap-plicable to natural gas-fired combined cycle plants (NGCCs). It should be realised that for the latter type of plants the natural gas should be converted in steam re-former reactor to a synthesis gas (i.e. an additional step compared to capture from IGCC), and the carbon content is considerably lower in natural gas than in coal. These aspects make it generally more expensive for natural gas than for coal per Mg4 of carbon dioxide captured. Figure 6.5.1 and Figure 6.5.3 in the annex show the calculated electricity produc-tion costs for IGCCs and NGCCs for the studies analysed (without and with capture and compression) and the costs of CO2 capture (€/Mg CO2).

2.1.3 Post-combustion capture from power plants

In a post-combustion process, the CO2 is separated from the flue gases of a power plant. Typical concentrations of CO2 in flue gases are given in Table 7.

Table 7. Typica l CO2 concentrat ions in f lue gases of power p lants

Facility Typical CO2 concentration in flue gases Power plant – NGCC 3%

Power plant – IGCC 6%

Power plant – boiler NG 8%

Power plant – boiler coal 15%

The best-known and developed technology is separation of CO2 from flue gases by an amine-based solvent. Other ways to capture CO2 is by using membranes (poly-mer- based, ceramic or metal-base) or in combination of membranes and solvent. In the latter option, the membranes replace the absorption column and act as a gas-liquid contact facilitator. Also considered is to fractionate the carbon dioxide by so-lidifying it. These alternatives are at the moment less energy efficient and more ex-pensive than chemical absorption. This can be attributed, in part, to the low CO2 partial pressure in the flue gases. Recovery systems based on amines are proven on commercially scale. These sys-tems can recover 85 to 95% of the CO2 in the flue gas and produces CO2 with a pu-rity of over 99.9%. Examples of available systems are the Econamine FG process of Fluor Daniel and the Amine Guard process licensed by UOP.

4 Mg = megagramme = tonne; Gg = ktonne; Tg = Mtonne; Pg = Gtonne


Over twenty commercial plants have been built using the Econamine FG process or its predecessor. All but one are relatively small plants (0.1 – 4 kg/s). An important process parameter is the heat requirement. In a power plant the heat can be obtained from the low-pressure steam turbine. Substantial reduction in heat requirements is reported over the last decade. In 1990 Tuke [1990] reported for a commercial operating plant in Australia a heat requirement of 4.5 MJ per kg of CO2 recovered. The CO2 concentration in the flue gases amounted to 7% and the con-centration of the chemical absorbent monoethanolamine (MEA) in the solvent amounted to 30%. In the early nineties Mariz [1991] and Sander [1992] reported that a heat consumption of 4.1 MJ/kg CO2 can be obtained by the Econamine proc-ess. According to Mimura [2000], the KS-1 solvent can reach less than 3.3 MJ/kg CO2 for flue gases with 7% CO2. They expect to obtain further improvements in the coming years. Figure 6.5.2 in the annex shows the calculated electricity production costs for PCs for the studies analysed (without and with capture and compression) and the costs of CO2 capture (€/Mg CO2).

2.1.4 Post-combustion capture from large industry

In addition to power plants, industrial sources are being considered for application of capture technologies, like cement plants, oil refineries, iron and steel plants, ammonia and hydrogen production plants, and natural gas processing sites. Al-though pre-combustion technologies may in some cases also be applicable (e.g. from high-caloric gases in the iron and steel industry), currently it is believed that post-combustion using amine-based technology is the most suitable technique. The technique is commercially proven and often ‘waste heat’5 might be present to pro-vide partly in the heat requirement of the capture process. Ammonia and hydrogen production processes produce often already a pure carbon dioxide stream. Usually, this stream is vented or used in other purposes like the manufacturing of urea. Typical concentrations of CO2 in flue gases from industrial facilities and typical capture costs are given in Table 8. Table 9 indicates the sensi-tivity of the capture costs in relation to the carbon dioxide concentration in the flue gases and the annual emitted carbon dioxide. Figure 2.1 depicts the sensitivity of the avoidance costs in relation to the percentage of waste heat available (i.e. per-centage to the total heat requirement for the capture process).

5 For the Rijnmond it has been calculated that yearly 7 PJ of HP/MP/LP ‘waste’ heat is available. This equals to 10% of the heat requirement if ALL carbon dioxide from industrial sources in this area would be recovered. A further 9 PJ of VLP (very low pressure steam) is available and over 36 PJ of heat water (100 °C or higher) [Rooijers, 2002]. Additionally, heat can also be extracted from the low-pressure section of the steam turbine (from e.g. CHP units). The availability of waste heat within a plant, however, is very site specific and may also depend on adjacent industries. In this study a conservative percentage of 20% availability of waste heat for total heat requirement has been assumed.


Table 8. Typica l CO2 concentrat ions in f lue gases of some industr ia l

fac i l i t ies

Facility Typical CO2 concen-tration in flue gases

Typical capture costs ex-cluding compression)

[€/MgCO2] Cement plants 15-25% 28

Iron and steel plants 15-20% 29

Ammonia plants (flue gas) 8% 36

Ammonia plants (pure CO2) Pure stream 3

Refineries 3-18% 29-424

Hydrogen (flue gas) 8% 36

Hydrogen (pure CO2) Pure stream 3

Petrochemical plants 8-13% 32-36

Table 9. Typica l CO2 capture costs (wi thout compression costs) f rom in-

dustr ia l sources (€/Mg) for var ious concentrat ions in f lue gas

( in %; row) and var ious emiss ion s izes of CO2 ( in Tg CO2; co l-

umn). Assumed is that 20% of the heat can be covered by

waste heat . In the las t row the compression costs are pre-

sented

CO2concentration in flue gas (%) 3% 5% 8% 10% 13% 15% 18% 20% Comp.

0.5 45 41 38 36 34 32 31 30 10

1.0 43 39 36 34 32 31 29 28 7

1.5 41 38 35 33 31 29 28 27 7

2.0 39 36 33 31 29 28 27 26 6

2.5 38 35 32 30 28 27 26 25 6

3.0 36 33 31 29 27 26 25 24 6

3.5 35 32 30 28 26 25 24 23 6

Ann

ual e

mis

sion

(T

gCO

2)

4.0 34 31 29 27 25 24 23 23 6


-50%

-40%

-30%

-20%

-10%

0%

10%

20%

30%

0% 10% 20% 30% 40% 50% 60% 70% 80% 90%

Waste heat availability (as % of heat required)

Red

uct

ion

in

co

sts

(% o

f to

tal

cost

s)

Figure 2.1. Reduct ion in capture costs (exc lud ing costs for compress ion) when

waste heat is ava i lable at the capture locat ion. The ava i labi l i ty of

waste heat is expressed as percentage of total heat required for

capture process. Assumed is standard heat coverage of 20% by

waste heat

2.2 Carbon d iox ide compress ion costs

To transport CO2 efficiently by pipeline the pressure needs to be at least 8 MPa. At this pressure the density versus the compression ratio is in many cases optimal. Higher pressures require more energy and investment costs while there is little gain in density (i.e. smaller pipelines). Depending on the pressure drop over the pipeline in some cases higher entrance pressures are required. A four-step centrifugal com-pressor compresses the carbon dioxide. Water is removed during the first compres-sion stages. Table 10 gives the main characteristics of compressors pressurising to 12 MPa.

Table 10. Operat ional condit ions for compress ion from 0.1 to 12 MPa for

a compressor with a capac i ty of 70 kg/s [Sulzer, 1999]

First stage

Second stage

Third stage

Fourth stage

Inlet/outlet pressure (bars) 1/3.8 3.8/10.3 10.2/38.3 120

Inlet/outlet temperature (°C) 30/155 35/128 35/165 35/152

Polytropic efficiency 85.4 84.7 83.6 76.8

Compression energy (kJ/kg CO2) 416

The electricity consumption is calculated according to equation (1). Constants are based on figures in Table 10. Total operating costs are calculated on basis of the in-vestment costs (see equation (2), operation and maintenance costs (5% of invest-ment costs) and electricity costs (0.04 €/kWh). The use of electricity results in extra


emission of CO2. In the study, it is assumed that the electricity is produced by a power plant without CO2 recovery with an emission factor of 0.70 kg CO2/kWh. Figure 2.2 depicts the compression costs as function of the flow for a number of capacity factors (load factors). The pie diagram in the same figure presents the cost breakdown to electricity costs, depreciation costs for total capital investment and operation and maintenance cost.

FP

PCE

Inlet

outlete ×

×= ln1 (1) FF

P

PCFCI C

inlet

outletC ×

×

×+×= 42 ln31 (2)

With: E Electricity use (kJe/s) Poutlet Outlet pressure (Pa) Pinlet Inlet pressure (Pa)

Ce1 Constant (87.85 kJe/kg) F CO2 flow (kg/s)

With: I Total investment costs (M€) C1 Constant (0.1 106 €/(kg/s)) C2 Constant (-0.71) C3 Constant (1.1 106 €/(kg/s)) C4 Constant (-0.60)

0

5

10

15

20

25

0 20 40 60 80 100 120 140 160

Flow to compressor (kg/s)

Co

mp

ress

ion

co

sts

(eu

ro/M

gC

O2)

97% 83% 70% 56% 42% 29%

Electricitycosts57%

O&M12%

Depreciationcosts 17%

Figure 2.2. Left f igure: Cost of compression as funct ion of f low for var i-

ous occupancy rate (100% = 8760 hours per year in opera-

t ion).

