Global carbon dioxide storage
potential and costs
By Ecofys in cooperation with TNO
our mission: a sustainable energy supply for everyone
Ecofys bv
P.O. Box 8408
NL-3503 RK Utrecht
Kanaalweg 16-G
NL-3526 KL Utrecht
The Netherlands
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+31 (0)30 280 83 00
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+31 (0)30 280 83 01
e-mail [email protected]
GLOBAL CARBON DIOXIDE STORAGE
POTENTIAL AND COSTS
Ecofys
Chris Hendriks
Wina Graus
TNO-NITG
Frank van Bergen
2004
EEP-02001
by order of the:
Rijksinstituut voor Volksgezondheid en Milieu
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 of carbon dioxide 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
I
Table 1.
Costs and plant characteristics for power plants with capture
of carbon dioxide
Type of capture technology
Pre-comb. Pre-comb. Post-comb. Post-comb. Post-comb.
Type of plant
Natural gas
Coal
Natural gas
(NGCC)
(IGCC)
(NGCC)
Coal
Natural gas
fired (steam) (Pulverized)
Without capture
Plant efficiency (%LHV)
Emission factor (kgCO2/kWh)
Power costs (€/kWh)
58.0%
47.0%
58.0%
42.0%
42.0%
0.35
0.72
0.35
0.48
0.81
3.1
4.8
3.1
3.8
4.0
51.5%
42.2%
52.0%
36.4%
33.7%
0.05
0.09
0.05
0.07
0.12
6.5%
4.8%
6.0%
5.6%
8.3%
4.6
6.4
4.1
5.0
6.0
85%
88%
85%
85%
85%
43
26
37
30
29
With capture
Plant efficiency (%LHV)
Emission factor (kgCO2/kWh)
Loss of plant efficiency
Power costs (€/kWh)
Power cost increase (%)
CO2 avoided (%)
Costs (€/tCO2)
Table 2.
Typical costs of CO2 capture for industrial plants
Facility
€/tCO2
Facility
€/tCO2
Cement plants
28
Refineries
29-42
Iron and steel plants
29
Hydrogen (flue gas)
Ammonia plants (flue gas)
36
Hydrogen (pure CO2)
3
Ammonia plants (pure CO2)
3
Petrochemical plants
32-36
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
II
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
Aquifer offshore
Natural gas field onshore
Natural gas field offshore
Empty oil field onshore
Empty oil field offshore
EOR onshore
EOR offshore
ECBM
2
5
1
4
1
4
Low
-10
-10
0
3
7
2
6
2
6
Medium
0
3
10
6
11
4
8
4
8
High
10
20
30
Potential of carbon dioxide 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
III
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.
Aquifers
14%
Oil fields onshore
9%
Oil fields offshore
6%
Coal beds
16%
Natural Gas fields
onshore
37%
Natural Gas fields
offshore
18%
Figure 1.
CO2 storage per type of underground reservoirs.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
IV
Oceania
Japan 4%
0%
Greenland Canada
0%
3%
South East. Asia
4%
U.S.A.
6%
Central America
South America
Eastern Asia
16%
Northern Africa
Western Africa
Eastern Africa
Southern Africa
Southern Asia
3%
Western Europe
Eastern Europe
Middle East
20%
Figure 2.
Former S.U.
21%
CO2 storage potential per region
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.
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 dioxide storage
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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
V
35
40
45
50
55
60
65
0
EOR onshore
200
400
Depleted Natural
gas fields onshore
Depleted oil fields
onshore
600
Enhanced Natural
gas recovery
onshore
1000
Storage potential (Pg CO2)
800
Aquifers
EOR offshore
Depleted oil and
Natural gas fields
offshore
World CO2-storage cost curve
1200
ECBM
1400
1800
world average of transport distance per type of reservoir and (3) typical storage costs per type of reservoir.
€/tCO2, (2) weighted
1600
Enhanced Natural
gas recovery
offshore
Figure 3. World cost curve CO2 storage. Costs are calculated by: (1) average capture and compression costs of 38.5
Total cost (euro/Mg CO2)
Table of contents
1
Introduction
1
2
CO2 capture and storage costs
3
2.1
2.1.1
2.1.2
2.1.3
2.1.4
2.2
2.3
2.4
3
4
5
6
7
9
10
12
3
Carbon dioxide capture
Economic analyses framework
Pre-combustion capture from power plants
Post-combustion capture from power plants
Post-combustion capture from large industry
Carbon dioxide compression costs
Carbon dioxide transport costs
Carbon dioxide storage costs
Potential of carbon dioxide storage
3.1
3.2
3.2.1
3.2.2
3.2.3
3.2.4
3.3
3.3.1
3.4
3.5
3.6
Type of reservoirs
Oil and Gas reservoirs
Oil reservoir: storage in EOR operations
Oil reservoir:storage in depleted oil fields
Gas reservoir: storage in operational gas fields
Gas reservoir: storage in depleted gas fields
Coal basins
Coal basin: in storage in ECBM operations
Aquifers
Results of the calculations
Cost curves for storage of carbon dioxide
14
14
14
15
19
20
23
23
23
24
26
29
4
Experience curves
32
5
Conclusions
34
References
36
Appendices
40
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
VIII
1 Introduction
Until so far only limited effort has been made to estimate CO2 regional storage potential worldwide. Hendriks [1994] developed a method for a worldwide potential
estimate for natural gas, oil and aquifer reservoirs by region. On regional scale considerable more effort has been undertaken. In the GESTCO project2 a validated estimate 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 Antarctica) 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 estimate 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 reservoir characterisation and limited knowledge about the ‘real’ potential of a reservoir.
