MS Thesis
Reykjavík Energy Graduate School of Sustainable Systems
Costs, Profitability and Potential Gains of the
CarbFix Program
Elisabet Vilborg Ragnheidardottir
Business Department University of Iceland
Advisors: Helga Kristjansdottir
William Harvey
Holmfridur Sigurdardottir
January, 2010
ABSTRACT
This paper aims to review the costs associated with the CarbFix injection program and
determine its possible revenues. The CarbFix costs are reviewed both in its current pilot
project state, as well as two larger scenarios involving the Hellisheidi geothermal power
plant in southwest Iceland and a pulverized coal plant. The Simple Multi-attribute
Technique (SMART) combined with a PESTLE analysis provides a detailed portfolio of
positive markets that CarbFix could enter with its knowledge to provide a service. While
costs of storage of CO2 in other types of reservoirs have been widely studied, there are
limited data on storage through mineralization. The largest cost contributors for both the
CarbFix pilot program and the Hellisheidi plant are the capital and monitoring costs, but
water and electricity costs become more predominant in the pulverized coal case. This
paper, specifically through its cost analysis, adds much needed information on the
economics of this emerging form of CCS. The cost analysis shows that the cost per tonne
of CO2 emitted would need to be 77!/tCO2 for the Hellisheidi scenario to be profitable
while the pulverized coal scenario would be profitable at 50!/tCO2 emitted. The market
analysis shows that the most efficient markets, in terms of low barriers to entry and
adequate purchasing power, are Russia, the United States, Canada, Italy and Germany.
KEYWORDS: carbon capture and storage; mineral carbonation; CarbFix; carbon dioxide;
Hellisheidi; Iceland
iii
TABLE OF CONTENTS
Abstract ........................................................................................................................... iii
I. Introduction.................................................................................................................11
II. Literature Review........................................................................................................15
II.1 Geological Storage ...............................................................................................15
II.2 Mineral Carbonation.............................................................................................18
II.3 Carbon Capture & Storage....................................................................................20
II.4 Associated Risks...................................................................................................22
II.5 Liability................................................................................................................24
II.5.1 Short-term versus Long-term .......................................................................24
II.5.2 Insurance .....................................................................................................25
II.5.3 Multiparty Liability .....................................................................................27
II.6 Regulations...........................................................................................................28
II.6.1 Classification of CO2 ...................................................................................28
II.6.2 Pore Space Ownership.................................................................................29
II.6.3 Licensing & Permits ....................................................................................29
II.7 Incentives .............................................................................................................30
II.8 Economics............................................................................................................31
II.8.1 Capture........................................................................................................33
II.8.2 Transport .....................................................................................................38
II.8.3 Storage ........................................................................................................40
iv
II.8.4 Monitoring ..................................................................................................42
II.8.5 Total CCS Costs ..........................................................................................43
II.9 PESTLE Analysis.................................................................................................44
II.10
III.
Simple Multi-Attribute Rating Technique .....................................................45
Techno-Economic Scenarios.................................................................................47
III.1CarbFix – Present Status & Methodology .............................................................47
III.1.1
H2S Abatement System .........................................................................48
III.1.2
Basalt ....................................................................................................49
III.1.3
CarbFix methodology............................................................................50
III.2CarbFix Pilot Program ..........................................................................................52
III.2.1
Data ......................................................................................................52
III.2.2
Cost Analysis ........................................................................................55
III.2.3
Profitability Assessment........................................................................59
III.3Hellisheidi full-scale scenario ...............................................................................63
III.3.1
Data ......................................................................................................63
III.3.2
Injection well calculations.....................................................................64
III.3.3
Cost analysis .........................................................................................65
III.3.4
Profitability assessment .........................................................................69
III.4CarbFix applied to a pulverized coal plant ............................................................72
IV.
III.4.1
Coal ......................................................................................................72
III.4.2
Existing plant and data ..........................................................................74
III.4.3
Cost analysis .........................................................................................75
III.4.4
Profitability assessment .........................................................................77
Market Analysis ...................................................................................................81
IV.1.1
Methodology.........................................................................................81
IV.1.2
Attribute descriptions ............................................................................86
v
IV.1.3
Purchasing power parity........................................................................91
IV.2
Data..................................................................................................................92
IV.3
Efficiency frontier ............................................................................................92
IV.4
Sensitivity analysis ...........................................................................................93
V. Conclusions.................................................................................................................97
References .....................................................................................................................101
vi
LIST OF FIGURES
Figure 1: CO2 captured vs. CO2 avoided...........................................................................32
Figure 2: Separation process of CO2 through chemical solvents. ......................................34
Figure 3: Costs for CO2 transport as a function of CO2 mass flow rate. ............................39
Figure 4: Levelized costs for CO2 transport as a function of CO2 mass flow rate. .............40
Figure 5: Well drilling cost as a function of depth. ...........................................................42
Figure 6: N-S geological cross section of the injection site, including injection well (HN-2)
and monitoring wells. ...............................................................................................51
Figure 7: Percentage breakdown of total capital costs for pilot program ...........................56
Figure 8: Percentage breakdown of total annual costs for pilot program. ..........................57
Figure 9: Sensitivity Analysis of annual cost factors, pilot program..................................58
Figure 10: Sensitivity Analysis of annualized capital costs, pilot program. .......................58
Figure 11: Accumulated Net Present Value of the CarbFix Pilot Program at 900!/tCO2. ..61
Figure 12: Debt Cover Ratios of the CarbFix Pilot Program at 900!/tCO2........................62
Figure 13: Accumulated Net Present Value of the CarbFix Pilot Program at 1.200!/tCO2.
.................................................................................................................................62
Figure 14: Changes in costs from pilot program to full-scale program. .............................67
Figure 15: Sensitivity Analysis of annual cost factors, full-scale program.........................67
Figure 16: Sensitivity Analysis of annualized capital costs, full-scale program.................68
Figure 17: Sensitivity Analysis of annualized capital costs, full-scale program with 10
injection wells. .........................................................................................................69
Figure 18: Accumulated Net Present Value of the Hellisheidi Full-Scale Program at
50!/tCO2. .................................................................................................................70
Figure 19: Accumulated Net Present Value of the Hellisheidi Full-Scale Program at
77!/tCO2. .................................................................................................................71
vii
Figure 20: Debt Cover Ratios of the Hellisheidi Full-Scale Program at 77!/tCO2. ............71
Figure 21: Sensitivity Analysis of annual cost factors, PC plant with 17 wells..................77
Figure 22: Internal Rate of Return on total cash flow and net cash flow for the Pulverized
Coal case with CarbFix at 13!/tCO2. ........................................................................78
Figure 23: Accumulated Net Present Value of the Pulverized Coal program with CarbFix
at 50!/tCO2. .............................................................................................................79
Figure 24: Debt Cover Ratios of the pulverized coal scenario at 50!/tCO2........................79
Figure 25: Value tree of PESTLE attributes by their category...........................................82
Figure 26: World map indicating countries that were used in the market analysis. ............92
Figure 27: Market analysis efficiency frontier. .................................................................93
Figure 28: Sensitivity analysis of the top three ranked weights in each category, Threats
and Opportunities. ....................................................................................................94
Figure 29: Natural gas production in tera joules per year by country.................................95
Figure 30: Changes in the weight of natural gas; lower performing countries. ..................95
Figure 31: Changes in the weight of natural gas: higher performing countries. .................96
viii
LIST OF TABLES
Table 1: Review of the costs for CCS according to the literature. .....................................43
Table 2: Most likely cost and applied cost of transport and injection of CO2 sequestration
.................................................................................................................................53
Table 3: Cost summary for carbon mineralization. ...........................................................55
Table 4: Economic parameters used for profitability assessment of the CarbFix pilot
program....................................................................................................................60
Table 5: Resulting profitability ratios from varying prices of !/tCO2, pilot program. ........63
Table 6: Cost increase for full-scale Hellisheidi program..................................................66
Table 7: Resulting profitability ratios from varying prices of !/tCO2, Hellisheidi full-scale
scenario....................................................................................................................72
Table 8: Characteristics overview of a 308 MWe reference pulverized coal plant and PC
plant with capture. ....................................................................................................75
Table 9: Cost increase for PC plant using CarbFix............................................................76
Table 10: Resulting profitability ratios from varying prices of !/tCO2, PC plant with
CarbFix. ...................................................................................................................80
Table 11: List of attributes, their unit, and the source and base year for the SMART
analysis. ...................................................................................................................83
Table 12: Attribute ranks, swing weights and normalized weights. ...................................85
ix
I. INTRODUCTION
The world is currently in a battle against increasing levels of carbon dioxide (CO2) in the
atmosphere and its negative effect on the environment. As economies and nations grow,
driven by continuous population increase, the emissions of those nations and their
industries add to global CO2 emissions. While energy efficiency and fuel choice for
electrical production remain driving forces in decreasing greenhouse gases, another path is
currently being pursued that not only could decrease emissions but also participate in
macroeconomic trading markets. Carbon, capture and storage (CCS) is a method by which
CO2 is captured as a clean stream and re-injected into various geological formations for the
purpose of long-term storage. Mineral carbonation is an option by which this re-injection
and storage of CO2 could take place. By fixing CO2 as a stable mineral the natural
weathering processes are replicated and nature is imitated, specifically in the CarbFix case
by using basalt to produce carbonates. CarbFix aims to test in-situ mineral sequestration of
CO2 by utilizing geothermal gases produced from the Hellisheidi geothermal power plant
located in southwest Iceland.
The questions that this thesis will specifically answer are the following:
1. What is the cost of storing one tonne of CO2 (tCO2) in the CarbFix pilot program?
2. What is the cost of storing one tCO2 using the CarbFix method for larger flow rates
of CO2?
3. What are the main cost drivers of the CarbFix method of CCS?
4. What is the possible revenue that may be achieved in relation to the determined
costs and differing prices of CO2 available on the market?
5. What are the positive markets with low barriers to entry that CarbFix should focus
on in the future?
Chapter 2 will review the literature of carbon capture and storage. The review provides an
oversight as to the total costs that are known today through both studies and research pilot
programs similar to the CarbFix program. The literature however distinctly shows that
while the costs for storage of CO2 in alternative sites, such as aquifers and oil fields, are
11
well known, cost information associated to mineral carbonation is limited. This paper adds
to the large portfolio of information on CCS as a process by identifying cost drivers of
mineral carbonation. The resulting information from this thesis will help to focus future
work, both engineering and geological, as to where sensitive points of the project lie
economically.
The third chapter models both technological and economical scenarios. The goals of the
chapter are to analyze the costs for three separate scenarios that differ in CO2 flow rate.
The first scenario considers the current CarbFix pilot program while the other two
scenarios are scaled up models, which assess the Hellisheidi geothermal power plant and a
pulverized coal plant. The capital and annual costs, such as water and energy, are scaled
from the pilot program as well as known geophysical requirements in order to achieve
correct geochemical reactions. A cost analysis is done by assessing both capital costs and
variable costs associated with water and energy, and determine an estimated cost per tCO2
stored. By analyzing the changes in the costs according to the differing flow rates the
sensitive cost factors are identified in order to better focus future work on where cost
reductions are needed. Specifically the costs associated with water and energy
requirements are modelled, reviewed and analyzed in order to better understand the effect
on the total costs per tonne.
As Chapter 3 provides a list of factors that dominate the resulting cost per tCO2 it is
important to know exactly how sensitive the cost is to variations in these factors. A Monte
Carlo simulation shows the sensitivity of the levelized cost to changes in those factors. The
results are important in order to understand the need for accurate cost estimates in the
beginning of the project and also determine in what range the capital costs must lie in order
for the levelized cost to lay within a corresponding range. However, as the flow rate is such
a dominant factor in the cost assessments for the large flow scenario, the pulverized coal
plant is also tested for its sensitivity to changes in water and energy requirements.
Chapter 3 also includes a profitability assessment for each scenario. The purpose is to
accurately identify at what cost per tCO2 the market must provide in order for the
scenarios, at current costs, to realize revenue. Carbon trading on the global market is
increasing due to public and political pressure to reduce greenhouse gases while still
providing a free market solution. Additionally, carbon taxes on energy related CO2 are not
uncommon in Europe and as governments try to produce additional state income while
reducing carbon dioxide emissions immobile emitters of CO2 must consider compliance
12
options. This paper then provides clues as to at what price the tax would need to be in
order for CarbFix to be an attractive option in lieu of paying the tax. Lastly, international
agreements such as the Kyoto Protocol provide nations with options to achieve emission
targets. In order for CarbFix to present this service as an option, to both nations and
corporations within those nations, the cost must be accurately defined in order to better
develop prices at which the service is offered.
As CarbFix is producing an industrial method for CO2 storage it is important to recognize
its future possibilities as revenue for Orkuveita Reykjavikur (Reykjavik Energy). This
possibility lies not only within the borders of Iceland but also on a global level and is the
main focus of Chapter 4. More international pressure on countries to reduce greenhouse
gas emissions is creating a more open market for companies that possess tools to realize
this goal. However, marketing a product in any given country can be an expensive and
lengthy process. Being aware of the proper countries to perform this marketing is
important and executing this action in the most efficient way a priority. The market
analysis in this chapter identifies the key factors that create a positive market for CarbFix
both through identifying opportunities and threats. The methodology includes identifying
attributes using the PESTLE analysis and then rating the attributes using the Simple MultiAttribute Rating Technique. The analysis also takes into account the purchasing power of
the country’s currency in order to identify countries that have a lower purchasing barrier.
The results from the market analysis provide a short list of those countries that are the most
viable markets for CarbFix to enter. Due to the prescriptive nature of the SMART analysis
a sensitivity analysis is also employed in order to better understanding the driving factors
that produce this short list of countries. The analysis only presents results according to the
preferences of the decision maker as elicited through the attributes. By changing the weight
of the top ranking attributes the changes in the top performer countries are shown.
Chapter 5 will bring together the results of each of the chapters in order to provide an
overall conclusion. The technological and economical models show the strong relationship
between the flow rate of CO2 and the resulting cost per tonne. This is due to the linear
relationship between the flow rate and the water requirements. The energy requirements
are also driven by the CO2 flow rate. The costs, while high in the pilot program, become
competitive at large flow rates when compared to the information in the literature review.
The information in Chapter 5 will also provide insight into the role of the number of
required wells. This accentuates the importance of the number of wells being determined
13
both for injection as well as monitoring. The Hellisheidi full-scale scenario is also one with
a dynamic that may change in the near future. The increased electrical production, and as
such annual CO2 emissions, can help to drive down costs in the future at the current costs.
All of these factors combined result in a program that may be highly competitive and a
viable service product in the future. The costs known and used for analysis in this thesis
are still on a preliminary basis as this is a pilot program. Internal learning through doing
may lead CarbFix to be a leader in the carbon mineralization method of carbon capture and
storage.
The market analysis provides a short list based on the attributes utilized in the SMART
analysis as well as the purchasing power of the market. It is important to note that while
some countries do not lie on the efficiency frontier, which produces the short list, they may
be acceptable markets to enter in the future. For example, Malaysia provides an adequate
attribute score and has sufficient power purchasing but does not lie on the efficiency
frontier. It is however the sensitivity of one particular attribute, natural gas, that provides
the most interesting information. While it was not listed as being the highest weighted
attribute it is found to be the most prominent attribute in terms of sensitivity in the
resulting markets. Natural gas production requires CO2 to be removed in order for the
natural gas to reach its required quality for sale. Tax associated to CO2 emissions from
natural gas has already motivated one company to turn to carbon storage as an alternative
option to the tax. Being aware of this key aspect can help CarbFix in the future to remain a
living organism capable of adapting as other countries possibly adopt this tax.
14
II. LITERATURE REVIEW
II.1 Geological Storage
Geological sequestration of carbon dioxide is in itself not a new idea towards the lowering
of atmospheric emissions. In fact, natural underground CO2 fields are present around the
world and have existed for geological timescales1 (Holloway, 2005). To date research has
mainly focused on depleted oil and gas fields, non-economic coal beds and saline aquifers
(Oelkers & Cole, 2008; Benson & Cole, 2008). The literature review and this Chapter
discuss the injection of CO2 into these types of formations where pressures and
temperatures are above the critical point, or 7,38 Mega Pascal (MPa) and 31,6°C2. These
formations are at depths of more than 1.000 m (McGrail et al., 2006).
Gas and oil fields are natural pools of trapped gases and fluids. They are covered by a cap
rock, which has trapped the oil and gas before exploitation by man. Once these fields are
depleted they can be used to re-inject CO2 and store it stably. The setup could be minimal
as most of the existing infrastructure, such as wells and geophysical data, can be re-used
and this would help minimize capital costs; however it may be necessary to drill new
injection wells instead of using the existing ones if the quality of the well has degraded
(IEA, 2004). Also, previous extraction of oil and gas must not damage or fracture the cap
rock (Holloway, 2005). Because there is usually no water present in gas fields the volume
of CO2 possible to store could be approximately equal to the volume of gas that was
present beforehand (Holloway, 2005).
Coal beds have fractures called cleats. Pores present in the cleat contain gas known as coal
bed methane (CBM). The methane is absorbed into the pores but is dependent on
temperature and pressure and can, depending on changes in these two factors, be desorbed
1
Periods of time as defined by significant historical and geological events such as mass
extinction.
2
When CO2 is injected into reservoirs with a temperature above 31,1°C and a pressure
above 7.39 MPa it is said to be at its supercritical state in where it has the properties
between that of being a gas and a liquid.
15
(Davidson, 1995 as cited by Holloway, 2005). Once the CO2 is pumped into this type of
reservoir it can absorb onto the coal and can be held in place, dependent on temperature
and pressure (Holloway, 2005). The methane recovered when CBM is released can
additionally have economic value, which can then offset the sequestration costs. This was
first tested on a large scale at the San Juan Basin in New Mexico. In 1995 CO2 was
injected through multiple wells and led to an increase in methane recovery from 77% to
95%. The total amount of CO2 injected over the following six years was 370 thousand
tonnes (Mazzotti, Pini & Storti, 2009).
Statoil in Norway is performing an industrial-scale example of the geological storage of
CO2 in a saline aquifer. In order to produce saleable natural gas according to consumable
specifications the CO2 is stripped (Alphen, Ruijven, Kasa, Hekkert & Turkenburg, 2009).
The CO2 is then re-injected into the offshore Sleipner West gas field and has been
operating since 1996 at a rate of 1 mega tonne (Mt) CO2 per year (Holloway, 2005; Torp &
Gale, 2004). The area in which Statoil is re-injecting is the Utsira formation, which is an
offshore sand bed 800-1.000 meters below the sea bottom and 150-200 m thick (Holloway,
2005; Torp & Gale, 2004). The purpose of this sequestration scheme was mainly due to
financial burdens that would have otherwise been incurred due to a carbon tax, !40 per
emitted tonne3, for offshore petroleum activities (Karstad, 1992 as cited by Alphen et al.,
2009). The extra costs to Statoil from this operation are $15 per tCO2 avoided4 (Herzog,
1999).
The sequestration of supercritical CO2 in basalt, depleted oil or gas reservoirs, coal beds
and aquifers all require an impermeable cap rock. This is due to the nature of CO2 at
various conditions but specifically its tendency to be more buoyant than in-situ fluids
(Benson & Cole, 2008; Oelkers & Cole, 2008). When the CO2 pervades the reservoir rock
the fluid that filled the rock’s pores is pushed out and the CO2 fills the space. Any barriers
to flow through the reservoir of the in-situ5 fluids can limit the amount of CO2 possible to
inject because of the pressure increases (Holloway, 2005). The migration behaviour of CO2
is dependent on the pore fluid’s properties; that is whether the CO2 will be miscible or
immiscible. Miscible means that the CO2 can mix completely with the pore fluid to form a
3
The tax was introduced in 1991.
In 1999 USD.
5
In-situ is a Latin phrase meaning literally “in its original place”.
4
16
single phase, whereas immiscible means the two phases remain separate (Benson & Cole,
2008).
The cap rock plays an important role, as the re-injection reservoir does not require a dome
shaped structure such as oil or gas fields. The reservoir can be flat as long as it is large
enough that the CO2 will simply rise until it reaches the cap rock. When the structure has
reached its full storage capacity the CO2 could spill out and follow migration paths of
interlocked pores and begin to fill any connecting formations (Holloway, 2005).
The options discussed for geological sequestration have incredible potential for storage as
they are estimated to have the capacity of up to 3,3 teratonnes (Tt) of CO2 in oil and gas
reservoirs, 36,7 Tt in saline aquifers and 734 gigatonnes (Gt) in unmineable coal beds6
(IPCC, 2005). As a comparison the annual CO2 emissions from fuel combustion in the
world are approximately 29 Gt (IEA Statistics, 2009). There are large uncertainties in
regards to the actual capabilities of storage. The storage potential will vary by region and
so a case-by-case analysis is always important and no real standardization analysis method
is available (IPCC, 2005).
Enhanced oil recovery (EOR) and enhanced gas recovery (EGR) are techniques used
currently in various locations and represents a more economical approach to CO2 reinjection. EOR is the process by which additional oil is recovered through various
processes, one of which is the injection of supercritical CO2. The CO2 displaces residual oil
that was not removed during primary production or secondary recovery (Ravagnani, Ligero
& Suslick, 2009). EGR is a similar process in which CO2 is used to displace residual
natural gas in mature reservoirs (Solomon, Carpenter & Flach, 2008). The additional oil or
gas recoverable can offset the sequestration costs (Holloway, 2005).