Right f igure: Cost a l locat ion to type of expenditure (50

kg/s; 0.04 €/kWh; 7500 hours/year , d iscount rate 10%, de-

prec iat ion per iod 15 year)

2.3 Carbon d iox ide t ransport costs

Transport of large amounts of carbon dioxide is usually most conveniently done by pipelines. In cases of large distances over sea, sometimes tanker transport might be more attractive. The carbon dioxide should be transported at relatively high pressure to ensure high density of the fluid, which diminishes substantially the required transport volume. At pressures above 7.4 MPa the density at transport temperature conditions is about 800-1000 kg CO2/m

3. The transport conditions between onshore and offshore differ in a number of aspects. The temperature of seawater is stable and often below 6 °C, while onshore the temperature may differ substantially form location to location


and from season to season. Also the question of safety (sudden escape of large amounts of carbon dioxide) is less urgent than for onshore transport. Transport pressure offshore can be as high as 30 MPa or higher, leading to higher transport volumes at the same pipe diameter (although not spectacular) and less required compression energy to compensate for pressure losses during transport. The costs for transport consist of construction costs (material costs, labour, mainte-nance, assurance, licences) and re-compression costs (compressors and electricity costs). The costs are depending on length of the route, number of highway and wa-ter crossing, and pressure and flow of the carbon dioxide to be transported. The construction costs at ‘standard conditions’ for a pipeline with a diameter of 1 metre are estimated at 1.1 M€ per kilometre. This number may be lower for on-shore construction and somewhat higher for offshore construction. Under more dif-ficult terrain situations, this number might increase by 10 to over 100%. When pipeline corridors can be used, the costs might slightly go down. Higher costs are expected in more densely populated areas (also higher safety requirements. i.e. more valves required), elevated areas, national parks, etc. Additional factors that might influence transport costs from region to region or from project to project are amongst others: • Difference in labour costs • Required licences • Required surface or subsurface construction • Safety requirements (number of valves, quality of material) • Climatological circumstances • Difference in logistics for supply of construction material These factors, however, have not been quantified in this study to specific regions or projects. Specific transport costs (i.e. costs per Mg CO2 transported over 100 km) depend on the economic criteria applied and on the velocity of the carbon dioxide obtained in the pipeline, which depends on terrain and pipeline conditions. Figure 2.3 shows the specific costs for two different velocities.

0

1

2

3

4

5

6

7

0 50 100 150 200 250 300

Flow (kg/s)

Tra

nspo

rt c

osts

(eu

ro/M

gCO

2/10

0 km

)

velocity 1 m/s velocity 3 m/s


F igure 2.3. Transport costs of carbon d iox ide for CO2 p ipel ine veloc ity of

1 and 3 metre per second (d istance 100 km onshore; e lec-

tr ic i ty costs 0.04 €/kWh; 7500 hours/year, d iscount 10%,

deprec iat ion per iod 25 years)

Depreciationcosts54%

O&M15%

Electricity costs31%

Figure 2.4. Cost al locat ion for transport costs to type of expenditure (50

kg/s; d is tance 100 km onshore; e lec tr ic i ty costs 0.04 €/kWh;

7500 hours/year, d iscount 10%, deprec iat ion per iod 25

years)

2.4 Carbon d iox ide s torage costs

The costs for injection are mainly costs for drilling wells and operational costs. In this study we assume that the costs for drilling is only depending on the depths of the well. One-km well costs about 1 M€, a 3-km well costs about 2.3 M€. Offshore additionally a platform is required for the period of drilling and injection. Here we assume re-use of an existing platform and the costs are estimated at about 23 M€ per platform. The specific costs for storage depends mainly on the number of required wells and the years of operation. The number of wells depends on the injectivity and the al-lowed overpressure. These factors will vary from type of reservoir (e.g. aquifer ver-sus empty natural gas field) and from location to location. Based on Wildenborg [1999] the specific storage costs of CO2 in aquifers and in empty natural gas and oil fields (onshore and offshore) are determined for three dif-ferent reservoir depths (Table 12). For enhanced oil recovery and enhanced coal bed methane storage costs calculation is considerably more complex and variable. Table 12 shows a range of costs for both storage options. For a particular storage by EOR or ECBM, the costs are sensi-tive to the oil price and natural gas prices. The cost range for such storage options is much larger than shown in the table. The costs are highly influenced by permeabil-ity of the reservoir (ECBM), terrain conditions, accessibility to grid, etc. The fig-ures in table 11 for EOR and ECBM should be seen as an indication for storage costs [Lysen, 2002; Alberta Research Council, 2000; Novem, 2001].


Table 12. Storage costs by depth ( in €/MgCO2)

Depth of storage (m)

1000 2000 3000

Aquifer onshore 1.8 2.7 5.9

Aquifer offshore 4.5 7.3 11.4

Natural gas field onshore 1.1 1.6 3.6

Natural gas field offshore 3.6 5.7 7.7

Empty oil field onshore 1.1 1.6 3.6

Empty oil field offshore 3.6 5.7 7.7

Low Medium High EOR onshore -10 0 10

EOR offshore -10 3 20

ECBM 0 10 30


3 Potential of carbon dioxide storage

3.1 Type of reservo i rs

Carbon dioxide can be stored in underground layers. Generally the following types of storage reservoirs are distinguished: • Empty natural gas fields • Empty oil fields • Remaining oil fields to explore with enhanced oil recovery (EOR) • Unmineable coal layers to which enhanced coal bed methane recovery can be

applied (ECBM) • Aquifers (water containing underground layers) Clearly oil, gas, and coal fields have proven their capability of holding oil and gas over geological time periods. Gas storage in aquifers is a human-induced phenome-non and therefore relatively new, although several natural analogues are known and currently under investigation. However, safety issues (anthropogenic or natural) remain and future field experiments and operations are required to be able to quan-tify the risks involved in CO2 sequestration. Recently, several projects were launched worldwide that focus on safety matters. Safety issues are complex and strongly location specific; it therefore goes beyond the scope of this study to take safety issues into consideration. This chapter discusses the methodology to estimate underground potential by type of storage reservoir for the following regional subdivision:

1. Canada 2. USA 3. Central America 4. South America 5. Northern Africa 6. Western Africa 7. Eastern Africa 8. South Africa 9. Western Europe

10. Central Europe 11. Former Sovjet Union 12. Middle East 13. Southern Asia (India+) 14. Eastern Asia (China+) 15. South Eastern Asia 16. Oceania 17. Japan.

3.2 Oi l and Gas reservo irs

The exclusive source of information for the calculations of global CO2 sequestra-tion potential in oil and gas reservoirs used in this investigation are the Digital Data Series of the United States Geological Survey covering their latest petroleum as-sessments [USGS, 1995; USGS, 2000]. Within the World Petroleum Assessment 2000 [USGS, 2000] the assessed areas were those judged to be significant on a


world scale in terms of known petroleum volumes, geological potential for new pe-troleum discoveries, and political or societal importance. In the World Petroleum Assessment 2000, the world (excluding the USA.) is divided in 8 regions, in which 270 assessment units6 were identified in 96 countries and 2 jointly held areas [USGS [1], 2000]. The United States were not re-assessed in the World Petroleum Assessment 2000. In this study, previous estimates by the USGS in 1995 were used [USGS [1 to 3], 1996]. In the USA 557 conventional plays7 were defined within 63 geological prov-inces. The results of the USA and World Assessments were combined to get a complete overview of the global petroleum occurrences. The assessments of the USGS provide a representative insight in the global oil and gas resources on the level of the Assessment Units, but is not sufficient for a full appraisal or evaluation of individual oil fields. Figure 6.5.7 in the Annex shows a graphical representation of the oil and gas occurrences.

3.2.1 Oil reservoir: storage in EOR operations

Enhanced oil recovery with CO2 injection (EOR-CO2) has been applied for decades in the oil industry. Nevertheless, publicly available data on CO2 injection and cy-cling in depleted oil and gas fields is extremely limited [Stevens, 1999]. The only reliable figures from field operations on EOR-CO2, on which our calculations should be based, result from these projects on the amount of CO2 that can poten-tially be stored. However, the only goal in these operations was to produce as much extra oil as possible. To date no individual CO2-EOR project has been directly monitored or even indirectly assessed specifically to determine CO2 sequestration [Stevens, 1999]. Therefore, the results of these operations are usually presented in relation to production figures, thus expressed in relation to “target original oil in place” (OOIP). For the calculation of the volumes of CO2 that can potentially be sequestered during EOR-operations, the method suggested by Stevens [1999b] was followed with some adaptations. Stevens [1999b] have related the extra oil produced via EOR-CO2, and thereby CO2 storage potential, to the OOIP. To calculate the OOIP from the Ultimate Recoverable Resources (URR, taken from the USGS assessments), the following formula was applied [Stevens, 1999]:

( ) 100/5+=

gravityAPI

URROOIP

6 An assessment unit is defined as a mappable volume of rock within the total petroleum system that encompasses fields (discovered and undiscovered) which share similar geo-logic traits and socio-economic factors. The fields within an assessment unit should consti-tute a sufficiently homogeneous population so that the chosen methodology of resource assessment is applicable. A total petroleum system might equate to a single assessment unit. If necessary, a total petroleum system can be subdivided into two or more assess-ment units in order that each unit is sufficiently homogeneous to assess individually [USGS, 2000]. 7 A play, as defined by the USGS, is a set of known or postulated oil and gas accumula-tions sharing similar geologic, geographic, and temporal properties, such as source rock, migration pathway, timing, trapping mechanism, and hydrocarbon type. A play differs from an assessment unit; an assessment unit can include one or more plays.


With: OOIP = original oil in place, in barrels of oil (BO) APIgravity = a measure of the density of the oil as specified by the American

Petroleum Institute gravity scale at 60 degrees Fahrenheit (°API). Specific gravity and API gravity are related as follows: °API = (141.5 / Specific gravity) –131.5. The API gravity of pure water is 10°. Gravity less than 10° API indicates the oil is denser than pure water. Most normal oils have API gravities from 25° to 45°. Viscos-ity and API gravity are usually inversely related [Waples, 1985].

URR = Ultimate Recoverable Resources, in barrels of oil (BO) Probably, not all oil (OOIP) will come in contact with the CO2. Stevens [1999b] conservatively assumed that about 75% of the resource oil would be amenable to miscible or immiscible flooding with CO2. Therefore, a "contact" factor of 0.75 was applied

COOIPOOIPC ×=

With: OOIPC = original oil in place contacted with CO2, in barrels of oil (BO) C = contact factor, no unit To calculate the percentage extra oil recovery (%EXTRA) due to CO2 injection, the approach from Stevens [1999b] was used. In their approach, although they realised that other factors affect recovery of OOIP, they selected oil gravity as the most readily simulated variable. Stevens [1999b] used an empirical relationship between oil gravity (API) and EOR recovery determined for 7 Permian Basin (U.S.A.) EOR projects (Figure 3.1). API gravity is in this study considered representing the com-position of the oil, since the composition of an oil and its density are closely re-lated. Heavy oil has a high density and high viscosity and is indicated by low API values, while condensate/light crude has low density and low viscosity and is indi-cated by high API values. More CO2 will be required to produce one barrel of heavy oil than for the production of a barrel of condensate/light crude. The extra oil due to EOR is then calculated by: EOR = (%EXTRA / 100) × OOIPC

With: EOR = extra oil due to enhanced oil recovery by CO2 injection, in

barrels of oil (BO) %EXTRA = percentage extra oil recovery due to CO2 injection, no unit OOIPC = original oil in place contacted with CO2, in barrels of oil

(BO) Based on Figure 3.1 a low value of 5, a best estimate of 12, and a high estimate of 20% was taken in this study.