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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
1
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
2
2 CO2 capture and storage costs
This chapter discusses the costs to capture (par. 2.1), compression (par. 2.2), transport (par. 2.3) and storage of carbon dioxide underground (par. 2.4).
2.1
Carbon dioxide capture
The goal of CO2 capture is to isolate carbon from the energy carrier in a form suitable for transport and storage. It is generally believed that a relatively pure stream
of carbon dioxide must be produced. This improves the economics for compression, 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 gasfired 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 opportunity 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 processes. 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 emissions of pollutants like SOx, NOx and particulates also will be reduced. This is either 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 captured).
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 processes, as they are still in an early stage of development and they can be applied
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
3
principally to the same kind of processes for which also alternative processes are
available.
2.1.1
Ec onomic a na lyses fra mew ork
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 process 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 assumptions. 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 comparison capture costs from power plants
Full load hours
Capital charge rate
Coal price
Natural gas price
7500 hours per year
11% (i.e. discount rate 10%; lifetime 25 years)
2 €/GJLHV
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 carbon 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
4
7.
8.
9.
10.
Ammonia plants
Refineries
Hydrogen
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 carbon dioxide and CO2 emission factors is given. Background discussion on the capture technologies and capture conditions is provided in the next sections.
Table 5.
Costs and plant characteristics for power plants with capture
of carbon dioxide.
Type of capture technology
Pre-comb. Pre-comb. Post-comb. Post-comb. Post-comb.
Type of plant
Natural gas Coal
Natural gas
Natural gas
(NGCC)
(NGCC)
fired (steam) (Pulverized)
(IGCC)
Coal
Without capture
Plant efficiency (%LHV)
Emission factor (kgCO2/kWh)
Power costs (€/kWh)
58.0%
47.0%
58.0%
42.0%
42.0%
0.35
0.72
0.35
0.48
0.81
3.1
4.8
3.1
3.8
4.0
51.5%
42.2%
52.0%
36.4%
33.7%
0.05
0.09
0.05
0.07
0.12
6.5%
4.8%
6.0%
5.6%
8.3%
4.6
6.4
4.1
5.0
6.0
85%
88%
85%
85%
85%
43
26
37
30
29
With capture
Plant efficiency (%LHV)
Emission factor (kgCO2/kWh)
Loss of plant efficiency
Power costs (€/kWh)
Power cost increase (%)
CO2 avoided (%)
Costs (€/Mg CO2)
Table 6.
Typical costs of CO2 capture for industrial plants
€/MgCO2
Facility
€/MgCO2
Cement plants
28
Refineries
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
29-42
Pre-c ombustio n c a pture from pow e r pla nts
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 subsequently combusted in the gas turbine of the power plant.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
5
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 applicable 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 reformer 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 production 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-c ombustion ca pture from pow er pla nts
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.
Typical CO2 concentrations in flue gases of power plants
Facility
Power plant – NGCC
Power plant – IGCC
Power plant – boiler NG
Power plant – boiler coal
Typical CO2 concentration in flue gases
3%
6%
8%
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 (polymer- 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 gasliquid contact facilitator. Also considered is to fractionate the carbon dioxide by solidifying it. These alternatives are at the moment less energy efficient and more expensive 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 systems can recover 85 to 95% of the CO2 in the flue gas and produces CO2 with a purity 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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
6
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 concentration 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 process. 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-c ombustion ca pture from la rge 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. Although 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 provide 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 sensitivity 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. percentage 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
7
Table 8.
Typical CO2 concentrations in flue gases of some industrial
facilities
Facility
Typical CO2 concentration in flue gases
Cement plants
Iron and steel plants
Ammonia plants (flue gas)
Ammonia plants (pure CO2)
Refineries
Hydrogen (flue gas)
Hydrogen (pure CO2)
Petrochemical plants
Table 9.
