2
Techno-economic analysis and modeling of
carbon dioxide (CO2) capture and storage
(CCS) technologies
J. O g d e n and N. J o h n s o n, University of California
Davis, USA
Abstract: This chapter presents an overview of the estimated costs of
implementing carbon dioxide (CO2) capture and sequestration (CCS) for
fossil energy systems. Cost models for the components of a CCS system are
reviewed and developed, including CO2 capture, transport via pipeline and
ship, and injection into various reservoirs for storage and/or enhanced fossil
fuel recovery. The chapter closes with a discussion of CCS system models
and future trends.
Key words: carbon capture and sequestration (CCS) economics, CO2
injection, CO2 capture, CO2 transport, CCS system modeling.
2.1
Introduction
Implementing carbon capture and sequestration (CCS) on a large scale will
involve major investments. Existing fossil energy conversion plants will
be retrofitted for carbon capture or replaced with new plants that integrate
carbon capture into the process. A new transport infrastructure will be
needed to bring carbon dioxide to suitable storage sites, such as underground
geological formations. The storage site will include injection wells, piping,
and monitoring equipment. In some cases, a new energy delivery system
could be required to bring decarbonized energy carriers such as hydrogen to
markets. Understanding the design, performance, and costs throughout the
whole system is crucial to evaluating the economic viability of fossil energy
with CCS, as compared to fossil energy without CCS, and in comparison
to other low-carbon energy supply options such as renewables and nuclear
power. In this chapter, we review current state of knowledge on technoeconomic modeling of fossil energy systems with CCS. We develop idealized
technical and cost models for the entire system and discuss methods and
metrics for economic evaluation.
A central question for techno-economic studies is how much it will cost
to implement CCS for a particular situation. To assess costs and carbon
dioxide (CO2) savings with CCS, we need to compare to a reference fossil
energy system without CCS. The modeller also needs to specify the system
boundaries for the particular analysis, the technology status (e.g., is the
27
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Developments and innovation in CCS technology
system based on current or advanced technology, are costs projected for
the nth plant?), economic and feedstock cost assumptions (the engineering/
economic model is embedded in a larger context of energy and policy), and
policy constraints such as carbon taxes.
These issues are illustrated through a simplified diagram of a ‘generic’
fossil energy system with carbon capture and storage (Fig. 2.1). Most
studies consider the total system as three ‘components’, (i) CO2 capture
from a source such as a fossil energy plant or industrial complex, (ii) CO 2
transport from the source to a sequestration site, and (iii) the CO2 storage
site itself (e.g., an underground deep saline aquifer, a depleted oil field, or a
deep unmineable coal formation). We have sketched a fourth ‘component’,
the energy demand. Clearly, the characteristics of the demand (the type of
energy carriers needed, the scale, location, and time dependence of demand)
determine what is required from a fossil energy system with CCS. Moreover,
fossil power plants with CCS are part of a larger energy system, which must
be considered in economic evaluation of scenarios for CCS deployment.
The design of each part of the system depends on a host of factors, some of
which are shown in italics. The size and location of the different components
of the system depend on regional factors such as the proximity of energy
supply to good sequestration sites, and costs depend on local energy prices
(for example, the price of natural gas versus coal). System models can be
either static or time dependent, generic or geographically specific.
Several metrics are commonly used for assessing the economics of fossil
energy systems with CCS (IPCC, 2005), relative to a reference case without
CCS. First is the capital cost of the system. Second is the levelized cost of
energy (for example $/kWh of electricity), which includes the time value of
money, and all fixed and variable operating costs. Third is the cost of CO2
in $/tonne of CO2 captured, or $/tCO2 emissions avoided.
Various levels of modeling can be used to understand the performance and
economics of the whole system. These are loosely grouped as ‘component
level engineering/economic models’, ‘system level engineering/economic/
spatial models,’ and ‘macro-economic and integrated assessment models’.
Most engineering/economic modeling studies to date focus on one component
such as the fossil energy conversion plant, the CO2 transport system or the
underground CO2 storage site. Table 2.1 shows the types of inputs and
outputs and modeling tools used in component models for different parts of
the system. These are described in detail in later sections of this chapter.
Some studies combine one or more components into system level
engineering/economic/spatial models. Most focus on either the fossil energy
complex or the CO2 transport and storage infrastructure (Hendriks, 1994;
Ogden, 2003; Herzog, 2006; McCoy, 2008). These models allow sensitivity
studies to understand the major costs at the system level. They also enable
use of geographic specific data for realistic regional case studies. With
© Woodhead Publishing Limited, 2010
Fossil energy complex
Fossil feedstock
(coal, NG,
petroleum,
coke, etc.)
CO2 transport
Distance, geography
Energy demand
Electricity and fuel
energy demands; end-use
technologies; geographic
layout and time dependence
of demand; fuel storage and
delivery system
Distance,
geography
CO2 sequestration site
Well depth; reservoir characteristics
(e.g., permeability, thickness, pressure,
temperature, capacity)
Recovered oil
or gas in the
case of EOR,
EGR, or ECBM
29
2.1 Fossil energy system with carbon capture and sequestration. Key variables are shown in italics.
Techno-economic analysis and modeling
© Woodhead Publishing Limited, 2010
Plant design, scale, cost, energy
efficiency, and capture efficiency;
product mix (e.g., electricity,
H2, liquid fuels); pressure,
temperature, and purity of CO2
Electricity, H2, liquid
fuel transport
30
Developments and innovation in CCS technology
Table 2.1 Component level engineering/economic models
Fossil energy plant w/CCS (Section 2.2)
Inputs: Plant type (post-combustion capture, pre-combustion capture, oxyfuel
combustion, capture technology type, new or retrofit); feedstock (coal, natural gas,
pet coke, biomass mix); plant capacity; technology status (current or advanced;
first plant or nth plant); equipment performance and costs; output product mix
(electricity, hydrogen, liquid fuels); CO2 capture rate; plant equipment selection
(e.g. type of capture system).
Model type: Process simulation for steady-state mass and energy flows (ASPEN,
HYSYS); specialized models for particular equipment; equipment cost and
performance, models based on existing supplier costs and projections for future
technology.
Outputs: Plant process flow diagram with mass and energy flows; feedstock and
energy inputs, product outputs; plant energy conversion efficiency; rate of CO2
capture; overall plant capital and operating cost as a function of scale; capital cost,
cost of carbon capture $/tonne CO2, cost of energy $/kWh electricity or $/GJ fuel.
CO2 transport (section 2.3)
Inputs: Transport mode (pipeline, ship, truck); CO2 flow rate; CO2 pressure, purity,
temperature; distance to sequestration site; pipeline costs per meter of length for
various diameters.
Model type: Pipeline fluid flow models that find CO2 flow rate as a function of
pressure (inlet and outlet), pipeline diameter and length. Cost models based on
existing pipeline costs and projections for future technology.
Outputs: Pipeline diameter, capital cost, booster compressor requirements, capital
and operating cost as a function of scale, levelized cost of transport $/tonne CO 2.
CO2 storage (section 2.4)
Inputs: CO2 flow rate; CO2 pressure, purity, temperature; sequestration site
reservoir characteristics (type of reservoir, pressure, permeability, layer thickness,
depth; storage capacity); injection well characteristics (depth, pipe diameter).
Model type: Model for diffusion of injected CO2 in porous media. For wells:
pipeline fluid flow models that find CO2 flow rate as a function of pressure (inlet
and outlet), pipeline diameter and length and well depth. Cost models based on
existing CO2 injection well costs and projections for future technology.
Outputs: Number of wells, well spacing, piping, and other sequestration site
equipment; capital and operating costs for wells and injection site. Levelized cost
of storage $/tonne CO2.
the increasing availability of geographic information system data, it has
become possible to do geographic specific case studies of fossil energy
systems with CCS (Herzog, 2006; Johnson and Ogden, 2008; Johnson et
al., 2008; Middleton and Bielicki, 2009). Existing CO2 sources and power
plant locations, sequestration sites, and potential pipeline locations can be
identified for a given region. The model develops an optimized design for
CO2 pipelines to connect sources of CO2 and storage sites. Most technoeconomic system models are static, and assume a fixed demand. However,
several scenarios for building up regional CCS-based systems over time
have been developed (Kuuskraa, 2007; IEA, 2008; Johnson et al., 2008).
The costs for making a multi-decade transition to a fossil energy system
with CCS can be estimated.
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Techno-economic analysis and modeling
31
Finally, models of CCS systems have been incorporated into larger models of
the energy economy such as MARKAL or NEMS or into integrated assessment
models such as MESSAGE. In these models, various energy supply options
compete to supply specified demands for energy services such as lighting,
cooling, and vehicle miles travelled. These models yield insight into the
potential role of fossil energy systems with CCS under different technology
assumptions or policy constraints. The next three sections deal with modeling
components, as a basis for discussing integrated system models.