0

5

10

15

20

25

25 30 35 40 45

APIgravity

Extraoildueto

EOR(%)

Figure 3.1. Relat ion between API gravity and percentage of extra o i l due

to EOR

The oil volume is multiplied by a ratio (RCO2) that relates the incremental oil vol-ume to the net quantity of needed CO2. The net quantity is the amount that is ulti-mately stored in the reservoir, assuming that about 5% of the CO2 purchased is lost to the atmosphere during recycling and from insecure wellbore leakage [Stevens, 1999b]. Two types of CO2 flooding exist: miscible and immiscible flooding. The majority of (active) EOR projects with CO2 have been executed by miscible flood-ing. In this study, no distinction is made between miscible and immiscible flooding. The range of values of the ratio, indicating the amount of oil in barrels per net Mg of injected CO2, is estimated from literature values. According to Wilson [2000] about 19 million m3 extra oil will be produced in Weyburn (equivalent to 120 mil-lion barrels) with a net amount of 18 Mg of permanently stored CO2. This equals about 0.15 Mg of CO2 per barrel of oil. Espie [2000] reports a value of 3.3 barrels of oil for each Mg of CO2 stored in the Permian settings in the North Sea area, or 0.3 Mg CO2 per barrel of oil. Stalkup [1984] reports that the net ratio in four field experiments varies between 0.17 and 0.78 Mg per barrel of oil, gross ratios are roughly twice as high. The ratios used by Stevens [1999b] are in agreement with other literature values: 0.336 Mg per barrel of oil for miscible oil and 0.559 Mg per barrel of oil for immiscible oil. These data are summarised in table 10.


Table 13. Resul ts of CO2-EOR f ie ld tests (after Lysen [2002])

Project Net CO2/oil Ra-tio (103cf/BO1)

Net CO2/Oil ra-tio (Mg/BO) 8

Source

Weyburn 2.7 0.15 Wilson, 2000

Willard-Wasson 3 to 4 0.17 to 0.22 Stalkup, 1984

SACROC main flood 4.6 0.26 Stalkup, 1984

Permian, North Sea 5.3 0.3 Espie, 2000

Average for miscible oil 6 0.336 Stevens, 1999b

Average for immiscible oil

10 0.559 Stevens, 1999b

Little Creek 13.5 0.76 Stalkup, 1984

SACROC tertiary pilot test

5 to 14 0.28 to 0.78 Stalkup, 1984

1 BO = barrel of oil Based on these figures it can be concluded that the ratio for net CO2 injection (in Mg CO2) versus oil production (in barrels of oil) varies approximately between 0.1 and 0.8. In this study, we assumed a low estimate of 0.15, a best estimate of 0.45, and a high estimate of 0.80 Mg CO2 per barrel of oil. The volume of CO2 that can potentially be sequestered is then calculated by: CO2 = EOR × RCO2 With: CO2 = volume of CO2 that can potentially be sequestered (Mg) EOR = extra oil due to enhanced oil recovery by CO2 injection, in barrels

of oil (BO) RCO2 = ratio for net CO2 injection versus oil production (Mg/BO) A low, best and high estimate for both the total CO2 to be sequestered and oil pro-duced was calculated. From the USGS assessments, values are given for the cumu-lative amount of oil produced in the past, the amount of proven oil not yet produced (remaining oil) and an estimate of the undiscovered resources. These values are considered to be equivalent to the URR, sensu Stevens [1999b], who also used the USGS assessments. The undiscovered resources are assumed to represent figures based on non-EOR recovery. Given the uncertainty in the undiscovered resources, three estimates are reported, called F5, F50, and F95. These indicate, respectively, that there is a certainty of 95, 50, and 5% that the amount of oil is at least as high as the reported value. The low estimate is calculated by: EOR = [“remaining oil” + F5] / (maximum API gravity +5)/100) × (minimum

%EXTRA/100) × C

CO2 = EOR × (minimum RCO2)

8 103cf/BO is converted to Mg/BO by multiplication with 0.056.


The best estimate is calculated by: EOR = [“remaining oil” + F50] / (median API gravity +5)/100) × (intermediate

%EXTRA/100) × C

CO2 = EOR × (intermediate RCO2) The high estimate is calculated by: EOR = [“remaining oil” + F95] / (minimum API gravity +5)/100) × (maximum

%EXTRA/100) × C

CO2 = EOR × (maximum RCO2) Table 20 in the annex shows the results per region. A summary of the results is given in Table 15. Although we realise that this is a very rough calculation, it is considered to be acceptable within the scope of this project. However, it must be noted that the calculated storage potential assumes that all future oil is produced with CO2-EOR. We consider it therefore as an estimate for the storage potential of the oil reservoirs with oil still remaining underground. This potential is indicated by ‘remaining oil’ in the tables and figures in the annex. The results of this study are considered to be in agreement with that of Rogner [1997]. Rogner [1997] states that in the past, on average only 34% of the in-situ oil was recovered with primary or secondary production methods. An additional fraction of the original in situ oil can be recovered from both abandoned and existing fields with advanced production technologies, these are the enhanced recovery technologies. Rogner [1997] assumed in his assessment that in future conventional oil production utilizes 40% of the in-situ occurrences. Rogner [1997] assumes that in addition to the present average of 34%, another 10% of the original in situ oil could be recovered from existing fields with advanced production techniques. The enhanced recovery potential for oil is estimated at 15% of the original in situ quantities. These figures fit well in the range of 5 to 20% indicated for CO2 enhanced production by Stevens [1999b]. However, it must be noted that Rogner [1997] includes all types of enhancement techniques while Stevens [1999b] considers only CO2 injection. Rogner [1997] estimates the total potential for enhanced recovery on 138 × 109 oil equivalents. Assuming an average oil density of 860 kg/m3 (BP, 1992) and a barrel of oil equaling 0.159 m3, this amount equals about 1.01 × 1012 BO. In this study, the calculated amount (in BO) for the enhanced recovery is 0.06 × 1012, 0.25 × 1012 and 0.92 × 1012 as, respectively, minimum, median, and maximum value. Given the uncertainties in the calculations we consider these values in fairly good agreement.

3.2.2 Oil reservoir:storage in depleted oil fields

The calculation of the volumes of CO2 that can potentially be sequestered in de-pleted oil reservoirs, thus without the simultaneous production of oil, is the reser-voir volume that was occupied by the produced oil. Basic assumption is that the volume of oil produced is related to the volume that can be occupied by the CO2. Part of the volume that was occupied by the oil will be occupied by water that can not be replaced by the CO2. Arbitrary, it is assumed that for the low, best, and high


estimate, respectively, 40, 60, and 80% of the original space can be used for CO2 storage. In the previous paragraph it was assumed all future oil is produced with CO2-EOR and that these reservoirs under EOR-production have no further storage potential. In line with these assumptions we have limited the calculations of the storage po-tential in depleted oil fields to those fields that are currently depleted. CO2 = [Total oil produced in the past] × [volume of BO] × [CO2-density] × S/100 With: CO2 = total storable CO2 [kg] [produced oil] = Total oil produced in the past (BO) [volume of BO] = volume of one barrel of oil [0.159 m3] [CO2-density] = density of CO2 at reservoir depth [750 kg/m3] S = “space factor”, % of the original space that can be used for

CO2 storage The value for the total, or cumulative, oil produced in the past is taken from the USGS assessments. For the USA the cumulative volume of produced oil is not re-ported, therefore a rough and arbitrary assumption has been made that 60% of all known oil was produced. From a CO2 storage point of view it can be concluded, under our assumptions, that the total storage potential decreases when large scale EOR-operations are postponed, given the fact that 3 to 10 times more CO2 can be stored in EOR operations than in depleted oil fields.9 Table 20 in the annex shows the results per region. A summary of the results is given in Table 15.

3.2.3 Gas reservoir: storage in operational gas fields

There are still many (economic) risks involved in the injection of CO2 in gas fields while simultaneously producing natural gas. Natural gas contaminated with CO2 has to be “cleaned” before it can be sold to the market. The calculated storage po-tential in this paragraph will, most likely, not become available until normal pro-duction ceases. The compressibility of CO2 under typical reservoir studies is significantly larger than the compressibility of natural gas. This means that a void space within the res-ervoir can store a much larger volume of CO2 (measured at standard pressure and temperature conditions) than methane [Stevens, 1999]. Additionally, the mass of the stored CO2 is far greater than the mass of the natural gas because the weight of a mole of CO2 is much greater than that of methane. As a conservative measure, it was assumed that 75% of the void space created by exploiting natural gas fields could be replaced with CO2, sensu Stevens [1999b].

9 the product of {[volume of BO] × [CO2-density] × S/100 } is 3 to 10 times smaller than the ratio for net CO2 injection versus oil production used in EOR


The number of moles of gas that occupies a certain volume at reservoir level is cal-culated by the gas law. It is assumed that at surface conditions the number of moles within a certain volume is equal for a CO2 and CH4. Gas law:

P

TRnzV

×××=

Thus:

zTR

PVn

×××=

With: V = volume at p and T (m3)

P = absolute pressure (N/m2 = Pa) n = number of moles (mole) T = absolute gas temperature (°K) R = gas constant (8.31441 J/mole · K) z = compressibility factor (dimensionless)

Assuming an equal volume V at reservoir depth, and given that P, T, and R are similar for CO2 and for CH4, the molar ratio can be calculated.

