Module 12 Economics of CO2 capture and storage

Guy Allinson, Peter Neal, Minh Ho, Dianne Wiley and Geoffrey McKee Adapted from CO2CRC Report Number RPT 06-0080

Overview

This module sets out the methods and assumptions used in carrying out economic analyses of carbon dioxide capture and storage (CCS) projects. It describes the methods and assumptions used when making generic cost estimates of CCS projects. For analyses of specific sites for special purposes, we might chose to adopt different methods and assumptions.

This module contains hypothetical examples to illustrate the methods we employ. The examples are not intended to represent any actual CCS project or opportunity.

Economics is an essential aspect of the evaluation of CCS projects. This module provides an overview of the economic considerations required to establish a CCS project.

Learning objectives

  • By the end of this module, you will have an understanding of -
  • How the costs of CCS are derived.
  • The concepts of CO2 avoided, $ per tonne avoided and injected and $ per MWh in the context of CCS.
  • The pitfalls of estimating the costs of CCS.

Summary

Cost estimates

The inputs to our cost estimates of CO2 capture and storage are the physical characteristics of the source of CO2 and the injection site as well as the unit costs of equipment and services in today's markets.

The estimates are subject to uncertainties because we cannot predict accurately storage reservoir parameters, gas compositions, capture equipment performance, unit costs and so on.

Costs per tonne of CO2 avoided

The total costs of CCS consist of capital, operating and decommissioning costs. We estimate these, phase them over time, calculate the present value and divide by the present value of the annual CO2 avoided. This gives the costs in $ per tonne of CO2 avoided.

CO2 avoided is the difference between amount of CO2 emitted without capture and the amount of CO2 emitted with capture.

Annualised costs

In much of the literature on the economics of CCS, authors derive annualised costs per tonne of CO2 avoided. This gives the same result as the costs based on present values as described above. However, it is only easily applicable if the capital costs are incurred at time zero and if the operating costs and the CO2 avoided are the same each year. These conditions are very restrictive.

Sometimes annualised costs are referred to as "levelised" costs.

Adding costs per tonne avoided

It is not valid to add together the costs of CO2 avoided in the capture process and the costs of CO2 avoided in the storage process. The costs per tonne of CO2 avoided in the CCS process as a whole must be calculated using the total CO2 avoided in the whole process.

Reference plant

Very often, the amount of CO2 avoided is calculated by reference to the same plant from which we capture the CO2. We also calculate CO2 avoided with reference to other possible sources of CO2. In general, we calculate CO2 avoided by reference to (a) the same plant (b) a black coal power station, (c) a brown coal power station and a (d) natural gas combined cycle power station as appropriate. In some cases, for instance capture from a natural gas processing plant, it is not appropriate to calculate CO2 avoided by reference to other sources of CO2.

Generic capital costs

Our estimates of real capital costs for generic cases are built up using the following cost categories -

  • Costs of equipment and materials
  • International freight (if applicable)
  • Local freight
  • Construction and installation costs
  • Engineering and project management costs
  • Owners' costs

The main text sets out how we estimate these costs in these categories.

Generic operating costs

For generic cases, we estimate real annual fixed operating costs as a percentage of real capital costs. The percentage varies depending on the equipment.

Generic decommissioning costs

For generic cases, we assume that real decommissioning costs are 25% of the real capital costs.

Cost translations

Our costs estimates are for local conditions and are expressed in local currency. Our procedure for translating these into US conditions expressed in US$ is set out in the main text.

Assumptions

The following table contains the assumptions the CO2CRC adopts in making generic cost estimates. For purposes of comparison, we adopt a similar list as the International Energy Agency. A full comparison between the CO2CRC's assumptions and the IEA assumptions is given in the main text.

Table 12.1 Summary of assumptions

Capture plant size

Power stations – 500 MW

Other plant – depends on the situation

Capture plant design and construction period

2 years

40% of capital costs spent in year 1 and 60% in year 2.