2.2
Carbon dioxide (CO2) capture
There are a variety of options for capturing CO2 from fossil energy plants.
These are classified as post-combustion, oxyfuel combustion, and precombustion decarbonization (Fig. 2.2). Post-combustion capture involves
separation of CO2 from combustion flue gases and is appropriate for retrofits
to existing fossil energy plants. In oxyfuel combustion, the fuel is burned in
pure oxygen, allowing ready capture of CO2. Pre-combustion capture involves
a gasification or reforming stage to produce a syngas, with subsequent
processing to allow capture of a pure stream of CO2. As shown in Fig. 2.3,
pre-combustion decarbonization adds flexibility, as a variety of products
can be made including electricity and fuels such as hydrogen, syngas, SNG
(synthetic natural gas), or methanol.
N 2, O 2, H 2O
Post-combustion capture
Flue gas
Fuel
Air
CO2 separation
Power and heat
CO2
Pre-combustion capture
Fuel
CO2
Gasification or
partial oxidation
shift + CO2
separation
H2
Air
Power and heat
N 2, O 2, H 2O
O2
Air
Air separation
CO2
compression,
transport, and
storage
N2
Oxyfuel combustion capture
Fuel
O2
Air
CO2(H2O)
Power and heat
Air separation
Recycle (CO2, H2O)
N2
2.2 CO2 capture processes (IPCC, 2005).
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Developments and innovation in CCS technology
Flexibility for
alternative
products
Natural gas
Coal
Biomass
Waste
CO2
Gasifier,
reformer
Gas
treatment
CO2
capture
CCGT
Alternatives or
additionalities
Electricity
Heat
H2
Synthesis gas
(CO + H2)
SNG
Methanol
Motor fuels
2.3 Pre-combustion capture options (CCGT = combined cycle gas
turbine) (IEA, 2008).
2.2.1
Plant level modeling
First, we define the system boundaries and the plant configuration. To assess
the incremental cost of implementing CO2 capture, we also specify a reference
case fossil energy plant without CO2 capture. Then process simulation
software such as ASPEN or HYSYS is used to estimate steady-state mass
and energy balances for the fossil energy plant. The process model sizes
and characterizes all the equipment that is needed in the plant, and energy
and material inputs and outputs. This forms the basis for estimating plant
capital and operation costs, energy conversion efficiency or heat rate, and
plant product mix. Generally, CO2 capture involves both extra capital costs
and additional energy use, for example, for CO2 compression. Table 2.2
shows results from a recent review paper by the IEA (2008) that estimates
the conversion efficiency for fossil power plants with and without CCS.
2.2.2
Economics of fossil energy plants with CO2
capture
The main economic metrics used to assess fossil energy systems with CO2
capture are the plant capital investment cost given in $ or $/kW, the cost of
electricity (or electricity and fuels), the avoided cost of carbon in $/tonne
CO2, and the capture cost for carbon in $/tonne CO2.
Plant capital investment cost
Once the plant mass and energy flows have been determined, and plant
equipment is sized, the total capital investment can be found. Plant investment
cost is typically given in $/kW.
Technology maturity is an important consideration in estimating plant
capital costs. For current CO2 capture technologies, costs are moderately well
© Woodhead Publishing Limited, 2010
Table 2.2 Characteristics of electric power plants with and without CO2 capture (IEA, 2008)
Efficiency (LHV %)
Electricity cost ($/MWh)
Technology
Start
CO2 capture
rate (%)
With CO2
capture
No CO2
capture
With CO2
capture
No CO2
capture
With CO2
capture
Reference plant
(no CO2 capture)
Coal steam
cycle
Coal steam
cycle, oxyfuel
Coal IGCC,
Selexol1
Biomass IGCC
Gas, CC,
California
Gas CC oxyfuel
85
85
90
90
85
85
85
85
85
95
2250–3200
1850–2500
2500–3100
2100–2600
2300–2800
1800–2400
2600–3000
1000–1200
800–1000
1250–1400
1500–2200
1300–2000
1900–2400
1500–2100
1600–2300
1300–2000
1900–2400
660–750
550–650
700–850
38
44
37
44
35
48
26
49
56
48
47
52
47
52
44
54
34
57
63
58
74–83
59–68
77–87
60–69
76–86
58–65
110–130
59–88
49–75
51–79
39
27–29
41–44
28–31
40–41
26
64–73
33–59
30–53
30–53
2010
2030
2020
2030
2010
2030
2025
2010
2030
2020
CC = combined cycle; IGCC = integrated gasification combined cycle.
TM Dow Chemical Company.
1
Techno-economic analysis and modeling
© Woodhead Publishing Limited, 2010
Investment costs ($/kW)
33
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Developments and innovation in CCS technology
known, because many of the processes such as gasification, reforming, and
CO2 compression are used commercially. However, for advanced or future
CO2 capture technologies, costs are more uncertain and projections must be
made. Here it is important to specify whether the advanced technology plant
is assumed to be the first of kind or the ‘nth’ plant (assuming the advanced
technology has been built many times and has met its goals). Technology
learning curves have been employed in some analyses to assess the transition
costs for bringing advanced CO2 capture technology from the first plant to
maturity (Kuuskraa, 2007; IEA, 2008).
The conventions for estimating the plant investment cost are not completely
consistent among studies in the literature. Indirect costs for installation, site
preparation, engineering, project contingency, and interest during construction,
are not always added to the equipment costs. Recent studies by the IPCC
(2005) and the IEA (2008) attempted to adjust for these differences to put
estimates from the literature on a consistent basis. Table 2.2 illustrates the
investment costs for a variety of coal power plant options with and without
CO2 capture in the 300–1000 MWe range (IEA, 2008). CO2 capture adds
40–100 % to the plant capital cost.
Cost of electricity
A second important metric is the cost of electricity from a fossil energy plant
with CO2 capture, as compared to the cost of electricity for a similar type of
plant without capture. The levelized cost of electricity (COE) is estimated
for a power plant as follows:
COE ($/kWh) =
(CRF*Ccap + COMf + COMv + Cfeed – CRco )
[2.1]
CO2 * CO2 )
where CRF is the capital recovery factor, Ccap is the total capital) investment
cost ($), COMf is the annual fixed operation
and*8760)
maintenance (O&M) cost ($/
(CF*Cap
year), COMv is the annual+variable
O&M
cost
excluding
feedstock ($/year),
(Tax
Cfeed is the annual feedstock cost ($/year) (e.g., coal, natural gas, biomass),
CRco is the annual credit for co-products ($/year) (e.g., fuels), CF is the annual
average plant capacity factor (%), Cap is the plant capacity (kW), 8760 is
the number of hours in one year, TaxCO2 is the carbon tax, if applicable ($/
x
E rate of the plant (tCO2/kWh). The
tCO2), and ECO2 is the CO2 emissions
feedstock cost per kWh of electrical output can be expressed as the product
of the plant heat rate (kJ feed/kWh electricity) and the price of feedstock ($/
kJ). The variable O&M costs depend on required energy inputs and the prices
of these inputs. The fixed O&M costs are often expressed as a fraction of the
total plant capital cost, typically 3–5 % of the capital cost per year.
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Techno-economic analysis and modeling
35
The cost of electricity with and without CO2 capture is estimated in Table
2.2, based on studies by the IEA (2008) for current and future technologies.
The efficiency is generally lower for power plants with CO2 capture and
capital costs are higher, yielding an electricity cost premium of 2–6 cents/
kWh or 40–100 %.
Avoided cost of CO2 emissions
To compare carbon capture with other options for reducing carbon emissions,
it is useful to estimate the avoided cost of CO2 emissions. For electricity
plants, this is defined as the difference in the electricity cost per kWh divided
by the difference in CO2 emissions per kWh compared to a reference system
without CO2 capture (IPCC, 2005):
LCavoided =
(COEcapture – COEref )
)
(ECO2ref – ECO2c
[2.2]
capture
where LCavoided is the levelized cost of avoided CO2 emissions ($/tCO2
avoided), COEcapture is the cost of electricity for the plant with capture ($/
kWh), COEref is the cost of electricity for a reference plant without capture
($/kWh), ECO2ref is the CO2 emissions rate of the reference plant (tCO2/kWh),
and ECO2capture is the CO2 emissions rate of the capture plant (tCO2/kWh).
Cost of CO2 capture
A similar metric is the cost of CO2 capture, also in $/tCO2. This is useful
for comparing to the market price of CO2, for example, for enhanced oil
recovery:
LCcapture =
(COEcapture – COEref )
CO2 capture
[2.3]
where LCcapture is the levelized cost of captured CO2 emissions ($/tCO2)
and CO2capture is the quantity of CO2 captured at the plant (tCO2/kWh). The
cost of captured CO2 is always less than the avoided cost of CO2 emissions
because the energy required to operate the CO2 capture system adds to the
amount of CO2 emitted per kWh. Table 2.3 summarizes the emissions rates
and costs for power plants with and without CO2 capture (IPCC, 2005).