22

COCO zTR

PVn

×××=

44

CHCH zTR

PVn

×××=

Thus:

2

4

4

2

4

2

1

1

CO

CH

CH

CO

CH

CO

z

z

z

z

n

n==

Thus, the molar ratio can be calculated by taking the ratio between the compressi-bility factors of CH4 and CO2. Figure 3.2 shows this resulting molar ratio. A ratio of 3 indicates that in a similar volume at reservoir depth 3 times more molecules of CO2 occupy that volume than would be the case for CH4 molecules at similar con-ditions.


y = 2E-07x 2 - 0.0015x + 4.1707

0

0.5

1

1.5

2

2.5

3

3.5

4

0 1000 2000 3000 4000 5000Depth

RatioCO2/CH4

Figure 3.2. Molar rat io of CO2/CH4 vs depth

From the USGS assessments values are given for the cumulative amount of gas produced in the past, the amount of proven gas not yet produced (remaining gas) and an estimate of the undiscovered resources. Given the uncertainty in the undis-covered resources, three estimates are reported, called F5, F50, and F95. These in-dicate, respectively, that there is a certainty of 95, 50, and 5% that the amount of gas is at least as high as the reported value. The value for the remaining gas is taken from the USGS assessments. For the USA the cumulative volume of produced gas is not reported, therefore a rough and arbi-trary assumption has been made that 40% of all known gas is still not produced. Using the minimum, median and maximum depth of the reservoir the low, median, and best CO2/CH4 ratio was calculated. The low estimate is calculated by: CO2 = 0.75 × [“remaining gas” + F5] × (minimum ratio CO2/ CH4) × density CO2 The best estimate is calculated by: CO2 = 0.75 × [“remaining gas” + F50] × (median ratio CO2/ CH4) × density CO2 The high estimate is calculated by: CO2 = 0.75 × [“remaining gas” + F95] × (maximum ratio CO2/ CH4) × density CO2 With:

CO2 = volume of CO2 that can potentially be stored (Mg) [“remaining gas” + F#] = total gas volume (m3) ratio CO2/ CH4 = volumetric ratio at reservoir depth (no unit) density CO2 = density CO2 at surface conditions, 1.98 × 10-3 Mg/m3

Table 20 in the annex show the results per region. A summary of the results is given in Table 15. Rogner [1997] states that in the past, on average only 70% of the in-situ natural gas was recovered with primary or secondary production methods. An additional


fraction of the original in situ gas can be recovered from both abandoned and existing fields with advanced production technologies, these are the enhanced recovery technologies. Rogner [1997] assumed in his assessment that in future conventional gas production utilizes 80% of the in-situ occurrences. This implies an increase in the gas production of 10% due to enhancement techniques. However, little is known about the enhancement effect, as can be concluded from the remark by Rogner [1997], who states that “So far, there has been no need to develop and deploy enhanced gas recovery methods. Extensive fracture stimulation comes closest to enhanced gas recovery”. The enhancement effect of CO2 injection is, to our knowledge, so far unknown. Therefore, in this study no enhancement effect is assumed for gas production.

3.2.4 Gas reservoir: storage in depleted gas fields

The same procedure was applied for storage in depleted gas fields. Instead of using the future gas (remaining + undiscovered) for the calculations, the value for the to-tal gas produced in the past was used. The value for the total, or cumulative, gas produced in the past is taken from the USGS assessments. For the USA the cumula-tive volume of produced gas is not reported, therefore a rough and arbitrary as-sumption has been made that 60% of all known gas was produced. Using the mini-mum, median and maximum depth of the reservoir the low, median, and best CO2/CH4 ratio was calculated. Table 20 in the annex show the results per region. A summary of the results is given in Table 15.

3.3 Coa l bas ins

3.3.1 Coal basin: in storage in ECBM operations

The global digital map of coal occurrences (constructed on several sources, amongst other IGCP 166, 1980) was used for the inventory of CO2 sequestration potential in coal basins. Although this inventory is not complete, it provides a rep-resentative overview of the major global coal occurrences. Lignite occurrences were excluded from the evaluation, since the possibility of CO2 storage in these low rank coals is still questionable. It is unlikely that the total area of the coal basins can be used for CO2 sequestration, e.g. because of the large number of wells required for ECBM operations. Conserva-tively, it was assumed that 10% of the total area could be used in the future. The amount of producible CBM and the amount of storable CO2 were estimated by the following calculation: PG = 0.1 × A × TH × ρcoal × GC × RF SCO2 = PG × ER× ρCO2 With: PG = producible gas [m3] SCO2 = storable CO2 [kg] A = surface area of coal basins [m2]


TH = cumulative thickness of the coal [m] ρcoal = coal density [Mg/m3] GC = gas content [m3

STP gas/Mg coal] RF = recovery factor [-] ER = exchange ratio [-] ρCO2 = density of CO2 at standard p, T conditions [= 1.977 kg/m3] Of course, this is a very rough calculation since it assumes homogeneous deposits throughout the investigated area. The recovery factor is an estimation of the part of the gas-in-place that can be re-covered. This depends among others on the completion of the separate coal seams and on the pressure drop that can be realised by pumping off large volumes of wa-ter. The production of CBM by conventional methods is often inefficient: normally only about 20% to 60% of the original GIP can be recovered. With gas injection the CBM recovery can be increased theoretically up to 100% [Stevens, 1999a]. Con-servatively, we assumed a recovery of 40%. The amount of CO2 (in m3) that can potentially be stored in the coal seams will be larger than the produced methane: based on experimental data from several authors [e.g. Puri, 1990; Stevenson, 1991; Hall, 1994] it is generally assumed that 2 mole-cules of CO2 replace one molecule of CH4. This ratio is called the Exchange Ratio. The adsorption capacity of coal for supercritical CO2 (P > 0.74 MPa) is probably much higher, possibly up to 5:1 at 12 MPa [Hall, 1994; Krooss, 2002]. Based on the literature and on laboratory results, it is very likely that the adsorption capacity of coals, and therefore the ER, increases to some extent with increasing depth. A low, best and high estimate for both the total CO2 to be sequestered and CBM produced was calculated by varying the exchange ratio from 2 for the low, 2.5 for the best, and 3 for the high estimate. For a limited number of coal fields the cumulative thickness of the coal is known. However, these all refer to minable coal resources, while ECBM operations occur in (deeper) unminable coal resources. The thickness of these deeper coal seems are therefore unknown and could well be zero. The expected coal thickness was esti-mated per region. The low, best and high estimates were calculated by varying the cumulative thickness from 0 for the low, the value for the expected thickness for the best, and twice the value for the expected thickness for the high estimate. Also, depth and gas content of the coal fields are unknown. For the gas content a minimum, intermediate and maximum value of 4, 8, and 20 m3/Mg was applied. Figure 6.10 in the annex shows the results per region. A summary of the results is given in Table 15. Figure 6.5.9 in the annex shows a graphical representation of the global hard coal occurrences.

3.4 Aqui fers

Volumes for CO2 storage potential in aquifers are more difficult to estimate, as already indicated by Hendriks [1994]. Little volumetric information on saline aquifers is known, since they have very limited economical value (contrary to for


example fresh water aquifers). Figure 6.5.8 in the annex shows the major sedimentary basins worldwide. The occurrence of saline aquifers is restricted to these basins. However, this does not imply that apropriate aquifers can be found in every part of these sedimentary basins. The total cumulative area of these basins is calculated to be about 80 million square kilometers, slightly higher than an earlier estimate of 70 million km2 by Hendriks [1994]. The relative distribution of the surface area of sedimentary basins in the 18 areas as defined in TIMER are shown in Figure 3.3.

Canada7%U.S.A. 7%

Central Am. 3%

South Am. 10%

Northern Afr. 6%

Western Afr. 6%

Eastern Afr. 2%

Southern Afr. 6%

Western Eur. 3%Eastern Eur.

1%

Former S.U.14%

Middle East 4%

Southern Asia 9%

Eastern Asia 6%

South East. Asia 3%

Oceania

12%

Japan1%

Greenland 1%

Figure 3.3. The re lat ive d is tr ibut ion of the surface area of sedimentary

basins in the 18 areas as def ined in TIMER.. Note that these

percentages resul t f rom rough calcaulat ions, and should be

considered as indicat ive)

In this study the assumptions by Hendriks [1994] are taken for the volume calculations of the median value. A value of 750 kg/m3 is taken for the density of the CO2, assuming that only aquifers below 750 m depth will be used for storage. Values for minimum and maximum are chosen arbitrarily, but within natural limits (Table 14). In this study we use the “prudent” approach, as identified by Hendriks [1994], taking the assumptions that about 1% of the aquifer is part of a structural trap and only 2% of the structural trap can be filled with CO2 [Van der Meer, 1992]. This 2% is a conservative value, since other studies indicate a much higher value (e.g. Wildenborg, [1999]).


Table 14. Range of aquifer thickness and porosity used in th is study

Aquifer thickness (m) Porosity (%) Minimum 50 5

Best 100 20

Maximum 300 30

The low estimate is calculated by: CO2 = area × Minimum Aquifer thickness × 0.01 × 0.02

× (Minimum porosity / 100) × density CO2 × 10-12 The best estimate is calculated by: CO2 = area × Best Aquifer thickness × 0.01 × 0.02

× (Best porosity / 100) × density CO2 × 10-12 The high estimate is calculated by: CO2 = area × Maximum Aquifer thickness × 0.01 × 0.02

× (Maximum porosity / 100) × density CO2 × 10-12 With:

CO2 = volume of CO2 that can potentially be sequestered (Pg) Area = surface area of sedimentary basins (m2) Aquifer thickness = thickness of aquifer (m) Porosity = porosity of the rock (%) Density CO2 = density CO2 at surface conditions (1.98 × 10-3 Mg/m3)

Table 20 in the annex shows the results per region. A summary of the results is given in Table 15.

3.5 Resu l ts o f the ca lcu la t ions

The ‘best’ estimate for total storage potential worldwide is about 1660 Pg CO2 (=Gtonne of CO2). This equals about 80 years of currently worldwide annual net emission of carbon dioxide to the atmosphere. The calculated storage potential ranges from 500 Pg (‘low’ estimate) to 6000 Pg (‘high’ estimate). The annex pre-sents tables with potentials for each region (Table 20).