EOR increases the recovery of original oil by 50% and EGR a 5 to 15% increase in gas
recovery (IEA, 2004). Even though these two techniques seem to be economical options to
offset CCS costs, they are sensitive to location. In general the farther the distance of the
injection reservoir from the point source of the CO2 emissions, the higher costs are for
transportation (IEA, 2004). However, in EGR and EOR the cost of injecting CO2 is limited
to the increased value in the additionally produced gas or oil, and the cost for
6
Original values were given in amounts of carbon. One tonne of carbon, when combined
with oxygen to produce CO2, has a mass of 3,67 tonnes.
17
transportation must not exceed this threshold. The deployment of CCS for the purpose of
EOR or EGR may be one of the key driving factors for the overall deployment of CCS as
an emissions reducer. Economics for EOR and EGR will lead to a market in which the
emitter can sell the CO2 to another entity, for example an oil production company, who is
attempting to increase their oil or gas production. Through increasing attempts by the
emitter to capture CO2 in an economical manner, at the lowest possible cost in order to
achieve the highest net gains, there may be a gain in technological knowledge through
learning by doing.
II.2 Mineral Carbonation
Fixing CO2 as a mineral is referred to as mineral carbonation and results in calcite
(CaCO3), dolomite (CaMg(CO3)2), magnesite (MgCO3), siderite (FeCO3), and magnesiumiron carbonate solid solutions (Oelkers, Gislason & Matter, 2008), which are stable over
geologic timescales and thus not prone to leakage (Oelkers & Cole, 2008). The process
itself is a naturally occurring one and referred to as silicate weathering. The
Intergovernmental Panel on Climate Change, IPCC, (2005) identified mineral carbonation
as one such method to produce stable elements over long periods with a retention rate7 of
near 100%. The IPCC however mainly addresses mineral carbonation as an ex-situ8
process in which the minerals would need to be mined and transported and after the
carbonation processes has taken place, the resulting carbonate contained in a waste site.
Hepple and Benson (2002) find in their research that an acceptable leakage rate for
geological sequestration was less than 1% per year. Their analysis considers six allowable
emissions levels to reflect the emissions scenarios set out by the IPCC Special Report on
Emissions Scenarios within a 300-year timeframe. It is however noted that mineralization
of CO2 would decrease the migration towards the surface (Hepple & Benson, 2002).
In order to fix the CO2 and produce these stable minerals there is a need for, in addition to
the CO2 itself, divalent cations9 such as Ca2+, Mg2+ and Fe2+(Gislason et al., 2009). The
groundwater present in basaltic rocks in Iceland has been found to be rich in Ca2+ and
7
The retention rate is the percent of CO2 that remains in the injection site and does not leak
in the long-term.
8
Ex-situ is the opposite of in-situ and refers to operations “off site”.
18
Mg2+(Arnorsson et al., 2003 as cited by Gislason et al., 2009). When CO2 is exposed to
this groundwater the reaction follows:
(Fe2+, Ca2+, Mg2+) + CO2 + H2O = (Fe,Ca,Mg)CO3 + 2H+
(1)
Oelkers et al. (2008) estimated that each one tonne of carbon to be fixed (approximately
3,67 tCO2) requires 8,8 tonnes of basaltic glass10. The precipitation of carbonates is
dependent on the pH. As the basalt dissolution increases the amount of cations available
increases and thus increases the pH until the precipitation begins (Matter et al., 2008).
Additionally the dissolution rate is increased with a lower silica content of the reactive
rock (Alfredsson, Hardarson, Franzson & Gislason, 2008). Through tracer tests it has been
confirmed that the basaltic bedrock at the Hellisheidi injection site is made up of
homogeneous porous media and thus a network of interconnected pore space for a large
reactive surface area (Khalilabad, Axelsson, Gislason, 2008).
An area being studied that is comparable to the CarbFix project is the Columbia River
Basalts Group (CRBG) in the United States, specifically in the states of Washington,
Oregon and Idaho. Its land coverage is 164.000 km2 and is estimated to have a volume of
174.000 km3. McGrail et al. (2006) state that the storage potential of this area is 100 Gt of
CO2. The area in the CarbFix pilot study is able to accommodate 12 Mt of CO2 (Gislason
et al., 2009)11. In comparison to this volume it takes 2.3 m3 to fix the CO2 produced
annually by one car and the human produced annual emissions from large industries12 is 29
Gt of CO2 (Oelkers & Cole, 2008).
The CRBG is made up of multiple lava flows and shows significant porosity as well as a
cap rock in the form of low-permeable interbedded sediments and impermeable basalt
between interflow zones (McGrail et al., 2006). Samples from the CRBG in the laboratory
have produced carbon mineralization when exposed to water and supercritical CO2.
9
Divalent cations are atoms that are missing electrons when they are compared to their
elemental state.
10
This is assuming 100% dissolution of the mineral and glass and that all divalent cations
end up in carbonates.
11
This is assuming that there is 10% porosity in the rock and 10% of the pores are filled
with calcite.
12
These are emissions primarily from coal, oil, natural gas, and the production of cement.
Their emissions constitute, of total CO2 emissions, 36%, 42%, 18% and 4% respectively
(Oelkers & Cole, 2008).
19
Another finding from McGrail et al. that may have more global relevance is their
comparison of CRBG samples to those from the Deccan basalts in India (2006).
The Deccan Volcanic Province (DVP) is one of the largest flood basalt formations in the
world. It is located in western central India and is estimated to cover 500.000 km2 and have
a volume of 512.000 km3, or three times the size of the CRBG (Eldholm & Coffin, 2000 as
cited by McGrail et al., 2006). Samples taken from this area and compared to the samples
from the CRBG showed similar mineralogy. The importance of the presence of the DVP is
accentuated even more when the fossil fuel powered electricity generation in the country is
considered. Of the 37 gigawatts (GWe) electrical production in India, 26% is located near
or on the DVP (McGrail et al., 2006). India was also listed as fourth in the top CO2
emitting countries of 2004 superseded only by Russia, China and the United States
(Marland et al., 2007 as cited by Oelkers & Cole, 2008).
Because basalt is dominant in seafloors there has been some discussion towards oceanic
injection. The advantages would be the large amount of water available and thus lower the
costs in regards to the water required in the CarbFix method of storage. The ocean floor
could also offer a low-permeable cap rock (Oelkers et al., 2008). The transportation costs
to move the CO2 flow from the source to these offshore locations may however outweigh
this reduction in water costs. Off shore pipelines tend to increase costs by 40 to 80% above
on-shore pipeline costs (IPCC, 2005).
II.3 Carbon Capture & Storage
Carbon capture and storage, more commonly referred to as CCS, is the process of three
separate actions: capture, transport and storage. The CO2 is captured from an immobile
emitter, such as a power plant, and is then transported via pipelines to a storage site. The
CO2 is injected into any of the reservoir formations discussed in Chapter II.1. CCS is a
manner of reducing atmospheric greenhouse gases by removing and sequestering CO2
before it ever reaches the atmosphere.
This literature review will present the economics and costs of CCS, which are still quite
high. Although technological advances are expected they depend on the continued research
and large-scale implementation of CCS in order for the larger scientific community to
learn how to reduce the costs. The IPCC identifies five key factors that will affect the rate
at which CCS is deployed (2005). The first is the governmental and international policy
20
regime and the emissions targets set in the future. Closely related is the second factor of
what baseline is used. The higher the emissions in the baseline and the lower the emissions
targets will lead to an increase in the pace at which large emitters turn to CCS as a possible
mitigation path.
The third factor is the nature of the future fuel source. If coal continues to be a significant
part of the energy mix in the future the outlook for CCS is more positive than if cleaner
production options are chosen, such as wind and solar. The nature of the emissions trading
programs can also have a large impact and is the fourth factor. A world where trading of
credits is unconstrained and the price is low will have a negative impact on CCS. This is
because the price of CCS is still quite high, and given the choice emitters will choose the
less expensive option of purchasing credits instead of committing to the capital that CCS
entails. To date economic modelling has shown CCS deployment when carbon dioxide
prices approach 25 to 30 US$/tCO2 avoided for coal plants (IEA, 2004). The fifth key
factor is the rate at which technological improvements are made and the reduction of costs
in CCS thus leading this emission reductions option to become more competitive.
The importance of CCS can be best exemplified through the Kaya equation named for
Professor Yoichi Kaya (1990) of the University of Tokyo.
Net (CO2) = [ P (GNP/P) (E/GNP) (CO2/E) ] – S
(2)
Where the net carbon dioxide emissions are a factor of P = population; GNP/P = per capita
Gross National Product; E/GNP = energy consumption per unit of GNP; CO2/E = amount
of CO2 emitted per unit of energy consumed; and S = amount of CO2 sequestered.
As the global community will continue to grow, the remaining avenues of reduction for net
CO2 emissions are to reduce the energy intensity of the economy, to reduce the carbon
intensity of the fuel used, and to increase the amount of CO2 sequestered. Equation 2 also
shows the connection between the economic growth of a nation and their resulting
emissions as well as the importance of the choice of fuel for electrical production in the
future. Energy efficiencies have already improved to some extent as the required amount of
energy to produce one unit of world Gross Domestic Product (GDP) has decreased steadily
1,6% on average per year between 1990 and 2006 (World Energy Council, 2008).
However, more efficiency gains will be essential to reducing emissions (IEA, 2004). These
efficiency gains will be most prominent in developing nations rather than in developed
ones as developing nations have more gains to be made. The fact remains however that as
21
world growth progresses, both in population size and economic growth, there will be an
increasing demand for energy services13. Carbon storage then becomes a key part of the
Kaya equation in stabilizing net emissions or even possibly reducing them.
II.4 Associated Risks
There are different risks that are associated with the re-injection of CO2. Some of these
risks are real, such as leakage, while others are perceived and connected to public
perception. While proper site selection, monitoring and verification of CO2 storage sites
can help to mitigate the real risks of leakage, the problem of negative public perception is
one that poses more qualitative problems (Robertson, Findsen, & Messner, 2006). Those
working in CCS and its future large-scale deployment maintain that this can only be
resolved through energy literacy and global environmental education of the public
(Marliave, 2009).
When a site is selected for storage it is important that all possible leakage sites are
assessed. These can be unknown open wells in an area outside of the injection site but
within the area of expected migration, as well as cracks in the cap rock. This accentuates
the importance of CO2 migration modelling and a deep understanding of the geophysical
and geochemical make up of the storage reservoir. Monitoring during and after injection
should focus on the lateral migration of CO2 as well as the vertical leakage in and outside
the vicinity of the storage area (Robertson, et al., 2006). Monitoring also has a direct effect
on verification of CO2 storage for the purposes of gaining trading credits.
In 2009 van der Zwaan and Gerlagh studied the effectiveness of CCS in terms of long-term
CO2 leakage. They assessed six separate leakage scenarios, one of which was no leakage,
and studied the annual leakage rates as well as cumulative storage until the year 2200.
Each of the scenarios were studied with the parameters that future climate control would
impose a carbon tax and a target of 450 parts per million by volume (ppmv) of CO2. The
scenarios where leakage was present were either through a constant leakage rate or a twolayer leakage rate, where the leakage would follow the path of a bell curve. The findings
13
Economic growth and energy consumption relationships may differ between income
groups. Middle income group countries show a positive correlation between economic
growth and energy consumption while high income group countries have a negative
correlation reflecting efforts to increase energy efficiency (Huang, Hwang & Yang, 2008).
22
conclude that a leakage rate of less than 1% would be acceptable which is in agreement
with the work done by Hepple and Benson (2002). An additional, and equally important,
result is that the cumulative geological storage of CO2 peaks at the year 2100 and then
begins to plateau. From the start date, the year 2000, until 2100 the cumulative storage
increases from a range of 50 to 200 Gt14. However the range in 2200, 100 years later, is
only 90 to 330 Gt calling for a continued effort to stabilize atmospheric concentration of
CO2 through utilization of energy resources low in carbon intensity coupled with CCS.
Regulations and permits will undoubtedly have an effect on how monitoring and
verification (M&V) will be required and carried out for CCS. The IEA (2007) identified
the possible way in which the phases of these actions would be compartmentalized: site
assessment, project baseline identification, operational and long-term monitoring. The site
assessment would require a characterization of the storage site in three different ways:
geographically, geologically and geochemically; and would include migration modelling.
The project baseline is an important aspect as it gives the current situation of the site and a
comparative standard during injection and post-injection. The operational monitoring
would include the monitoring of the injection wells and any monitoring wells for possible
leakage as well as any other sites that were possibly identified as leakage risks during the
site assessment. The long-term monitoring is one of the most controversial aspects of the
M&V framework. The surface and subsurface would need to be monitored but the main
questions remain: how long is the entity required to monitor and how frequently?
Additionally, after the entity has been released by a pre-determined contract from
monitoring, is it the States’ responsibility to continue monitoring, and for how long?
The European Union has addressed some of these issues of regulation requirements in the
Directive concerning geological storage of carbon dioxide and resulting amendments to
older Directives (Directive 2009/31/EC). The storage of CO2 under seabeds has been
addressed by the amendment to the 1996 London Protocol while Directive 2008/1/EC15 is
a suitable framework for addressing the environmental and health risks of CO2 capture.
Directive 85/337/EEC16 concerning the effects of projects on the environment is also
14
This range is excluding the “no leakage” scenario.
Directive 2008/1/EC of the European Parliament and of the Council of 15 January 2008
concerning integrated pollution prevention and control.
16
Council Directive of 27 June 1985 on the assessment of the effects of certain public and
private projects on the environment.
15
23
amended to be applicable to CCS and requires environmental impact assessments.
Directive 2004/35/EC17 and 2003/87/EC18 were also amended to include CCS operations,
specifically the latter Directive to include a financial burden on the operator of the storage
site in the case of environmental clean up due to damage.
Directive 2009/31/EC,19 in addition to these amendments, sets guidelines on regulation of
CCS in member states. The factor of storage site selection is, while under control of the
member state, under the Directive required to be one that presents no significant risk of
leakage and no significant environmental or health risks. Storage sites are mandated to be
operated with a storage permit as well as a permit required for exploration of a site for
possible storage. As Iceland proceeds to adopt this Directive in its legislation projects such
as the Hellisheidi full-scale scenario will likely be required to follow the guidelines as
prescribed by the Directive.
II.5 Liability
The subject of risk is directly related to the subject of liability. At what point is the private
entity relieved of its liability and risk assumed to be a public liability? There are many
issues that have to be included in liability such as the time frame, the extent of the liability,
who specifically is liable for what portion of the CCS process and trans-border issues.
Directive 2009/31/EC makes some provisions, which will help clarify the issue of liability
in CCS projects in the future.
II.5.1 Short-term versus Long-term
The time frame can be split into two different periods; short-term and long-term. The
short-term time frame is generally considered to be the operational liability and is the time
during injection and any post-injection period as stipulated by contracts (Robertson et al.,
2006). There are numerous issues to be covered by operational liability such as the
17
Directive on environmental liability through prevention and remedying of environmental
damage.
18
Directive on emissions trading and subsequently the surrender of emissions allowance in
cases of CO2 leakage.
19
Directive 2009/31/EC of the European Parliament and of the Council of 23 April, 2009
on the geological storage of carbon dioxide.
24
environmental, health and safety liability. The short-term timeframe is generally thought to
be the lesser problem of the two in terms of allocating responsibility and many feel should
be modelled after the oil and gas industry (Robertson et al., 2006).
During the long-term time frame the main aspects are the environmental effects such as
leakage, in-situ effects such as contamination of water supplies or damaged hydrocarbon
resources (Robertson et al., 2006). Additionally, trans-border liability has become an issue
as the CO2 may migrate into the pore space of other nations (IEA, 2007). All of these
factors, especially the latter, are closely related to pore space ownership, which is covered
in Chapter II.6. To review the list and give a better understanding of the connection to
liability the first issue is addressed: leakage. Currently there are many efforts to account
and verify global CO2 emissions as well as on a national level. This can be connected to
the national emissions targets due to the Kyoto Protocol and due to trading schemes of
carbon credits. Should there be a leakage of CO2 in the long-term the accounting
inventories would need to be corrected as well as liability of the CO2 possibly reassigned
(Robertson et al., 2006).
The in-situ liability is connected to any contamination of natural resources present in the
sub-surface that may be damaged by the CO2 and its unforeseen migration. This could be a
water supply or hydrocarbon resources. Again, it is emphasized the importance of correct
site assessment and modelling to better understand and forecast the long-term effects of reinjection of CO2. There is some legislation already in place that would deal with these
liability issues such as the United States Safe Drinking Water Act (US SDWA)20. The
trans-border liability is one that would need to be addressed and dealt with on an
international scale through protocols. Any migration of CO2 and resulting damage would
then need to follow these frameworks on how to assess liability and within what time
frame (Robertson et al., 2006).
II.5.2 Insurance
There is also discussion in the CCS world as to whether there should be a requirement of
insurance (Robertson et al., 2006) and, again, for what time period? Currently there are no
insurance products related to the post-injection period and very limited products offered
20
Standards on the drinking water in the United States as set out by the Environmental
Protection Agency (EPA).
25
during the injection period. Also, while the insurance may answer the calls for a clear
liability framework it may also hinder the deployment of CCS as a technology. CCS is
currently still a maturing technology and the costs high; adding an additional cost of
insurance, especially if the perception of risk is high, could lead to industries abandoning
research and trial efforts (Robertson et al., 2006).
Directive 2009/31/EC makes provisions for the transfer of responsibility requiring that
responsibility be transferred from the operator to the state when and only if evidence
indicates that the stored CO2 is contained in a permanent manner. The state should then at
that point continue monitoring for a period of 30 years in a fashion that would confirm
permanent containment. Should there be any form of leakage during the post-closure
monitoring period the operator is not liable for recovery costs unless there is fault on the
operator’s part before the transfer. However, the operator is required to make a financial
contribution before the transfer and guidelines regarding the amount have yet to be
determined. The operator is also required to attain some type of financial security, possibly
in the form of an insurance policy, before the injection may begin. This financial security
would then cover any operator liability that may arise during the injection or post-closure
phase.
Some regulating authorities are offering indemnities to industries wishing to explore CCS
in their regions. An example can be seen currently in the American Clean Energy
Leadership Act (ACELA), which in September of 2009 was submitted to the United States
Congress. Through this Act there would be an amendment to the Energy Policy Act of
200521, Section 963, allowing for indemnity of ten large-scale re-injection projects that can
inject and store yearly over 1 Mt of CO2. The indemnity would cover issues of liability
related to health and safety, loss or damage to property and injury or destruction of natural
resources (ACELA, 2009).
Another example of clarifying and relieving liability is the Carbon Storage Stewardship
Trust Fund Act (CSSTFA) of 2009. This bill differs from the ACELA in that it offers a
framework instead of direct indemnity. During injection the entity is required to deposit a
risk-based fee into a fund on a tCO2 injected basis. After a contractual post-injection period
the government would claim stewardship over the site. Any hazards that may present
21
The Act provides financial incentives and loan guarantees for energy production,
specifically ones that do so while decreasing emissions.
26
themselves in the long-term are then addressed using funds that were collected during
injection. Some other characteristics of the Bill are the requirement of insurance during
injection, although not limited to third-party insurance, as well as an established standard
for measurement, monitoring and verification during the post-injection stewardship, which
is outlined in coordination with the Environmental Protection Agency (CSSTFA, 2009).
In the process of laying down the legislation framework for CCS there must be caution
placed in not increasing negative public perception. For example, the Price-Anderson Act
of 1957, while a good act for laying the framework for insurance requirements and
liability, is not an Act that CCS would be well served to copy. The reason being that the
Price-Anderson Act deals with the insurance and liability issues of nuclear plants. By
pursuing a similar cap there may be a public misperception that CCS entails the same risks
and is comparable to nuclear energy production when in fact the two are entirely different
(Robertson et al., 2006).
II.5.3 Multiparty Liability
As CCS is a multi-stage process in which many different entities may partake, the steps of
the process must also be clearly defined. At what point is the entity responsible for
transport legally liable for any damages and at what point does the entity responsible for
injection take over? The Australian government in 2005 outlined the Regulatory Guiding
Principles for Carbon Capture and Storage, which outlined the processes from start to
finish and thus could be used as a guideline for where liability transfers. The process
identified the following phases (MCMPR, 2005):
•
Capture; the CO2 from an industrial process, electricity generation or hydrogen
production to the flue stacks.
•
Transport; from the flue stack to the injection well.
•
Injection; pre- and post-injection activities
•
Post-closure phase; storage, decommissioning and long-term responsibility.
All of these issues underscore the importance of understanding the risks, clearly
identifying the responsible parties, outlining the time frames and properly classifying CO2
and its subsequent ownership. Public awareness is as well a large factor and one that, while
there is agreement is a crucial element, remains to receive more work on the part of the
27
government entities as well as industry. These issues will be explored more in Chapter II.6
and how regulations and permits can set these guidelines.
II.6 Regulations
All of the issues mentioned in Chapters II.4 and II.5 regarding risk and liability should and
will be addressed in the future through regulations and permit allowances. While there are
currently regulations that will have an impact on CCS projects, such as Directive
2009/31/EC, the extent of that impact will be more known once CO2 emissions are more
formally defined. There are three different ways in which CO2 could be defined and
classified: as an industrial product, as a waste product or as a resource (Robertson et al.,
2006). Waste products are generally subject to more stringent environmental regulations
than industrial products. The last classification, resource, leads to issues directly related to
liability, such as that of ownership, which would inevitably lead to greater liability.