15-25%
15-20%
8%
Pure stream
3-18%
8%
Pure stream
8-13%
Typical capture costs excluding compression)
[€/MgCO2]
28
29
36
3
29-424
36
3
32-36
Typical CO2 capture costs (without compression costs) from industrial sources (€/Mg) for various concentrations in flue gas
(in %; row) and various emission sizes of CO2 (in Tg CO2; column). Assumed is that 20% of the heat can be covered by
waste heat. In the last row the compression costs are pre-
Annual emission (TgCO2)
sented
0.5
1.0
1.5
2.0
2.5
3.0
3.5
4.0
CO2concentration in flue gas (%)
3%
5%
8%
10% 13%
45
41
38
36
34
43
39
36
34
32
41
38
35
33
31
39
36
33
31
29
38
35
32
30
28
36
33
31
29
27
35
32
30
28
26
34
31
29
27
25
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
15%
32
31
29
28
27
26
25
24
18%
31
29
28
27
26
25
24
23
20%
30
28
27
26
25
24
23
23
Comp.
10
7
7
6
6
6
6
6
8
Reduction in costs (% of total costs)
30%
20%
10%
0%
-10%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
-20%
-30%
-40%
-50%
Waste heat availability (as % of heat required)
Figure 2.1.
Reduction in capture costs (excluding costs for compression) when
waste heat is available at the capture location. The availability 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 dioxide compression 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 compressor compresses the carbon dioxide. Water is removed during the first compression stages. Table 10 gives the main characteristics of compressors pressurising to
12 MPa.
Table 10.
Operational conditions for compression from 0.1 to 12 MPa for
a compressor with a capacity of 70 kg/s [Sulzer, 1999]
Inlet/outlet pressure (bars)
Inlet/outlet temperature (°C)
Polytropic efficiency
Compression energy (kJ/kg CO2)
First
stage
1/3.8
30/155
85.4
Second
stage
3.8/10.3
35/128
84.7
Third
stage
10.2/38.3
35/165
83.6
416
Fourth
stage
120
35/152
76.8
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 investment costs (see equation (2), operation and maintenance costs (5% of investment costs) and electricity costs (0.04 €/kWh). The use of electricity results in extra
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
9
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.
P 
E = Ce1 × ln outlet  × F
 PInlet 
With:
E
Poutlet
Pinlet
Ce1
F
Electricity use (kJe/s)
Outlet pressure (Pa)
Inlet pressure (Pa)
Constant (87.85 kJe/kg)
CO2 flow (kg/s)
97%
83%

P
I =  C1 × F C2 + C 3 × ln outlet
 Pinlet

(1)
70%
56%
42%
With:
I
C1
C2
C3
C4


 × F C4  × F (2)



Total investment costs (M€)
Constant (0.1 106 €/(kg/s))
Constant (-0.71)
Constant (1.1 106 €/(kg/s))
Constant (-0.60)
29%
Compression costs (euro/MgCO2)
25
20
15
Depreciation
costs 17%
10
Electricity
costs
57%
5
0
0
20
40
60
80
100
120
140
O&M
12%
160
Flow to compressor (kg/s)
Figure 2.2.
Left figure: Cost of compression as function of flow for various occupancy rate (100% = 8760 hours per year in operation).
Right figure: Cost allocation to type of expenditure (50
kg/s; 0.04 €/kWh; 7500 hours/year, discount rate 10%, depreciation period 15 year)
2.3
Carbon dioxide transport 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/m3. 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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
10
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, maintenance, assurance, licences) and re-compression costs (compressors and electricity
costs). The costs are depending on length of the route, number of highway and water 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 onshore construction and somewhat higher for offshore construction. Under more difficult 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.
Transport costs (euro/MgCO2/100 km)
velocity 1 m/s
velocity 3 m/s
7
6
5
4
3
2
1
0
0
50
100
150
200
250
300
Flow (kg/s)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
11
Figure 2.3.
Transport costs of carbon dioxide for CO2 pipeline velocity of
1 and 3 metre per second (distance 100 km onshore; electricity costs 0.04 €/kWh; 7500 hours/year, discount 10%,
depreciation period 25 years)
O&M
15%
Electricity costs
31%
Depreciation
costs
54%
Figure 2.4. Cost allocation for transport costs to type of expenditure (50
kg/s; distance 100 km onshore; electricity costs 0.04 €/kWh;
7500 hours/year, discount 10%, depreciation period 25
years)
2.4
Carbon dioxide storage 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 allowed overpressure. These factors will vary from type of reservoir (e.g. aquifer versus 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 different 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 sensitive 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 permeability of the reservoir (ECBM), terrain conditions, accessibility to grid, etc. The figures in table 11 for EOR and ECBM should be seen as an indication for storage
costs [Lysen, 2002; Alberta Research Council, 2000; Novem, 2001].