Table 15. Est imate for underground CO2 storage potentia l for var ious un-

derground reservoirs

CO2 seq potential (Pg CO2) CO2 seq potential (Pg CO2) Total Low Best High Low Best High

Remaining oil fields onshore 9 112 734

Remaining oil fields offshore 3 37 308

Depleted oil fields onshore 22 33 44

Depleted oil fields offshore 20 60 107

54 242 1194

Remaining gas fields onshore 219 391 925

Remaining gas fields offshore 149 281 778

Depleted NG fields onshore 4 219 391

Depleted NG fields offshore 20 20 32

392 910 2126

ECBM 0 267 1480 0 267 1480

Aquifers 30 240 1081 30 240 1081

Total 476 1660 5880 476 1660 5880 Table 17 presents storage estimates from literature sources. The calculated values in this study are in very reasonable agreement with those published elsewhere. The ‘best’ estimate of total storage capacity in oil and gas field (depleted and non-depleted) is in the range 1000 to 1800 Pg CO2. The storage potential by ECBM es-timated in this study is about twice as high as in Ref[3]/Ref[4]. It should be noted that there are considerable uncertainties around this estimate. The estimate on aquifers is in good agreement with the ‘conservative’ estimate in Ref[2] (see Table 16), especially given the fact that other sources were used to es-timate the aquifer surface area. The major differences are caused by the allocation of the areas of the Former Sowjet Union to Asia or to Eastern Europe.However, if a less ‘prudent’ approach is taken, i.e. less strict requirement for closed structures, the total storage capacity might be manifold.


Table 16. Compar ison between volume ca lcu lat ions of Hendr iks [1994]

and this s tudy for storage in aquifers

Hendriks [1994] This study Area Storage

capacity Area Storage Capac-

ity Minimum Storage Capac-

ity Best Storage Ca-pacity Maxi-

mum

Pg Pg Pg Pg

Canada 2 17 78 U.S.A. 2 17 78

North America 40 4 35 155

Central Am. 1 7 33

South Am. 3 23 103

Latin America 40 4 30 136

Northern Afr. 2 13 61

Western Afr. 2 15 68

Eastern Afr. 1 5 25

Southern Afr. 2 14 63

Africa 40 6 48 216

Western Europe 1 7 32

Western Europe 10 1 7 32

Eastern Eur. 0 3 15

Eastern Europe 30 0 3 15

Former S.U. 4 33 148

Southern Asia 3 21 96

Eastern Asia 2 13 60

South East. Asia 1 6 29

Oceania 4 28 126

Japan 0 2 8

Oceania and Asia 50 13 104 468

Middle East 1 10 44

Middle East 10 1 10 44

Greenland 0 3 15

0 3 15

Total 220 30 237 1066

Table 17. Compar ison of storage est imates (Pg CO2)

Ref[1] Ref[2] Ref[3]/Ref[4] Ref[5] Ref[6] Oil fields 385 370 126 242

Gas fields 500-1800

1500 1500 800 910

ECBM na na 150 na 267

Aquifers na 200 4000 na 240

Ref [1]: Turkenburg [1999] Ref [2]: Hendriks [1994] Ref [3]: IPCC [2001]

Ref [4]: ARC [2000] Ref [5]: Stevens [2000] Ref [6]: this study


3.6 Cost curves for s torage of carbon d iox ide

The potentials for carbon dioxide storage per region are shown in cost curve dia-grams in the annex. The costs comprise the summation of the average costs for storage in the reservoir and the estimated average regional transport costs. The transport costs per region are determined by estimating the average distance of economic centres (i.e. concentration of CO2 sources) to each type of storage reser-voirs. The transport costs are categorised in five so-called cost-windows (see Table 18).

Table 18. Transport costs for four cost-w indows. I t is assumed that for

transport over larger d istances more CO2 transports wi l l be

combined leading to larger p ipel ines and smal ler specif ic costs

per km-transport

Distance Source – Stor-age reservoir

Average distance (km)

Average costs (€/Mg CO2)

Short < 50 km 1

Medium 50 – 200 3

Long 200 – 500 5

Very long 500 and 2000 10

Extreme long 2000 and more 30

The estimated transport costs per region are shown in Table 19. The costs estima-tion is made on basis of the information on carbon dioxide emissions; Figure 6.5.5 (Global CO2 point sources), Figure 6.5.6 (GDP per grid cell) and on information on reservoir occurrences; Figure 6.5.7 (oil and gas) Figure 6.5.8 (hard coal basins) and Figure 6.5.9 (saline aquifers). The figures can be seen in the annex. It should be noted that this approach gives a very rough indication of the costs. The costs represent average costs per region. In the case various economic centres or concentrations of CO2 sources are present, transport and storage costs might deviate considerably between locations. It was, however, outside the scope of this study to elaborate on this in more detail.


Table 19. Est imated transport costs per region per type of storage

reservoir (€/Mg CO2)

Aquifers Oil and gas onshore

Oil and gas offshore

Coal

Canada 5 5 10 5

U.S.A. 5 5 30 5

Central Am. 3 1 5 10

South Am. 3 3 3 1

Northern Afr. 3 3 3 30

Western Afr. 3 5 5 30

Eastern Afr. 5 5 30 30

Southern Afr. 3 5 3 3

Western Eur. 3 5 3 3

Eastern Eur. 10 1 30 3

Former S.U. 10 10 30 30

Middle East 3 1 3 30

Southern Asia 5 10 3 5

Eastern Asia 10 5 10 3

South East. Asia 5 3 3 10

Oceania 3 30 10 5

Japan 5 30 10 3

Greenland 10 30 10 30



4 Experience curves

Carbon dioxide capture and storage systems are in an early stage of development. The reported costs concern full-scale plants (thus not demonstration, pilot or plants built in the initial phase of implementation of the technology) and the costs should be regarded as indicative only. Actual costs could differ ± 30% from the reported costs. Large-scale deployment of the carbon dioxide sequestration systems will most certainly lead to systems with lower energy penalties and lower costs than systems put into operation in the first years of implementation. For a quantification of such learning curves, Rubin [2002] examined the develop-ment of flue gas desulphurization systems (FGD) and selective catalytic reduction systems to control NOx emissions (SCR). Improvements in performances and re-duction in cost of this technology have accompanied the deployment of FGD sys-tems over the past several decades. Cost reductions are typically described by an equation of the form: yi = axi

-b, where yi = cost to produce the ith unit, xi = cumula-tive production through period i, b = the learning rate exponent, and a = coefficient (constant). According to this equation, each doubling of cumulative production re-sults in cost savings of (1 – 2-b), which is defined as the learning rate, while the quantity 2-b is defined as the progress ratio. These cost reductions reflect not only the benefits of learning by doing at existing facilities, but also the benefits derived from investment in research and development that produce new knowledge and generations of a technology. Total capital costs for FGD and SCR show a significant decline over time. Both technologies became implemented significantly in the early eighties. The observed learning rates are 11% and 12% for FGD and SCR systems, respectively. Many of the process improvement that contributed to lower costs were the result of sustained R&D programs and inventive activity (especially improved understanding and con-trol of process chemistry, improved materials of construction, simplified absorber designs, and other factors that improve reliability). Increased competition between FGD and SCR vendors also may have been a contributing factor. A careful look at the underlying technological changes over several decades indicates that the cost reduction primarily reflect the fruits of technology innovation. Carbon sequestration systems are also environmental control systems. These sys-tems have similarities with the FGD and SCR systems, but also essential differ-ences can be observed (e.g. the energy costs share is substantial larger in carbon di-oxide sequestration systems than in the other systems, and total investment costs per plant are significantly larger). Nevertheless, the results presented can provide useful guidelines for assessing the influence of technological change on future compliance costs for carbon dioxide sequestration systems. In addition it should be noted that most cost figures available to date result from desktop studies and are not


derived from actually made investments. It is not unusual that costs increase at first plant construction, before cost reductions can be observed. Costs for storage are also likely to reduce when storing CO2 underground is in-creasingly deployed. The possibilities to reduce costs for storage in depleted fields and aquifers will probably be less than for EOR and ECBM. Costs for depleted res-ervoirs are mainly related to drilling wells, a current mature technology. Neverthe-less, reductions may be obtained by a better understanding of the storage process. This may lead to less required monitoring and observation wells and improved de-sign of the storage location. Little information is available for EOR and ECBM. Better understanding of the ‘underground processes’ of these options might lead to considerable cost reduction. For these options, however, the price of the oil and natural gas is of large influence on the storage costs. High energy prices may even lead to benefits for CO2 storage. Figure 4.1 shows the development of costs for three different carbon dioxide se-questration activities: capture, transport and storage. In the figure we assume (arbi-trarily) that when 2% of the total capture potential has been implemented, the se-questration cost level is at the level as reported in this study. When the reported cost level will be reached depends on the activity level that will be developed to carry out RD&D on carbon dioxide sequestration technology and to the level of implementation. For capture technology we assume the same learning rate as for deNOx and deSOx systems has been observed (12%, b = -0.184). For transport we assume arbitrarily 5% (b=-0.074) and for storage activities we assume arbitrarily 8% (b=-0.120).