Plant life

25 years

Load factors

Pulverised coal power stations - 85%

Natural gas power stations - 90%

Other plants – to be determined later

Cost of debt

No debt. Fully equity financed

Discount rate

7% real for capture from oil and gas facilities

Fees and owners' costs

7% of engineering, procurement and construction (EPC) costs

Contingency

10% of engineering, procurement, construction and owners' (EPCO) costs

Commissioning and working capital

We make no separate allowances for commissioning and working capital. These are taken into account in our capital cost phasing assumptions.

Decommissioning

We assume that decommissioning costs are 25% of the original real capital costs.

Maintenance

Maintenance costs are part of our estimates of operating costs

Labour

Labour costs are part of our estimates of operating costs

Fuels and raw materials

We assume that electric power used for CCS equipment is generated using natural gas costing A$3.50 per GJ.

Water

A$20 per megalitre

Effluent/emissions and solids disposal

We assume that the costs of these are part of the operating costs.

Site conditions

Ambient air temperature – 25°C onshore and 17°C offshore

Ambient air relative humidity - 60%

Ambient air pressure 1.01325 bar

Lower Heating Value is used in all efficiency calculations

Heat content

We assume that a super-critical black pulverised coal plant has a thermal efficiency of 40%.

We assume that a natural gas combined cycle (NGCC) power plant has a thermal efficiency of 56%.

Gas composition and CO2 recovery

CO2 recovery = 90%.

Gas compositions are shown in the following table –

Methodology

The CO2 capture and storage system consists of –

  1. Extracting CO2 from a mixed gas stream in an industrial process. The industrial process might be electric power generation, natural gas processing, furnaces, boilers and so on. The capture technology might be chemical or physical absorption, gas separation membranes, pressure swing adsorption (including vacuum swing adsorption) and low temperature cryogenic separation.
  2. Compressing CO2 from capture (atmospheric) pressure to a pressure required for CO2 transport in a pipeline. We need to compress the CO2 to more than 8.3 megapascals (MPa) (approximately 1,200 pounds per square inch - psi) so that it is in a supercritical state ready for transport. This initial compression occurs at the source of the CO2 after the capture process or as part of the capture process.
  3. Transporting the CO2 in a pipeline from the source to the point of injection.
  4. Recompressing the CO2, as required, along the transport route and possibly at the storage location before it is injected.
  5. In the case of injection offshore, constructing and installing platforms to support the injection wells and equipment. In the case of injection onshore, constructing and installing infrastructure to support the injection wells and equipment.
  6. Injection wells and flowlines connecting the wells to the pipeline used to transport the CO2.

Inputs to cost estimates

The inputs to the estimates of capital and operating costs are -

1. Engineering estimates of the size and number of different pieces of equipment and the number and features of the wells required. These estimates depend on a range of inputs such as the following (not a complete list) -

  • The mixed gas composition at the source.
  • The mixed gas flow rate.
  • The capture technology.
  • The extracted CO2 flow rate.
  • The period of injection.
  • The CO2 pressure at the input to the pipeline.
  • The distance from the source to the injection site (the sink).
  • The relative elevation between source and sink.
  • The water depth (if the reservoir is offshore).
  • The depth of the storage reservoir beneath the surface of the earth.
  • The reservoir temperature and pressure.
  • The reservoir net thickness.
  • The reservoir permeability

2. Estimates of the unit costs of equipment and services in today's markets. These depend on the type of equipment and hardware and their unit costs at market prices.

We first make preliminary estimates of the size and number of pieces of hardware required. We then apply estimates of unit costs to derive the total capital and operating costs of the CCS project.

All cost estimates are usually preliminary. They cannot be made firm until a particular site is specified, designed and engineered in detail and until quotations are received for the equipment required. The purpose of estimates is to give broad-brush estimates as inputs to economic and business planning.

All cost estimates apply at a particular point in time. The costs of equipment and services change over time because of market forces.

Uncertainties

Both the engineering and the economic data are subject to uncertainties. In some cases these are potentially large. For instance, there are difficulties in predicting accurately the nature of the reservoir and its behaviour during the injection process. Uncertainties can arise with variations of CO2 flow rates and the level of impurities. There are also uncertainties in unit costs because different providers of equipment and services will in general quote different costs. In addition, the costs of labour materials and energy can fluctuate considerably.