2.2.3
Production of hydrogen and other fuels with CO2
capture
Although much of the emphasis is on CO2 capture at fossil fuel electric
power plants, pre-combustion decarbonization opens the possibility of making
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Developments and innovation in CCS technology
Table 2.3 Emissions rates and costs associated with power plants with and without
CO2 capture (IPCC, 2005)
CO2 emissions
rate (kgCO2/MWh)
Electricity
cost ($/MWh)
Technology
With CO2 No CO2 With CO2 No CO2 Cost of
Cost of
capture
capture capture capture captured CO2 avoided CO2
($/tonne CO2) ($/tonne CO2)
Coal PC plant 92–145
NGCC
40–66
Coal IGCC
65–152
736–811 62–86
344–379 43–72
682–846 54–79
43–52
31–50
41–61
23–35
33–57
11–32
29–51
37–74
13–37
IGCC = integrated combined cycle; NGCC = natural gas combined cycle; PC =
pulverized coal.
hydrogen or other syngas-derived fuels from fossil resources with CO2
capture (Fig. 2.3). CO2 capture adds perhaps 20 % to the cost of producing
hydrogen from coal (Ogden, 2003).
2.2.4
Cost of electricity: sensitivity to the value of
carbon
In the previous sections we presented results for the cost of electricity for
fossil power systems with and without CO2 capture. In general, the cost of
electricity is higher with CO2 capture, but carbon emissions are reduced
by over 80 %. Figure 2.4 shows how the costs of electricity compare at
different valuations of carbon (e.g., through a carbon tax). Plants with CCS
are preferred for carbon taxes in the range of $40–70/tCO 2.
2.3
Carbon dioxide (CO2) transport
This section describes the economics of transporting CO2 from the point of
capture at large-scale industrial point sources to onshore or offshore storage
sites. Three options are possible for transporting CO2: tanker trucks (onshore),
pipelines (onshore and offshore), and ships (offshore). Tanker trucks have
been deemed impractical for transporting the enormous quantities of CO 2
produced by large-scale industrial point sources. Consequently, this section
focuses on the economics of pipeline transport for onshore applications and
pipeline and ship transport for offshore applications.
Onshore pipeline transport is a proven technology with approximately
2400 km of large CO2 pipelines in operation globally (Gale and Davison,
2004; Zhang et al., 2006). The majority of these pipelines are used to supply
enhanced oil recovery operations in the USA. Several studies identify pipeline
transport as the most economical method for moving large volumes of CO2
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Techno-economic analysis and modeling
37
0.25
Cost of electricity ($/kWh)
0.2
NGCC with CO2 capture
NGCC no capture
PC plant no capture
PC plant w/CO2 capture
IGCC plant no capture
IGCC plant w/CO2 capture
0.15
0.1
0.05
0
0
25
50
Carbon tax ($/tonne CO2)
75
100
2.4 Cost of electricity from fossil power plants (c. 2010 technology)
for different values of carbon tax.
overland (Svensson et al., 2004; Doctor et al., 2005). Pipeline transport has
also been identified as the most economical method for offshore transport of
CO2 for distances less than 500–1000 km (Bock et al., 2003; Doctor et al.,
2005; Wildenborg et al., 2005). For longer distances, ship transport may be
preferable.
2.3.1
Pipeline transport
The cost of pipeline transport is affected by the characteristics of both the
pipeline route and the pipeline itself. Elements of the route that can impact
cost include both the physical geography (e.g., river and road crossings,
parks, terrain) and social geography (e.g. population density, regional labor
and land costs, local acceptance) (Hendriks et al., 2003). In addition, pipeline
characteristics, such as length, diameter, materials, the number of bends, and
the need for booster stations, are important determinants of cost.
Pipeline design
Fluid flow models that use hydraulic equations for turbulent flow (Woodhill
Engineering Consultants, 2002; Bock et al., 2003; Hendriks et al., 2003;
Ogden et al., 2004; McCoy and Rubin, 2008; Vandeginste and Piessens,
2008) are useful in estimating pipe diameter since they include the parameters
relevant to pipeline design (i.e., inlet and outlet pressures, pipeline length,
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Developments and innovation in CCS technology
CO2 mass flow rate, pipeline roughness factor, elevation change along the
segment, and CO2 density, viscosity, and average temperature) and are
thus flexible in their application. There are practical constraints on pipeline
operating conditions. To avoid two-phase flow, CO2 should be transported
in the supercritical phase, which occurs at a pressure greater than 7.38 MPa
(Skovholt, 1993). It is recommended that it is transported at pressures greater
than 8.6 MPa where changes in compressibility can be avoided at a range
of temperatures used for pipeline operation. Table 2.4 lists common design
parameters for CO2 pipeline transport.
Since pipelines are not available in continuous diameters, the pipeline
diameter used for a particular project is constrained by the available discrete
sizes, or nominal pipe size (NPS). The NPS generally corresponds to the
external diameter in inches of commercially available pipelines (McCoy
and Rubin, 2008). In some cases, it may be economically advantageous to
design the pipeline with booster compressor stations every 150–300 km. If
CO2 is recompressed at intervals, this allows use of smaller diameter, lower
cost pipelines. However, there is a trade-off between lower pipe costs and
the added costs of compression. These issues are discussed in Zhang et al.
(2006), McCoy (2008), and Bock et al. (2003).
Comparison of actual and calculated pipeline diameters
The capacity, length, elevation difference, and actual diameter of several
existing CO2 pipelines are known (Table 2.5) (Vandeginste and Piessens,
2008). Using this information, it is possible to compare the actual diameters
with those calculated from the pipeline models provided by McCoy and
Rubin (2008) and Vandeginste and Piessens (2008). Table 2.5 indicates
that both models accurately estimate the diameters of the existing CO 2
pipelines.
Table 2.4 Common design parameters for pipeline transport (Bock et al.,
2003)
Parameter
Value
Units
Inlet pressure
Minimum outlet pressure
Average CO2 temperature
Average CO2 density
Average CO2 viscosity
Pipeline roughness factor
Pipeline capacity factor
CO2 purity in pipeline
Change in elevation
15.2
10.3
25
884
6.06 ¥ 10–5
4.57 ¥ 10–5
100
100
0
MPa
MPa
°C
kg/m3
N–s/m2
meters
%
%
meters
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
39
Table 2.5 Comparison between actual and calculated pipeline diameter for existing
CO2 pipelines
Pipeline
Capacity Length Elevation Actual NPS McCoy NPS Vandeginste
(Mt/year) (km)
difference diameter
diameter
NPS
(m)1
(in)
(in)
diameter (in)
Transpetco
Sheep
Mountain
part 1
Sheep
Mountain
part 2
Bravo
Weyburn
3.4
6.4
193
296
1094
893
12.6
20
12
18
14
18
9.3
360
464
24
24
24
7.4
1.8
351
330
955
46
20
14
20
14
20
14
1
Elevation difference represents a decrease in the elevation between the start and
end points of the pipeline.
Note: For the calculated values, the flow rate (capacity), length, and elevation
change given in the table for each specific pipeline are used. The inputs listed in
Table 2.4 are used for the unknown parameters.
Offshore pipeline design
Woodhill Engineering Consultants (2002), Dahowski et al. (2005), and
Bock et al. (2003) examine offshore CO2 pipeline design and cost and note
two significant differences between onshore and offshore pipeline design.
First, booster stations are impractical for offshore pipelines so long offshore
pipelines may require larger diameters than equivalent onshore pipelines in
order to maintain pipeline pressure. Second, in designing offshore pipelines
one must consider not only the change in pressure between the inlet and
outlet, but also the gravity head gain due to the large decrease in elevation
from the shore to the outlet at –2000 to –3000 m. Hence, the allowable
pressure drop is much greater for offshore pipelines, which may reduce the
diameter required for these pipelines.
Pipeline cost
For onshore CO2 pipelines, the costs include capital costs (engineering,
installation, and materials) and operations and maintenance (O&M) costs
(monitoring, inspection, and repair). If booster stations are required, additional
capital costs and O&M costs are incurred. The energy cost for operating the
booster pump or compressor can be a significant annual expense.
Onshore pipeline capital costs
We surveyed several studies that estimate onshore CO2 pipeline capital
costs, including (Woodhill Engineering Consultants, 2002; Bock et al., 2003;
© Woodhead Publishing Limited, 2010
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Developments and innovation in CCS technology
Hendriks et al., 2003; Parker, 2004; McCoy and Rubin, 2008). Based on
these studies, average pipeline capital cost functions were developed for six
discrete pipeline lengths from 50–500 km and several nominal pipe sizes
from 4–30 inches. These functions were used to derive Equation 2.4 for
calculating pipeline capital cost as a function of pipeline NPS and length:
C = 32.086L–0.033D
[2.4]
where C is the capital cost (2005$/m), L is the pipeline length (km), and D
is the nominal pipe size (in). The capital cost per meter shows very little
dependence on overall pipeline length L and is approximately linear in D.