II.6.1 Classification of CO 2
In the current CCS projects, and the corresponding pre-existing legislation, the
classification seems to be unclear and contradictory. The Sleipner project in Norway gives
a mixed signal as to the perception of CO2. The CO2 itself is classified as an industrial
commodity because it is the result of industrial activities: the production of natural gas. A
regulation and monitoring requirement of the Sleipner project, however, is the Pollution
Control Act, which protects against pollution and waste, giving the impression that it
should be classified as a waste (Ministry of the Environment, Norway, 1981).
The EPA, in a publication from 2008, admits that CO2 is not listed as a hazardous
substance according to the Comprehensive Environmental Response, Compensation and
Liability Act22, however it maintains that there may be other hazardous substances present
in the CO2 stream such as mercury. This substance, in reaction with groundwater, could
produce sulphuric acid, which is a listed hazardous waste. This makes the assumption that
all flue gas scrubbers are equal and does not make allowances for the fact that flue gas
composition is also varied depending on the point source.
22
The CERCLA, more commonly known as the Superfund, is a law that allows the EPA to
clean up contaminated sites and seek financial compensation from the liable party.
28
II.6.2 Pore Space Ownership
One topic that has received a considerable amount of attention is pore space ownership and
property rights (IEA, 2007). This is especially important when the migration of the CO2
plume falls into a property not owned by the injection site property owners. The rights can
be twofold then with the pore space being owned by the surface owner but the injected
CO2 owned by the operating entity. This would lead the issue back to liability as well as
possible pore space renting demands by the surface owner. There are also two different
theories that are defined as the “American rule” and the “English rule.” The first holds that
the owner of the surface is the pore space owner while the latter argues that the mineral
rights owner, or in this case the owner of the CO2, is the pore space owner (Wilson &
Gerard, 2007). In Iceland the laws seem to follow more closely to the “American rule” as
there are no restrictions on ownership in relation to depth (Elin Smaradottir, personal
communication, December 6, 2009). Any injected CO2 and resulting possible migration
would need to be closely followed so as not to violate pore space ownership of surrounding
properties.
A reason why clear frameworks for regulation, as well as liability and monitoring, are
difficult to develop is because there are many governmental entities that may have
jurisdiction and each with its own policy on regulation. There are ministries that oversee
energy matters, environmental and natural resources and storing CO2 can cross all of these
paths in a lateral manner (Robertson et al., 2006). Thus, there is an extended amount of
coordination needed in order to identify all stakeholders and address all of their needs.
II.6.3 Licensing & Permits
Regardless of who holds pore space ownership and what regulations are set into place there
will have to be a licensing or permits framework. A licensing regime has been outlined by
Australia who seems to be taking the global lead in defining complex issues concerning
CCS. The regime gives the option of four separate permits (IEA, 2007).
•
Exploration permit; a six-year permit. The permit requires some information such
as site assessments to be performed on the hand of the applicant and
administrational fees. If after the six-year period no further permits have been
processed the original permit is deemed complete and all rights are relinquished.
29
•
Storage retention lease; a 5-year permit lease. This permit is useful for sites that are
identified as positive geological formations for storage but no CO2 stream is yet
economically available for injection. A storage plan is required so as not to promote
pore space hoarding.
•
Injection and storage permit; injection is permitted at a specified rate and for a
certain period of time, generally the life of the CO2 stream. The area permitted for
storage is the injection site and the modelled migration path.
•
Decommissioning; the decommissioning would replicate regulations already in
place by the Offshore Petroleum Act of 2006.
II.7 Incentives
While the legal issues previously outlined may have a deterring effect on the deployment
of CCS, other international bodies are working towards creating incentives that may
encourage CCS along. The incentives can take many forms; some being direct actions such
as taxes or subsidies, while others rely on free market trade to develop incentives.
The Kyoto Protocol is an international agreement formed from the United Nations
Framework Convention on Climate Change, which binds certain nations voluntarily to
targets of lowering greenhouse gas emissions. The application of the protocol would set to
reduce emissions by nations by a certain percentage when benchmarked against 1990
levels of emissions. The Kyoto Protocol allows for three mechanisms that are marketbased in helping achieve these targets. At this time only one would have a possible future
effect on the CCS industry: the Clean Development Mechanism (CDM). The CDM allows
a developed nation to invest and partake in emission reducing projects in developing
countries in which it can earn credits, or carbon emission reductions (CER), towards its
own emission targets. Although CCS is not currently an approved CDM project the topic is
actively being debated and the possibility of it being included later is positive (UNFCCC,
1998).
The European Union Emissions Trading Scheme (EU ETS) resulted from the European
Energy Policy that aims to decrease carbon intensity, decrease emissions, and increase
energy security and energy efficiency. The EU ETS is a multi-national trading scheme that
is segmented into three separate trading phases. Currently Phase II is in place; it began in
30
2008 and will end in 2012. Phase III will begin January 1st, 2013. Large emitters would be
allotted allowances for the emission of CO2 on a t/CO2 basis. At the end of each fiscal year
the emitter must return the allowances equal to emissions for that year. The trading
mechanism then allows for those emitters that are able to decrease emissions in the most
economical fashion to sell allowances to those emitters who exceed their allowance
(Directive 2003/87/EC).
In the European Union there are also subsidies, which can be given by the State to any
entity wishing to undertake a project in the domestic economy. The main aim of subsidies
is to help industries. If a subsidy were considered to be a reward to CCS then the form of
taxes could be considered the penalty to the carbon intensive industries. As mentioned
previously in Chapter II.1, Statoil was subject to a tax on carbon, which ultimately was a
leading factor that led them to begin storing CO2. The ultimate goal and effect on
emissions of the subsidy and the tax are the same but they employ different social
pressures on the emitter. There are also large international groups that are considering CCS
for funding such as the Global Environment Facility (GEF). The GEF allocates funds to
developing countries that wish to undertake projects that protect the global environment
(Robertson et al., 2006).
II.8 Economics
The following sections will cover the costs of capture, transport and storage in recent
literature so that the CarbFix costs can be placed in context. The totality of these three
processes can present the mitigation costs associated to CCS as a process. The mitigation
cost is however not just the sum of these three parts as there is a distinction to be made
between the amount of CO2 captured and the amount of CO2 avoided. The additional
components of capture, transport and storage require some additional work and energy,
which increases the fuel and as such emissions produced per net unit of product, or
kilowatt-hour (kWh). The amount of emissions avoided will always be less than the
emissions captured unless the capture and storage requires no work. Due to the smaller
quantity of CO2 to spread the cost on, the cost per tCO2-avoided basis will always be more
than that of tCO2 captured (IPCC, 2005). This is represented in Figure 1.
31
Figure 1: CO2 captured vs. CO2 avoided. (Source: IPCC, 2005)
The costs of capture and mitigation can also be found by the following formula:
Costavoided = [Costcaptured x CE] / [effnew / effold – (1-CE)]
(3)
Where CE = fraction of CO2 captured; effnew = the efficiency of the power plant with
capture; effold = the efficiency of the power plant without capture (IEA, 2004). The
difference between the cost of capture and mitigation is largely dependent on the energy
efficiency penalty and as this factor decreases the two costs will begin to gravitate towards
each other.
When comparing a reference plant to a plant with capture it is common in academic
literature to compare similar plants, for example, a coal plant without capture to a coal
plant with capture. If a comparison were made to a coal plant with capture to a geothermal
power plant the emissions avoided would not seem very impressive as the emissions per
kWh are much lower in geothermal plants then coal plants.
Chapter II.8.1 compares costs between a coal reference plant and the same plant with
capture. If however, the marginal cost approach is taken in order to compare any two
plants with and without capture, regardless of the fuel source, the following formula could
be used:
MC = (COEcap – COEref) / (Eref – Ecap)
(4)
32
Where the mitigation cost (MC) is found through the COEcap = cost of electricity of the
capture plant; COEref = cost of electricity of the reference plant; Eref = energy requirements
of the reference plant and Ecap = energy requirements of the capture plant.
II.8.1 Capture
Large sources of CO2 are industrial emitters such as fossil-fuel power plants, cement
treatment plants and oil and gas refineries (IPCC, 2005). The flue gas exiting the plant
contains CO2 from production although the content of CO2 in the gas varies according to
the source. In a coal-fired power plant the composition is of approximately 14% while a
natural gas fired plant may contain 3 to 4% (Holloway, 2005; IPCC, 2005). There are four
different routes that can be taken to capture a clean stream of CO2: capture from industrial
process streams, post-combustion capture, oxy-fuel combustion, and pre-combustion
capture (IPCC, 2005). The following section goes into detail on post-combustion capture
or the capture of CO2 from flue gases produced by fossil fuel combustion in order to make
the connection to the pulverized coal scenario in Chapter III.4.
One method of capture is the separation of CO2 through a chemical solvent and is currently
the common option. It has a capture efficiency of 85-90% (IPCC, 2005). The flue gas exits
the power plant and is then cooled before it comes into contact with the solvent and the
CO2 attaches. Once this is done the solvent is transported to a separate container where it is
manipulated in either pressure or temperature to release the CO2. The solvent is then
regenerated and free to be returned to the original vessel for reuse. Chemical solvents are
the best option when CO2 in the flue gas is at low concentrations such as less than 15%
(IEA, 2004).
A common chemical solvent is monoethanol amine (MEA), an amine-based solvent,
although others are available. The cost of the MEA is 1,25$/kg (Rao & Rubin, 2002). The
choice of solvent can be affected by the amount of by-products that form during use as
well as the decomposition rate (IPCC, 2005). The more by-products that are produced
increases the costs associated with cleanup and disposal, and the faster the solvent
decomposes leads to additional costs for replacement solvent. In some cases the byproducts and decomposed solvent can even be classified as hazardous waste and require
special disposal (Rao & Rubin, 2002).
33
Although MEA is the most commonly used amine there are competitors entering the
market as research and development is being completed. One such competitor is the KS1
amine developed by Mitsubishi and is being tested in various plants. One example is a coal
plant in Nagasaki, Japan where in 2006 10 tCO2 was captured per day (Oishi, 2006). The
KS1 solvent has a lower energy requirement and is not as vulnerable to degradation
leading to less waste but it is a more expensive solvent than MEA (Ho, Allinson & Wiley,
2009).
Sequestration requires that the gas be stripped of any additional species such as nitrogen
oxide (NOX), sulphur oxide (SOX) and other by-product gases in order for easier
compression and storage. The presence of these by-products can also have negative effects
on the solvent and decrease the ability for regeneration. Costs of capture generally include
the costs for compression, which changes the CO2 to a supercritical state making transport
easier and cheaper (Rubin, 2008).
The largest portion of the costs associated to capture is due to the energy penalty required
for regeneration of the solvent using heat as well as the steam necessary for stripping the
CO2 and compression of the subsequent stream (IPCC, 2005). The capture portion of CCS
can be quite energy intensive and can constitute an energy penalty of between 9 and 34%
(Aroonwilas & Veawab, 2007; Herzog, 1999). Post-combustion treatment is generally
twice as energy intensive than pre-combustion (Rubin, 2008). Figure 2 shows the process
of the CO2 capture through solvents (sorbents) and the regeneration of the solvent. After
the solvent has adsorbed the CO2 in the capture unit it enters the regeneration unit where
the CO2 is released and the solvent returned to the capture unit. As can be seen in Figure 2
energy is required in order for the release of CO2 during the regeneration.
Figure 2: Separation process of CO2 through chemical solvents (Source: IPCC, 2005).
34
This capture technology can be retrofitted to existing fossil fuel plants. The disadvantages
are that the site may be constrained in the area available for additional equipment. Also,
the remaining plant life would need to be significant so that the high capital costs of the
capture equipment would be justified. Additionally, an older plant may have lower
efficiencies, which means the unavoidable energy penalty will have a greater effect on the
net output (IPCC, 2005). However an advantage is that the site, although perhaps not preplanned to include CCS, has an existing infrastructure and the facilities may be amortized
to a considerable degree. Also, they have a higher baseline of CO2 emissions compared to
new plants that may have lower emissions due to environmental pressures at the time of
design (Simbeck, 2001).
When considering the regions where plants, specifically coal-fired, may have substantial
life times left in order to justify retrofitting for capture technology, the United States may
have to wait until 2010-2020 to see any substantial actions. This is because the USA
peaked in its coal-fired generation construction around 1970 and since most plants have a
life of 40 to 50 years the remaining life of these plants should only average 2 to 12 years
(IEA, 2004). Some plants are being adapted to allow for better efficiency and this may
justify reanalyzing the capture retrofitting option as the plant may have an extended lifetime due to these changes in efficiency. However, Japan and China have only recently
begun building the main bulk of their coal-fired power plants and the average age is under
15 years of age making them optimum for retrofitting (IEA, 2004). The deployment of
CCS in China would be difficult to predict at this moment due to political uncertainty in
regards to emissions reductions.
Capital cost for capture generally includes the cost of the design, purchase and installation
of the capture system. The incremental cost is then the difference in capital cost between a
reference plant23 and the same plant with capture while producing the same amount of net
output on an MWe basis for example (IPCC, 2005). This then represents the amount of
additional capital needed in order to capture CO2. An additional comparison is the
incremental product cost in which the cost of electricity (COE) in $/kWh increases when
capture is added. The incremental COE gives an appropriate idea of what effect the capture
has on the cost of electricity. The COE can be found with the following equation:
23
A reference plant refers to a power generating plant with no capture and “business as
usual” emissions.
35
COE = [(TCR)(FCF) + (FOM)] / [(CF)(8760)(kW)] + VOM + (HR)(FC)
(5)
Where COE = levelized cost of electricity ($/kWh), TCR = total capital requirement ($),
FCF = fixed charge factor (fraction/yr), FOM = fixed operating costs ($/yr), CF = capacity
factor (fraction), 8760 = total hours in a typical year and kW = net plant power (kW),
VOM = variable operating costs ($/kWh), HR = net plant heat rate (kJ kWh-1), FC = unit
fuel cost ($/kJ), (IPCC, 2005). Using Equation 5 to calculate the COE of both a reference
plant and the plant with capture and comparing them can then give the incremental COE.
Equation 5 helps to explain why the economics of capture can sometimes seem bleak
especially when the energy penalty is considered. The energy is assumed to come from the
power plant itself. In Equation 5 the addition of capture means that the TCR is increasing
as well as the FOM and VOM. The kW in the denominator however is decreasing. Even if
the energy required for the capture were obtained elsewhere, outside of the plant, the unit
fuel cost would still increase. Overall the unit capital cost ($/kW) will increase and lead to
higher COE costs in ($/kWh). Cost is also dependent on the capacity factor of the plant and
the fixed charge rate (IPCC, 2005). The cost of the CO2 captured is represented in the
following equation:
$/tCO2 = [(COE)capture – (COE)ref] / (CO2, captured kWh-1)
(6)
Where CO2, captured kWh-1 = total mass of CO2 captured (in tonnes) per net kWh (IPCC,
2005).
Costs for capture are in the range of US$ 18-72/tCO2 avoided (Herzog, 1999; David &
Herzog, 2001; IEA, 2004; Simbeck, 2001) and adds 44-87% to the capital costs of a plant,
$/kW (IPCC, 2005). Of the total costs for CCS the capture portion can contribute 83 to
93% (Rubin, 2008; Rubin, Chen & Rao, 2007). David (2000) compares four separate
pulverized coal (PC) plants and readjusts the economic evaluation to common factors such
as yearly operating hours, fixed charge factor and fuel prices to find that the range of the
incremental COE increase is 2,27 to 5,66 ¢/kWh.
Appendix A contains an adapted table from the IPCC that compared a compilation of
studies to illustrate the difference in cost of CO2 captured between studies and the resulting
range of US$ 23-35/tCO2 captured for new pulverized coal plants. This range is smaller
than the US$ 18-72 range cited from Herzog and others because as has already been
explained in Chapter II.8 the cost of capture on a tCO2 basis is always less than the cost of
tCO2 avoided. The highest and lowest values were taken for simplification purposes. If the
36
lowest value and highest value are studied more closely the same key elements are seen
leading to the difference in cost on a tCO2-captured basis. The highest case, a study by
Parsons in 2002 (as cited by IPCC, 2005) uses a reference plant with a much lower net
output (MWe) for the reference plant, 462 MWe, then the study conducted by the
International Energy Agency, (IEA GHG24), 758 MWe (2004). Also, the fixed charge
factor is much higher in the Parsons case, or 15,5% while the IEA GHG study uses 11,0%.
The capacity factor and the plant efficiency are also lower for the Parsons case. This
supports the notion that the cost of capture for new plants is sensitive to factors such as net
output or fixed charge factor as well as efficiency.
The following two columns in Appendix A show the lowest and highest costs for CO2
capture for existing pulverized coal plants. Both studies were conducted by Chen et al.
from 2003 (as cited by IPCC, 2005) and use relatively similar values for the two cases. The
capital cost has been fully amortized which does help to lower the COE. The lower case
constitutes an existing plant that adds an MEA capture system and has a higher capital cost
than the higher value case. However, the higher case assumes that instead of accessing the
required energy penalty internally that a natural gas boiler is added to compensate for this.
This leads to a higher fuel cost, as the natural gas must now be purchased in addition to the
coal. The capital costs are lower but the new fuel costs seem to be a sensitive factor when
existing plants are considered. The same technique of adding a natural gas boiler is
performed by Simbeck in 2001 in order to compensate for the additional energy needs.
While the IPCC compilation of reports shows incremental COE increases of between 1,8 to
4,6¢/kWh some later studies, such as by the IEA (2004), found that the COE increases
would be in the range of 1-2¢/kWh. When the results found by David (2000) are added,
which have already been mentioned, the resulting range in the literature can be from 15,66¢/kWh. This is quite a large range and only accentuates the importance that plants
considering CCS must prepare their own analysis with the economical and technical
parameters that best fit their plant.
The IEA also projects that a coal plant starting operations in 2010 would see an
incremental cost of 775 US$/kW when capture is added while the same plant starting
operations in 2020 would only have an incremental cost of 695 US$/kW. This represents a
10% decrease in capital cost in $/kW basis while David and Herzog (2001) maintain that
24
Greenhouse Gas Research & Development Program
37
capital costs for capture could decline by as much as 33% by 2012 for a pulverized coal
plant. The cost range of 23 to 35 US$/tCO2 from the IPCC could also decline to as much as
10 to 25 US$/tCO2 according to the IEA (2004).
David (2000) through the study of the sensitivity of mitigation costs to technical and
economic variations found that the mitigations costs for a PC plant were most sensitive to
changes in the heat rate and energy requirement25. By decreasing the energy requirement
for capture by 10% the mitigation costs decreased by nearly 8% while a decrease of 10% in
the heat rate led to a decrease of mitigation costs by just over 4%. The least sensitive
factors were the operating and maintenance (O&M) costs as well as the incremental O&M.
There are, however, advancements being made that could possibly lower the capture costs.
As all technologies follow a learning curve26 the costs are expected to lower similarly, as
SOx scrubbers have done so through time (IPCC, 2005). The incremental COE and
mitigation costs could be reduced by 35% in 2012 when compared to 2000 (David, 2000).
Projects include advanced amines, chilled ammonia, and increased plant efficiency (Rubin,
2008). Perhaps the most promising option is sterically hindered amines that do not have as
strong of a bonding strength between the solvent and the CO2 and as such requires less
energy to release the CO2 from the solvent (IEA, 2004).
II.8.2 Transport
The most common method for transporting CO2 streams is by pipelines. The costs are
generally expressed in terms of US$/tCO2 captured. The major cost contributors are
construction costs, operations and maintenance and other costs that may include design,
insurance and right-of-way,27 (ROW) (IPCC, 2005). The cost of transport is dependent on
multiple factors including flow rate, diameter and distance. A report from the IEA (2004)
maintains that the cost is 1 to 5 US$/tCO2 transported per 100 km while Heddle, Herzog
and Klett (2003) find that when the flow is more than 10 Mt per year that the costs reach
economies of scale and are less than 1 US$/tCO2 per 100 km. These figures were then reexamined and confirmed in 2006 by McCollum and Ogden.
25
The energy requirement can be illustrated by ER = EP/E where EP = energy penalty and
E = emissions of CO2.
26
A phenomenon in which unit costs of technologies decrease as more units are produced.
27
ROW: The cost associated with the granting of land for transportation.
38
Figure 3 shows the increase in capital costs ($/km) as a function of flow rate at differing
distances of transport length. As the flow rate and length of the distance increases the
capital costs increase in $/km. The range of costs in $/km are much closer together when
the flow rate is small but diverge as the flow rate increases.
Figure 3: Costs for CO2 transport as a function of CO2 mass flow rate. (Source: McCollum
& Ogden, 2006)28
Figure 4 shows the effect of mass flow rate on the levelized cost, $/tCO2, after operations
and maintenance costs, types of terrain, and regional cost variations are considered and at
varying distances for transport length. As the flow rate increases the levelized cost falls
due to the larger amount of CO2 to spread the costs on. The type of terrain in which the
transportation takes place in can also affect the overall costs. The costs in Figure 4 can be
higher if the terrain is difficult to accommodate pipelines or if the ROW is very expensive.
These costs could however also be significantly reduced if there were a network of
pipelines to which multiple plants could connect (IEA, 2004).
28
Expressed in year 2005 US$.
39
Figure 4: Levelized costs for CO2 transport as a function of CO2 mass flow rate. (Source:
McCollum & Ogden, 2006)29
II.8.3 Storage
Costs for storage have been estimated to be approximately between 0,5 – 8 US$/tCO2
stored30. The most economical storage sites are those that are onshore, shallow and
permeable (IPCC, 2005). The more permeable a site is the more CO2 that is able to be
stored, and fixed costs are spread over a larger amount than if the storage capacity were
small. As mentioned earlier in regards to transport, the costs related to offshore are more
than those onshore. Additionally the shallower a reservoir is, the smaller the depth required
for drilling, which can exponentially reduce drilling costs. Thus storage and injection costs
are a function of the distance that the CO2 must travel as well as the depth.