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
12
Table 12. Storage costs by depth (in €/MgCO2)
Depth of storage (m)
1000
2000
3000
Aquifer onshore
Aquifer offshore
Natural gas field onshore
Natural gas field offshore
Empty oil field onshore
Empty oil field offshore
EOR onshore
EOR offshore
ECBM
1.8
4.5
1.1
3.6
1.1
3.6
Low
-10
-10
0
2.7
7.3
1.6
5.7
1.6
5.7
Medium
0
3
10
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
5.9
11.4
3.6
7.7
3.6
7.7
High
10
20
30
13
3 Potential of carbon dioxide storage
3.1
Type of reservoirs
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 phenomenon 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 quantify 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
3.2
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.
Oil and Gas reservoirs
The exclusive source of information for the calculations of global CO2 sequestration 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 assessments [USGS, 1995; USGS, 2000]. Within the World Petroleum Assessment
2000 [USGS, 2000] the assessed areas were those judged to be significant on a
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
14
world scale in terms of known petroleum volumes, geological potential for new petroleum 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 provinces. 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: stora ge in EOR opera tions
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 cycling 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 potentially 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 EORCO2, 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]:
OOIP =
URR
(API gravity + 5)/ 100
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 geologic traits and socio-economic factors. The fields within an assessment unit should constitute 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 assessment 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 accumulations 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
15
With:
OOIP
APIgravity
=
=
URR
=
original oil in place, in barrels of oil (BO)
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°. Viscosity and API gravity are usually inversely related [Waples, 1985].
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
OOIPC = OOIP × C
With:
OOIPC
C
= original oil in place contacted with CO2, in barrels of oil (BO)
= 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 composition of the oil, since the composition of an oil and its density are closely related. 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 indicated 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
= 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
= original oil in place contacted with CO2, in barrels of oil
OOIPC
(BO)
With: EOR
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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
16
25
20
Extra
oil
due
15
to
EOR
(%)
10
5
0
25
30
35
40
45
API
gravity
Figure 3.1. Relation between API gravity and percentage of extra oil due
to EOR
The oil volume is multiplied by a ratio (RCO2) that relates the incremental oil volume to the net quantity of needed CO2. The net quantity is the amount that is ultimately 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 flooding. 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 million 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
17
Table 13. Results of CO2-EOR field tests (after Lysen [2002])
Project
Weyburn
Willard-Wasson
SACROC main flood
Permian, North Sea
Average for miscible oil
Average for immiscible
oil
Little Creek
SACROC tertiary pilot
test
1
BO = barrel of oil
2.7
3 to 4
4.6
5.3
6
10
Net CO2/Oil ratio
(Mg/BO) 8
0.15
0.17 to 0.22
0.26
0.3
0.336
0.559
13.5
5 to 14
0.76
0.28 to 0.78
Net CO2/oil Ratio (103cf/BO1)
Source
Wilson, 2000
Stalkup, 1984
Stalkup, 1984
Espie, 2000
Stevens, 1999b
Stevens, 1999b
Stalkup, 1984
Stalkup, 1984
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 produced was calculated. From the USGS assessments, values are given for the cumulative 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
18
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: stora ge in depleted oi l fields
The calculation of the volumes of CO2 that can potentially be sequestered in depleted oil reservoirs, thus without the simultaneous production of oil, is the reservoir 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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
19
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 potential 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
[produced oil]
[volume of BO]
[CO2-density]
=
=
=
=
S
=
total storable CO2 [kg]
Total oil produced in the past (BO)
volume of one barrel of oil [0.159 m3]
density of CO2 at reservoir depth [750 kg/m3]
“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 reported, 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 Ga s reservoir: stora ge in opera tion a l ga s 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 potential in this paragraph will, most likely, not become available until normal production 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 reservoir 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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
20
The number of moles of gas that occupies a certain volume at reservoir level is calculated 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:
z × n× R ×T
P
V =
Thus:
n=
V ×P
R ×T × z
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)
With:
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.