0%

25%

50%

75%

100%

125%

150%

175%

200%

225%

0% 10% 20% 30% 40% 50% 60% 70%

Cumulative implemented CO2 capture (% of maximum)

Rel

ativ

e co

sts

(% o

f b

ase

cost

s)

costs (capture) costs (transport) costs (transport)

Figure 4.1. Development of carbon dio ixde sequestrat ion costs for

capture, transport and storage. Assumed is that reported

costs are val id when 2% of the potentia l has been

implemented. The learn ing rate assumed is 12% cost

decrease by doubl ing of the capaci ty (for capture), 5% (for

transport) , and 8% (for storage)


5 Conclusions

Carbon dioxide might be stored underground in five different types of reser-voirs: depleted oil and gas field, coal beds (combined with enhanced coal bed methane recovery), in producing oil fields (combined with enhanced oil recovery), and in saline aquifers. The total estimated underground storage potential is estimated to range from 500 to 6000 Pg. The ‘best’ estimate amounts to 1660 Pg. Natural gas fields of-fers the highest storage potential. The potential for aquifers is estimated to range from 30 to 1100 Pg. However, when requirements for a closed structure are less severe, the potential in aquifers might be manifold. Hydrocarbon reservoirs may offer the lowest costs for storage. Onshore stor-age is generally less expensive than offshore storage. Extra produced oil or extra produced natural gas recovery often reduce costs for storage. The costs will range considerably from project to project and are also very dependent on the actual oil and gas price. In various cases it could be economically beneficial to apply enhanced oil recovery. Storage combined with enhanced coal bed methane is currently often more expensive because of to the large amounts of wells required. The carbon dioxide can be recovered from industrial sites and from power plants. In this report the capture cost is expressed in €/Mg CO2 avoided. This might be a useful way to compare different mitigation strategies. However, technologies with lowest capture costs will not automatically represent the technology with the lowest mitigation costs. Capture costs depend on applied technology and fuel used. Another way to compare mitigation costs (and probably a more objective way) is to present (electricity) production costs (e.g. in €/kWh) for technologies with equal emission factor. Capture costs are about 26 €/Mg CO2 (coal-fired plants) to 29 to 43 €/Mg CO2 (natural gas-fired plants). Power production costs increase with 35 to 40 percent (IGCC, and capture from natural gas-fired plants) to about 50% for pulverised coal-fired plants. Costs for industrial sources are in the range of 35 to 45 €/Mg CO2. Costs depend on the level of concentration of carbon dioxide in the flue gas and the availability of ‘waste’ heat at or nearby the plant site. The reported costs concern full-scale plants and do not reflects costs for demonstration plants and pilot plants. Costs to compress the captured carbon dioxide range roughly from 6 to 10 €/Mg CO2. About 60% of the costs are electricity use. Compression costs are considerably higher for small flows. Transport costs over 100 km range from 1 to 6 €/Mg CO2. The high end of the costs is for flows of 25 kg/s. For flows larger than 250 kg/s the costs are about 2 €/Mg CO2. When higher velocities through the pipeline can be applied, costs may be futher reduced. Over 50% of the costs are formed by depreciation costs. The av-erage transport costs per region per type of reservoir vary from 1 to over 30 €/Mg CO2. The uncertainty in the reported costs is about ± 30%.



References

Alberta Research Council, 2000. Enhanced Recovery of Coalbed Methane / Carbon Dioxide Sequestration, Report for the IEA Greenhouse Gas R&D Programme (PH3/34).

Audus, 2000. Leading Options for the Capture of CO2 at Power Stations, H. Audus, in Proceedings of the 5th Greenhouse Gas Control Technology Confer-ence, August 2000.

Bolland, 1992. New Concept for Natural Gas Fired Power Plants which simplify the Recovery of Carbon Dioxide. Energy Convers. Mgmt., 33(5-8), pp467-475 (1992).

Bolland, 2000. Natural Gas Fired Power Cycles with Integrated CO2 Capture, O. Bolland, H. Undrum, and M. Myhre-Nielsen, in Proceedings of the 5th Green-house Gas Control Technology Conference, Cairns, Australia, August 2000.

BP, 1992. BP Review of the World, The British Petroleum Company (p.189).

Chiesa, 1998. A Comparative Analysis of IGCCs with CO2 Sequestration, P. Chi-esa, S. Consonni, and G. Lozza, in Proceedings of the 4th Greenhouse Gas Control Technology Conference, Interlaken, Switzerland, September 2002.

Chiesa, 1999. Natural Gas Fired Combined Cycle with Low CO2 Emissions, P. Chiesa, and S. Consonni, 44th ASME Gas Turbine and Aeroengine Congress, Indianapolis, USA.

Condorelli, 1991. Engineering and Economic Evaluation of CO2 Removal from Fossil-fired Power Plants, Volume 2: Coal Gasification Combined Cycle Power Plants, , P. Condorelli, SC Smelser, and G.J. Mc Cleary, Electric Power Research Institute, Report # IE-7365 (1991).

Dave, 2000. Economic Evaluation of Capture and Sequestration of CO2 from Austra-lian Black Coal-fired Power Stations, N.C. Dave, G.J. Duffy, J.H. Edwards, and A. Lowe, in Proceedings of the 5th Greenhouse Gas Control Technology Con-ference, Cairns, Australia, August 2000.

Doctor, 1996. KRW Oxygen-Blown Gasification Combined Cycle: Carbon Dioxide Recovery, Transport and Disposal, Argonne National Laboratory, ANL/ESD-34 (1996).

Espie, 2000. Options for Establishing a North Sea Geological Storage Hub, AA. Espie, in: Williams, D., Durie, B., McMullan, P., Paulson, C. & Smith, A. (eds.), Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT V), Cairns, Australia, ISBN 0 643 06672 1.

Foster and Wheeler, 2000. CO2 Capture via Partial Oxidation of Natural Gas, IEA GHG R&D Programme, report PH3/21.


Foster and Wheeler, 2000. Precombustion Decarbonisation, IEA GHG R&D Pro-gramme, report PH2/19.

Gambini, 2000. CO2 Emission Abatement from Fossil Fuel Power Plants by Exhaust Gas Treatment. M. Gambini and M. Vellini, Proceedings of 2000 International Joint Power Generation Conference, Florida, (2000).

Hall, 1994. Adsorption of Pure Methane, Nitrogen, and Carbon Dioxide and Their Binary Mixtures on Wet Fruitland Coal, Hall, F.E., Chunhe Zou, Gasem, K.A.M., Robinson, R.L., and Yee, D., SPE 29194, Eastern Regional Confer-ence & Exhibition, Charleston, WV, pp. 329-344.

Hendriks, 1991. Technology and Cost of Recovering and Storing Carbon Dioxide from an Integrated Gasifier Combined Cycle Plant, Hendriks C.A, K. Blok, and W.C. Turkenburg, Energy, the international Journal, 16(11/12) (1991).

Hendriks, 1992. Verwijdering en opslag van CO2 bij de elektriciteitsopwekking (Re-covery and Storage of CO2 from Power generation), C.A. Hendriks, J.C.M. Farla, and K. Blok, Department of Science, Technology and Society, Utrecht University, the Netherlands (1992).

Hendriks, 1994. Carbon Dioxide Removal from Coal-fired Power Plants. C.A. Hendriks, Kluwer Academics Publisher, Dordrecht, the Netherlands (1994).

Hendriks, C.A., Van der Waart, A.S., Byers, C., Phylipsen, D., Voogt, M., and Hofman, Y. Building the cost curve for CO2 storage: sources of CO2,, March 2002.

IGCP 166, 1980. World Coal Fields, editor Rijks Geologische Dienst, the Nether-lands.

IPCC, 2001. Climate Change 2001: Mitigation, Part of third Assessment Report by WGIII of Intergovernmental Panel on Climate Change, 2001.

Krooss, 2002. High-pressure methane and carbon dioxide adsorption on dry and moisture-equilibrated Pennsylvanian coals, Krooss B.M., van Ber-gen F., Gensterblum Y., Siemons N., Pagnier H.J.M., David P., Interna-tional Journal of Coal Geology 51, 69– 92.

Lysen, 2002. PEACS, Opportunities for Early Application of CO2 sequestra-tion Technology, Lysen, E.H., editor, International Energy Agency Greenhouse Gas R&D Programme, July 2002.

Mariz, 1995. Carbon Dioxide Recovery: Large Scale Design Trends, Sixth Petro-leum Conference at the South Saskatchewan Section, The Petroleum Society of CIM, Regina Canada (1995).

Novem, 2001. Potential for CO2 sequestration and Enhanced Coal bed Methane Production in the Netherlands, Novem, Sittard, 2001.

Parson, 1996. Carbon Dioxide Recovery in Air-blown and oxygen-blown Integrated Gasification Combined Cycle Power Plants, , IEA GHG R&D Programme, report PH2/4.


Pruschek, 1996. Concepts of CO2 Removal from Fossil-fuel Based Power Genera-tion Systems, R. Pruschek and G. Gottlicher, Universität GH Essen.

Puri, 1990. Enhanced Coalbed Methane Recovery, Puri, R., and Yee, D., SPE paper 20732.

RIVM, 2002. Written communication October 2002, Bilthoven, the Nether-lands.

Rogner, 1997. An Assessment of World Hydrocarbon Resources, H-H. Rogner, Annual Rev. Energy Environ. 1997, pp. 217-262.

Rooijers, 2002. Van Restwarmte naar nuttige warmte in de Rijnmond, Rooijers, F.J., F. de Haan, M. Groot, K. Blaauw, S. Slingerland, K. Slin-gels, I. de Keizer, CE, Delft, 2002.

Rubin, 2002. Experience Curves for Environmental Technology and their Relation-ship to Government actions, E.S. Rubin, M.R. Talor, S. Yeh, and D.A. Houn-shell, Proceedings of the 6th Greenhouse Gas Control Technology Conference, Kyoto, Japan, October 2002.

Simbeck, 1998. A Portfolio Selection Approach for Power Plant CO2 Capture, Separation and R&D Options, D. Simbeck, in Proceedings of the 4th Green-house Gas Control Technology Conference, August 1998, Interlaken, Switzer-land.

Smelser, 1991. An Engineering and Economic Evaluation of CO2 Removal from Fossil Fuel-fired Power plants, Vol 1: Pulverised Coal-fired Power Plants. Electric Power Research Institute, Report IE-7365.

Stalkup, 1984. Miscible Displacement, Stalkup, F.I., SPE Monograph Series, Vol-ume 8, ISBN 0-89520-319-7.

Stevens, 1999a. CO2 injection for Enhanced Coal bed Methane Recovery: Project screening and design, Stevens, S.H., and Pekot, L., in Proc. of the 1999 Int. CBM Symp., Tuscaloosa, Alabama.

Stevens, 1999b. Sequestration of CO2 in Depleted Oil and Gas Fields: Barriers to Overcome in Implementation of CO2 Capture and Storage (Disused Oil and Gas Fields), Stevens, S.H., V.A. kuuskraa, and J.J. Taber, Report for the IEA Greenhouse Gas R&D Programme (PH3/22).

Stevenson, 1991. Adsorption/Desorption of Multicomponent Gas Mixtures at In-Seam Conditions, Stevenson, M.D., Pinczewski, W.V., Somers, M.L., and Bagio, SPE 23026.

TNO, 2002. This study.

Turkenburg, 1999. Fossiele brandstoffen in een duurzame energievoorziening: de betekenins van CO2-verwijdering, Turkenburg, W.T., and C.A. Hendriks, Na-tuurwetenschap en Samenleving en Ecofys, Utrecht (1999).