The literature shows that the cost estimates for mineral carbonation storage are admittedly
limited. The costs presented in the IPCC report on carbon capture and sequestration (2005)
are based on ex-situ mineral carbonation and conveys practices of conventional mining for
29
30
Expressed in year 2005 US$.
Ideally assumed to be equal to the amount of CO2 captured.
40
reactive ores. The mined ores are then put through a still experimental phase called wet
process scheme.31 These costs were estimated at 50 to 100 US$/tCO2 stored depending on
the ore chosen and only represent the storage cost associated with producing the chemical
reaction between the metal ions and the carbonic acid (IPCC, 2005). The ex-situ mineral
carbonation process requires mining, transport of the ores as well as additional energy
separate from that to process and clean the CO2 stream from the flue gas. The total
required additional energy, for both capture and wet process scheme, is then 60 to 180%
for a power plant when compared to a similar power plant with no CCS (O’Conner et al.,
2007). There are additional CO2 emissions due to these extra processes and a life cycle
assessment shows that for each t/CO2 stored an additional 0,05 t/CO2 are produced (Newall
et al., 2000).
In addition to the storage costs are the costs of drilling when storage is to take place in
deep geological formations, as is considered here. Figure 5 shows the correlation between
costs and depth for well drilling. The range of costs when drilling is below 2.000 metres is
much smaller than when the drilling exceeds 2.000 metres. Although the figure appears to
exhibit a linear relationship it is exponential as the scale is log.
31
The solid ore is suspended in an aqueous solution so as to release the metal ions. These
ions then come in contact with dissolved carbon, carbonic acid (H2CO3), and produces fine
particles of carbonate. There are also byproducts and non-reacted solid materials remaining
and the process requires filtration and drying so as to recover the residual metal ions for
reuse.
41
Figure 5: Well drilling cost as a function of depth. (Source: Heddle et al., 2003)
Site screening and selection is estimated to cost $1.685.00032 in order to screen and
evaluate the possibility of CO2 injection (Smith, 2001). This includes, as defined by Smith,
a definition of screening factors, collection of data describing the candidate area,
evaluating with respect to screening factors and preparing the final report to rank the site.
In order to evaluate the site multiple tasks must be undertaken including but not limited to:
installing sampling wells, analyzing samples, installing a test well and logging the
performance as well as site modelling and seismic evaluations.
II.8.4 Monitoring
Monitoring is essential in CCS programs to ensure there is no leakage as described in
Chapter II.4. Leakage in this paper refers to the limits set by Ha-Duong and Keith (2003)
where a leakage rate of less than 0,1% per year is considered to be perfect storage. This
limit can be found by considering future emissions, which are vital in calculating how long
storage is required. If it is possible to store CO2 for a time between 100 and 2.000 years
then the leakage rate can be between 0,01% and 1% (IEA, 2004). Zwaan and Gerlagh
(2009), as well as Hepple and Benson (2002), have confirmed this rate. Monitoring data is
limited but have been estimated to add 0,1-0,3 US$/tCO2 stored to the CCS total cost
(IPCC, 2005).
32
In 2001 US$.
42
II.8.5 Total CCS Costs
As can be seen in Table 1 the differing cost ranges for the separate actions of capture,
transport and storage, including monitoring, gives us an idea of the costs of CCS on a
captured basis. In order to find the mitigation cost, tCO2 avoided, Equation 3 from Chapter
II.8 can be used to find the resulting range. For example, if this range is considered in
conjunction with a pulverized coal plant, which has a 20% decrease in efficiency due to the
energy penalty33 and has 90% capture efficiency, the range of costs is US$ 31,6 –
62,1/tCO2 avoided as per Equation 3.
Table 1: Review of the costs for CCS according to the literature. 34
USD
Unit
Lower Value
Higher Value Reference
Capture
tCO2 avoided
18
72
Herzog, 1999; David &
Herzog, 2001; IEA, 2004;
Simbeck, 2001
Capture
tCO2 captured
23
35
IPCC, 2005
Transport
tCO2 captured
1
5
IEA, 2004
Storage
tCO2 captured
0,5
8
IPCC, 2005
Monitoring
tCO2 captured
0,1
0,3
IPCC, 2005
CCS total
tCO2 captured
24,6
48,3
-
The capture costs avoided and captured include costs for capture and compression to
suitable transport pressures. The transport costs include those for pipeline infrastructure
and operations and maintenance costs. The costs for storage include costs for drilling,
infrastructure, project management, licensing and site selection. The range given for the
monitoring costs are dependent on monitoring requirements. The lower value includes
costs for repeated seismic surveys, wellhead pressure and injection rate monitoring while
the higher value includes additional costs such as well logging and surface CO2 flex
monitoring.
33
34
In this case the energy efficiency is assumed reduce from 45% to 36%.
Costs have not been adjusted for inflation and thus may be higher then presented.
43
II.9 PESTLE Analysis
A tool that is often used to assess external risk factors is the PESTLE analysis. This
acronym stands for political, economic, socio, technical, legal and environmental analysis.
These six separate external influences can be the source of risk or opportunity for a firm as
well as a driving force in the market that the firm is trying to enter (McGee et al., 2005).
This analysis is used in combination with the SMART analysis explained in Chapter II.10,
to evaluate opportunities for CarbFix in the global marketplace. This type of analysis can
help not only to identify risks and opportunities today but also possible future business
environments. By being aware of the status of these external influences, such as the type of
political party currently in place in a country market, a firm is better able to minimize risk
events (Worthington & Britton, 2006).
Political factors are any actions by the government that may affect the behaviour or actions
of a firm. This could be in the form of taxes, regulations, subsidies to competitors and
many other actions (Cheverton, 2004). These can also be large and far-reaching impacts
such as the fall of a political party or commanding regime, or a complete country profile
overhaul such as the fall of the U.S.S.R. This could be the fall of the exchange rate and
thus less buying power of the household (Cheverton, 2004). All are external factors that
can affect the demand of the product or service of a firm.
Socio and cultural factors that can affect the demand of a product or service are an
important indication as to the cultural demographic of the market. This factor not only
lends to what type of products or services are demanded but also the values of the culture
(Cheverton, 2004). This can be for example the demand for ecologically friendly products
pointing towards a culture that is environmentally oriented. Technological factors are any
factors that can affect the production or use of a product or service not only in the firm
entering the market but also of the competitors (Cheverton, 2004).
Legal aspects of the PESTLE analysis cover laws and regulations in place that will affect
the business operations of a firm. Laws can affect the costs of a firm through employment
laws, production laws, and waste removal laws (Worthington & Britton, 2006). The more
stringent the laws the more costs can be accrued due to actions that the firm may not have
undertaken in the absence of the law. Environmental factors can range from resources that
are readily or scarcely available that may be required for production to weather patterns
44
and harsh weather climates that may hinder regular business actions such as transport
(Cheverton, 2004).
II.10 Simple Multi-Attribute Rating Technique
The SMART analysis is based on the preferences of a decision maker. It is a prescriptive
analysis that describes the alternative best chosen when the decision maker behaves in
accordance to preferences (Goodwin & Wright, 2004). This type of analysis is commonly
used where the level of uncertainty is low or information is readily available. Information
can be in the form of known costs or through proxies35, which describe a certain attribute
in a quantitative manner (Goodwin & Wright, 2004). The analysis provides the decision
maker with the correct course of action to take where multiple alternatives were present.
Before being able to employ the SMART analysis an objective must be set out and is
determined to be the goal met by the decision determined through SMART. Attributes are
then the performance of factors that can help achieve this predetermined objective and the
score determined to be the value (Edwards, 1971). There are then 8 stages of the analysis
as described in the following (Goodwin & Wright, 2004).
•
The first stage is to determine the decision maker.
•
The second stage is to determine all the alternative avenues available to meet the
predetermined objective.
•
The third stage is to identify and define those attributes that can affect the choice of
alternative.
•
The fourth stage involves assigning a quantitative value to each identified attribute.
This may be done through proxies.
•
The fifth stage is to determine the weight of each attribute. This is a key stage and
determines how important each attribute is.
•
The sixth stage is to find the weighted average of the values that have been given to
each attribute. The weighted average is found by multiplying the weight of an
attribute by its value.
35
An attribute which may not be directly related but be a descriptive representative.
45
•
The seventh stage is to analyze the results of the aggregate scores. The aggregate
score is found by summing all of the weighted averages of all of the benefits for
one decision alternative.
•
The eighth stage is generally a sensitivity analysis to determine how sensitive the
final decision path is to changes in values.
46
III. TECHNO-ECONOMIC SCENARIOS
III.1 CarbFix – Present Status & Methodology
CarbFix is a pilot study being performed at the Hellisheidi geothermal power plant area
located in southwest Iceland. It was launched September 29th, 2007 and is a cooperation
between four partners: Reykjavik Energy (OR), University of Iceland36, University of
Columbia37 and the Centre National de la Recherche Scientifique in Toulouse, France. The
goal of the CarbFix pilot program is to test the in-situ sequestration of carbon dioxide
(CO2) through mineral carbonation in basalt. The project will develop industrial methods
of CO2 storage in basaltic rock. The project consists of field scale injection of watersaturated CO2 into basalt, laboratory experiments, geochemical modelling and natural CO2
water analogues. Through this program considerable expertise and knowledge are built up
in order to continue advancing science for CO2 storage in basalt.
The Hellisheidi power plant is a geothermal plant that currently has a capacity of 213 MWe
but is due to be extended to 303 MWe (Reykjavik Energy, 2009). It produces
approximately 60.000 tCO2 per year (Gislason et al., 2009) but with the future increases in
production this will reach approximately 90.000 tCO238. The CO2 emissions combined
with hydrogen sulphide (H2S), hydrogen (H2), nitrogen (N2), methane (CH4) and oxygen
(O2) make up the geothermal non-condensable gas, which is present in the geothermal
steam (Gislason et al., 2009). They are drawn up from the produced fluids from wells and
are discharged to atmosphere. The composition of the gas is mainly carbon dioxide, or
83% of mass, while the hydrogen sulphide is 16% and the remaining elements combined
make up 1% of the gas (Matter et al., 2008).
In the 2008 Environmental Report from Reykjavík Energy the hydrogen sulphide
emissions are discussed and a project proposed to reduce these emissions from the Hengill
36
37
Institute of Earth Sciences
Earth Institute – Lamont-Doherty Earth Observatory
47
area, where the Hellisheidi geothermal plant is located. This would be accomplished by
separating the H2S from the geothermal gas, mixing it with water and re-injecting into the
ground. This program, like CarbFix, is in its initial research stages. After this process the
stream from the H2S abatement system is an almost pure stream of CO2. CarbFix then has
a unique opportunity to use this pure stream to test re-injection and mineral carbonation of
CO2.
III.1.1
H 2 S Abatement System
The resulting flow from the abatement system is a compressed and cooled gas containing
98% CO2 and 2% H2S (Matter et al., 2008). It is then transported to the injection site by a
3-kilometer long HDPE pipeline (Sigurdardottir, 2009).
The costs of the abatement system were not included in the profitability analysis of this
thesis, as they are regarded as a sunk cost39. The H2S abatement is a separate project from
CarbFix and would be performed regardless of the CarbFix status. The author did want to
provide some of the costs and energy requirements that this process entails for reference.
Although the literature costs have been given in US$, all of the following cost analysis will
be in Euros, !.
The capture efficiency describes how much of the gas coming through the abatement
system is actually cleaned and ready for pipe-end use. As there are always some losses as
well as downtime in the system for operations and maintenance an efficiency of 95% has
been used here. This also corresponds to the average capacity factor of a geothermal plant.
As the pilot program research continues the capture efficiency may change. Thus streams
from the pilot project, 0,07 kg/s, and also from a full-scale scenario, 1,9 kg/s, would be
scaled down to 0,067 kg/s and 1,8 kg/s respectively.
The abatement system requires some internal energy use by the Hellisheidi plant in order
to separate and compress the gas stream from the geothermal steam. The equipment costs
for the pilot program were approximately 0,58 million Euros while the electrical
38
Calculations based on CO2 emissions by sector as published by Bloomfield, Moore &
Neilson, 2003.
39
Costs that cannot be recovered once they have been incurred.
48
requirement yielded a yearly cost of 0,05 million Euros. The electricity costs are based on
an energy requirement of 173 kW and a cost of electricity of 0,036 !/kWh40.
The cost of the abatement system was also analyzed based on a full-scale scenario, in
which all of the geothermal gas from Hellisheidi would be processed through the system
and subsequently sequestered using the CarbFix method. The total capital costs and
electrical requirements were scaled41 and increased to 4,17 million Euros and the
electricity cost to 1,02 million Euros per year. The energy requirements were scaled from
173 kW to 3,4 MW.
III.1.2
Basalt
Basalt is an igneous rock that can be present as glassy or crystalline. It contains calcium
oxide (CaO), which is a key element of mineral carbonation (Sigurdardottir, 2008). A
reaction between the CO2 and the calcium present produces calcite (CaCO3), which is a
stable geological formation and has a small of risk of leakage (Oelkers & Cole, 2008;
Gislason et al., 2009)). More than 90% of Iceland’s bedrock is basaltic (Sigurdardottir,
2008) but basalt makes up less than 10% of the Earth’s crust (Gislason et al., 2009).
Although 10% may seem like a small percentage, that portion of the crust does an
incredible amount of work to reduce atmospheric CO2, as approximately 33% of the CO2
consumed through natural weathering is done so by basalt (Oelkers et al., 2008).
Using the basalt present towards the mineral carbonation process does have some
requirements and challenges. There are water requirements for re-injection that must be
met as well as the presence of a cap rock in order to prevent leakage. The cap rock helps to
keep the dissolved CO2 in contact with the basalt for a sufficient time in order for the
carbon mineralization to take place (Oelkers et al., 2008). However, this may prove in the
future to not be absolutely required. This is due to the nature of the water when it has been
mixed with CO2. While supercritical CO2 is buoyant and lighter than the water present in
the geological formation, water-saturated CO2 is heavier and thus would tend to sink (S.R.
Gislason, personal communication, October 23, 2009).
40
This cost is found by referring to Reykjavík Energy’s stated prices at
http://www.or.is/Fyrirtaeki/Verdskraogskilmalar/Rafmagn/ given in ISK and exchanged to
Euros. Prices accessed May 2009 and may have changed.
41
The equation is explained in detail in Chapter III.3 and is listed as Equation 7.
49
III.1.3
CarbFix methodology
The CarbFix method begins after the H2S abatement system has produced a clean stream of
CO2. The site for re-injection is approximately 3 km south of the Hellisheidi power plant.
The water requirement, as described by Gislason et al. (2009), maintains that for each kg/s
of CO2 flow there is a need for 27 litres/second (l/s) when the water temperature is at 19°C.
While dry CO2 could be injected, the mineral carbonation process would be expected to be
slower as the CO2 would need to react with the groundwater (Matter et al., 2008). This
could ultimately allow for a higher possibility of leakage. Water from well HN-1 is
pumped to the injection well HN-2 where it flows into an injection pipe. The CO2 gas is
piped from the H2S abatement system and will continue down the well HN-2 inside the
injection pipe. At a suitable depth the CO2 will be dissolved in the water. The injection
pipe leads the water containing the dissolved CO2 down to a depth where it reaches the
basaltic rock. The temperature at this depth is between 30°C and 50°C (Matter et al.,
2008).
Tracers42 are added for monitoring the fate of the injected CO2 in the subsurface (Gislason
et al., 2009). The gas stream of CO2 is piped from the abatement system to well HN-2, the
re-injection well, through a plastic pipeline. The delivery pressure from the abatement
system, 30 bar, is sufficient so no further pressurization is needed.
The area for re-injection is estimated to be 3 kilometres (km) long, 1.500 m wide and 600
m thick (Aradottir, Sonnenthal, Bjornsson, Gunnlaugsson, & Jonsson, 2009). As
mentioned in Chapter II.2, Gislason et al. (2009) estimate that the volume of this target
area can accommodate 12 Mt of CO2. To give a clear picture of how much this is the
current total yearly CO2 stream from Hellisheidi is 60.000 tonnes and as such, this area
would accommodate 200 years of re-injection.
Figure 6 shows the layout of the wells HN-2 and HN-1 as well as the monitoring wells.
The wells, HN-1 (water) and HN-2 (injection well), are identified within the boxes.
Multiple monitoring wells in conjunction with the tracers will allow for reservoir
monitoring as well as the aquifer along the hydraulic gradient (Matter et al., 2008). The
deep monitoring wells are marked by HN-4, HK-34, HK-31 and HK-26 and the shallow
42
Tracers are the injection of chemicals into systems in order to assess the recovery during
various times and at multiple observation points, in this case the monitoring wells
(Khalilabad, Axelsson & Gislason, 2008).
50
monitoring wells are marked by HK-12, HK-25, HK-7 and HK-13. The injection well has
a depth of 1.300 meters and the monitoring wells at between 100 and 1.400 meters
(Gislason et al., 2009).
Figure 6: N-S geological cross section of the injection site, including injection well (HN-2)
and monitoring wells. (Alfredsson et al., 2008)
The equipment requirements for the re-injection process include pumps, check valves,
pressure relief and control valves, water level sensors and gas sensors. The energy
requirements for re-injection, which make up a significant portion of the variable costs, are
due to the pumps and control valves. They are dependent on the flow rate of the water and
the CO2.
There are two separate cases that will be considered in this thesis, which will be the
CarbFix pilot program currently in process and a full-scale Hellisheidi scenario. In the pilot
51
program the aim is to inject CO2 at a rate of 0,067 kg/s43 with approximately 2 l/s of water.
This would be a total of 2.100 tCO2 per year. The full-scale project would however, if
undertaken in the future, inject at a rate of 1,8 kg/s and sequester a total of 57.000 tonnes
per year.
III.2 CarbFix Pilot Program
The following section details the costs and economic parameters of the CarbFix pilot
program. The purpose of the pilot program is to test the storage abilities of basalt. Should
the sequestration prove to be a long-term solution a decision will be made whether to
continue on a full scale. Understanding the key cost drivers of this process will not only
help to make an informed decision but also signify what areas need more focus in order for
this to be economical.
It is also important to note that the following section does not review the costs of the
capture system, as that is a sunken cost. Please refer to Chapter III.1.1 for a review of the
H2S abatement plant, which acts as a capture system in this process.
III.2.1
Data
The capital costs were given to a certain degree of uncertainty. A three-point method44
with 95% confidence interval was used and the resulting costs used in the application of
the cost analysis. Table 2 shows the most likely cost that was given and the applied cost
after the three-point method. The monitoring wells total 9 and each well has a cost of 0,3
million Euros while the site screening costs were directly referenced from Simbeck (2001)
and adjusted for inflation.
43
This is the injection rate of 0,07 kg/s after a capture efficiency limitation has been
applied as was discussed in Chapter III.1.1.
44
The three-point method is a statistical estimation technique based on the normal
distribution. Three estimates are used (best case, most likely case, worst case) with a
confidence interval in order to find an estimation of the applied cost.
52
Table 2: Most likely cost and applied cost of transport and injection of CO2 sequestration
Million !
Most Likely Cost
Applied Cost
Equipment
0,23
0,24
Installation
0,21
0,22
Design
0,2
0,21
Injection Well
1,8
1,89
Monitoring Wells
2,7
2,88
Site Screening
N/A
1,52
Total
5,14
6,94
The life of the project is 30 years to reflect the average lifetime of a geothermal power
plant. Although the Hellisheidi power plant has been operational since 2006, meaning that
its remaining lifetime should be 27 years, some geothermal power plants have been
operational past the 30-year mark (Sanyal, 2005). Thus for this model 30 years has been
used as the lifetime horizon.
The capital costs were annualized45 using an interest rate of 4,6% and a payback period of
15 years. The interest rate is found using the Euro Interbank Offered Rate (EURIBOR)
with an additional credit default spread (CDS). The EURIBOR is a daily average of the
interest rates on unsecured funds borrowed between banks and is supplied by a panel of
European banks. The CDS is used as a representative figure of the risk premium. In this
case the CDS of Iceland was used although the CDS of Reykjavík Energy may be higher.
The interest rate used is thus the absolute best rate at which the current market offers. If the
scenarios in this model prove to be not profitable at the interest rate of 4,6% then it will be
of little difference if the risk premium of Reykjavík Energy is higher. The EURIBOR for
September 24th, 2009 was 1,242 while the CDS was 340,246 basis points (bp), or 3,402%47
and these two figures together represent the interest rate used, or 4,6%.
45
The annualized capital costs is the cost per year of capital and additional costs incurred
due to interest, or the cost of acquiring capital, over the life of the project.
46
The CDS of Iceland is based on 10 years and not 15 years as our payback period
assumes, as the 15-year timeframe was not available.
53
The resulting annualized capital costs were 0,65 M!. As some of the costs were given in
varying currencies the following exchange rates were used according to the 2009 averages
from January to June: ISK48/US$ = 124; EUR/US$ = 0,74; ISK/EUR = 166. These
exchange rates are constant throughout Chapters III.3 and III.4 as well. The operating and
maintenance costs were calculated by using a factor of 0,02549 of the capital costs for the
equipment, injection wells and monitoring wells resulting in a yearly cost of 0,13 M!.