V ×P
R × T × z CO 2
V ×P
=
R × T × z CH 4
nCO 2 =
nCH 4
Thus:
1
nCO 2
z CO 2 z CH 4
=
=
1
nCH 4
z CO 2
z CH 4
Thus, the molar ratio can be calculated by taking the ratio between the compressibility 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 conditions.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
21
4
3.5
3
y = 2E-07x 2 - 0.0015x + 4.1707
2.5
Ratio
CO2/ 2
CH4 1.5
1
0.5
0
0
1000
2000
3000
Depth
4000
5000
Figure 3.2. Molar ratio 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 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
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 arbitrary 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
[“remaining gas” + F#]
ratio CO2/ CH4
density CO2
=
=
=
=
volume of CO2 that can potentially be stored (Mg)
total gas volume (m3)
volumetric ratio at reservoir depth (no unit)
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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
22
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
Ga s reservoir: stora ge in deplet ed ga s 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 total 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 cumulative volume of produced gas is not reported, therefore a rough and arbitrary assumption has been made that 60% of all known gas was produced. Using the minimum, 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
3.3.1
Coal basins
Coa l ba sin: in sto ra ge in ECB M ope ra tions
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 representative 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. Conservatively, 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
SCO2
= 0.1 × A × TH × ρcoal × GC × RF
= PG × ER× ρCO2
With:
PG
= producible gas [m3]
SCO2 = storable CO2 [kg]
A
= surface area of coal basins [m2]
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
23
TH
ρcoal
GC
RF
ER
ρCO2
=
=
=
=
=
=
cumulative thickness of the coal [m]
coal density [Mg/m3]
gas content [m3STP gas/Mg coal]
recovery factor [-]
exchange ratio [-]
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 recovered. 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 water. 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]. Conservatively, 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 molecules 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 estimated 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
Aquifers
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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
24
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.
Oceania
Japan
1%
Greenland
12%
South East. Asia
1%
Canada 7%
U.S.A. 7%
3%
Central Am. 3%
Eastern Asia 6%
South Am. 10%
Southern Asia 9%
Northern Afr.
Middle East 4%
6%
Western Afr. 6%
Former S.U.14%
Eastern Afr. 2%
Southern Afr. 6%
Eastern Eur.
1%
Western Eur. 3%
Figure 3.3. The relative distribution of the surface area of sedimentary
basins in the 18 areas as defined in TIMER.. Note that these
percentages result from rough calcaulations, and should be
considered as indicative)
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]).
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
25
Table 14. Range of aquifer thickness and porosity used in this study
Aquifer thickness (m)
50
100
300
Minimum
Best
Maximum
Porosity (%)
5
20
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
Area
Aquifer thickness
Porosity
Density CO2
=
=
=
=
=
volume of CO2 that can potentially be sequestered (Pg)
surface area of sedimentary basins (m2)
thickness of aquifer (m)
porosity of the rock (%)
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
Results of the calculations
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 presents tables with potentials for each region (Table 20).
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
26
Table 15. Estimate for underground CO2 storage potential for various underground reservoirs
Total
Remaining oil fields onshore
Remaining oil fields offshore
Depleted oil fields onshore
Depleted oil fields offshore
Remaining gas fields onshore
Remaining gas fields offshore
Depleted NG fields onshore
Depleted NG fields offshore
ECBM
Aquifers
Total
CO2 seq potential (Pg CO2)
Low
Best
High
9
3
22
20
219
149
4
20
0
30
476
112
37
33
60
391
281
219
20
267
240
1660
734
308
44
107
925
778
391
32
1480
1081
5880
CO2 seq potential (Pg CO2)
Low
Best
High
54
242
1194
392
910
2126
0
30
476
267
240
1660
1480
1081
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 nondepleted) is in the range 1000 to 1800 Pg CO2. The storage potential by ECBM estimated 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 estimate 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
27
Table 16. Comparison between volume calculations of Hendriks [1994]
and this study for storage in aquifers
Hendriks [1994]
This study
Area
Storage Area
capacity
Storage Capac- Storage Capac- Storage Caity Minimum
ity Best
pacity Maximum
Pg
Pg
Pg
Pg
Canada
U.S.A.
North America
2
2
4
1
3
4
2
2
1
2
6
1
1
0
0
4
3
2
1
4
0
13
1
1
0
0
30
40
Central Am.
South Am.
Latin America
40
Northern Afr.
Western Afr.
Eastern Afr.
Southern Afr.
Africa
40
Western Europe
Western Europe
10
Eastern Eur.
Eastern Europe
30
Former S.U.
Southern Asia
Eastern Asia
South East. Asia
Oceania
Japan
Oceania and Asia
50
Middle East
Middle East
10
Greenland
220
Total
17
17
35
7
23
30
13
15
5
14
48
7
7
3
3
33
21
13
6
28
2
104
10
10
3
3
237
78
78
155
33
103
136
61
68
25
63
216
32
32
15
15
148
96
60
29
126
8
468
44
44
15
15
1066
Table 17. Comparison of storage estimates (Pg CO2)
Ref[1]
Oil fields
Gas fields
ECBM
Aquifers
500-1800
na
na
Ref [1]: Turkenburg [1999]
Ref [2]: Hendriks [1994]
Ref [3]: IPCC [2001]
Ref[2]
385
1500
na
200
Ref[3]/Ref[4]
370
1500
150
4000
Ref[5]
126
800
na
na
Ref[6]
242
910
267
240
Ref [4]: ARC [2000]
Ref [5]: Stevens [2000]
Ref [6]: this study
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
28
3.6
Cost curves for storage of carbon dioxide
The potentials for carbon dioxide storage per region are shown in cost curve diagrams 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 reservoirs. The transport costs are categorised in five so-called cost-windows (see Table
18).