U.S. Geological Survey, 1996 [1], U.S.G.S. Digital Data Series 30, 1995 National Assessment of United States Oil and Gas Resources


U.S. Geological Survey, 2000, U.S.G.S. Digital Data Series 60, U.S.G.S. World Petroleum Assessment 2000.

Van der Meer, 1992. Investigation regarding the storage of carbon dioxide in aquifers in the Netherlands, L.H.G. van der Meer, J. Griffioen, and C.R. Geel, TNO-NITG, Delft, the Netherlands.

Waples, 1985. Geochemistry in petroleum exploration, Waples, D., Geological sci-ence Series, ISBN 90-277-2086-X, p. 217.

Wilson, 2000. CO2 sequestration in oil reservoirs – a monitoring and research op-portunity, Wilson, M., Moberg, R., Stewart, B., and Thambimuthu, K., in: Wil-liams, D., Durie, B., McMullan, P., Paulson, C. & Smith, A. (eds.), Proceedings of the Fifth International Conference on Greenhouse Gas Control Technologies (GHGT V), Cairns, Australia, ISBN 0 643 06672 1.

Wildenborg, 1999. Kostencalculatie van CO2-verwijdering via ondergrondse op-slag – KOCA-CO2, in Dutch, Wildenborg, A.F.B., Hendriks, C., Van Wees, J.D., Floris, F., Van der meer, L.G.H., Schuppers, J., Blok, K., Parker-Witmans, N., TNO/Ecofys-rapport NITG 99-128B.


Appendices

GLO

BAL

CARBO

N D

IOXID

E S

TO

RAG

E P

OTEN

TIA

L A

ND

CO

STS

41

012345678910

Doc

tor

(199

6)

Chi

esa

(199

8)

Sim

beck

(199

8)

Con

dore

lli(1

991)

H

endr

iks

(199

4)

Aud

us(1

995)

P

rusc

hek

(199

6)

Par

sons

(199

5)O

2-bl

own

Par

sons

(199

5)A

ir-bl

own

Par

sons

(199

5)A

ir-bl

own

Sto

rk(2

000)

C

ompr

imo

(200

1)

Electricity production costs (euroct/kWh)

020406080100

120

140

Capture costs (euro/MgCO2 avoided)

Ele

ctric

ity p

rodu

ctio

n co

sts

with

out c

aptu

re1

[eur

oct/k

Wh]

Ele

ctric

ity p

rodu

ctio

n co

sts

with

cap

ture

[eur

oct/k

Wh]

Cos

t of c

aptu

re [e

uro/

MgC

O2]

Fig

ure

6.5

.1.

Co

mp

ari

so

n o

f e

lectr

icit

y p

rod

ucti

on

co

sts

an

d C

O2 c

ap

ture

an

d c

om

pre

ssio

n c

osts

fo

r C

O2 c

ap

ture

fro

m I

nte

gra

ted

Ga

sif

ier

Co

mb

ine

d C

ycle

s o

n e

qu

al

eco

no

mic

ba

sis

GLO

BAL

CARBO

N D

IOXID

E S

TO

RAG

E P

OTEN

TIA

L A

ND

CO

STS

42

012345678910

Smels

er (1

991)

Hendr

iks (1

994)

Simbe

ck (1

998)

Mar

iz (1

995)

Dave

(200

0)

Stork

(200

0)


020406080100

120

140


Ele

ctric

ity p

rodu

ctio

n co

sts

with

out c

aptu

re1

[eur

oct/k

Wh]

Ele

ctric

ity p

rodu

ctio

n co

sts

with

cap

ture

[eur

oct/k

Wh]

Cos

t of c

aptu

re [e

uro/

MgC

O2]

Fig

ure

6.5

.2.

Co

mp

ari

so

n o

f e

lectr

icit

y p

rod

ucti

on

co

sts

an

d C

O2 c

ap

ture

an

d c

om

pre

ssio

n c

osts

fo

r C

O2 c

ap

ture

fro

m P

ulv

eri

se

d

Co

al

po

we

r p

lan

ts o

n e

qu

al

eco

no

mic

ba

sis

.

GLO

BAL

CARBO

N D

IOXID

E S

TO

RAG

E P

OTEN

TIA

L A

ND

CO

STS

43

012345678910

Audus

(199

5)

Bollan

d (1

992)

Fos

ter W

heele

r (19

99)

Foste

r Whe

eler (

1999

)

Stork

(200

1)

Simbe

ck (1

998)

Chiesa

(199

9)


020406080100

120

140


Ele

ctric

ity p

rodu

ctio

n co

sts

with

out c

aptu

re1

[eur

oct/k

Wh]

Ele

ctric

ity p

rodu

ctio

n co

sts

with

cap

ture

[eu

roct

/kW

h]

Cos

t of

capt

ure

[eur

o/M

gCO

2]

Fig

ure

6.5

.3.

Co

mp

ari

so

n o

f e

lectr

icit

y p

rod

ucti

on

co

sts

an

d C

O2 c

ap

ture

an

d c

om

pre

ssio

n c

osts

fo

r C

O2 c

ap

ture

fro

m N

atu

ral

ga

s

Co

mb

ine

d C

ycle

s o

n e

qu

al

eco

no

mic

ba

sis

.

GLO

BAL

CARBO

N D

IOXID

E S

TO

RAG

E P

OTEN

TIA

L A

ND

CO

STS

44

012345678910

IGC

C (

pre-

com

bust

ion)

PC

(po

st-c

ombu

stio

n)N

GC

C (

pre-

com

bust

ion)

NG

CC

(po

st-c

ombu

stio

n)C

onve

ntio

nal N

G (

post

-co

mbu

stio

n)


020406080100

120

140


Ele

ctric

ity p

rodu

ctio

n co

sts

with

out c

aptu

re [e

uroc

t/kW

h]E

lect

ricity

pro

duct

ion

cost

s w

ith c

aptu

re [e

uroc

t/kW

h]C

ost o

f cap

ture

[eur

o/M

gCO

2]

Fig

ure

6.5

.4.

Esti

ma

ted

ele

ctr

icit

y p

rod

ucti

on

co

sts

wit

ho

ut

an

d w

ith

ca

ptu

re a

nd

ca

rbo

n d

iox

ide

ca

ptu

re c

osts

fo

r v

ari

ou

s t

yp

es o

f

po

we

r p

lan

ts


F igure 6.5.5. Industr ia l and power p lant CO2 point sources [Hendr iks, 2002]

Figure 6.5.6. Gross Domestic Product per gr id ce l l [RIVM, 2002]


Figure 6.5.7. Global o i l and gas occurences [TNO, 2002]

Figure 6.5.8. Global sal ine aquifers occurences [TNO, 2002]


Figure 6.5.9. Global hard coal occurences [TNO, 2002]


Table 20. CO2 storage potent ia ls for the 18 wor ld regions

Pg CO2 ONSHORE

Low Best High Low Best High Low Best High Low Best High Low Best HighCanada 0.0 0.4 3.1 0.7 1.1 1.5 6.6 8.1 10.2 0.1 6.6 8.1 0.0 8.5 51.0U.S.A. * 0.8 6.2 44.5 2.5 3.7 4.9 6.0 7.7 15.3 1.8 6.0 7.7 0.0 31.7 190.2Central Am. 0.1 2.1 14.5 0.5 0.8 1.0 0.8 1.2 4.4 0.2 0.8 1.2 0.0 0.0 0.0South Am. 0.7 8.3 53.8 2.3 3.4 4.5 8.7 17.6 49.4 0.2 8.7 17.6 0.0 2.0 11.7Northern Afr. 0.4 4.5 23.8 1.2 1.8 2.4 13.8 19.4 42.6 0.1 13.8 19.4 0.0 0.0 0.0Western Afr. 0.1 1.6 17.8 0.2 0.3 0.3 1.1 2.7 6.7 0.1 1.1 2.7 0.0 0.2 1.3Eastern Afr. 0.0 0.0 0.2 0.0 0.0 0.0 0.1 0.4 1.3 0.0 0.1 0.4 0.0 0.0 0.0Southern Afr. 0.0 0.1 0.6 0.0 0.0 0.0 0.0 0.1 0.2 0.0 0.0 0.1 0.0 7.4 44.6Western Eur. 0.0 0.1 1.1 0.1 0.2 0.2 4.7 10.4 16.9 0.2 4.7 10.4 0.0 1.0 5.7Eastern Eur. 0.1 0.9 5.1 0.3 0.4 0.6 2.9 3.9 6.6 0.0 2.9 3.9 0.0 0.7 4.2Former S.U. 1.7 21.8 132.4 4.8 7.2 9.6 71.0 126.3 331.5 0.3 71.0 126.3 0.0 25.0 150.1Middle East 5.1 62.0 405.8 7.9 11.8 15.7 92.3 168.1 372.6 0.3 92.3 168.1 0.0 0.0 0.0Southern Asia 0.0 0.4 2.1 0.1 0.1 0.2 3.9 9.5 24.0 0.2 3.9 9.5 0.0 2.0 11.9Eastern Asia 0.2 3.0 23.0 1.0 1.5 2.0 3.9 7.8 23.5 0.1 3.9 7.8 0.0 158.0 840.7South East. Asia 0.1 1.0 6.0 0.6 0.9 1.2 2.8 7.0 17.9 0.1 2.8 7.0 0.0 19.0 113.9Oceania 0.0 0.0 0.2 0.0 0.0 0.0 0.1 0.2 0.5 0.0 0.1 0.2 0.0 11.3 54.1Japan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.1 0.5Greenland 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.3 1.5 0.1 0.0 0.3 0.0 0.0 0.0Total 9 112 734 22 33 44 219 391 925 4 219 391 0 267 1480