Capital cost estimates given by Equation 2.4 represent average CO2
pipeline construction costs in the USA. Several project-specific factors
can influence the actual cost of construction, including population density,
physical terrain, regional location, and river and road crossings. In particular,
regional cost variations in the USA can exceed 30 % (McCoy and Rubin,
2008) and construction in urban areas or rocky, marshy, or mountainous
terrain can significantly increase the installation cost. Another issue that
can affect estimates of construction costs is the observed rapid escalation
of the costs of the labor and materials required for building pipelines over
the past few years. An equipment cost index (e.g. Marshall and Swift) that
accounts for this escalation should be used to adjust costs of older studies.
The literature provides a range of fixed O&M costs for onshore pipelines
between 0.5 and 4 % of the total capital cost with an average of 2.2 %. The
levelized cost of onshore pipeline transport ($/tCO2 transported) is shown in
Fig. 2.5 as a function of CO2 flow rate and pipeline length. The cost of CO2
transport scales approximately linearly with the pipeline length and shows
strong scale economies with flow rate, varying approximately as the flow
rate to the –0.6 power. For a 100 km pipeline, the levelized cost is between
$1 and $2.50/tCO2 for plants producing > 5000 tCO2 per day. The levelized
cost increases substantially for longer pipelines, but is still between $4 and
$10/tCO2 for a 500 km pipeline transporting >5000 tCO2/day. Because the
technology associated with onshore pipeline transport is mature, costs are
not expected to benefit from technological learning in the future.
Offshore pipeline capital costs
Several studies estimate offshore pipeline costs for scenarios in which CO2
is injected directly into the ocean at depths exceeding 2000 m (Sarv, 2001;
Woodhill Engineering Consultants, 2002; Bock et al., 2003; Doctor et al.,
2005). Fig. 2.6 compares the levelized cost of onshore and offshore pipelines
for a transport distance of 500 km. Total offshore costs are 2.3–2.6 times
larger than equivalent onshore costs.
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
35.00
100 km
41
500 km
Pipeline levelized cost ($/tonne CO2)
30.00
25.00
20.00
15.00
10.00
5.00
0.00
0
5000
10 000
15 000
20 000
CO2 mass flow rate (tonnes/day)
25 000
30 000
2.5 Levelized cost for onshore pipeline transport.
Levelized cost ($/tonne CO2)
40.00
Offshore
35.00
Onshore
30.00
25.00
20.00
15.00
10.00
0.00
0.00
0
5000
10 000
15 000
20 000
25 000
CO2 mass flow rate (tonnes/day)
30 000
35 000
2.6 Comparison of onshore and offshore pipeline costs for a 500 km
transport distance.
2.3.2
Ship transport
Presently, there are only four ships worldwide that operate specifically for CO2
transport. These ships are small-scale vessels used primarily for distributing
food-grade CO2 with capacities between 1000 and 1500 m3 (Aspelund et al.,
2006). In order to handle the large quantities of CO2 associated with CCS,
much larger vessels would be required. As these vessels do not currently
exist, cost estimates are largely based on existing LPG ships that operate
© Woodhead Publishing Limited, 2010
42
Developments and innovation in CCS technology
under similar conditions to those required for CO2 transport (Aspelund et
al., 2006). The processes involved in ship transport include liquefaction,
intermediate storage, loading, ship transport, and unloading at either an
onshore port or an offshore injection platform.
Transport system design
Several studies examine the cost of CO2 transport by ship (Sarv, 2001; Bock
et al., 2003; Svensson et al., 2004; Doctor et al., 2005; Aspelund et al.,
2006). We follow the discussion in Aspelund et al. (2006) which includes
a detailed description of each system component and, thus, provides a good
template for system design. Prior to ship transport, CO2 is compressed, dried,
cleaned of unwanted components, and liquefied. Liquid CO2 is then stored in
either caverns or semi-pressurized steel tanks and a loading system transfers
CO2 from storage to the ship and includes piping, a marine loading arm,
pumps, and an export building. The ship then transports CO2 to an offshore
injection platform, where it is unloaded. Offshore unloading of a cryogenic
liquid has not been performed for any previous process, but Aspelund et
al. (2006) describes a novel technology for this system, which includes
a submerged turret loading system, piping, and pumping, expansion, and
heating systems. It is assumed that CO2 will be injected in batches while
the ship is connected to the platform.
Ship transport costs
Given the number of liquefiers, storage tanks, ships, and loading and unloading
systems, the capital and O&M costs for a particular project can be identified.
Cost estimates are listed in Table 2.6. Figure 2.7 shows the calculated levelized
cost of ship transport for CO2 mass flow rates from 4000–30 000 tonnes/day
(1.5–11 Mt/year) given the reference parameters in Table 2.6. In this case,
the levelized cost of ship transport is $22–43/tCO2. Liquefaction accounts
for the largest portion of the total transport cost (50–64 %) and the cost does
not decline with scale since the liquefier capacity in this case is fixed and the
variable cost of electricity is significant. In fact, liquefaction accounts for
~88 % of total energy use in the transport chain and ~93 % of the total cost
of energy. Consequently, any reduction in this cost can significantly decrease
the cost of transport. Aspelund et al. (2006) discusses several methods for
reducing the energy requirement for liquefaction, including increasing the
inlet pressure and decreasing the impurities in the feed.
Storage, loading, and unloading system costs benefit from economies of
scale since these systems are better utilized as the CO2 flow rate increases.
Ship costs account for 17–23 % of total costs and exhibit cost spikes when
additional ships are required.
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
43
Table 2.6 Reference parameters for cost analysis (Bock et al., 2003; Svensson et al.,
2004; Doctor et al., 2005; Aspelund et al., 2006)
Parameter
Value
Offshore distance
Electricity price
Bunker oil price
Natural gas price
500
0.05
309
8
Units
km
$/kWh
$/tonne oil
$/GJ
Capital costs
50
Liquifier (1 Mt CO2/year)
Steel storage tank (3000 m3)
10
Loading system
50
Semi-refrigerated ship (20 000 m3)
54
Unloading system
60
Million $
Million $
Million $
Million $
Million $
O&M costs
Non-fuel O&M for ships
4.7
Non-energy O&M for other components
2
Liquefier energy use
110
Loading energy use
0.2
Ship energy use
0.6
Unloading energy use
0.65
Harbor tax
40 000
% of capital
% of capital
kWh/t CO2
kWh/t CO2
tonnes oil/hr
kWh/t CO2
$
50.00
Liquefaction
45.00
Storage
Loading
Levelized cost ($/tonne CO2)
40.00
Unloading
35.00
Tanker ships
30.00
25.00
20.00
15.00
10.00
5.00
0.00
4000
6000
8000 10 000 12 000 14 000 16 000 18 000 20 000 25 000 30 000
CO2 mass flow rate (tonnes/day)
2.7 Levelized cost of ship transport.
2.3.3
Comparison of pipeline and ship transport costs for
offshore injection
When transporting CO2 to offshore injection sites, studies indicate that pipelines
are less expensive than ships at distances less than 500–1000 km (Sarv,
© Woodhead Publishing Limited, 2010
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Developments and innovation in CCS technology
1999; Bock et al., 2003; Doctor et al., 2005). Based on the cost estimates
in this chapter, ship transport becomes more economical than pipelines at
distances greater than 750 km (Fig. 2.8). Since pipeline transport benefits
from economies of scale more than ship transport, the breakeven distance
is expected to shift to longer distances as the CO2 mass flow rate increases.
However, since booster compression is difficult with offshore pipelines, the
maximum length of these pipelines may be limited. Given that early offshore
CCS projects will likely be sited in preferred sites near shore, pipelines are
likely to be the preferred mode of transport in the near term unless ship
transport costs can be significantly reduced. Ship transport may be favored
for long-distance transport (> 500 km) and in cases where the location of
injection sites changes and flexibility in routing is required.
2.4
Carbon dioxide (CO2) injection
This section describes the economics of injecting CO2 into geologic reservoirs
for long-term storage. CO2 can be injected for ‘storage-only’ into deep saline
aquifers or depleted oil and gas reservoirs or it can be used to enhance recovery
of valuable fossil fuels, such as oil, natural gas, and coalbed methane. This
section begins with an overview of models for injection site infrastructure
requirements and then discusses the costs of the various components for
each reservoir type.
120.00
Ship transport
Offshore pipeline
Levelized cost ($/tonne CO2)
100.00
80.00
60.00
40.00
20.00
0.00
0
200
400
600
800
1000 1200
1400
Offshore distance (km)
1600
1800
2.8 Comparison of pipeline and ship costs at various offshore
distances (8000 tCO2/day).