The remaining costs are CO2 flow dependent of the stream exiting the H2S abatement
system as well as on the flow of the water. In the pilot program the flow entering the
abatement system is 0,07 kg/s but due to capture efficiencies, 95%, has been reduced to
0,067 kg/s. The water requirement is 27 l/s for each kg/s of CO2, which results in a yearly
water requirement of 56.6 million litres. The water costs were calculated to be 0,0001
!/litre50 which gives a yearly cost of 0,008 M!.
The energy requirement for the transportation and injection is approximately 200 kW. This
is split up between pumping, 15 kW and support systems, 185 kW. Using an electricity
cost of 0,036 !/kWh and a capacity factor of 95% the yearly costs were 0,06 M!. It is
assumed that pumping energy requirements will scale linearly with flow rates and support
system power consumption is fixed to a certain degree.
Monitoring
The remaining cost is monitoring for CO2 leakage and other environmental damages.
There are many different techniques available. Specific regulatory requirements have yet to
47
Although the currency exchange rates are based on the averages of January to June of
2009 this is not the same method used representative figure for the CDS. This is because
the CDS on September 24th of 2008 was 340bp, the same as the date used for this year.
Additionally, before the September 24th date of 2008 the point spread was fairly stable.
The average from January to June resulted in 728bp, a much higher figure. Thus we can
assume that the CDS has followed a bell curve from September of 2008 until 2009 and a
hypothesis can be made that it is perhaps finding market equilibrium once again.
48
Icelandic Krona
49
The O&M factor takes into account the labor costs of injection. This is slightly lower
than the 3% factor used for capture in literature as there is no solvent to renew or waste to
dispose of. It is also lower than the 3% factor used for transport, as the CarbFix method of
transportation does not employ the use of booster stations (Neele, Hendriks, Brandsma, &
Blomen, 2009).
50
This cost is found by referring to Reykjavík Energy’s stated prices at
http://www.or.is/Fyrirtaeki/Verdskraogskilmalar/Kaltvatn/ given in ISK and exchanged to
Euros. Prices accessed May, 2009 and may have changed.
54
be established although Directive 2009/31/EC makes advances towards this (Benson &
Cole, 2008; Directive 2009/31/EC). The costs used for this case were as given by the
scientists from the University of Iceland and are in adherence to the pilot program and the
need to academically and legitimately verify that storage of CO2 in basalt is a long-term
solution. This can mean that in the future the costs would be lower or that perhaps they will
not scale with size. The costs were 0,21 M! per year and include the sampling of the
ground water and the potential CO2 leakage. A 10 – 50% decrease in the annual cost of the
monitoring, with all other parameters remaining the same, resulted in a 3 – 10% decrease
in the cost per tCO2.
III.2.2
Cost Analysis
The cost analysis is performed in order to better understand the driving force behind the
levelized cost per tCO2. In this way it can be better understood where possible cost
reductions may lie. Table 3 shows the total costs associated with the pilot program for reinjection. The resulting cost per tCO2 sequestered is 503! and is found by totalling all
annual costs, including annualized capital costs, and dividing the sum figure by the total
amount of CO2 sequestered per year. This large cost is attributable to the small amount of
CO2 that is being sequestered, 2.100 tonnes annually, as well as to the high cost for
monitoring and capital.
Table 3: Cost summary for carbon mineralization.
Million !
Contributor
Capital costs
6,94
Electricity costs
0,06
Water costs
0,008
O&M
0,13
Monitoring
0,21
Capital costs annualized
0,65
Total annual costs
1,06
tCO2 sequestered, annually
2.100
!/tCO2 sequestered
503
55
Figure 7 shows the costs by percentage of total capital costs. The key components are the
monitoring wells, injection well and site screening, making 93% of the capital costs. The
installation, design and the actual equipment needed are only a small portion. The costs
associated to the design are considerably high because this is a pilot program.
Figure 7: Percentage breakdown of total capital costs for pilot program
Figure 8 shows the percentage ratio of total annual costs. The cost of electricity and water
contribute only a small portion to the annual costs. The major contributors to the annual
costs are the annualized capital costs followed by monitoring and the operations and
maintenance costs. The literature review provided that the cost over monitoring adds
approximately 0,1 to 0,3$/tCO2 captured which using the previously mentioned exchange
rate of 0,74 EUR/USD results in range of 0,074 – 0,22 !/tCO2. The monitoring costs in the
CarbFix pilot program are much higher due to the low flow rate and are 100!/tCO2
captured.
56
Figure 8: Percentage breakdown of total annual costs for pilot program.
The results lead to a conclusion that in order to decrease the cost per tCO2 the bulk of the
cost research would need to focus on the capital costs, specifically the number of required
monitoring wells, as well as the annual monitoring costs. However the following full-scale
scenario provides more insight as to where the real cost reductions can be found.
In order to better understand the effect decreases in cost have on the cost per tCO2
sensitivity analysis is performed. Each cost factor is changed while the other factors remain
constant. Figure 9 represents the decrease in cost per t/CO2 that can be realized by
reductions of annual costs such as annualized capital costs, electricity, water and
monitoring. The most sensitive factor in the pilot program is the capital costs while the
costs of water and electricity have small impacts on the levelized cost. The bottom axis of
the graph shows the decrease in levelized costs as the percentage change in the annual cost
increases.
57
Figure 9: Sensitivity Analysis of annual cost factors, pilot program.
When the annualized capital costs are more closely reviewed in the sensitivity analysis it is
the decrease in the cost of monitoring wells followed by the decrease in cost of the
injection well that can realize the largest reductions in annualized capital costs as can be
seen in Figure 10. The abscissa, similar to Figure 9, shows the decrease in the original
capital costs as the levelized cost decreases in !/tCO2.
Figure 10: Sensitivity Analysis of annualized capital costs, pilot program.
58
A Monte Carlo simulation51 on the CarbFix pilot program and a range of possible capital
costs provides additional information. The simulation includes 5,000 runs and the capital
costs assumed to follow a normal distribution. The mean of the simulation is 486 !/tCO2
while 90% of the events are between 456 and 515 !/tCO2.
III.2.3
Profitability Assessment
The profitability assessment performed on the pilot program is done to find what the price
of mitigation would need to be in order for the system to realize a reasonable return. This
could be through the form of a trading price on the carbon market or carbon dioxide
emissions tax imposed by the government. As the costs are high and the captured amount
of CO2 low the profitability assessment returns quite high figures for a needed price per
tCO2.
The key profitability ratios and figures that were looked at were the following: Debts-toCapital ratio (D/C), Return-on-Equity ratio (ROE), the internal rate of return (IRR), the net
present value (NPV) of the net cash flow and the net profit or loss over the project life. The
D/C ratio helps us to understand the financial strength of the project. The higher the ratio
the more debt there is than capital and thus the higher chance of default due to the weight
of those debts. There are varying versions of this ratio and so it is important to point out
that the debts here are considered to be the short and long term debts while the capital is
the net profit and the shareholder equity. The ROE shows the income that is generated with
shareholder money and is the profit after tax in ratio to the total capital at a given time.
The NPV is a consideration of the future cash flows when the time value of money is taken
into account. It is dependent on the discount factor used and the risk level of the project.
The IRR is the rate at which the NPV is equal to zero and projects are usually considered
acceptable when the IRR is higher than the minimum acceptable rate of return (MARR)
given by a company or shareholders, in this case 15%.
Additionally, the net profit (loss) over the project life is considered. It is the profit after tax
after deductions have been made for payable dividends. All of the ratios and figures
considered in the profitability assessments, with the exception of the net profit (loss), are
51
Monte Carlo simulation is a mathematical and computer based model in which multiple
combinations of factors are generated to find the probability that a specific outcome will
happen (Goodwin & Wright, 2004).
59
for year 8 giving the project sufficient time to progress and giving a deadline for which to
begin to show financial promise. The net profit (loss) figure is calculated using the full life
of the project, or 30 years.
The economic parameters used in all of the profitability assessments discussed are the
following, in addition to the capital costs and variable costs discussed in preceding section:
Table 4: Economic parameters used for profitability assessment of the CarbFix pilot
program.
Economic Parameters
Variable cost, !/tCO2
32,5
Fixed cost, M!/year
0,34
Time horizon, years
30
Loan interest rate, %
4,6
Payback period, years
15
Working capital, M!
0,18
Discount rate, %
15
Loan management fee, %
2
Income tax, %
15
Depreciation rates, %
Equipment
5
Injection wells
15
Monitoring wells
15
Other
20
The initial price is 900!/tCO2 avoided, approximately 97% higher than the cost, which
means that if the selling price in the trading market were to be 900 ! per tonne then the
sequestration at Hellisheidi and its resulting trading permits would realize a certain profit
per year. Similarly, if the tax is 900 !/tCO2 emitted then the profit can be assumed to be a
saved cost. While all aspects of the profitability analysis will be covered, it is clear this will
not be economical.
Figure 11 represents the progression of the NPV of the total and net cash flows through the
life of the project. The net cash flow becomes positive at year 4, 2013, while the total cash
60
flow remains negative until year 12. From year 1 until year 12 the NPV of the total cash
flow is building from -7.
Figure 11: Accumulated Net Present Value of the CarbFix Pilot Program at 900!/tCO2.
At year 8 the project has a 34% D/C ratio and the ROE is 22%. The NPV is -1 M! for total
cash flow52 and the NPV of the net cash flow53 is 2 M!. The IRR is 11% and the NPV of
the net profit over the life of the project is 3 M!. This proves that at this price a shareholder
would not wish to continue as there is never a positive cash flow and the IRR is quite lower
than the discounting rate.
Figure 12 shows the minimum acceptable debt coverage is 1,5 and that the debt service
coverage, or the availability of cash flows to meet debts, meets this minimum. As well the
NPV of the cash flow after tax is satisfactory to cover the principal payments on loans
taken and the interest as shown by the debt service coverage.
52
53
Total cash flow is the cash flow after variable costs, fixed costs and taxes.
Net cash flow is the total cash flow after the loan costs have been deducted.
61
Figure 12: Debt Cover Ratios of the CarbFix Pilot Program at 900!/tCO2.
The second price is 1.200!/tCO2 avoided which results in a positive NPV in year 8 but
only of 1 M! on the total cash flow and 4 M! on the net cash flow. The ROE is 19% and
the D/C ratio 24%. There is a 20% IRR and a net profit of 6 M!. Figure 13 shows the
progression of the NPV at this price. The net cash flow becomes positive in year 3 and the
net cash flow remaining negative until 2015.
Figure 13: Accumulated Net Present Value of the CarbFix Pilot Program at 1.200!/tCO2.
The final price is 1.500!/tCO2 avoided and shows slight improvement with the NPV at 4
M! and 6 M! on the total and net cash flows at year 8 and IRR at 29%. The D/C ratio is
19% and the ROE 17%. This project would result in a total net profit of 9 M!.
62
The figures used in this profitability assessment are very unrealistic when compared to the
current trading price which is fluctuating around 15 !/tCO2 and the highest points, in 2006,
were only 33 !/tCO254. Similarly, the price of emission taxes do not come close to these
high figures with the range of the taxes in Europe55 at 3,7 to 50 !/tCO2 (Baranzini,
Goldemberg & Speck, 2000). Table 5 summarizes the prices used in the CarbFix pilot
program profitability analysis.
Table 5: Resulting profitability ratios from varying prices of !/tCO2, pilot program.
Price
!/tCO2
Debts/Capital
Ratio
Return on
Equity Ratio
Net Present
Value of Cash
Flow (M!)
Total
Net
Internal
Rate of
Return
Net
Profit
(Loss)
M!
900
34%
22%
(1)
2
11%
3
1.200
24%
19%
1
4
20%
6
1.500
19%
17%
4
6
29%
9
III.3 Hellisheidi full-scale scenario
If the sequestration of CO2 through basalt proves technically successful, a decision will
need to be made by Reykjavík Energy as to whether to continue this on a full-scale
scenario, and storing all of the CO2 emitted from the Hellisheidi plant.
III.3.1
Data
In order to find the costs, most of which are unknown at this time, a scaling factor is used
based on the increased flow of CO2 and applied to the costs given in the CarbFix pilot
portion.
Scaling Factor = [ Flowfullscale / Flowpilot ] 0,6
(7)
54
As per the database at www.pointcarbon.com and in reference to the spot market. The
futures market for the EU ETS give a range of 15 to 17 !/tCO2.
55
The range represents those five nations in Europe, which currently implement an
emissions tax: Sweden, Norway, Netherlands, Denmark and Finland.
63
The resulting scaling is used in two separate ways. The first way is to find the increase in
flow from the CarbFix pilot program to the Hellisheidi full-scale scenario, which would
have an effect on the energy requirement. The second method is using the scaling factor to
find the possible increase of costs of equipment. The flow in the full-scale scenario is 27
times more than the pilot program, as the full-scale scenario considers the current
electricity production at Hellisheidi and its resulting CO2 emissions, or 60.000 tonnes per
year. Using a scaling exponent of 0,6 the scaling factor for equipment is 7. By using these
two factors the equipment and other capital costs as well as electricity costs can be
estimated. However not all electricity scales equally. The figures that were given in
Chapter III.2 were those that the CarbFix pilot program uses 200 kW total energy, which is
split between pumps and support systems. While the pumping energy requirement should
scale with the flow, the support systems would not. The resulting energy requirement is
650 kW. The water costs are calculated using the water requirement of 27 l/s per kg/s of
CO2, which is given.
III.3.2
Injection well calculati ons
A large portion of the capital costs are the injection wells and the number of wells needed.
The number of injection wells needed is dependent on three factors. The first is the rate at
which the CO2 mixed fluid reacts with the basalt forming carbonates. The second is the
rate at which the fluid flows away from the injection well. Should the water flow slowly
from the injection well and react at a higher rate with the basalt the risk is that the injection
well and area surrounding it becomes clogged by carbonate scaling, limiting the amount of
solution that is possible for re-injection. The third factor is the amount of water flow the
injection well is able to maintain.
Typical wells at Hellisheidi are able to receive 80 to 120 l/s (H. Sigurdardottir, personal
communication, July 10, 2009). The injection area being considered has a horizontal
permeability of 500 mD and 4% porosity. The ground water velocity is 25 m/year and is
slower than had originally been expected. This could result in problems of clogging around
the injection hole and requires additional increases in groundwater flow in order to push
the fluid away from the injection site (Aradottir, et al., 2009). This has been resolved by
pumping two monitoring wells in order to push the fluid (H. Sigurdardottir, personal
communication, October 27, 2009).
64
The rate at which the fluid reacts with the basalt to produce carbonates is still under
scientific study and as such a best-case and worst-case scenario are considered. The bestcase scenario bases the number of injection wells required on the water flow the well is
able to receive. If the typical value of a well at Hellisheidi, 80 to 120 l/s, is used then only
one well is required, as the flow of the full-scale scenario would be 49 l/s. The worst-case
scenario assumes that the injection wells required are 10 and will be presented after the
sensitivity analysis of the best-case scenario.
III.3.3
Cost analysis
In the full-scale scenario the flow of CO2 has increased from 0,067 kg/s (the CarbFix pilot
program) to 1,806 kg/s resulting in a cost of 31!/tCO2 sequestered. As Table 6 shows, the
only factors that were not scaled were the costs for the injection well as this remains at one
for the best case; the monitoring wells as they are assumed to be sufficient for the full-scale
scenario as they were in the pilot program; and the annual monitoring costs. The costs for
the design were also not scaled using the cost from the pilot program as a base as this is
considered to be too high. Design generally represents 10 to 15% of the equipment and
installation costs. In the pilot program the design costs represent approximately 55%. The
design was estimated using the equipment cost scaling equation and a base cost of 0,08
M!. The site screening also remained the same as the same area is assessed, merely for a
larger amount of CO2 to sequester.
The costs of licensing and permits have now been included which leads to a 0,06 M!
capital cost increase. This cost also includes an Environmental Impact Assessment as
required by Directive 85/337/EEC. As has been mentioned in Chapter III.2.1, the
monitoring costs in the CarbFix pilot program may be quite high to address the
environmental concerns and exhaustively harvest scientific data. There are also
uncertainties as to what type of monitoring will be required in the future. For example, at
this time the amount of CO2 being sequestered in the CarbFix pilot program is not enough
to be able to monitor with geophysical methods (Internal memo, Reykjavik Energy, 2009).
In the Hellisheidi full-scale scenario mineralization may be monitored using this
technology.
65
Table 6: Cost increase for full-scale Hellisheidi program.
Million Euros
Pilot program
Hellisheidi full-scale
tCO2 sequestered, annually
2.100
57.000
Capital costs
Equipment
0,24
1,73
Injection well
1,89
1,89
Monitoring wells
2,88
2,88
Site screening
1,52
1,52
Installation
0,22
1,58
Design
0,21
0,59
Licensing & Permits
-
0,06
Total capital costs
6,94
10,23
Annual costs
Capital costs annualized
0,65
0,96
Electricity costs
0,06
0,2
Water costs
0,008
0,22
O&M costs
0,13
0,16
Monitoring costs
0,21
0,21
Total annual costs
1,06
1,75
!/tCO2 sequestered
503
31
As can be seen in Figure 14 the costs attributed to the water requirement leads to the
largest increase. The water increased from 1,8 l/s to 48,8 l/s and the yearly requirement is
now 1.539 million litres per year. This is 27 times more because the water will directly
scale with the increased flow of CO2. The electricity costs do increase by 0,14 million
Euros per year as well but are not directly related to flow because some of the equipment
does not scale linearly.
66
Figure 14: Changes in costs from pilot program to full-scale program.
It is interesting to analyze the sensitivity of the factors contributing to the cost on a tCO2
basis as compared to the CarbFix pilot plant scenario. As can be seen in Figure 15 the
annualized capital costs for the full-scale scenario are the most effective way of reducing
the cost of tonne captured. This is similar to the CarbFix pilot program however the water
and electricity costs are equally as prominent as the monitoring now.
Figure 15: Sensitivity Analysis of annual cost factors, full-scale program.
67
The water costs for the full-scale scenario are now slightly more sensitive and can result in
a 6% decrease as opposed to an insignificant decrease in the pilot program when the annual
water cost is decreased by 50%.
In Figure 16 it can be seen that the capital cost factor that can lead to the highest
percentage decrease in annualized capital costs are the monitoring wells. The cost of the
injection wells are still the second most influential factor but not as influential as they were
in the pilot program scenario. Where in the CarbFix pilot program the injection well costs
could contribute to a 14% decrease in levelized costs they now only contribute 9%.
Figure 16: Sensitivity Analysis of annualized capital costs, full-scale program.
The Monte Carlo simulation utilizing 5,000 runs produces a mean of 29!/tCO2 while 90%
is within the range of 28 and 31!/tCO2. The levelized cost is now much less sensitive as
the spread of costs is more due to the higher amount of CO2 per year stored.
As mentioned before in Chapter III.3.2, the number of injection wells in this section is
based on the capability of a well to receive a certain amount of water flow in l/s and
ignoring the other two contributing factors. This leads to the question of what effect the
possible increase in the number of injection wells may have. If the number of injection
wells required increases from 1 to 10 the capital costs for injection would rise from 1,89
M! to 18,9 M! and the annualized capital costs 2,55 M!.
With 10 injection wells the cost per tonne increases from the original 31!/tCO2 to 66
!/tCO2; more than twice as expensive. The Monte Carlo simulation utilizing 5,000 runs
produces a mean of 63,7!/tCO2 while 90% is within the range of 58 and 69!/tCO2. In
68
Figure 17 it can be seen that the injection wells for the full-scale program are now the
largest contributor to the annualized capital costs.
Figure 17: Sensitivity Analysis of annualized capital costs, full-scale program with 10
injection wells.
III.3.4
Profitability assessment
A similar profitability assessment is performed on the full-scale scenario56 as in the
CarbFix pilot program. The purpose of the assessment is not to find if the program is
profitable under the current prices, as they are lower than the cost per tonne for
sequestration, but to find the profitability under varying costs to find the required market
price or emission tax.
The same economic parameters are used as in the CarbFix pilot program, with the variable
cost increasing to 7,25 !/tCO2, fixed cost 0,37 M!, and the working capital increasing to
1,26 M!.
The first evaluated price is 50 !/tCO2 which is the highest current tax placed on CO2
emissions in Europe as presented in Chapter III.2.3. Over the 30 year horizon the total net
profit sums to 4,1 M! and the NPV remains negative until year 19. At year 8 the NPV is at
-3 M! for the total cash flow and 1.14 M! for the net cash flow. Figure 18 shows the
69
progression of NPV; particularly the negative NPV of the total cash flow until
approximately half way through the life of the project.
Figure 18: Accumulated Net Present Value of the Hellisheidi Full-Scale Program at
50!/tCO2.
The IRR is 7% and never reaches above 16% throughout the life of the program. The ROE
is 20% and the D/C ratio 36%. All in all this is not an attractive investment and calls for a
higher price per tonne or reduced costs.
Preferably the price of one tCO2 would need to be 77 !/tCO2 or higher. At this price the
NPV is positive in year 8 although at only 3 M! for the total cash flow. The NPV of the net
cash flow at year 8 is 7 M!. The IRR however is 22% and ROE 17%. The D/C is still high
but begins to become more acceptable at 21% and the total profit is 10,8 M!.
Figure 19 shows the NPV of the total cash flow breaking the zero mark at the year 2014, or
5 years from the start of the project.
56
The profitability assessment maintains that the injection well requirements are 1.
70
Figure 19: Accumulated Net Present Value of the Hellisheidi Full-Scale Program at
77!/tCO2.
Figure 20 shows the loan life coverage ratio meets the minimum of 1,5 and the debt service
coverage increasing steadily.