Pg CO2 OFFSHORE

Low Best High Low Best High Low Best High Low Best High Low Best HighCanada 0.0 0.3 3.2 0.0 0.0 0.0 0.7 0.8 1.3 0.0 0.0 0.0 2.2 17.3 77.7U.S.A. * 0.1 0.5 4.8 1.0 3.0 5.4 0.7 0.8 1.4 1.2 1.3 1.9 2.2 17.3 77.6Central Am. 0.2 2.8 20.5 2.1 6.3 11.2 5.6 9.4 26.7 1.3 0.8 1.8 0.9 7.3 32.7South Am. 0.3 5.8 52.4 2.1 6.3 11.2 3.6 14.3 60.4 0.4 0.5 0.9 2.9 23.0 103.4Northern Afr. 0.1 0.9 6.4 0.9 2.7 4.8 1.5 3.1 9.8 0.1 0.1 0.2 1.7 13.4 60.5Western Afr. 0.4 6.1 67.4 2.6 7.8 13.9 4.7 11.7 28.5 0.4 0.5 0.9 1.9 15.1 68.0Eastern Afr. 0.0 0.1 0.6 0.0 0.0 0.0 0.2 1.2 4.0 0.0 0.0 0.0 0.7 5.5 24.6Southern Afr. 0.0 1.0 10.6 0.2 0.5 1.0 0.5 1.2 4.5 0.0 0.0 0.0 1.8 14.0 63.1Western Eur. 0.3 4.0 39.9 3.4 10.3 18.2 12.9 26.8 111.9 10.3 10.1 13.3 0.9 7.0 31.7Eastern Eur. 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.4 3.4 15.2Former S.U. 0.2 2.9 19.3 1.7 5.1 9.0 24.0 71.3 287.3 2.1 2.2 5.3 4.1 33.0 148.5Middle East 0.8 9.3 61.1 3.4 10.3 18.4 69.9 85.0 116.3 0.7 0.7 1.4 1.2 9.7 43.6Southern Asia 0.1 0.6 3.0 0.4 1.3 2.3 1.3 4.6 12.9 0.6 0.6 1.2 2.7 21.2 95.5Eastern Asia 0.0 0.5 3.4 0.4 1.2 2.2 0.2 0.3 1.0 0.1 0.1 0.1 1.7 13.4 60.3South East. Asia 0.1 1.4 10.9 1.3 3.8 6.7 16.5 31.9 61.3 2.6 3.0 4.4 0.8 6.4 28.8Oceania 0.0 0.5 5.0 0.5 1.5 2.6 6.9 16.9 39.9 0.3 0.4 0.8 3.5 28.1 126.3Japan 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.0 0.2 1.9 8.4Greenland 0.0 0.0 0.0 0.0 0.0 0.0 0.0 1.9 10.4 0.0 0.0 0.0 0.4 3.3 15.0Total 3 37 308 20 60 107 149 281 778 20 20 32 30 240 1081

REM. OIL FIELDS DEPL. OIL FIELDS REM. GAS

Aquifers

DEPL. GAS FIELDS

REM. OIL FIELDS DEPL. OIL FIELDS REM. GAS

ECBM

DEPL. GAS FIELDS


Cost curves per region for carbon dioxide storage underground

GLO

BAL

CARBO

N D

IOXID

E S

TO

RAG

E P

OTEN

TIA

L A

ND

CO

STS

50

Ta

ble

21

. Le

ge

nd

co

st

cu

rve

s

Can

ada

U.S

.A.

Cen

tral

Am

.S

ou

th A

m.

No

rth

ern

Afr

.W

este

rn A

fr.

Eas

tern

Afr

.S

ou

ther

n A

fr.

Wes

tern

Eu

r.a

Rem

. Oil

onR

em. O

il on

Rem

. Oil

onR

em. O

il on

Rem

. Oil

onR

em. O

il on

Rem

. Oil

onR

em. O

il on

Rem

. Oil

onb

Dep

l. O

il on

Dep

l. O

il on

Dep

l. O

il on

Dep

l. O

il on

Dep

l. O

il on

Dep

l. O

il on

Dep

l. O

il on

Rem

. Oil

off

Rem

. Oil

off

cD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il on

Dep

l. O

il on

dR

em. G

as o

nR

em. G

as o

nR

em. G

as o

nR

em. G

as o

nR

em. G

as o

nR

em. G

as o

nR

em. G

as o

nD

epl.

Oil

off

Dep

l. O

il of

fe

Aqu

ifer

Aqu

ifer

Rem

. Oil

off

Rem

. Oil

off

Rem

. Oil

off

Rem

. Oil

off

Aqu

ifer

Rem

. Gas

on

Rem

. Gas

on

fR

em. O

il of

fE

CB

MA

quife

rA

quife

rA

quife

rA

quife

rR

em. O

il of

fA

quife

rA

quife

rg

EC

BM

Rem

. Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il of

fh

Dep

l. O

il of

fD

epl.

Oil

off

Rem

. Gas

off

Rem

. Gas

off

Rem

. Gas

off

Rem

. Gas

off

Rem

. Gas

off

Rem

. Gas

off

Rem

. Gas

off

IR

em. G

as o

ffR

em. G

as o

ffD

epl.

Gas

off

Dep

l. G

as o

ffD

epl.

Gas

off

Dep

l. G

as o

ffD

epl.

Gas

off

Dep

l. G

as o

ffD

epl.

Gas

off

jD

epl.

Gas

off

Dep

l. G

as o

ffE

CB

ME

CB

ME

CB

ME

CB

ME

CB

ME

CB

ME

CB

M

Eas

tern

Eu

r.F

orm

er S

.U.

Mid

dle

Eas

tS

ou

ther

n A

sia

Eas

tern

Asi

aS

ou

th E

ast.

Asi

aO

cean

iaJa

pan

Gre

enla

nd

aR

em. O

il on

Rem

. Oil

onR

em. O

il on

Rem

. Oil

off

Rem

. Oil

onR

em. O

il on

Aqu

ifer

Aqu

ifer

Rem

. Oil

off

bD

epl.

Oil

onD

epl.

Oil

onD

epl.

Oil

onD

epl.

Oil

off

Dep

l. O

il on

Dep

l. O

il on

Rem

. Oil

off

Rem

. Oil

off

Aqu

ifer

cD

epl.

Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Rem

. Gas

off

Dep

l. O

il of

fD

epl.

Oil

off

EC

BM

EC

BM

Dep

l. O

il of

fd

Rem

. Gas

on

Rem

. Gas

on

Rem

. Gas

on

Dep

l. G

as o

ffR

em. G

as o

nR

em. G

as o

nD

epl.

Oil

off

Dep

l. O

il of

fR

em. G

as o

ffe

EC

BM

Aqu

ifer

Aqu

ifer

Rem

. Oil

onR

em. O

il of

fR

em. O

il of

fR

em. G

as o

ffR

em. G

as o

ffD

epl.

Gas

off

fA

quife

rR

em. O

il of

fR

em. O

il of

fA

quife

rE

CB

MD

epl.

Oil

off

Dep

l. G

as o

ffD

epl.

Gas

off

Rem

. Oil

ong

Rem

. Oil

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. O

il on

Aqu

ifer

Rem

. Gas

off

Rem

. Oil

onR

em. O

il on

Dep

l. O

il on

hD

epl.

Oil

off

Rem

. Gas

off

Rem

. Gas

off

Dep

l. O

il of

fD

epl.

Oil

off

Dep

l. G

as o

ffD

epl.

Oil

onD

epl.

Oil

onD

epl.

Oil

off

IR

em. G

as o

ffD

epl.

Gas

off

Dep

l. G

as o

ffR

em. G

as o

nR

em. G

as o

ffA

quife

rD

epl.

Oil

off

Dep

l. O

il of

fR

em. G

as o

nj

Dep

l. G

as o

ffE

CB

ME

CB

ME

CB

MD

epl.

Gas

off

EC

BM

Rem

. Gas

on

Rem

. Gas

on

EC

BM


Canada

jIhg

f

e

dcb

a

0

2

4

6

8

10

12

14

16

18

0 5 10 15 20 25 30 35 40 45 50

Storage potential (Pg CO2)

Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

USA

jIh

g

f

e

dcb

a

0

5

10

15

20

25

30

35

40

0 10 20 30 40 50 60 70 80


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


Central America

a

b c d

e f

g h I

j

0

5

10

15

20

25

0 5 10 15 20 25 30


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

South America

a

b c d

e

f

g h I

j

0

2

4

6

8

10

12

0 10 20 30 40 50 60 70 80 90


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


North Africa

ab c d

e

fg h I

j

0

5

10

15

20

25

30

35

40

45

0 10 20 30 40 50 60 70


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

West Africa

j

Ihg

fedcb

a

0

5

10

15

20

25

30

35

40

45

0 5 10 15 20 25 30 35 40 45


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


East Africa

abc d

e

f

g h I

j

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6 7 8


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

South Africa

a

b

cde

f

g h I

j

0

2

4

6

8

10

12

14

0 5 10 15 20 25 30


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


West Europe

a

b

c d e

f

g h I

j

0

2

4

6

8

10

12

14

0 10 20 30 40 50 60 70


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

East Europe

a

b c d

e

f

g

hIj

0

5

10

15

20

25

30

35

40

0 2 4 6 8 10 12 14


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


Former Sovjet Union

ab c d

e

f

g h I

j

0

5

10

15

20

25

30

35

40

45

0 50 100 150 200 250 300 350 400


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

Middle East

ab c d

e

f

g h I

j

0

5

10

15

20

25

30

35

40

45

0 50 100 150 200 250 300 350 400 450 500


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


South Asia

a

b c d

e f

g h I

j

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 35 40 45 50


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

East. Asia

a

b c d

e f

g h I

j

0

2

4

6

8

10

12

14

16

0 5 10 15 20 25 30 35 40 45 50


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


South East Asia

a

b c d

e

f g h

I

j

0

5

10

15

20

25

0 10 20 30 40 50 60 70 80


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

Oceania

a

b

cd e f

g

hIj

0

5

10

15

20

25

30

35

0 10 20 30 40 50 60 70


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


Japan

a

b c

def

g

hIj

0

5

10

15

20

25

30

35

0 1 1 2 2 3


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)

Greenland

a

b c d e

fgh I

j

0

5

10

15

20

25

30

35

40

45

0 1 2 3 4 5 6


Tra

nsp

ort

an

d s

tora

ge

cost

s (e

uro

/Mg

CO

2)


Global carbon dioxide storage potential and costs - Ecofys · PDF fileGlobal carbon dioxide storage potential and costs ... Wina Graus TNO-NITG Frank van ... GLOBAL CARBON DIOXIDE

Documents