© Woodhead Publishing Limited, 2010
2000
Techno-economic analysis and modeling
2.4.1
45
Injection site design
To estimate the cost of CO2 injection, it is necessary to calculate the required
number of injection wells and the extent of the underground CO2 plume.
The number of injection wells can be derived from the maximum injection
rate per well, which is dependent on the specific characteristics of a target
reservoir (e.g., permeability, porosity, pressure, and thickness). Ahmed (2006)
provides a detailed review of the reservoir fluid flow equations that can be
used to model CO2 injection rates. These equations address steady-state,
pseudo-steady-state, and transient (unsteady-state) flow regimes (Ahmed,
2006).
Several studies use the steady-state equation for radial flow of an
incompressible fluid to model the maximum injection rate from a single
well into a reservoir (Hendriks, 1994; Ogden et al., 2004; Middleton and
Bielicki, 2009):
qwell =
2p kh(pe – pw )
r
m ÈÍln e ˘˙
r
Î w˚
[2.5]
where qwell is the injection rate (m3/s), k is the absolute permeability (m2), h
is the reservoir thickness (m), re is the radius of influence of the well (m), pe
is the pressure at re and is commonly the initial reservoir pressure (Pa), pw
is the bottomhole injection pressure (BHIP) (Pa), rw is the wellbore radius
(m), and m is the viscosity of CO2 at reservoir pressure and temperature
(Pa–s). This steady-state model makes the simplifying assumption that
flow is constant throughout the reservoir and that pressure at every location
in the reservoir remains constant in time. McCoy (2008) has extended the
steady-state model to include the effects of multiple wells and finds that
injectivity decreases as the number of wells at a site increases. Consequently,
the maximum injection rate of a well is likely to be smaller than predicted
by models that don’t consider the effects of neighbouring wells.
The maximum extent of the underground CO2 plume over the life of the
project is important since it provides the radius of influence (re) used in
calculating the injection rate and also identifies the area of influence used to
identify site characterization costs. Various studies have developed models
for calculating plume radius for different reservoir types (Hendriks, 1994;
Bock et al., 2003; Nordbotten et al., 2005; McCoy, 2008).
2.4.2
Carbon dioxide (CO2) injection for storage only
Two geologic reservoir types are commonly considered for long-term storage
of CO2 without enhanced recovery: deep saline aquifers and depleted gas
reservoirs. A typical CO2 injection site includes injection wells and surface
© Woodhead Publishing Limited, 2010
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Developments and innovation in CCS technology
equipment (e.g., distribution pipelines and headers). In some cases, compressors
or pumps may be required to achieve the required wellhead injection pressure
at each well. Costs include well drilling, surface equipment, permitting, and
site characterization.
Deep saline aquifers
Given reservoir and injection parameters, flow equations can be used to
determine the maximum plume radius and maximum injection rate for a target
aquifer. Table 2.7 provides parameters for two representative saline aquifers
and lists the calculated plume radius and injection rate for each aquifer. The
injection rate is highly sensitive to changes in certain reservoir parameters like
permeability and thickness and can range from tens to thousands of tonnes
CO2 per day. Several studies limit the injection rate per well to 2500–3400
t/day (Hendriks et al., 2004; Ogden et al., 2004; McCoy, 2008).
Site characterization costs
Given the injection rate and plume radius, the number of required injection
wells and area of the CO2 plume (or ‘area of review’) can be calculated. Site
characterization costs include 3-D seismic imaging of the area of review,
drilling of characterization wells, and data processing and modeling services.
McCoy (2008) estimates these costs as $38 610/km2 for 3-D imaging,
$3 000 000 per well for drilling of characterization wells, and 30 % of the
total cost for data processing, modeling, and other services. One well is
required for every 65 km2 of the area of review. Equation 2.6 describes
Table 2.7 Common aquifer and injection parameters (Nordbotten et al., 2005;
Stauffer et al., 2009)
Input parameter
Cold/shallow
Hot/deep
Units
Wellhead injection pressure
Reservoir pressure (pe)
Maximum BHIP (pw)
Reservoir temperature
Reservoir CO2 viscosity (m)
Reservoir CO2 density (r)
Reservoir depth (d)
Reservoir thickness (h)
Porosity (F)
Permeability (k)
10.3
10
15
35
5.77 ¥ 10-5
714
1000
30
0.15
1.97 ¥ 10–14
10.3
30
45
155
3.95 ¥ 10–5
479
3000
30
0.15
1.97 ¥ 10–14
MPa
MPa
MPa
°C
Pa–s
kg/m3
m
m
5.9
5300
km/well
tonnes/day/well
Calculated parameter
Plume radius (re) @ 20 years
4.8
Max injection rate (qwell)
1850
© Woodhead Publishing Limited, 2010
m2
Techno-economic analysis and modeling
47
the total site characterization cost (corrected to 2005$) as a function of the
area of review:
Csite = 117 344A + 2.70 ¥ 106
[2.6]
where A is the area of review (km2). In developing an aquifer site for CO2
injection, permitting studies must be conducted and land, mineral leases,
and permits must be purchased. The estimated average cost is approximately
$23 000 per well (Bock et al., 2003; Bank and Kuuskraa, 2006).
Well drilling costs
Well drilling costs include the costs of drilling and completing wells for
CO2 injection. Since limited data is available on the costs of drilling wells
specifically for CO2 injection, most studies assume that the costs will be
similar to those for drilling onshore oil wells in the USA (Bock et al., 2003;
McCoy, 2008; Eccles et al., 2009; Stauffer et al., 2009). Based on 2004 Joint
Association Survey (JAS) data, Equation 2.7 describes the well drilling cost
as a function of well depth (API, 2007):
Cdrill = (–3.9 ¥ 10–8d3 + 4.00 ¥ 10–4d2 – 0.84d + 903)d
[2.7]
where d is well depth (m) and Cdrill is the drilling cost (2005$/well). For
typical well depths of 1–3 km, the cost is $0.4–$2.7 million per well.
Surface equipment
Several studies assume that surface equipment costs for CO2 injection are
similar to the costs of equipping water injection wells for secondary oil
recovery (Bock et al., 2003; McCoy, 2008; Eccles et al., 2009). These
studies use data published by the Energy Information Administration (EIA,
2007) on lease equipment costs for secondary oil recovery in West Texas.
Equations 2.8 and 2.9 were developed from 2005 EIA data using the approach
employed by McCoy (2008):
Cequip = 0.0121d2 – 21.745d + 53 818
[2.8]
[2.9]
ÈCequip, N wells > 20
Í
0.5
Cequip,N = Í
Ê 21 ˆ
C
ÍÎ equip ÁË N wells ˜¯ , N wells ≤ 20
where Cequip is the surface equipment cost (2005$/well).
O&M costs include normal daily expenses, surface maintenance, and
subsurface maintenance and are derived from EIA (2007) data for secondary
oil recovery:
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Developments and innovation in CCS technology
COM = 8.76d + 13 267
[2.10]
where COM is the O&M Cost (2005$/well/year). McCoy (2008) reports the
monitoring cost to be ~$0.02/tCO2 injected.
Assuming a project life of 20 years and capital recovery factor (CRF) of
11.75 %, the levelized cost of CO2 injection can be calculated. Figure 2.9
shows the levelized cost for CO2 injection into a cold/shallow aquifer for
several annual CO2 flow rates. The contribution of each cost component
to the overall cost is also shown. The most surprising finding is that site
characterization contributes ~90 % of the total levelized cost while drilling
costs contribute less than 7 %. In the hot/deep case, well drilling costs are
significantly larger so well drilling and site characterization costs account
for ~30 % and ~60 % of the total cost, respectively. The levelized cost of
CO2 injection varies from $1.70 to $2.90/tonne CO2 for the cold/shallow
case and from $1.40 to $3.30/tonne for the hot/deep case.
In both cases, site characterization costs are significant and consequently
methods to reduce these costs could substantially reduce the cost of CO2
injection. Two potential methods are targeting aquifers that generate smaller
plumes (e.g., thick reservoirs) and using sites that have been previously
characterized.
$3.50
Land, permitting, and mineral cost
O&M and monitoring cost
$3.00
Site characterization cost
Levelized cost ($/tonne CO2)
Injection equipment cost
Well drilling cost
$2.50
$2.00
$1.50
$1.00
$0.50
$0.00
1000
4000
8000
12 000
16 000
CO2 mass flow rate (tonnes/day)
20 000
30 000
2.9 Contribution of each cost component to the total levelized cost of
CO2 injection into a cold/shallow aquifer.
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
49
Depleted gas reservoirs
Most studies of CO2 injection into depleted gas reservoirs focus on type I
reservoirs, where natural gas is produced via pressure depletion (Oldenburg
et al., 2001, 2004; Bock et al., 2003; Zhang et al., 2007; Hughes, 2009).