Table 18. Transport costs for four cost-windows. It is assumed that for
transport over larger distances more CO2 transports will be
combined leading to larger pipelines and smaller specific costs
per km-transport
Distance Source – Storage reservoir
Short
Medium
Long
Very long
Extreme long
Average distance
(km)
< 50 km
50 – 200
200 – 500
500 and 2000
2000 and more
Average costs (€/Mg
CO2)
1
3
5
10
30
The estimated transport costs per region are shown in Table 19. The costs estimation 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.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
29
Table 19. Estimated transport costs per region per type of storage
reservoir (€/Mg CO2)
Aquifers
Canada
U.S.A.
Central Am.
South Am.
Northern Afr.
Western Afr.
Eastern Afr.
Southern Afr.
Western Eur.
Eastern Eur.
Former S.U.
Middle East
Southern Asia
Eastern Asia
South East. Asia
Oceania
Japan
Greenland
5
5
3
3
3
3
5
3
3
10
10
3
5
10
5
3
5
10
Oil and gas
onshore
5
5
1
3
3
5
5
5
5
1
10
1
10
5
3
30
30
30
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Oil and gas
offshore
10
30
5
3
3
5
30
3
3
30
30
3
3
10
3
10
10
10
Coal
5
5
10
1
30
30
30
3
3
3
30
30
5
3
10
5
3
30
30
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
31
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 development of flue gas desulphurization systems (FGD) and selective catalytic reduction
systems to control NOx emissions (SCR). Improvements in performances and reduction in cost of this technology have accompanied the deployment of FGD systems 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 = cumulative production through period i, b = the learning rate exponent, and a = coefficient
(constant). According to this equation, each doubling of cumulative production results 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 control 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 systems have similarities with the FGD and SCR systems, but also essential differences can be observed (e.g. the energy costs share is substantial larger in carbon dioxide 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
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
32
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 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.
Relative costs (% of base costs)
Figure 4.1 shows the development of costs for three different carbon dioxide sequestration activities: capture, transport and storage. In the figure we assume (arbitrarily) that when 2% of the total capture potential has been implemented, the sequestration 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).
225%
200%
175%
150%
125%
100%
75%
50%
25%
0%
0%
10%
20%
30%
40%
50%
60%
70%
Cumulative implemented CO2 capture (% of maximum)
costs (capture)
costs (transport)
costs (transport)
Figure 4.1. Development of carbon dioixde sequestration costs for
capture, transport and storage. Assumed is that reported
costs are valid when 2% of the potential has been
implemented. The learning rate assumed is 12% cost
decrease by doubling of the capacity (for capture), 5% (for
transport), and 8% (for storage)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
33
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 coalfired 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 average 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%.
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
34
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
35
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GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
39
Appendices
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
40
0
1
2
3
4
5
6
7
8
9
Doctor
(1996)
Chiesa
(1998)
Simbeck Condorelli Hendriks
(1998)
(1991)
(1994)
Cost of capture [euro/MgCO2]
Electricity production costs with capture [euroct/kWh]
Electricity production costs without capture1 [euroct/kWh]
Audus
(1995)
Pruschek Parsons Parsons Parsons
(1996)
(1995)
(1995)
(1995)
O2-blown Air-blown Air-blown
Stork
(2000)
Comprimo
(2001)
0
20
40
60
80
100
120
140
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Gasifier Combined Cycles on equal economic basis
Figure 6.5.1. Comparison of electricity production costs and CO2 capture and compression costs for CO2 capture from Integrated
Electricity production costs (euroct/kWh)
10
Capture costs (euro/MgCO2 avoided)
41
0
1
2
3
4
5
6
7
8
9
Sm
r(
se
l
e
)
91
9
1
s
)
94
9
(1
ck
be
m
Si
(
)
98
9
1
iz
ar
M
(
)
95
9
1
e
av
D
)
00
0
(2
k
or
St
)
00
0
(2
0
20
40
60
80
100
120
140
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Coal power plants on equal economic basis.
Comparison of electricity production costs and CO2 capture and compression costs for CO2 capture from Pulverised
ik
dr
en
H
Cost of capture [euro/MgCO2]
Electricity production costs with capture [euroct/kWh]
Electricity production costs without capture1 [euroct/kWh]
Figure 6.5.2.