Figure 20: Debt Cover Ratios of the Hellisheidi Full-Scale Program at 77!/tCO2.
Table 7 presents the profitability ratios and results from the two different prices reviewed
in this profitability assessment for the Hellisheidi full-scale scenario. The price of CO2
emitted would need to be higher than 77!/tCO2.
71
Table 7: Resulting profitability ratios from varying prices of !/tCO2, Hellisheidi full-scale
scenario
Price
!/tCO2
Debts/Capital
Ratio
Return on
Equity Ratio
Net Present
Value of Cash
Flow (M!)
Total
Net
Internal
Rate of
Return
Net
Profit
(Loss)
M!
50
36%
20%
(3)
1,14
7%
4,1
77
21%
17%
3
7
22%
10,8
Hellisheidi full-scale in 10 years
As mentioned in Chapter III.1, the Reykjavik Energy plants to increase its electrical
production at the Hellisheidi geothermal power plant in the near future, and as such its CO2
emissions. In order to assess what change the future emissions scenario would have on the
levelized cost, a similar cost analysis was performed. Corrections are made to the power
and water requirement and the capital costs as per the scaling equation from Chapter
III.3.1. The energy requirement is now 1,1 MWe and the water requirement 73 l/s. The
costs per kWh and per litre are held constant. The cost per tCO2 is now 26!. One key factor
that future scenarios will need to take into account are the costs incurred by the adoption of
Directive 2009/31/EC and specifically the costs related to insurance as mentioned in
Chapter II.5.2.
III.4 CarbFix applied to a pulverized coal plant
III.4.1
Coal
Over 45% of the North American power generation is from the combustion of coal, which
is the highest CO2 emissions producer of all power generation systems (Simbeck, 2001).
Coal has high carbon content and so through combustion produces more CO2 emissions
than other power generation systems. The carbon content by weight varies from 60 to over
90% depending on the type of coal used. It also can vary in heating value (kJ/kg), with that
the higher the carbon content, the higher the heating value.
72
According to the IPCC Special Report on Emission Scenarios (2000) multiple future
energy mix scenarios are analyzed with their corresponding forecasted effect. There are
three specific scenarios, which are of interest specifically due to the characteristics after
2020: A1F1, fossil-intensive, A1T, non-fossil energy sources and A1B, a balance of energy
sources. The fossil-intensive future could result in a 5-degree rise in global temperatures
while even the non-fossil energy source future could still result in a 3-degree rise due to the
higher CO2 concentrations already present prior to 2020.
Coal-fired generating plants are classified according to their steam conditions: sub critical,
supercritical and ultra-supercritical. These different types of cycles have different
efficiencies with the supercritical being the most mature technology and having an
efficiency of 44% and 45% based on the lower heating value, (LHV) (IEA, 2004). Plants in
the USA usually have lower efficiencies when compared to Europe due to the higher
sulphur content in the coal and as such higher flue gas temperatures.
There is also a limit on the efficiency of a coal-fired steam cycle plant, which adheres to
the Carnot efficiency:
= TH – TC/ TH. If the maximum boiler temperature due to the
metallurgical limitations of the steel used is 580°C (Coutsouradis, 1994) and the cooling
water temperature is 20°C than the efficiency limit is 66%57. Once corrections have been
made to the efficiency for internal power requirements and losses it reaches the more
commonly seen figures of approximately 45% (IEA, 2004).
There are discussions in the literature, such as from the IEA, as to whether CCS should be
utilized more in developing nations that have less efficient plants and more emissions. One
argument says that this idea is flawed due to the lower efficiency in these plants. When the
energy requirements due to capture and pressurization are accounted for, the fuel
requirements become higher and as such the emissions increase. However, because the
plant is less efficient the cost for fuel is higher than in comparison to a plant with a more
efficient cycle. Thus the cost of electricity will be higher and the cost of avoidance in
t/CO2 higher (IEA, 2004).
57
= (580-20)/(580+273)
73
III.4.2
Existing plant and data
The reference plant used in this case is based on work done by Simbeck (2001) and SFA
Pacific, Inc. Simbeck analyzes the costs of a 308 MWe gross pulverized coal plant with
capture and an additional natural gas auxiliary boiler. The information in Table 8
summarizes the plant used as the base reference plant with capture in the CarbFix cost
analysis.
Simbeck, in his analysis58, allows for all but 10% of the original plant capital to be
amortized. This remaining capital is then refinanced with the additional capital for the new
capture equipment and the fixed charged rate set at 15%. The original capital cost
unamortized is 21 M! which added to the new capital gives a total of 269 M!.
Instead of internally consuming the energy penalty for capture, a natural gas boiler is
added and as such additionally the gas fuel costs yearly. There is a flue gas
desulphurization (FGD) system added in order to strip the gas of SO2 and decrease the
occurrences of degradation of amines. Simbeck gives a total cost captured of 18,5!/tCO2.
If the range from the literature, presented in Table 1, is readjusted to Euros the range is 17
to 26 !/tCO2 captured. Thus the cost in the reference plant with capture is within the range,
however on the lower spectrum. This is due to the option to use an older plant with the
remaining capital refinanced.59 The range of increase in capital costs is 34% and the
increase in COE is 0,029!/kWh while the literature gives the range of 0,014 to
0,036!/kWh60 (David, 2000).
58
The analysis by Simbeck is given in USD but has been exchanged to Euros using the
exchange rates from Chapter III.2.1.
59
The lower figure can also be a reflection of the lack of inflation correction.
60
Original figures given in USD.
74
Table 8: Characteristics overview of a 308 MWe reference pulverized coal plant and PC
plant with capture. (Simbeck, 2001)
Reference plant design
Boiler type
Sub critical
Coal type
Sub-bit
Emission control technologies (SO2/NO X)
Electro Static Precipitator
Gross output (MWe)
308
Net output (MWe)
291,5
Plant capacity factor, %
85
Coal cost, LHV (! MM/Btu)
0,38
Reference plant emission rate (tCO2/MWh)
0,971
Capture plant design
CO2 capture technology
MEA
Gross plant output with capture (MWe)
341
Additional equipment
Flue gas desulphurization
Net plant output with capture (MWe)
291,5
Auxiliary boiler/fuel used (type, LHV cost)
NG. !3,2/MM Btu LHV
CO2 capture system efficiency, %
88
CO2 emission rate after capture (tCO2/MWh)
0,121
-1
CO2 captured (Million Mt yr )
2,36
CO2 avoided (Million Mt yr-1)
1,8
Cost results
Cost year basis
2001
Fixed charge factor, %
15
Capture plant TCR (!/kW)
682
Reference plant COE (!/MWh)
22
Capture plant COE (!/kW)
29,5
Incremental COE (!/kWh)
7,5
III.4.3
Cost analysis
In Table 9 the cost increases are summarized for a pulverized coal plant using the CarbFix
method for storage with a CO2 flow of 74,8 kg/s and water flow rate of 2.020 l/s. The
scaling formula, Equation 7, is used here again based on the pilot program. The flow is
1.125 times more than the original 0,067 kg/s in the CarbFix pilot program and the
equipment cost scaling, also using a factor of 0,6, is 68. The injection well calculations
75
were based on the flow rate of the water and the resulting requirement was 17 wells. No
additional costs for transport are added as the CarbFix pilot program included costs for
transport 3 km from the H2S abatement plant. The costs have been scaled up and thus the
storage site in this scenario assumed to be within 3 km from the pulverized coal plant. The
costs for licensing and permits have also not been included due to the uncertainty of future
legislation connected to Directive 2009/31/EC. The energy requirement is 18 MWe and
results in an annual cost of 6,83 M!. The total annual costs are 22,78 M! and result in a
cost of 9,65!/tCO2 captured.
Table 9: Cost increase for PC plant using CarbFix.
Million Euros
Hellisheidi full-scale
Pulverized coal plant
tCO2 sequestered, annually
57.000
2.360.382
Capital costs
Equipment
1,73
16,13
Injection well
1,89
32,13
Monitoring wells
2,88
2,88
Site screening
1,52
1,52
Installation
1,58
14,72
Design
0,59
5,52
Licensing & Permits
0,06
-
Total capital costs
10,23
72,89
Annual costs
Capital costs annualized
0,96
6,83
Electricity costs
0,2
5,44
Water costs
0,22
9,01
O&M costs
0,16
1,28
Monitoring costs
0,21
0,21
Total annual costs
1,75
22,78
!/tCO2 sequestered
31
9,65
In Table 9 it is shown that when the CarbFix method is added to a PC plant the
predominant cost factor is the water as well as the annualized capital costs as has been in
previous scenarios. This is also exhibited in Figure 21, which shows that the most
reductions lie in the costs related to water and capital costs. Also, the percentage of
76
reduction in the levelized cost is lower than previously seen in the CarbFix pilot program
and the full-scale scenario. Where before the reduction in annualized capital costs could
reduce the levelized cost by 32%, it now only contributes 18%.
Figure 21: Sensitivity Analysis of annual cost factors, PC plant with 17 wells.
The Monte Carlo simulation based on changes in capital costs and 5,000 runs provides a
mean of 9,5!/tCO2 and the range, with 90% probability, between 9,23 and 9,77 !/tCO2.
This shows the pulverized coal case is far less sensitive to capital costs then the CarbFix
Pilot program or the Hellisheidi full-scale program.
The simulation when run in order to look at changes in water and energy requirements
returns a different range. The water requirement is adapted to be anywhere in the range of
23 to 31 l/s, depending on the pressure of the CO2 (Gislason, 2009), while the energy
requirements are reduced to 16 MW and up to 21 MW. Larger gains can be made here as
the mean is 9,6!/tCO2 and the range, with 90% probability, between 8,5 and 10,8 !/tCO2.
Thus the pulverized coal scenario is far more sensitive to changes in water and energy
requirements than it is to changes in capital costs.
III.4.4
Profitability assessment
Three different prices of CO2 on a tonne basis are considered for the pulverized coal plant
scenario. The variable cost is 6,12! per tCO2 and the fixed cost 1,49 M!/year. The first is
the price of 13!/tCO2, which represents the current spot market trading price of carbon
77
dioxide permits. The results are a negative NPV of total cash flows at year 8, -43 M!, and
remaining negative through the life of the project, as well as -6 M! for the NPV of net cash
flow. The D/C ratio is 40% showing a weak financial structure and a 1% IRR. The ROE is
18% and the net profit is totalled at 28 M!.
Figure 22 shows that the IRR of both the total cash flow and net cash flow do not meet the
required 15%, the project’s discount rate, until year 2021, 11 years after the start of the
project.
Figure 22: Internal Rate of Return on total cash flow and net cash flow for the Pulverized
Coal case with CarbFix at 13!/tCO2.
The second and third prices used present a different picture. The first price, 17!/tCO2,
represents the current futures market price of carbon dioxide. The NPV is negative in year
8, -8 M! for total cash flows, but becomes positive in year 10. The NPV of the net cash
flows is at 29 M! at year 8. The IRR is 13% and ROE 16%. The D/C is 26% and the net
profit 69 M!.
The third price, 50!/tCO2, represents the highest tax on carbon dioxide emissions currently
employed in Europe. The NPV of total cash flows becomes positive in year 2 and at year 8
is 283 M! and the IRR is 79%. The NPV of the net cash flows at year 8 is 320 M! and is
positive at year 1. This is represented in Figure 23.
78
Figure 23: Accumulated Net Present Value of the Pulverized Coal program with CarbFix
at 50!/tCO2.
The D/C is 9%, which is very good and the ROE is 14%. As shown in Figure 24 the
acceptable minimum of loan and debt coverage is always met.
Figure 24: Debt Cover Ratios of the pulverized coal scenario at 50!/tCO2.
The total net profit, or in the case of a carbon tax costs avoided, is 409 M!. These are very
promising figures and should be studied further in terms of CarbFix as a mitigation
technology towards future emissions taxes. Table 10 summarizes the results of the three
separate profitability assessments used in this chapter.
79
Table 10: Resulting profitability ratios from varying prices of !/tCO2, PC plant with
CarbFix.
Price
!/tCO2
Debts/Capital
Ratio
Return on
Equity Ratio
Net Present Value
of Cash Flows
(M!)
Total
Net
Internal
Rate of
Return
Net
Profit
(Loss)
M!
13
40%
18%
(43)
(6)
1%
28
17
26%
16%
(8)
29
13%
69
50
9%
14%
283
320
79%
409
Due to the fact that CarbFix does not include capture, and thus the costs related to capture
not included in the profitability assessment, the last price of 50!/tCO2 is reviewed again.
When the cost of capture as determined by Simbeck is added, 18,5!/tCO2 captured, the
profitability assessment shows some changes. The NPV is reduced to 116 M! for the total
cash flow and 153 M! for the net cash flow. The NPV of the total cash flow becomes
positive a year later with capture, or in year 3. The D/C increases to 15% as opposed to 9%
without capture and the ROE increases to 15%. The net profits over the 30 years are 219
M! where as without capture they are 409 M!.
80
IV. MARKET ANALYSIS
IV.1.1
Methodology
In order to perform the market analysis the stages described in Chapter II.10 were used.
The first stage, determining the decision maker, is found by choosing the project manager
of the CarbFix project. Considering what countries are available as possible markets
completes the second stage. In order to determine the countries that would be used in this
market analysis the prerequisite was set that the country must possess the correct type of
mineral composition for in-situ mineralization. In addition to basalt, Oelkers et al. (2008)
discuss ultramafic rocks that are also compatible to basalt for mineralization. As storage
can take place offshore as well as onshore there are a number of locations off the coast of
certain countries that may be applicable to the CarbFix method of storage (Goldberg &
Slagle, 2009).
The PESTLE analysis is used for the third stage; identifying attributes. Using the PESTLE
analysis 25 attributes and proxy values are found in order to score each country. As the
PESTLE analysis identifies external opportunities and threats a value tree is constructed
and can be seen in Figure 25. The value tree shows the two categories, threats and
opportunities; the general external concerns of a company when entering a market. To
assess these concerns distinct attributes are identified in each category in order to be able
to assign values and assess them.
81
Figure 25: Value tree of PESTLE attributes by their category.
These attributes are considered to be influencing factors as to what degree the market
would be positive to CarbFix. The attributes then enter into stage 4 where each attribute is
assigned a quantitative proxy value. Table 11 outlines the attributes found through the
PESTLE analysis, the source of the proxy value and the year that the information is
collected from.
82
Table 11: List of attributes, their unit, and the source and base year for the SMART
analysis.
Attribute
Unit
Source
Year
Ease of doing business
Ranking (1=best, 183=worst)
Doing Business, World Bank (2009)
2009
Environmental sustainability
Score (0=worst, 100=best)
Esty et al. 2008
2008
Kyoto trend
% change (1990-2012)
United Nations (1998)
1998
GDP per capita
PPP (current international $)
World Bank Indicators (2009)
2008
Country risk
Score (0=best, 7=worst)
OECD (2009)
2008
CO2 emissions per capita
Kg CO2
World Bank Indicators (2009)
2005
Elec. production from coal
GWh
International Energy Agency (2009b)
2006
Elec. production from hydroelectric
GWh
International Energy Agency (2009b)
2006
Elec. production from natural gas
GWh
International Energy Agency (2009b)
2006
Elec. production from nuclear
GWh
International Energy Agency (2009b)
2006
Elec. production from oil
GWh
International Energy Agency (2009b)
2006
Elec. production from waste
GWh
International Energy Agency (2009b)
2006
Elec. production from biomass
GWh
International Energy Agency (2009b)
2006
Elec. production from geothermal
GWh
International Energy Agency (2009b)
2006
Elec. production from solar
GWh
International Energy Agency (2009b)
2006
Elec. production from tidal, wave
GWh
International Energy Agency (2009b)
2006
Elec. production from wind
GWh
International Energy Agency (2009b)
2006
Planned/Operational CCS projects
# (in the next 10 years)
Zero Emissions Platform, MIT (2009)
2009
Natural gas production
Terajoules
International Energy Agency (2009c)
2006
Energy imports
% (of net energy use)
World Bank Indicators (2009)
2006
Intellectual property rights
Score (0=worst, 10=best)
Dedigama (2008)
2009
2
Population density
# (per km )
World Bank Indicators (2009)
2008
Nationally protected land
% (of total surface area)
World Bank Indicators (2009)
2006
World Bank Indicators (2009
2007
DK Publishing, World Atlas (2008)
2009
3
Freshwater resources per capita
m
Access to seawater
# (1=true, 0=false)
After the collection of these attributes and proxies they are defined as either positive or
negative. Positive attributes are those that contribute positively towards the market for
CarbFix, otherwise called an opportunity. A negative attribute is any attribute that draws
the market away from CarbFix, otherwise a threat. The positive attributes add to the
aggregate score while the negative attributes subtract value from the score.
The fifth stage of the market analysis, using the SMART, is to determine the weight of
each attribute. This is done by first asking the decision maker to imagine a hypothetical
market in which all of the attributes were at their least preferred level. The decision maker
83
is then asked if only one attribute could be moved to its most preferred level, which should
that be. The first attribute chosen is freshwater resources per capita and the remaining
attributes are all ranked accordingly. As freshwater resources per capita is the first chosen
attribute it receives a weight of 100. The remaining weights are found by employing swing
weights. Swing weights compare a swing of an attribute from the least preferred level to
most preferred level in comparison to the base weight, or the attribute with a weight of
100. For example the second ranked attribute is electrical production from coal. The
question is then posed, “Consider a swing from a market with no electrical production
from coal to a market where coal is the only source of electrical production with a swing
from a market with no fresh water resources to a country with excess fresh water
resources.” The value given is 95 and as such is the appropriate weight for the attribute
electrical production from coal. Each attribute is swing weighted against the base weight
until all of the attributes have been valued.
As shown in Table 12 the swing weights are summed up to 1.501 and the weights then
normalized. Dividing the attribute weight by the total sum and the result multiplied by 100
normalizes the weights.
84
Table 12: Attribute ranks, swing weights and normalized weights.
Attribute
Rank
Weight
Normalized
Freshwater resources per capita
1
100
6,7
Elec. from coal
2
95
6,3
CO2 emissions per capita
3
90
6,0
Population density
4
89
5,9
Ease of doing business
5
85
5,7
Country risk
6
84
5,6
Elec. from hydroelectric
7
83
5,5
Elec. from nuclear
8
82
5,5
Elec. from waste
9
81
5,4
Elec. from biomass
10
80
5,3
Elec. from solar
11
79
5,3
Elec. from tidal, wave
12
78
5,2
Elec. from wind
13
77
5,1
Energy imports
14
76
5,1
Natural gas production
15
75
5,0
Kyoto trend
16
50
3,3
Planned/Operational CCS projects
17
45
3,0
Environmental sustainability
18
40
2,7
Nationally protected land
19
30
2,0
GDP per capita
20
20
1,3
Elec. from natural gas
21
18
1,2
Elec. from geothermal
22
15
1,0
Elec. from oil
23
14
0,9
Intellectual property rights
24
10
0,7
Access to seawater
25
5
0,3
Total
1.501
A description of the attribute proxy values used in the analysis is given in the next chapter,
IV.1.2. The description discusses both the source of the values used and the effect of the
attribute value on the aggregate score.
85
IV.1.2
Attribute descriptions
Ease of doing business ranking
The Ease of Doing Business score is published in the 2010 Doing Business, a part of the
World Bank publications (2009). It is a measure of the regulations in place for business
activities that take place during the life cycle of a business and the time and actions
required for each activity. A total of 183 countries are compared with a standard case of a
limited liability company of medium size, or 60 employees. The countries are ranked from
1 to 183, with the lower figure being the better score. The Ease of Doing Business score is
only a time and motion indicator score and does not consider economic stability, labour
skills present in the economy, or the strength of the regulating institutions (World Bank,
2010). This proxy value is chosen to represent one of the political factor attributes. It
represents the ease with which business can be done in the prospective market. This is
attribute is listed as a negative because the higher the score, the worse that country is
considered to have an environment that supports ease of doing business.
Environmental sustainability index
The second attribute in the political factors is the environmental sustainability of the
market or the way in which the policies of the country support a sustainable environment.
A proxy of the environmental sustainability index score represents this attribute. This
index considers 21 indicators and which represent 76 data sets. These 21 indicators
represent 5 categories: environmental systems, reducing environmental stresses, reducing
human vulnerability, social and institutional capacity and global stewardship. Each country
receives a score from 0 to 100, with 100 representing the highest value achievable (Esty et
al., 2008). This is a positive attribute as the higher the score the better the country is
promoting environmentally sustainable policies.
Kyoto trend
The attribute “Kyoto Trend” represents both the commitments by Annex I61 countries to
the Kyoto Protocol as well as the trends in emissions shown by non-Annex I countries. The
Kyoto Protocol following the United Nations Framework Convention on Climate Change
61
Annex I countries are defined and listed in the United Nations Framework Convention
on Climate Change.
86
(UNFCCC, 1998), is a voluntary commitment by industrialized nations, otherwise known
as Annex I countries, to reduce global greenhouse gases. It is important to note that the
UNFCCC is not a legal binding target but a treaty. The period of the Kyoto Protocol, from
2008 until 2012, sets a reduction target for each country to reduce their emissions of
greenhouse gases by a certain percentage in comparison to their emissions in the base year,
1990 (UNFCCC, 1998). The proxy used for all Annex I countries is the listed commitment
in the Kyoto Protocol unless otherwise stated here.
Article 4 of the Kyoto Protocol allows for those economies that wish to do so to meet their
target reduction together. This is for example done through the European Union member
states that jointly committed to an 8% decrease through the decision by the European
Council in 2004 (Council Decision 280/2004/EC). This joint decision is described as the
EU-15 who reallocated the target reductions amongst themselves in order to reach the
average goal of 8% decrease. Those countries who are part to the EU-15 are here
represented in the Kyoto Trend by the proxy of their commitment to reductions pursuant to
Decision 280/2004/EC.