These reservoirs are attractive because they are proven long-term geologic
traps for gas storage, have already been extensively characterized, and
have existing gas production infrastructure that may be converted for CO 2
injection. Unlike saline aquifers where only about 2 % of the pore space is
available for CO2 storage, 80–95 % of this space may be available in type
I reservoirs. This means that less reservoir volume is required for storing
a given amount of CO2. These reservoirs are also favored since they are
appropriate for enhanced gas recovery (EGR) (see Section 2.4.3).
Although depleted gas reservoirs have several advantages over saline
aquifers for CO2 storage, there are also some disadvantages. First, many
gas production wells have been drilled into these reservoirs and there is a
risk of leakage if the abandoned wells are not capped appropriately. Second,
pressures in depleted type I gas reservoirs are typically 2–5 MPa (Oldenburg
et al., 2001), which is significantly smaller than the projected bottom hole
CO2 injection pressure (15–35 MPa). Hughes (2009) examines techniques
for reducing BHIP, but concludes that a high-tech flow control device will
be required at the base of the tubing in order to maintain flow. The need for
this device could present a serious technical challenge to CO2 injection into
depleted gas reservoirs.
The equipment required for CO2 storage is almost identical for depleted
gas reservoirs and saline aquifers. The exception is the flow control devices
that will likely be required for the former. The characteristics of depleted gas
reservoirs fall within a large range and thus widely different injection rates
are possible (Bock et al., 2003; Oldenburg et al., 2004; Hughes, 2009). In
order to capture the impacts of different injection rates on cost, two injection
rates are modeled: 150 and 1500 tonnes per day. Based on these rates, the
number of injection wells is estimated and storage costs can be derived.
Storage costs in depleted gas fields differ from those in saline aquifers
since these sites have been previously characterized and developed for gas
production. Consequently, the permitting cost is reduced to ~$9000 per well
(Bank and Kuuskraa, 2006) and site characterization cost is eliminated.
Furthermore, it is assumed that existing gas production wells can be
converted to CO2 injection wells at one third of the cost of drilling new
wells (Oldenburg et al., 2004). However, new injection equipment must be
installed since existing gas distribution equipment may not be sufficient for
the quantities and pressures of supercritical CO2. Consequently, injection
equipment, O&M, and monitoring costs are consistent with injection into
aquifers (see p. 47). The cost of flow control devices is not known as this
technology has not yet been developed.
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Developments and innovation in CCS technology
The levelized costs for the two injection rates (150 and 1500 tonnes/day/
well) are estimated to be ~$1.40/tonne and ~$0.20/tonne CO2, respectively.
The smaller injection rate requires additional wells and thus has a much larger
cost. It is evident that the cost of CO2 storage in depleted gas reservoirs
is substantially lower than storage in saline aquifers because costly site
characterization is unnecessary and injection wells cost less since they are
converted from existing production wells. If new injection wells are drilled,
the levelized cost increases 50–60 % for both injection rates, but is still lower
than the cost for storage in saline aquifers.
2.4.3
Carbon dioxide (CO2) injection for enhanced fossil
fuel recovery
In some cases, CO2 injection can enhance the recovery of valuable fossil
fuels and thus generate revenue that can be used to offset the costs of CCS.
In this section, the costs associated with enhanced gas recovery (CO2–EGR),
enhanced oil recovery (CO2–EOR), and enhanced coalbed methane recovery
(CO2–ECBM) are reviewed. Although storage capacities associated with
these pathways are relatively small, they represent near-term opportunities
for reducing the cost of CCS while advancements in cost-effective capture
technologies are developed.
Site design
For enhanced fossil fuel recovery, the required number of production and
injection wells can be estimated using a ‘rule of thumb’ method described
in Bock et al. (2003) and given by Equation 2.11.
È(Q /eff )˘
N iwells = Í CO2
˙ (I : P )
Î qproduct ˚
[2.11]
where Niwells is the number of injection wells, QCO2 is the total design mass
flow rate of CO2 (scm CO2/day), eff is the CO2 effectiveness factor [scm
CO2/scm methane (CH4) or scm CO2/bbl oil], qproduct is the average gas or
oil production rate per well (scm CH4/day/well or bbl oil/day/well), and I:P
is the injector to producer well ratio. The CO2 effectiveness factor represents
the quantity of CO2 stored for every scm CH4 or barrel of oil produced.
Common ranges for the input parameters are listed for each of the reservoir
types (Table 2.8).
In addition to injection and production wells, all enhanced fossil fuel
recovery sites must include surface equipment for distributing CO2 and
processing the produced fuel for sale. In some cases, water disposal equipment
and/or CO2 separation and recycling equipment are required.
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
51
Table 2.8 Common ranges for input parameters for Equation 2.11 (Bock et al.,
2003; Pashin and McIntyre, 2003; Reeves et al., 2003; Oldenburg et al., 2004; EIA,
2007; Durucan and Shi, 2009; Robertson, 2009)
Reservoir type
CO2 effectiveness
factor
Average gas or oil
production rate
EGR
EOR
ECBM
1.5–3
1400–140 000
85–227 40–70
1.5–10
1700–14 000+
Injector to producer
well ratio
1:1
1:1.1
1:1
Enhanced gas recovery (CO2–EGR)
In type I gas reservoirs, gas production declines over time as reservoir
pressure is depleted. Pressure depletion recovers 80–90 % of original gas
in place (OGIP), leaving about 10–20 %. It is postulated that CO2 injection
into these reservoirs could allow for enhanced recovery of the remaining gas
through repressurization of the reservoir and displacement of methane by
CO2. Consequently, CO2–EGR could potentially generate revenue through
sale of natural gas while storing CO2.
With CO2–EGR, it is assumed that all of the production equipment is
already in place so incremental capital costs include conversion of existing
production wells to CO2 injection wells, installation of CO2 injection and
distribution equipment, and permitting. Equipment capital costs are derived
using the equations for storage in depleted gas reservoirs outlined on p. 49.
O&M costs include O&M for production and injection equipment, monitoring,
and gas processing, treatment, and compression. The O&M cost for injection
equipment is given by equation 2.10 and the production equipment O&M
cost is derived from EIA (2007) data for gas production in West Texas:
COMp = 405.81d0.5517
[2.12]
where COMp is the annual O&M cost of gas production (2005$/well) and d
is well depth (m). Monitoring is estimated to be $0.02/tCO2 and the cost of
natural gas treatment and compression is estimated by Bank and Kuuskraa
(2006) to be ~$0.025 per scm of CH4. CO2 separation and recycling equipment
may be necessary if substantial CO2 breakthrough occurs at the production
wells and can add substantial cost.
Incremental gas production associated with CO2–EGR is estimated to
be 80–90 % of annual total production (Oldenburg et al., 2001, 2004).
The incremental revenue from gas sales is calculated by multiplying the
incremental gas production by the wellhead gas price and assuming a royalty
tax of 12.5 %.
A sensitivity analysis given the baseline parameters in Table 2.9 and
wellhead natural gas price of $4/GJ indicates that the levelized storage cost
is most sensitive to the CO2 effectiveness factor, average gas production
© Woodhead Publishing Limited, 2010
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Developments and innovation in CCS technology
Table 2.9 Reservoir characteristics for a baseline case and at three depths (EIA,
2007; Hughes, 2009)
Scenario
Average
depth (m)
Average gas production
rate (scm/day/well)
CO2 effectiveness factor
(scm CO2/scm CH4)
Shallow
Medium
Deep
Baseline
1220
2439
3659
1000
7000
7000
14 000
7000
2.8
1.7
1.4
3
$20.00
Levelized cost ($/tonne CO2)
$10.00
$0.00
–$10.00
–$20.00
–$30.00
CO2 effectiveness factor
Average gas production rate
Natural gas price
Well depth
–$40.00
–$50.00
–$60.00
–100 %
–50 %
0%
50 %
100 %
150 %
Percentage change in parameter
200 %
250 %
2.10 Sensitivity of levelized cost to various parameters.
rate, and the natural gas price (Fig. 2.10). This figure is generally applicable
to all enhanced fossil fuel recovery operations. In particular, high prices
for the produced gas or oil improves project economics through increased
revenue while a reduction in the CO2 effectiveness factor results in improved
economics since more product (i.e., revenue) is produced for each unit of CO2.
Reservoirs with high average production rates also have better economics
since they generate more revenue per well.
The levelized cost of CO2 storage is calculated for three reservoir depths
given the parameters in Table 2.9 and a wellhead natural gas price of $4/
GJ. The storage cost ranges from –$8.00 to –$11.00/tCO2, which suggests
that revenue generated from methane recovery can offset CO2 storage costs.
However, if a CO2 capture and transport cost of $50/tonne is assumed,
CO2–EGR would require a $40/tCO2 carbon credit or a wellhead natural
gas price >$7/GJ in order to be economic.