Electricity production costs (euroct/kWh)
10
Capture costs (euro/MgCO2 avoided)
42
0
1
2
3
4
5
6
7
8
9
s
du
Au
)
95
9
(1
nd
lla
o
B
)
92
9
(1
Cost of capture [euro/MgCO2]
e
st
Fo
er
el
he
rW
Electricity production costs with capture [euroct/kWh]
)
99
9
(1
Electricity production costs without capture1 [euroct/kWh]
er
st
Fo
W
er
el
he
)
99
9
(1
k
or
St
)
01
0
(2
ck
be
m
Si
(
)
98
9
1
a
es
hi
C
)
99
9
(1
0
20
40
60
80
100
120
140
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Combined Cycles on equal economic basis.
Figure 6.5.3. Comparison of electricity production costs and CO2 capture and compression costs for CO2 capture from Natural gas
Electricity production costs (euroct/kWh)
10
Capture costs (euro/MgCO2 avoided)
43
0
1
2
3
4
5
6
7
8
9
IGCC (pre-combustion)
PC (post-combustion)
Electricity production costs without capture [euroct/kWh]
NGCC (pre-combustion)
Conventional NG (postcombustion)
Cost of capture [euro/MgCO2]
NGCC (post-combustion)
Electricity production costs with capture [euroct/kWh]
0
20
40
60
80
100
120
140
power plants
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Figure 6.5.4. Estimated electricity production costs without and with cap ture and carbon dioxide capture costs for various types of
Electricity production costs (euroct/kWh)
10
Capture costs (euro/MgCO2 avoided)
44
Figure 6.5.5. Industrial and power plant CO2 point sources [Hendriks, 2002]
Figure 6.5.6.
Gross Domestic Product per grid cell [RIVM, 2002]
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
45
Figure 6.5.7.
Global oil and gas occurences [TNO, 2002]
Figure 6.5.8.
Global saline aquifers occurences [TNO, 2002]
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
46
Figure 6.5.9.
Global hard coal occurences [TNO, 2002]
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
47
Table 20.
CO2 storage potentials for the 18 world regions
Pg CO2
ONSHORE
REM. OIL FIELDS DEPL. OIL FIELDS
REM. GAS
DEPL. GAS FIELDS
ECBM
Low
Best High Low Best High Low Best High Low Best High Low
Best
High
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
51.0
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
190.2
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
0.0
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
11.7
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
0.0
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
1.3
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
0.0
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
44.6
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
5.7
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
4.2
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
150.1
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
0.0
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
11.9
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
840.7
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
113.9
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
54.1
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
0.5
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
0.0
9
112
734
22
33
44
219
391
925
4
219
391
0
267
1480
Canada
U.S.A. *
Central Am.
South Am.
Northern Afr.
Western Afr.
Eastern Afr.
Southern Afr.
Western Eur.
Eastern Eur.
Former S.U.
Middle East
Southern Asia
Eastern Asia
South East. Asia
Oceania
Japan
Greenland
Total
Pg CO2
Canada
U.S.A. *
Central Am.
South Am.
Northern Afr.
Western Afr.
Eastern Afr.
Southern Afr.
Western Eur.
Eastern Eur.
Former S.U.
Middle East
Southern Asia
Eastern Asia
South East. Asia
Oceania
Japan
Greenland
Total
OFFSHORE
REM. OIL FIELDS DEPL. OIL FIELDS
REM. GAS
DEPL. GAS FIELDS
Aquifers
Low
Best High Low Best High Low Best High Low Best High Low
Best
High
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
77.7
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
77.6
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
32.7
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
103.4
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
60.5
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
68.0
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
24.6
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
63.1
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
31.7
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
15.2
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
148.5
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
43.6
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
95.5
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
60.3
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
28.8
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
126.3
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
8.4
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
15.0
3
37
308
20
60
107
149
281
778
20
20
32
30
240
1081
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
48
Cost curves per region for carbon dioxide storage
underground
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
49
U.S.A.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
ECBM
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
Former S.U.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Canada
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Rem. Oil off
ECBM
Depl. Oil off
Rem. Gas off
Depl. Gas off
Eastern Eur.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
ECBM
Aquifer
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
a
b
c
d
e
f
g
h
I
j
a
b
c
d
e
f
g
h
I
j
Table 21. Legend cost curves
Middle East
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Central Am.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Rem. Oil off
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Eastern Asia
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Rem. Oil off
ECBM
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
Northern Afr.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Rem. Oil off
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Eastern Afr.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
South East. Asia Oceania
Rem. Oil on
Aquifer
Depl. Oil on
Rem. Oil off
Depl. Oil off
ECBM
Rem. Gas on
Depl. Oil off
Rem. Oil off
Rem. Gas off
Depl. Oil off
Depl. Gas off
Rem. Gas off
Rem. Oil on
Depl. Gas off
Depl. Oil on
Aquifer
Depl. Oil off
ECBM
Rem. Gas on
Western Afr.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Rem. Oil off
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
Southern Asia
Rem. Oil off
Depl. Oil off
Rem. Gas off
Depl. Gas off
Rem. Oil on
Aquifer
Depl. Oil on
Depl. Oil off
Rem. Gas on
ECBM
South Am.