Because not all countries are party to the Kyoto Protocol and thus have no target, either
because they have not ratified the Protocol through their domestic legislation or because
they are considered to be a non-Annex I country, CO2 emissions data are analyzed and
forecasted. Data is available through the World Bank (2009) in regards to the CO2
emissions total per year from 1990 until 2005. Using this data the years from 2006 until
2012 are forecasted and the percentage increase or decrease from 2012 compared to 1990
levels used as a “trend” value.
The resulting trend figure is either a positive or negative depending on its value. Any
trends that are positive are then reversed to a negative figure, as countries that are
increasing their CO2 emissions are less likely to be considering carbon storage at this
juncture. It is more likely that countries that are exhibiting decreasing trends would have
an open market for storage. Thus, any negative trends are reversed to a positive figure and
contribute to the aggregate score.
GDP per capita
The Gross Domestic Product (GDP) per capita is the sum market value of the final
products and services produced in the boundaries of a country spread over the total of the
population (World Bank, 2007). This indicator gives us a snap shot of the standard of
87
living in a country and is often regarded as a social indicator (van den Bergh, 2009). The
higher the GDP per capita the higher the living conditions in a country although this
indicator does not take into account multiple other factors such as income distribution (van
den Bergh, 2009). This attribute is a positive figure and contributes to the aggregate score.
Country risk
The Country Risk Classification is a rating produced by the Organisation for Economic
Co-operation and Development (OECD). It measures the country’s credit risk or the
possibility of a country defaulting on its external debt62. Generally, the higher the risk
rating of a country is, the higher the risk premium that is placed on interest rates. This
classification was originally done in connection to the Arrangement on Export Credits63 in
order to define the risk premium added to the premium rate (OECD, 2009). The
classification itself does not have to directly relate to a specific company in the country as
an individual company may have a higher credit profile then the country itself. However,
the higher the risk classifications of the country the lower the probability of many
companies in that country being of lower risk. This attribute is negative and subtracts from
the aggregate score as the higher the figure the more risk possibly involved in business
operations in this country.
CO2 emissions per capita
The CO2 emission per capita indicator is collected from the World Bank Indicators. The
World Bank defines carbon dioxide emissions as those resulting from the production for
cement as well as the burning of fossil fuels and the consumption of fuels whether solid,
liquid or gas (World Bank, 2007). Although a high emission per capita would generally be
viewed socially as a negative factor, this attribute is a positive factor. This is due to the fact
that CarbFix would have a more positive entry to markets that have high supplies of CO2
that need to be sequestered.
62
Also known as foreign debt.
Trade and Agriculture Directorate of the Organization for Economic Co-operation and
Development, Participants to the Arrangement on Officially Supported Export Credits, 5.
August, 2009.
63
88
Electricity production by fuel source
There are 11 attributes that describe the amount of electricity produced by fuel source in
GWh. Some of the attributes are positive while others are negative and this is dependent on
the amount of CO2 produced through their generation. The information on the amount of
GWh produced is collected from the International Energy Agency (2009b).
The positive attributes include electrical production from coal, natural gas, oil and
geothermal. The amount of CO2 emitted per kWh from these sources is 1.160 grams (g),
400 g, 680 g and 40 g respectively (IEA Statistics, 2009). Although geothermal produces a
small amount of CO2 per kWh this is a positive factor because it is the same type of
technology used in the CarbFix pilot program and thus an easily transferred technology.
The negative attributes include electrical production from hydroelectric, nuclear, waste,
biomass, wind, solar (including photovoltaic) and tidal, wave and ocean. These are
negative because capture is performed through pre-combustion, post-combustion and oxycombustion. These sources of electrical production do not provide a flue gas source in
which capture could take place.
Planned or operational CCS projects
This attribute takes into account any planned CCS projects or that are already operational.
The value listed is the number of projects that meet the following criteria. The project must
be planned to take place within the next 10 years and must have already have a chosen
storage site. Any project in which the CO2 will be utilized for EOR or EGR was not
included. Projects both with on shore and off shore storage were included. Thus the
number of actual projects may be higher but did not meet the criteria for this evaluation.
The information on the projects was collected from the Zero Emissions Platform database
(2009) as well as from the Massachusetts Institute of Technology (2009).
The value is a negative attribute and subtracts from the aggregate score. This is because
this is considered to be domestic knowledge and thus a competitor in CCS for CarbFix.
Natural gas production
Natural gas contains CO2 that must be stripped away in order for the gas to be sold to users
much like in the Statoil natural gas sales contract (Torp & Gale, 2004). The amount of CO2
that must be separated depends on the contract between the producer and the buyer. A
market where large amounts of natural gas are being produced offers an already available
89
concentrated source of CO2. The costs of capture have already been addressed and the
producer of the natural gas has incurred this cost and should consider it to be a sunk cost.
This attribute then is positive and adds to the aggregate score. This data is compiled from
the IEA statistics on natural gas (IEA, 2009c).
Energy imports as a percentage of net energy use
As CO2 is produced at the source of the immobile emitter, the end-user, or energy buyer,
does not have to consider the CO2 emissions. Countries that import a large part of their
energy have possibly smaller amounts of CO2, or emitter points, available for storage. This
attribute is negative and subtracts from the aggregate score.
Intellectual property rights
The method by which CarbFix performs in-situ mineralization is classified as a service or
purchased knowledge. It is then important that the market in which is entered into has a
strong regulatory system to protect intellectual property rights. The International Property
Rights Index (IPRI) (Dedigama, 2009) was used as a proxy for this attribute. The Index
was designed and modelled to better gauge the effectiveness of domestic regulations in
protecting property rights, both physical and intellectual. The IPRI measures 3 categories;
legal and political environment, physical property rights and intellectual property rights
(IPR). The IPR spans 70 countries in total spanning 95% of the world’s GDP. Countries
are scored from 0 to 10 with the higher figure representing the best possible environment
for protecting intellectual property. This attribute is a positive factor and adds to the
aggregate score.
Population density
The population density was found through the World Bank Indicators database (2009). The
higher the density the more negative the value. This is due to the negative perception the
general public may have towards CCS without further energy literacy of the public. As
CCS would require additional infrastructure and perhaps piping to distant storage sites, the
higher the population density figure may hinder that development. This attribute subtracts
from the aggregate score.
90
Nationally protected land
The amount of land that is nationally protected as a percentage of total square kilometres
of surface area is a negative factor. If a land mass is nationally protected there may be
greater difficulty in receiving permits or licenses to begin storage of CO2. The data is
collected from the World Bank Indicators database (2009). This attribute subtracts from
the aggregate score.
Freshwater resources per capita
The process of in-situ mineralization requires water and any scarcity of that resource is a
negative factor. The amount of freshwater resources available per capita gives an idea of
the amount of abundance or scarcity in that country. This is a positive attribute and adds to
the aggregate score. Data for this proxy is collected from the World Bank Indicators
database (2009).
Access to seawater
As mentioned in the previous paragraph, water is a vital element in the CarbFix method of
storage. Any country that has a low freshwater resource may however use seawater. This
attribute is a value of 0 to 1 in where 0 represents no access to seawater and 1 represents
seawater access through country borders. This attribute adds to the aggregate score.
Information is gathered from a world atlas (DK Publishing, 2008).
IV.1.3
Purchasing power parity
The threats and opportunities are not enough to clearly define the optimum choice of
market entrance for a company. In order to find the markets that best present business
opportunities for CarbFix some sort of cost or purchasing power must be considered. In
this way it is not only found the markets that are positive for CarbFix but also have a
financial upper hand in purchasing power. It is when these two factors, attributes and
purchasing power, are considered together that we can produce an efficiency frontier. The
efficiency frontier is the market options that best meet the preferences of the decision
maker as well as contain within their markets sufficient purchasing power.
The purchasing power considered against the attributes in this analysis was the purchasing
power parity (PPP) in international dollars. The PPP follows the “law of one price” theory
in which the price of identical goods in two separate countries should be the same price
91
when expressed in the same currency. The PPP not only reflects exchange rates but also
inflation and whether a particular currency is overvalued or undervalued. The data is
retrieved from the International Monetary Fund database for the year of 2009.
IV.2 Data
In total there were 67 countries considered to be possible markets. The data are presented
in Appendix B. As mentioned, the prerequisite was that each market contains within its
country borders an applicable mineral for in-situ mineralization. After all of the attribute
proxy values are collected the markets reduce to 49 due to lack of data. Figure 26 shows
those countries who were included due to on-shore basalt, offshore basalt, both and
ultramafic as well as those countries that were not able to be included although they have
storage capabilities.
Figure 26: World map indicating countries that were used in the market analysis.
IV.3 Efficiency frontier
After the attribute aggregate scores and the purchasing power of the currency are paired
together the results are reviewed in a scatter chart. Figure 27 shows the total results and the
efficiency frontier. Those countries that lie on the efficiency frontier are Russia, the United
92
States, Canada, Italy and Germany. Those countries dominate the others in either the
aggregate attribute score or purchasing power. These five countries initially are then the
five that show the most promise as positive markets for CarbFix to enter.
Figure 27: Market analysis efficiency frontier.
It is important to note that a second interview was taken with another applicable decision
maker. The two decision makers differ in roles in the project as well as educational
background. The purpose of the second interview is to note any changes to the efficiency
frontier that may be present. The results show that while there was some difference in the
results in the lower performing countries, ultimately the efficiency frontier presents the
same five countries that should be focused on.
IV.4 Sensitivity analysis
The SMART analysis employs the use of prescriptive weights. In order to better
understand the changes in weights has on the overall outcome a sensitivity analysis is
performed. In this case the weights that are given to the two different categories,
opportunities and threats, will be changed.
The first analysis is to reduce the top three ranked attributes in the category “Threats” to a
weight of zero with all other threats remaining the same. The attributes, population density,
93
ease of doing business, country risk had originally weights of 89, 85 and 84. The second
analysis is to reduce the top three ranked attributes in the category “Opportunities” to a
weight of zero with all other opportunities remaining the same. The attributes, freshwater
per capita, electrical production from coal and CO2 emissions per capita had originally
weights of 100, 95 and 90. Figure 28 shows that the change from the left axis, or where the
top three attributes in opportunities are brought to zero, to the right axis where the top three
attributes in the threats are brought to a zero.
Figure 28: Sensitivity analysis of the top three ranked weights in each category, Threats
and Opportunities.
The sensitivity analysis shows that, regardless of these changes, the top performers remain
the same, as well as most of the countries showing very little change. China does perform
better when less weight is place on the opportunities and more weight on the threats.
In order to further understand why these changes made little difference to the aggregate
scores another sensitivity analysis is performed. The top rated countries in aggregate scores
are countries that have some natural gas production. This attribute has a weight of 75 and
is listed as an opportunity. As Figure 29 shows the top two ranked countries in the
aggregate scores were Russia and the United States, both countries with high production
values of natural gas.
94
Figure 29: Natural gas production in tera joules per year by country.
The sensitivity analysis was performed by giving the attribute of natural gas production a
weight of zero as well as 100 to reflect what changes this had on aggregate score values.
Figure 30 shows the lower performing countries and the change in the weight of natural
gas has on the aggregate score performance. The weight is currently at 75 and as is shown
at a weight above 75 there is relatively no change to the lower performing countries.
However there are distinct points that must be considered. For example, at a weight of 45
and less China dominates Canada. Also, at a weight of 5 or less China is the top performer.
Figure 30: Changes in the weight of natural gas; lower performing countries.
95
Figure 31 is the same graph as Figure 30 both more specifically targeted at the changes to
the scores of the United States and Russia. It shows that when the top two performing
countries are examined it is clear that at a weight of 25 or less that the United States is the
top performer.
Figure 31: Changes in the weight of natural gas: higher performing countries.
96
V. CONCLUSIONS
This paper reviewed the current CarbFix pilot program and its associated costs to find cost
drivers. In order to better understand the changes in cost drivers relative to CO2 flow, two
additional scenarios were considered; the full-scale injection scenario from the Hellisheidi
geothermal power plant, and a capture ready pulverized coal plant. The cost analysis shows
that while the CarbFix pilot program is largely dominated by the capital costs, specifically
monitoring wells, the injection well and site screening, the Hellisheidi full-scale scenario is
dominated by the monitoring wells with all of the other capital costs more evenly spread.
The costs of CO2 captured per tCO2 for these two scenarios are 503! and 31!, respectively.
A sensitivity analysis of both the pilot program and the full-scale scenario shows where the
largest reductions in the cost per tonne can be realized. The pilot program shows relatively
no changes when the water and electricity costs are reduced and this is due to the small
flow of CO2, which the two factors are dependent on. The pilot program can realize the
most reductions in the levelized cost by reducing the capital costs associated to the
monitoring and injection wells. A reduction in these costs of up to 50% can result in a
reduction in the levelized cost in a range from 15 to 23%. The full-scale scenario proves to
be more dependent on the water and electricity requirements, as the flow of CO2 is 27
times more than in the pilot program. A 50% reduction in the water and electrical
requirements could result in a 6% reduction in the levelized cost. Both scenarios, when
applied with a Monte Carlo simulation, show a decreasing sensitivity to capital costs as the
flow increases. The pilot program, with its smaller flow, is the most sensitive providing a
range from 456 to 515!/tCO2. The Hellisheidi scenario shows a much smaller range of 28
to 31!/tCO2.
The pulverized coal plant scenario and its cost analysis is where the greater appeal lies.
The flow is 1.125 times more than in the pilot program and the cost per tonne 9,65!. The
water and electricity costs make up 63% of the total annual costs. The sensitivity analysis
also shows that the water costs are the leading target to reduce the annual costs, providing
up to a 20% reduction in the levelized costs. Even when capture costs are added the total
costs of 28,15!t/CO2 lies within an acceptable range of 18,2 to 35,7!/tCO2 as provided by
the literature. A Monte Carlo simulation also shows that the range of cost per tonne is far
97
less sensitive to changes in capital costs then the changes in the water and electricity
requirements. The range, when the capital costs are tested, is from 9,23 to 9,77!/tCO2
while the range for the water and electricity factors was from 8,5 to 10,8!/tCO2.
These results show that the predominant cost factors are flow dependent and as the flow
increases the CarbFix method of CCS becomes more sensitive to water and electricity
requirements, predominantly the water. When the flow is small the predominant factors are
the capital costs. The number of injection wells is also an important factor and one that
must be studied extensively as the associated capital costs can play a major role. When the
Hellisheidi scenario was increased in regards to injection well requirements, from 1 to 10,
the costs changed drastically. This emphasizes the importance and need for more
geoscientific work concerning injection wells. The cost per tonne increased from 31! to
66!/tCO2, more than twice as expensive. Also, the sensitivity changes as the Monte Carlo
simulation shows that the range is now between 58 and 69!/tCO2. This is an 11-point
difference where the Hellisheidi scenario with one injection well only showed a range of 3
points. The costs analysis also shows that the Hellisheidi full-scale program may become
more economical in the future as the electrical production increases providing more CO2
flow. In 10 years, given that the flow will increase from 60 thousand to 90 thousand tCO2
per year, the cost of the scenario with one injection well decreases from 31!/tCO2 to
26!/tCO2.
The profitability assessment of the three scenarios indicates as to what cost CO2 per tonne
must lie at in order for the scenario, at its current costs, to provide revenue at an acceptable
rate. The CarbFix pilot program provides a price of 1.200!/tCO2 or higher while the
Hellisheidi scenario provides a more reasonable price of 77!/tCO2 or higher. These prices
are dependent on the investor and what the appropriate required return is acceptable, as
well as loan rates and other economic parameter assumptions. However, both scenarios
would find difficulty in competing in a trading market where the current price is
fluctuating around 15!/tCO2.
The pulverized coal plant with capture and CarbFix storage method provides a much more
positive outlook. While a price of 17!/tCO2 could be acceptable, depending on the
investor, a price of 50!/tCO2 would be more reasonable. Even when the capture costs are
included in the profitability assessment the price of 50!/tCO2 still fairs well and offers a
valid investment opportunity. This is comparable to the highest tax currently exhibited in
Europe on energy based CO2 emissions. CarbFix may be better positioned, at its current
98
costs, to work towards a costs avoided scenario where an energy based CO2 tax is
implemented.
The market analysis employs the use of the Simple Multi-Attribute Rating Technique
combined with a PESTLE analysis. The results take into account the external factors, in the
form of opportunities and threats that provide a positive market with low barriers to entry
for CarbFix. The analysis shows that the most efficient markets to enter at this time,
according to the attributes identified and the strength of the market’s currency are Russia,
the United States, Italy and Germany. However, these results may be skewed by the
attribute attached to natural gas production even though it is not a predominant attribute.
When the sensitivity of the top rated threats and opportunities are analyzed there is
relatively no change. When the attribute of natural gas production on its own is tested for
sensitivity there is more change. When this attribute is given a weight of 5 or less China
becomes the top performer while between 5 and 25 the United States outranks the rest.
From the weight of 75 to 100 there is relatively no change with Russia remaining the top
performer and the lower rated countries remaining constant in ranking.
As the SMART analysis is a prescriptive approach it is important that the weights attached
to the attributes are in 100% accordance to the decision maker’s priorities, specifically the
attribute of natural gas production. It is also important that as markets and technologies
change that this sensitivity of the market analysis be reassessed. A Norwegian tax on CO2
in 1991 is one of the main incentives that led to Statoil to store CO2. If more countries
decide to implement a similar tax perhaps the weight of the natural gas attribute should be
increased, as such changing the analysis.
In the future it will be important to work on the major cost factors of the CarbFix method
of storage depending on the flow being assessed. Work should continue in both reducing
capital costs, specifically in the form of monitoring wells, as well as working towards
lower water and energy requirements. The water requirements can be changed according to
the temperature or by using seawater and as such continued research would be needed to
assess what changes this would have on the actual reaction of the basalt and saturated CO2.
The number of required injection wells will also need to be accurately known in order to
bind the capital costs. As the market analysis in this paper only reviewed foreign markets it
would be wise to review the domestic market in terms of potential customers, such as
aluminium smelters. Also, CO2 is a resource and can be utilized in other ways while also
99
providing revenue. Other opportunities should be economically assessed so as to wholly
define all the possible methods of utilization.
This analysis should be reviewed once costs for monitoring are standardized through
legislation both in the international community as well as within the Icelandic legal system.
As Directive 2009/31/EC is adopted into Icelandic legislation and more defining
requirements finalized through the European Council of the European Union additional
factors such as insurance could increase the cost per tonne captured. It is therefore
important for Reykjavik Energy to remain well informed of these changes and
subsequently review this analysis with those changes in mind.
100
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107
APPENDIX A: STUDY COMPARISON OF CCS SCENARIOS & COSTS
Assumptions & Results
Parsons
(2002)
IEA (2004)
Chen et al. (2003)
Chen et al.
(2003)
Existing
Existing
*
*
Reference plant
New
Boiler type
New
super
Ultra
sub
sub
Coal type and %S
bit, 2,5% S
bit, 1% S
sub-bit, 1,1% S
sub-bit, 1,1% S
Emission control technologies
FGD, SCR
FGD, SCR
FGD
FGD
Net output (MWe)
462
758
248
248
Capacity factor (%)
65
85
80
76
Net efficiency, LHV (%)
42,2
44,0
33,1
33,1
Coal cost LHV (US$/GJ)
1,29
1,50
1,20
1,20
Emissions rate (tCO2/MWh)
0,774
0,743
1,004
1,004
Capture plant
CO2 capture technology
Net output with capture (MWe)
MEA
MEA
MEA
MEA
329
666
140
282
FGD upgrade
FGD upgrade
Additional equipment
NG. $5,06 GJ-1
Auxiliary boiler/fuel used (type, LHV
cost)
Net plant efficiency, LHV (%)
30,1
34,8
18,7
90
87,5
90
90
0,108
0,117
0,117
0,369
1.830
4.061
1.480
1.480
CO2 production pressure (MPa)
8,4
11,0
13,9
13,9
CCS energy requirement (% more input
MWh-1)
40
26
77
CO2 reduction per kWh (%)
86
84
82
CO2 capture system efficiency (%)
CO2 emission
(tCO2/MWh)
rate
after
capture
CO2 captured (Mt/yr)
A-1
63
APPENDIX A: STUDY COMPARISON OF CCS SCENARIOS & COSTS
Assumptions & Results
Parsons
(2002)
IEA
(2004)
Chen et al.
(2003)
Chen et al.
(2003)
Cost results
**
Cost year basis (constant dollars)
2000
2004
2000
2000
Fixed charge factor (%)
15,5
11,0
14,8
14,8
Reference plant TCR (US$/kW)
1.281
1.319
0
0
Capture plant TCR (US$/kW)
2.219
1.894
837
654
938
575
837
654
Reference plant COE (US$/MWh)
51,5
43,9
20,6
20,6
Capture plant COE (US$/MWh)
85,6
62,4
66,8
62,2
Incremental COE (US$/MW)
34,1
18,5
46,2
41,7
% increase in capital cost (over ref.
plant)
73
44
% increase in COE (over ref. plant)
66
42
225
203
Cost of CO2 captured (US$/tCO2)
35
23
31
56
Cost of CO2 avoided (US$/tCO2)
51
29
56
66
Incremental
(US$/kW)
TCR
for
capture
Notes: All costs in this table are for capture only and do not include the costs of CO2
transport and storage. *Reported HHV values converted to LHV assuming LHV/HHV =
0.96 for coal. **Reported capital costs increased by 8% to include interest during
construction.