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
53
Enhanced oil recovery (CO2–EOR)
Although CO2–flood enhanced oil recovery is a proven technology that is
currently used at over 80 sites worldwide (Bock et al., 2003), no CO2–EOR
projects currently utilize CO2 from power plants. CO2–EOR is attractive since
it can improve the recovery of domestic oil while storing CO2 and producing
substantial revenue from oil sales. This technique is employed at sites that
have already undergone primary and secondary recovery so most of the
infrastructure for oil production and CO2 injection is already in place.
Capital costs for converting a site to CO2–EOR include: (i) conversion of
water injection and/or production wells to CO2 injection wells; (ii) workover
of existing production wells and equipment; (iii) installation of equipment
for distributing and injecting CO2; and (iv) installation of CO2 separation,
compression, and recycling equipment. The equations for calculating the
capital costs of converting existing wells to CO2 injection wells, installing
CO2 distribution and injection equipment, and permitting are summarized
on pages 47–49. An equation for the cost of upgrading existing production
wells and equipment for CO2–EOR is derived from EIA (2007) estimates
of additional lease equipment costs for water flooding in West Texas:
Cprod = 91 510ln(d) – 567 823
[2.13]
where d is well depth (m). CO2 separation and recycling equipment costs
are determined using the design and costs given in Bock et al. (2003). O&M
costs include O&M for production and injection equipment, monitoring, CO2
processing, and fluid lifting. The O&M cost for production and injection
equipment is given by Equation 2.10 and the monitoring cost is assumed to
be $0.02/tCO2. The CO2 processing O&M cost is estimated to be 1 % of the
oil price per Mscf CO2 (e.g., $0.25/Mscf at $25/barrel) and the cost for fluid
lifting is assumed to be $0.25/barrel of total liquid production (Advanced
Resources International, 2006).
Annual revenue from the sale of oil is calculated by multiplying annual
oil production by the first purchase oil price and assuming a royalty tax of
12.5 %. The first purchase oil price is the price received at the well and can
be derived from the marker oil price (Advanced Resources International,
2006). Based on the annual revenue and costs, the levelized cost of CO 2
storage is determined (Table 2.10).
Table 2.10 indicates that the storage cost associated with CO2–EOR is
negative even at a relatively low oil price of $20/bbl. For marker oil prices
of $35 and $60/bbl, the breakeven cost of CO2 is estimated to be $50/tonne
CO2 and $108/tonne CO2, respectively. This is consistent with McCoy &
Rubin (2009), which estimates the breakeven cost of CO2 to be $117–195/
tonne CO2 for a marker oil price of $60/bbl. Given that most estimates of
CO2 capture and transport costs for power plants are less than $50/tonne
CO2, this model suggests that CO2–EOR should be economically viable for
© Woodhead Publishing Limited, 2010
54
Developments and innovation in CCS technology
Table 2.10 Reservoir characteristics and levelized cost for three oil fields (Bock et
al., 2003; McCoy and Rubin, 2009)
Average
depth (m)
Average oil
production rate
(bbl/day/well)
CO2 effectiveness
factor (scm
CO2/barrel oil)
Storage cost1
($/tonne CO2)
Baseline
SACROC, Kelly
Snyder Field
Northeast
Purdy Unit
1220
2042
40
35
170
103
–$13.82
–$11.35
2499
41
82
–$5.89
Oil field
1
Assuming $20/bbl marker oil price, maximum CO2 recycle ratio of 3, and design
CO2 mass flow rate of 8000 tonnes/day.
most CO2 sources at oil prices greater than ~$35/bbl. Despite the positive
economics of CO2–EOR, the limited locations and low storage capacity of
these sites suggest that opportunities for storing power plant CO2 emissions
via CO2–EOR will be limited.
Enhanced coalbed methane (CO2–ECBM)
Deep unmineable coal beds are valued for the significant quantities of methane
that they contain. Generally, this methane is extracted by pressure depletion and
dewatering of the reservoir. However, CO2 can effectively enhance methane
recovery since its higher affinity for coal results in desorption and displacement
of adsorbed methane, resulting in additional recovery of 10–20 % of OGIP
(Reeves et al., 2004; Robertson, 2009). CO2–ECBM can be employed as a
secondary recovery technique at sites that have previously undergone primary
recovery or as part of primary recovery at undeveloped sites. Reeves et al.
(2004) find that undeveloped sites provide better economics since there is a
larger methane resource with which to offset CO2 storage costs.
Capital costs for new CO2–ECBM developments include permitting, mineral
rights, and land, drilling of CO2 injection and methane production wells,
installation of equipment for water disposal, distributing CO2, methane, water,
and treating and compressing methane for sale. CO2 recycling equipment
may be necessary if substantial CO2 breakthrough occurs at the production
wells. However, several studies suggest that CO2 breakthrough is negligible
with appropriate well spacing (Reeves, 2001; Robertson, 2009).
Bock et al. (2003) and Bank and Kuuskraa (2006) provide per-well costs
for permitting, mineral rights, and land costs. The average of these values
is approximately $23 000 per well. Drilling costs for both production and
injection wells are given by Equation 2.7 and CO2 injection equipment costs
are given by Equations 2.8 and 2.9. Methane production equipment costs
include gas gathering pipelines, production well equipment, and electric
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
55
power infrastructure. Gas gathering and electric power equipment costs are
estimated by Bank and Kuuskraa (2006) as $58 000/well and $16 000/well,
respectively. Production well equipment costs are reported by the EIA (2007)
for the four primary coalbed methane sites in the USA (Table 2.11). Water
disposal equipment design and costing for shallow underground re-injection
are given in Bank and Kuuskraa (2006).
O&M costs are divided into four components: well maintenance, monitoring,
water disposal, and natural gas treatment, processing, and compression.
O&M costs for injection wells are determined using Equation 2.10 and
O&M costs for CBM production wells are estimated using EIA (2007)
data for CBM projects in each of the four basins. Monitoring is estimated
to be $0.02/tonne CO2 and water disposal O&M is estimated by Bank and
Kuuskraa (2006) to be $0.10/barrel of water. The cost of gas treatment and
processing is estimated by Bank and Kuuskraa (2006) to be $0.025 per scm
CH4. Annual revenue from the sale of natural gas is calculated by multiplying
annual gas production by the wellhead gas price and assuming a royalty tax
of 12.5 %.
The levelized cost of CO2 storage for the four primary coal bed methane
basins in the USA is estimated using the input parameters from Table 2.11
and a wellhead gas price of $4/GJ. These estimates range from –$12.00/tCO2
in the San Juan Basin to $26.00/tCO2 in the Appalachian Basin. In fact, the
only basin in which methane recovery offsets CO2 storage costs is the San
Juan basin which has relatively high methane production. In this ‘best case’
basin, the breakeven cost of CO2 for wellhead gas prices of $6/GJ and $10/
GJ are $23/tCO2 and $46/tCO2, respectively. This analysis suggests that the
potential for economic CO2–ECBM projects will be limited to sites with
very high gas production and, even in these cases, either high wellhead gas
prices or significantly reduced CO2 capture costs will be required.
Since gas production and CO2 injection rates have a large impact on storage
costs, technologies that can improve these rates (e.g., horizontal wells and
Table 2.11 Reservoir characteristics of primary coalbed methane basins in USA and
baseline case (Pashin and McIntyre, 2003; Reeves et al., 2003; Bank and Kuuskraa,
2006; EIA, 2007; Durucan and Shi, 2009)
Coal basin
Average Average gas
Average water CO2
Production
depth
production rate production rate effectiveness well
(m)
(scm/day/well) (bbl/day/well) factor (scm
equipment
CO2/scm CH4) cost ($/well)
Appalachian
Black Warrior
Powder River
San Juan
Baseline case
610
610
457
945
600
1700
3000
3000
14 000
7000
3
20
50
100
100
3
2
5
3
3
© Woodhead Publishing Limited, 2010
$26 000
$30 000
$16 000
$66 000
–
56
Developments and innovation in CCS technology
nitrogen injection) could potentially reduce future costs (Durucan and Shi,
2009). Several studies have examined the injection of flue gas rather than
pure CO2 since it would eliminate the need for CO2 capture and nitrogen
improves gas production (Reeves et al., 2004; Durucan and Shi, 2009;
Robertson, 2009; Zarrouk and Moore, 2009). These studies find improved
overall economics, but minimal CO2 storage benefits and higher costs per
tCO2 since much smaller quantities of CO2 are injected (Reeves et al., 2004;
Robertson, 2009).