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Rem. Oil off
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Japan
Aquifer
Rem. Oil off
ECBM
Depl. Oil off
Rem. Gas off
Depl. Gas off
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
Southern Afr.
Rem. Oil on
Rem. Oil off
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
Greenland
Rem. Oil off
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
Rem. Oil on
Depl. Oil on
Depl. Oil off
Rem. Gas on
ECBM
Western Eur.
Rem. Oil on
Rem. Oil off
Depl. Oil on
Depl. Oil off
Rem. Gas on
Aquifer
Depl. Oil off
Rem. Gas off
Depl. Gas off
ECBM
50
Canada
18
hI j
Transport and storage costs (euro/MgCO2)
16
g
14
f
12
e
10
8
b
c
d
6 a
4
2
0
0
5
10
15
20
25
30
35
40
45
50
Storage potential (Pg CO2)
USA
40
hI j
Transport and storage costs (euro/MgCO2)
35
g
30
25
20
f
15
e
10
b
c
d
a
5
0
0
10
20
30
40
50
60
70
80
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
51
Central America
25
Transport and storage costs (euro/MgCO2)
j
20
15
g
h
I
10
e
f
5
b
c
d
a
0
0
5
10
15
20
25
30
Storage potential (Pg CO2)
South America
12
j
Transport and storage costs (euro/MgCO2)
10
g
h
I
f
8
e
6
b
c
d
4
a
2
0
0
10
20
30
40
50
60
70
80
90
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
52
North Africa
45
j
Transport and storage costs (euro/MgCO2)
40
35
30
25
20
15
10
g
f
h
I
e
b
5
c
d
a
0
0
10
20
30
40
50
60
70
Storage potential (Pg CO2)
West Africa
45
j
Transport and storage costs (euro/MgCO2)
40
35
30
25
20
15
g
10
e
b c
h
I
f
d
a
5
0
0
5
10
15
20
25
30
35
40
45
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
53
East Africa
45
j
40
Transport and storage costs (euro/MgCO2)
g
35
h
I
f
30
25
20
15
e
10
bc
a
d
5
0
0
1
2
3
4
5
6
7
8
Storage potential (Pg CO2)
South Africa
14
j
Transport and storage costs (euro/MgCO2)
12
10
g h
I
f
8
cde
b
6
a
4
2
0
0
5
10
15
20
25
30
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
54
West Europe
14
j
Transport and storage costs (euro/MgCO2)
12
10
g
h
I
f
8
c
d
e
b
6
a
4
2
0
0
10
20
30
40
50
60
70
Storage potential (Pg CO2)
East Europe
40
hIj
Transport and storage costs (euro/MgCO2)
35
g
30
25
20
f
15
e
10
5
b
c
d
a
0
0
2
4
6
8
10
12
14
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
55
Former Sovjet Union
45
j
40
Transport and storage costs (euro/MgCO2)
g
35
h
I
f
30
25
20
e
15
b
c
d
a
10
5
0
0
50
100
150
200
250
300
350
400
Storage potential (Pg CO2)
Middle East
45
j
40
Transport and storage costs (euro/MgCO2)
g
35
h
I
f
30
25
20
15
10
e
5
b
c
d
a
0
0
50
100
150
200
250
300
350
400
450
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
56
500
South Asia
16
j
Transport and storage costs (euro/MgCO2)
14
g
12
e
h
I
f
10
b
c
d
8
a
6
4
2
0
0
5
10
15
20
25
30
35
40
45
50
Storage potential (Pg CO2)
East. Asia
16
j
Transport and storage costs (euro/MgCO2)
14
g
12
e
h
I
f
10
b
c
d
8
a
6
4
2
0
0
5
10
15
20
25
30
35
40
45
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
57
50
South East Asia
25
Transport and storage costs (euro/MgCO2)
j
20
15
I
10
f
g
h
e
b
c
d
5
a
0
0
10
20
30
40
50
60
70
80
Storage potential (Pg CO2)
Oceania
35
hIj
g
Transport and storage costs (euro/MgCO2)
30
25
20
c
15
d
e
f
b
10
a
5
0
0
10
20
30
40
50
60
70
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
58
Japan
35
hIj
g
25
20
ef
d
15
b c
a
10
5
0
0
1
1
2
2
3
Storage potential (Pg CO2)
Greenland
45
j
40
Transport and storage costs (euro/MgCO2)
Transport and storage costs (euro/MgCO2)
30
35
g
h
f
I
30
25
20
c
b
d
e
15 a
10
5
0
0
1
2
3
4
5
6
Storage potential (Pg CO2)
GLOBAL CARBON DIOXIDE STORAGE POTENTIAL AND COSTS
59
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