A-2
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
Albania2
X
1
X
Algeria
Angola1
Southeast
Indian
Ridge
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean
Flood Basalt
Gulf of
Aden
Kerala
Basin
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian Ridge
45
Juan de Fuca
Ridge
X
1
X
1,3
Australia
X
BosniaHerzegovina2
X
Brazil1,3
X
Argentina
Cameroon
1,3
1
X
X
X
Canada
X
Chile1
X
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-1
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
1
Southeast
Indian
Ridge
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean
Flood Basalt
X
X
X
X
Gulf of
Aden
Kerala
Basin
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian
Ridge 45
X
China
3
Colombia
1,3
Costa Rica
2
X
X
Croatia
Dominican
3
Republic
X
3
X
Ecuador
1
El Salvador
X
3
X
Eritrea
1
X
Ethiopia
1
X
France
Germany
1
X
3
Guatemala
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-2
Juan de Fuca
Ridge
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
Honduras3
1,3
India
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean Flood
Basalt
X
X
Gulf of
Aden
X
1
Indonesia
X
Israel1
X
Italy
Southeast
Indian
Ridge
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian
Ridge 45
X
4
Japan
Kerala
Basin
X
1
X
1
Kenya
X
1,3
Malaysia
X
Mexico1
X
Morocco
1
X
X
1
Mozambique
1,3
Nicaragua
X
X
X
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-3
Juan de Fuca
Ridge
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
Nigeria1
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean
Flood Basalt
X
X
Gulf of
Aden
Kerala
Basin
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian
Ridge 45
Juan de Fuca
Ridge
X
1,3
Panama
Peru
Southeast
Indian
Ridge
X
3
X
Philippines1
X
1
Russia
X
1,3
South Africa
X
X
3
Sri Lanka
X
1
Tanzania
X
Turkey1
X
1,3
United States
Uruguay
1
X
X
X
1,3
Venezuela
X
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-4
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
Vietnam1
Yemen
Southeast
Indian
Ridge
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean
Flood Basalt
Kerala
Basin
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian Ridge
45
X
1,3
X
1
Zimbabwe
X
Afghanistan1
X
1,3
X
Cuba
X
X
3
Djibouti
X
1
X
1,3
Guinea
X
Guyane1,3
X
1
X
Guyana
Iran
Gulf of
Aden
1
Libya
X
X
X
3
Madagascar
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-5
Juan de
Fuca Ridge
APPENDIX B: COUNTRIES INCLUDED IN ANALYSIS AND THEIR STORAGE SITE CAPABILITIES
On-shore
basalt
Montenegro2
MidAtlantic
Ridge 0
Coco
Ridge
Caribbean
Flood Basalt
Gulf of
Aden
Kerala
Basin
Ultramafic
Ninetyeast/
Broken Ridge
Walvis
Ridge
Ontong
Java
Southwest
Indian Ridge
45
X
1,3
Namibia
X
New
Caledonia2
X
Oman2,3
X
Papua
New
Guinea2,3
X
Puerto Rico3
X
X
X
X
1
Saudi Arabia
X
Somalia3
Swaziland
Southeast
Indian
Ridge
X
1
X
1 – Oelkers et al., 2008; 2 – Juerg Matter, personal communication; 3 – Goldberg & Slagle, 2009; 4 – Cipolli et al., 2004 *Shaded countries were not included due to lack of data.
B-6
Juan de
Fuca Ridge
APPENDIX C: COUNTRY DATA
Unit
Albania
Algeria
Angola
Argentina
Australia
Ease of Doing Business
#
0,82
1,36
1,69
1,18
0,09
Environmental Sustainability
#
8,40
7,70
3,95
8,18
7,98
Decimal
-0,24
1,05
1,25
0,52
0,08
Th. $
7.72
8.03
5.90
14.33
35.68
#
6
3
6
7
0
Metric
tonnes
1,1
4,2
0,5
3,9
18,1
Coal
TWh
0
0
0
2,1
198,9
Hydro
TWh
5,0
0,2
2,7
38,2
16,0
Nat. Gas
TWh
0
34,2
0
57,8
30,6
Nuclear
TWh
0
0
0
7,7
0
Oil
TWh
0,1
0,8
0,3
8,0
2,4
Waste
TWh
0
0
0
0
0
Biomass
TWh
0
0
0
1,4
2,0
Geothermal
TWh
0
0
0
0
0
Solar
TWh
0
0
0
0
0,03
Tidal
TWh
0
0
0
0
0
Wind
TWh
0
0
0
0,07
1,7
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Future/Current CCS
#
0
1
0
0
5
Nat. Gas Production
Petajoules
0,7
3.844,9
30,4
1.765,0
1.713,6
Decimal
0,47
0
0
0
0
#
Energy Imports
Int. Property Rights
3,5
4,0
2,8
4,3
8,2
Population Density
100/km
2
1,15
0,14
0,14
0,15
0,03
Nationally Protected Land
Decimal
0,01
0,05
0,10
0,06
0,10
8,6
0,3
8,4
7,0
23,4
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
1
1
Aggregate Score
#
0,03
19,28
0,17
8,71
10,08
Int. $
49,65
38,97
51,79
2,03
1,47
Power Purchasing Parity
C-1
APPENDIX C: COUNTRY DATA
Unit
BosniaHerzegovina
Brazil
Cameroon
Canada
Chile
Ease of Doing Business
#
1,16
1,29
1,71
0,08
0,49
Environmental Sustainability
#
7,97
8,27
6,38
8,66
8,34
Decimal
4,77
0,97
2,01
-0,06
1,33
Th. $
8,39
10,30
2,22
36,44
14,46
#
7
3
6
0
2
Metric
tonnes
7,0
1,8
0,2
16,6
4,1
Coal
TWh
7,3
10,2
0
104,7
9,8
Hydro
TWh
5,9
348,8
3,7
355,5
34,3
Nat. Gas
TWh
0
18,3
0
33,4
11,4
Nuclear
TWh
0
13,8
0,2
98,0
0
Oil
TWh
0,2
12,4
0
9,4
0,9
Waste
TWh
0
0
0
0,02
0
Biomass
TWh
0
14,8
0
9,0
1,1
Geothermal
TWh
0
0
0
0
0
Solar
TWh
0
0
0
0,02
0
Tidal
TWh
0
0
0
0,03
0
Wind
TWh
0
0,2
0
2,5
0
Future/Current CCS
#
0
0
0
3
0
Nat. Gas Production
Petajoules
0
435,1
0
7.206,4
78,8
Decimal
0,27
0,08
0
0
0,67
#
3,3
4,7
3,8
7,9
6,5
0,74
0,23
0,41
0,04
0,22
0,005
0,18
0,09
0,01
0,04
9,4
28,5
14,7
86,4
53,27
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
2
Population Density
100/km
Nationally Protected Land
Decimal
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
1
1
Aggregate Score
#
0,09
0,4
0,05
34,9
0,68
Int. $
0,81
1,51
243,89
1,18
350,57
Power Purchasing Parity
C-2
APPENDIX C: COUNTRY DATA
Unit
China
Colombia
Costa Rica
Croatia
Ease of Doing Business
#
0,89
0,37
1,21
1,03
Environmental Sustainability
#
6,51
8,83
9,05
8,46
Decimal
1,39
-0,07
2,02
0,02
Th. $
5,96
8,88
11,24
19,08
#
2
4
3
5
Metric tonnes
4,3
1,4
1,7
5,2
Coal
TWh
2.301,4
4,1
0
2,3
Hydro
TWh
435,8
42,7
6,6
6,1
Nat. Gas
TWh
14,2
6,7
0
2,1
Nuclear
TWh
54,8
0
0
0
Oil
TWh
51,5
0,1
0,5
2,0
Waste
TWh
0
0
0
0
Biomass
TWh
2,5
0,6
0,07
0,01
Geothermal
TWh
0
0
1,2
0
Solar
TWh
0,1
0
0
0
Tidal
TWh
0
0
0
0
Wind
TWh
3,9
0,06
2,7
0,02
Future/Current CCS
#
3
0
0
0
Nat. Gas Production
Petajoules
2.279,5
285,2
0
103,1
Decimal
0,07
0
0,49
0,54
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
4,7
4,9
5,6
4,9
Population Density
100/km
2
1,42
0,40
0,89
0,79
Nationally Protected Land
Decimal
0,15
0,25
0,22
0,06
Th. m3
2,13
48,0
25,2
8,5
Access to sea water
#
1
1
1
1
Aggregate Score
#
23,31
1,56
0,13
0,6
Int. $
3,72
1.231,42
344,17
4,19
Freshwater per capita
Power Purchasing Parity
C-3
APPENDIX C: COUNTRY DATA
Unit
Dominican Republic
Ecuador
El Salvador
Eritrea
Ease of Doing Business
#
0,86
1,38
0,84
1,75
Environmental Sustainability
#
8,30
8,44
7,72
5,94
Decimal
1,94
0,93
2,27
5,28
Th. $
8,22
8,01
6,79
0,63
#
5
7
4
7
Metric tonnes
2,0
2,2
1,1
0,2
Coal
TWh
1,9
0
0
0
Hydro
TWh
1,4
7,1
2,0
0
Nat. Gas
TWh
1,3
1,5
0
0
Nuclear
TWh
0
0
0
0
Oil
TWh
9,5
6,8
2,5
0,3
Waste
TWh
0
0
0
0
Biomass
TWh
0,03
0
0,02
0
Geothermal
TWh
0
0
1,1
0
Solar
TWh
0
0
0
0
Tidal
TWh
0
0
0
0
Wind
TWh
0
0
0
0
Future/Current CCS
#
0
0
0
0
Nat. Gas Production
Petajoules
0
26,0
0
0
Decimal
0,80
0
0,44
0,27
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
4,5
4,0
4,8
3,8
Population Density
100/km
2
2,03
0,49
2,96
0,49
Nationally Protected Land
Decimal
0,24
0,23
0,01
0,05
Th. m3
2,2
32,4
2,9
0,6
Access to sea water
#
1
1
1
1
Aggregate Score
#
0,02
0,31
-0,003
-0,05
Int. $
21,04
0,51
0,51
6,83
Freshwater per capita
Power Purchasing Parity
C-4
APPENDIX C: COUNTRY DATA
Unit
Ethiopia
France
Germany
Guatemala
Honduras
Ease of Doing Business
#
1,07
0,31
0,25
1,10
1,41
Environmental Sustainability
#
5,88
8,78
8,63
7,67
7,54
Decimal
2,50
0
-0,21
1,98
2,67
Th. $
0,87
34,04
35,61
4,76
3,96
#
7
0
0
5
6
Metric tonnes
0,1
6,2
9,5
0,9
1,1
Coal
TWh
0
26,3
302,3
1,1
0
Hydro
TWh
3,3
61,1
27,3
3,8
2,6
Nat. Gas
TWh
0
22,1
76,1
0
0
Nuclear
TWh
0
450,2
167,3
0
0
Oil
TWh
0,01
7,1
9,6
2,0
3,4
Waste
TWh
0
3,1
7,4
0
0
Biomass
TWh
0
1,9
14,0
1,0
0,04
Geothermal
TWh
0
0
0
0
0
Solar
TWh
0
0,02
2,2
0
0
Tidal
TWh
0
0,5
0
0
0
Wind
TWh
0
2,2
30,7
0
0
Future/Current CCS
#
0
1
5
0
0
Nat. Gas Production
Petajoules
0
49,2
653,7
0
0
Decimal
0,09
0,50
0,61
0,34
0,53
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
3,7
7,2
8,3
4,3
4,4
Population Density
100/km
2
0,81
1,13
2,36
1,26
0,65
Nationally Protected Land
Decimal
0,19
0,10
0,22
0,33
0,20
Th. m3
1,6
2,9
1,3
8,2
13,5
Access to sea water
#
0
1
1
1
1
Aggregate Score
#
-0,05
-2,28
4,04
0,04
0,06
Int. $
4,55
0,91
0,84
4,53
8,47
Freshwater per capita
Power Purchasing Parity
C-5
APPENDIX C: COUNTRY DATA
Unit
India
Indonesia
Israel
Italy
Japan
Kenya
Malaysia
Ease of Doing Business
#
1,33
1,22
0,29
0,78
0,15
0,95
0,23
Environmental
Sustainability
#
6,03
6,62
7,96
8,42
8,45
6,90
8,40
Decimal
1,52
2,24
1,70
-0,07
-0,06
1,32
3,42
Th. $
2,97
3,97
27,55
30,76
34,1
1,59
14,22
#
3
5
3
0
0
6
2
Metric
tonnes
1,3
1,9
9,2
7,7
9,6
0,31
9,4
Coal
TWh
508,4
58,6
35,9
50,4
298,9
0
23,1
Hydro
TWh
113,6
9,6
0,03
43,4
95,6
3,3
7,1
Nat. Gas
TWh
62,1
19,5
9,08
158,1
254,5
0
58,6
Nuclear
TWh
18,6
0
0
0
303,4
0
0
Oil
TWh
31,5
38,7
6,8
45,9
120,7
2
2,7
Waste
TWh
0
0
0
3,1
7,3
0
0
Biomass
TWh
1,9
0
0
3,7
15,1
0,3
0
Geothermal
TWh
0
6,7
0
5,5
3,1
0,9
0
Solar
TWh
0,02
0
0
0,04
0
0
0
Tidal
TWh
0
0
0
0
0
0
0
Wind
TWh
8,0
0
0
3,0
1,8
0
0
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Future/Current CCS
#
0
0
0
2
0
0
0
Nat. Gas Production
Petajoules
1.089,2
2.980,9
87,6
418,3
148,5
0
2.608,7
Decimal
0,23
0
0,88
0,85
0,81
0,21
0
#
Energy Imports
Int. Property Rights
5,6
4,1
6,5
6,1
7,6
4,2
6,2
Population Density
100/km
2
3,83
1,26
3,38
2,04
3,5
0,68
0,82
Nationally Protected Land
Decimal
0,05
0,11
0,16
0,07
0,09
0,12
0,18
1,1
12,6
0,1
3,1
3,4
0,6
21,9
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
1
1
1
1
Aggregate Score
#
7,97
15,35
0,75
2,46
0,87
-0,03
13,43
Int. $
16,17
5.684,27
3,65
0,87
114,48
38,3
1,91
Power Purchasing Parity
C-6
APPENDIX C: COUNTRY DATA
Unit
Mexico
Morocco
Mozambique
Nicaragua
Nigeria
Ease of Doing Business
#
0,51
1,27
1,35
1,17
1,25
Environmental
Sustainability
#
7,98
7,21
5,39
7,34
5,62
Decimal
0,10
1,21
1,02
0,95
1,76
Th. $
14,50
4,39
0,86
2,68
2,08
#
3
3
6
7
6
Metric tonnes
4,1
1,6
0,1
0,7
0,8
Coal
TWh
31,7
13,5
0
0
0
Hydro
TWh
30,4
1,6
14,7
0,4
7,7
Nat. Gas
TWh
113,6
3,0
0,01
0
13,4
Nuclear
TWh
10,9
0
0
0
0
Oil
TWh
53,8
5,0
0,01
2,1
2,0
Waste
TWh
0
0
0
0
0
Biomass
TWh
2,5
0
0
0,1
0
Geothermal
TWh
6,7
0
0
0,3
0
Solar
TWh
0,01
0
0
0
0
Tidal
TWh
0
0
0
0
0
Wind
TWh
0,06
0,2
0
0
0
Future/Current CCS
#
0
0
0
0
0
Nat. Gas Production
Petajoules
1.885,6
2,6
103,4
0
1.111,8
Decimal
0
0,95
0
0,39
0
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
4,8
5,1
4,2
3,6
3,5
Population Density
100/km
2
0,55
0,70
0,28
0,47
1,66
Nationally Protected Land
Decimal
0,01
0,01
0,06
0,18
0,06
3,9
0,9
4,7
33,9
1,5
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
1
1
Aggregate Score
#
9,36
-0,61
0.44
0,21
5,51
Int. $
8,06
5,09
13.149,04
7,63
75,42
Power Purchasing Parity
C-7
APPENDIX C: COUNTRY DATA
Unit
Panama
Peru
Philippines
Russia
South Africa
Ease of Doing Business
#
0,77
0,56
1,44
1,20
0,34
Environmental
Sustainability
#
8,31
7,81
7,79
8,39
6,90
Decimal
1,57
0,83
1,28
0
0,28
Th. $
12,50
8,51
3,51
16,14
10,11
#
3
3
4
4
3
Metric tonnes
1,8
1,3
0,9
10,5
8,7
Coal
TWh
0
0,8
15,3
178,8
235,6
Hydro
TWh
3,6
21,5
9,9
175,3
5,6
Nat. Gas
TWh
0
2,6
16,4
457,8
0,07
Nuclear
TWh
0
0
0
156,4
11,8
Oil
TWh
2,3
2,3
4,7
24,4
0
Waste
TWh
0
0
0
2,7
0
Biomass
TWh
0,08
0,2
0
0,04
0,3
Geothermal
TWh
0
0
10,5
0,5
0
Solar
TWh
0
0
0
0
0,5
Tidal
TWh
0
0
0
0
0
Wind
TWh
0
0
0
0,01
0,03
Future/Current CCS
#
0
0
0
0
0
Nat. Gas Production
Petajoules
0
77,83
115,87
24.463,65
75,53
Decimal
0,72
0,15
0,43
0
0
#
5,3
4,2
4,5
4,1
6,8
0,46
0,23
3,03
0,09
0,4
0,1
0,14
0,1
0,07
0,06
44,1
56,7
5,4
30,4
0,94
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
2
Population Density
100/km
Nationally Protected Land
Decimal
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
1
1
Aggregate Score
#
0,3
0,68
0,67
122,38
1,84
Int. $
0,62
1,53
23,33
19,33
4,81
Power Purchasing Parity
C-8
APPENDIX C: COUNTRY DATA
Unit
Sri Lanka
Tanzania
Turkey
USA
Uruguay
Ease of Doing Business
#
1,05
1,31
0,73
0,04
1,14
Environmental Sustainability
#
7,95
6,39
7,59
8,10
8,23
Decimal
3,19
1,08
0,99
0,32
0,45
Th. $
4,56
1,26
13,92
46,72
12,73
#
6
6
4
0
4
Metric tonnes
0,56
0,1
3,5
19,5
1,7
Coal
TWh
0
0,1
46,7
2.128,5
0
Hydro
TWh
4,6
1,4
44,2
317,7
3,6
Nat. Gas
TWh
0
1,2
80,7
839,3
0
Nuclear
TWh
0
0
0
816,2
0
Oil
TWh
4,8
0,02
4,3
80,6
2,0
Waste
TWh
0
0
0,1
22,9
0
Biomass
TWh
0
0
0,06
49,0
0,05
Geothermal
TWh
0
0
0,09
16,6
0
Solar
TWh
0
0
0
0,6
0
Tidal
TWh
0
0
0
0
0
Wind
TWh
0
0
0,1
26,7
0
Future/Current CCS
#
0
0
0
11
0
Nat. Gas Production
Petajoules
0
14,6
34,7
20.052,4
0
Decimal
0,41
0,07
0,72
0,29
0,75
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
4,6
4,5
5,3
7,8
5,5
Population Density
100/km
2
3,12
0,48
0,96
0,33
0,19
Nationally Protected Land
Decimal
0,18
0,39
0,02
0,15
0,003
Th. m3
2,5
2,0
3,1
9,3
17,8
Access to sea water
#
1
1
1
1
1
Aggregate Score
#
-0,04
0,06
0,37
108,25
0,12
Int. $
50,96
512,24
1,08
1,00
16,91
Freshwater per capita
Purchasing Power Parity
C-9
APPENDIX C: COUNTRY DATA
Unit
Venezuela
Vietnam
Yemen
Zimbabwe
Ease of Doing Business
#
1,77
0,93
0,99
1,59
Environmental
Sustainability
#
8,00
7,39
4,97
6,93
Decimal
0,60
4,91
1,40
-0,50
Th. $
12,80
2,78
2,40
0,16
#
7
5
6
7
Metric tonnes
5,6
1,2
0,96
0,9
Coal
TWh
0
9,7
0
4,2
Hydro
TWh
79,5
23,6
0
5,6
Nat. Gas
TWh
14,8
20,9
0
0
Nuclear
TWh
0
0
0
0
Oil
TWh
16,1
2,3
5,3
0,02
Waste
TWh
0
0
0
0
Biomass
TWh
0
0
0
0
Geothermal
TWh
0
0
0
0
Solar
TWh
0
0
0
0
Tidal
TWh
0
0
0
0
Wind
TWh
0
0
0
0
Future/Current CCS
#
0
0
0
0
Nat. Gas Production
Petajoules
1.088,6
293,1
0
0
Decimal
0
0
0
0,09
#
Kyoto Trend
GDP per capita
Country Risk
Elec. Production
CO2 Emissions per capita
Energy Imports
Int. Property Rights
3,2
4,4
5,0
3,2
Population Density
100/km
2
0,32
2,78
0,44
0,32
Nationally Protected Land
Decimal
0,72
0,05
0
0,15
26,3
4,3
0,1
1,0
Freshwater per capita
Th. m
3
Access to sea water
#
1
1
1
0
Aggregate Score
#
5,23
1,42
-0,02
-0,02
Int. $
2.125,63
6.351,69
90,96
35,49
Purchasing Power Parity
C - 10
APPENDIX D: MAP OF COUNTRIES INCLUDED IN MARKET ANALYSIS
D-1