2.5
Carbon dioxide (CO2) capture and storage (CCS)
system modeling
In this section, we discuss the cost of a complete fossil energy system with
CCS, drawing on the individual models described in Sections 2.2–2.4 for CO2
capture, transport, and storage (Table 2.12). We consider power plants in the
range of 300–1000 MW, which produce 4000–25 000 tonnes of captured CO2
per day; CO2 transport systems capable of moving this amount of CO2 up
to 500 km, and various schemes for CO2 injection and storage in geological
formations such as saline aquifers and depleted oil and gas fields, including
EGR, EOR, and ECBM.
CO2 capture is the largest single cost involved in implementing CCS,
accounting for $15–75/tCO2 captured. The transport cost of CO2 shows strong
scale economies, decreasing with flow rate, and increasing with distance,
with costs of perhaps $1–8/tCO2 for onshore pipelines, and three times that
for offshore pipelines. Geological storage costs $0.5–5/tCO2. With enhanced
recovery of fossil fuels, the cost of CO2 injection and storage can become
negative, depending on the value of the produced oil or gas.
Generic cost ranges are interesting because they give an order of magnitude
on costs. However, more realistic system models are needed to look at the
prospects for CCS for a particular region or situation. With the increasing
availability of geographic information system data, it has become possible
to do geographic specific case studies of fossil energy systems with CCS
(Herzog, 2006; Johnson and Ogden, 2008; Johnson et al., 2008; Middleton
and Bielicki, 2009). Existing CO2 sources and power plant locations,
sequestration sites, and potential pipeline locations can be identified for a
given region. The model develops an optimized design for CO2 pipelines
to connect sources of CO2 and storage sites. Most techno-economic system
models are static and assume a fixed demand. However, several scenarios
for building up regional CCS-based systems over time have been developed
and help to estimate the costs for making a multi-decade transition to a
fossil energy system with CCS (Kuuskraa, 2007; IEA, 2008; Johnson et al.,
2008).
An example of an optimization model for a coal-based hydrogen production
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
57
Table 2.12 Range of costs for each component of a CCS system
CCS system component
Capital cost
CO2 capture
Incremental capital cost vs
plant w/o CO2 capture
∑ 300–1000 MWe Power Plant
Coal PC
$750–1000/kWe (+40–50 %)
Coal IGCC
$500–700/kWe (+25–40 %)
NGCC
$300–500/kWe (+50 %)
∑ 300–1000 MWth H2 Plant
Coal gasification
$–50 to +50 /kWth
NG reformer
$150–200/kWth (+60 %)
CO2 transport
Onshore pipeline
∑ 100 km
4000 t/d
25 000 t/d
∑ 500 km
4000 t/d
25 000 t/d
Offshore pipeline
∑ 500 km
4000 t/d
25 000 t/d
Ship
∑ 500 km
4000 t/d
25 000 t/d
Levelized cost $/tCO2
Cost of CO2 capture
29–51
37–74
13–37
2–8
30
Total installed capital cost
$28 million ($280 000/km)
$55 million ($550 000/km)
2.6
0.8
$130 million ($260 000/km)
$260 million ($520 000/km)
12.5
4.0
$335 million ($710 000/km) 36
$680 million ($1 360 000/km) 11
$360 million
$970 million
CO2 injection1
∑ Injection wells
1000 m
3000 m
∑ Deep saline aquifer
4000 t/d
25 000 t/d
∑ Depleted gas reservoir
4000 t/d
25 000 t/d
∑ Enhanced gas recovery
4000 t/d
25 000 t/d
∑ Enhanced oil recovery
4000 t/d
25 000 t/d
∑ Enhanced coalbed methane
4000 t/d
25 000 t/d
43
23
$420 000/well
$2 700 000/well
$17–20 million
$81–102 million
1.8–2
1.4–1.7
$1–7 million
$5–44 million
0.2–1.4
0.2–1.4
$22–172 million
$140–1100 million
–11 to –8
–11 to –8
$175–513 million
$1100–3200 million
–14 to –6
–14 to –6
$54–348 million
$336–2200 million
–12 to 26
–12 to 26
Monitoring
0.2
1
Injection costs are based on reference cases in Section 2.4, but could be much
larger or smaller depending on reservoir characteristics and, in the case of
enhanced fossil fuel recovery, oil/gas prices.
© Woodhead Publishing Limited, 2010
58
Developments and innovation in CCS technology
system with CCS in the state of Ohio is illustrated in Fig. 2.11 (Johnson et al.,
2008). Beginning with a GIS database, locations of demand (large polygons),
coal plant locations (white/black circles), and rights of way are indentified.
From this, a set of possible pathways between demand centers (cities) and
coal plants is found (Fig. 2.11a), and mathematical programming techniques
are used to select the spatially optimal (lowest cost) supply network (Fig.
2.11b). A build-out scenario is postulated, assuming an introduction rate for
hydrogen vehicles. In Figure 2.12, we show the growth of the network as
the hydrogen demand rises from 5 % of vehicles to 75 %. A more extensive
hydrogen pipeline network and more coal to hydrogen plants are added as
(a)
(b)
2.11 Coal-based hydrogen system optimization with CCS (a) shortest
distance pathways between all coal plants and design centres; (b)
optimal hydrogen pipeline network (Johnson et al., 2008).
(a)
Pipeline
(b)
Interstate
Coal plant
Intercity station
(c)
Sequestration site
Demand center
2.12 Build-out scenario for coal-based hydrogen system with CCS
(a) 5%; (b) 25%; (c) 75% (Johnson et al., 2008).
© Woodhead Publishing Limited, 2010
Techno-economic analysis and modeling
59
demand grows. In this study, the hydrogen delivery system (an extensive
network of pipelines from the power plant to hydrogen refuelling stations)
is found to be a major cost factor. By comparison, the pipeline system for
transporting CO2 is relatively small since power plants are located near good
sequestration sites.
Finally, models of CCS systems have been incorporated into larger
models of the energy economy. In these models, various energy supply
options compete to supply specified demands for energy services such as
lighting, cooling, and transportation. These models yield insight into the
potential role of fossil energy systems with CCS under different technology
assumptions or policy constraints. A recent study by the IEA (2008) used the
MARKAL energy/economics model to examine the potential role of various
technologies in reaching low-carbon futures by 2050. Two future scenarios
with deep carbon emissions cuts were explored (the ACT Map and BLUE
Map Scenarios). They find that coal with CCS plays a major role in meeting
a goal of reducing energy-related carbon emissions by 50 % compared to a
business as usual scenario. As shown in Fig. 2.13, 14–19 % of the emissions
reduction is due to use of CCS in fossil power plants, industry, and fuel
production. CO2 capture and sequestration is seen as a critical technology
for meeting future climate goals.
2.6
Future trends
Models for fossil energy systems with CCS have been developed at the
individual component and system level. There remain many uncertainties in
the inputs to such models and in the equations themselves, especially those
governing injection and storage in underground reservoirs.
In the future, as there is more experience with building and operating
CCS systems, the uncertainties in cost and performance of power plants, fuel
production systems, and industrial plants with CCS should decline and cost
estimation should become more accurate. This is important as CO2 capture
is the single largest cost associated with a CCS system. Another major
source of uncertainty in current cost models is the need to better understand
how CO2 behaves in underground storage reservoirs over a period of time.
Characterization of reservoirs to estimate injectivity and storage capacity a
priori is an active area of research. Progress in this area will improve the
quality of cost models for injection sites.
The design of a fossil energy system with CCS is regionally dependent.
In recent years, several studies have made use of GIS-based data sets to
design CO2 pipeline systems in realistic regional case studies. Similar
techniques are used to design and route conventional oil and gas pipelines
and are proving useful for understanding the possibilities for locating CO2
pipelines. In addition, they allow development of CCS system designs that
© Woodhead Publishing Limited, 2010
60
BLUE Map 48 Gt CO2 reduction
ACT Map 35 Gt CO2 reduction
Nuclear, 6 %
© Woodhead Publishing Limited, 2010
CCS power,
8%
Power fossil
fuel switching
and efficiency,
17 %
End-use fuel
switching, 3 %
Nuclear, 6 %
CCS
industry and
transformation,
9%
Hydrogen
FCVs, 4 %
Power fossil fuel
switching and
efficiency, 7 %
End-use fuel
switching,
3%
CCS power,
10 %
End-use fuel
efficiency, 24 %
End-use fuel
efficiency, 28 %
Total
renewables,
16 %
Electrification,
2%
Electricity enduse efficiency,
16 %
Total
renewables,
21 %
Electrification,
6%
Electricity enduse efficiency,
12 %
2.13 Reduction in CO2 emissions for the ACT Map and BLUE Map scenarios relative to the Baseline scenario by
technology area, 2050 (FCV = fuel cell vehicle) (IEA, 2008).
Developments and innovation in CCS technology
CCS
industry and
transformation,
6%
Techno-economic analysis and modeling
61
optimize for low cost and incorporate land use constraints. There has been
some innovative work on build-out strategies as well. In the future, such
tools will be very valuable to examine different strategies for implementing
CCS on a large scale.
2.7
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