Uncertainties for the capture technologies are related to the different technologies and the range of data available from which to estimate performance for a given source. For instance, relatively mature technologies, such as amine adsorption that have already been applied at different scales in different international locations, will have fewer uncertainties than newer technologies that have limited or no industrial application.

Capital, operating and decommissioning costs

Estimating the costs of CCS involves estimating the capital, operating and decommissioning costs of each of the components of the system. The capital costs are the costs of constructing and installing equipment and are incurred at the beginning of the project. The operating costs are the costs of running and maintaining the system on a regular basis after it is constructed. The decommissioning costs are the costs of disposing of the equipment in an environmentally safe manner at the end of the project.

As an illustration, we might estimate the real capital costs (capex), the real operating costs (opex) and the real decommissioning costs of a hypothetical CCS project to be as shown in Table 12.2 below.

Real costs are the costs at today's prices for the components of the system (steel, materials, labour etc). For Table 12.2, we assume that the construction period is from year 1 to year 2 inclusive and that CO2 storage begins in year 3 and finishes in year 27. Therefore CO2 capture and storage lasts for 25 years. The project is abandoned in year 28.

In the case of enhanced oil or gas (for example enhanced coal bed methane recovery) projects there will be an annual revenue stream in addition to the costs shown in Table 12.2. These revenues clearly will offset the costs shown in the table. Moreover, if there is a carbon trading regime, the benefits of selling carbon credits would also offset the costs. In any commercial CCS operation, the revenues from trading CO2 credits plus any extra revenues from enhanced recovery would exceed the costs of CCS and yield a profit.

Table 12.2 Illustrative real costs of a CCS project in $million

The present value of costs

Based on the example costs set out in Table 12.2, we calculate the present value (PV) of the costs as shown in Table 12.3.

Table 12.3 Calculating the present value of real capital and operating costs in $million

This calculation is based on a real discount rate 7%, our default assumption for the discount rate as discussed later. We assume end-year discounting.

The PV of real costs in this example is the amount of money which would need to be placed in an alternative investment today to allow the investment to pay the capital and operating costs of the CO2 storage project as they become due at the end of each year. The alternative investment yields a real return of 7% per year. The PV is therefore the equivalent cost of the project as at today.

An example of the calculation of power station costs before and after capture is given in Appendix 1.

CO2 avoided

In the CCS system CO2 is captured from a mixed gas stream and injected into the subsurface. However, not all of the CO2 is extracted from the mixed gas stream. It is emitted. CO2 is also generated and emitted in the CCS process itself, for instance in compressing the CO2 before and during transport and injection.

Of course, additional CO2 is also generated in the process of manufacturing the equipment forming part of the CO2 storage system. However, this is not included in our calculations.

To take into account the CO2 emitted in the CCS process, we calculate the "CO2 avoided". This is calculated below with example data –

Table 12.4 CO2 avoided

* Assumes a CO2 recovery rate of 90%

In the example in Table 12.4 we assume that the CCS process itself generates CO2 emissions. For coal fired power stations the energy penalty (the extra energy required to capture and store CO2) might be as much as 30% as is assumed in this case. The CCS process would then capture and store a percentage of the original CO2 emitted plus the CO2 emitted from the capture plant. This percentage is the rate of CO2 recovery and is assumed to be 90% in Table 12.4.

An example of how we determine the CO2 avoided in the case of a power station is given is Appendix 2.

Specific costs per tonne of CO2 avoided

Based on the example costs set out in Table 12.2, and assuming that the CO2 avoided is 8.6 million tonnes per year, we can calculate the specific costs per tonne of CO2 avoided and per tonne of CO2 injected as shown below.

Table 12.5 Specific costs

We divide by the present value of the CO2 avoided (or injected) because then the CO2 avoided (or injected) is in the same terms as the present value of the costs so that the ratio represents a valid comparison.

The present value of the CO2 avoided in the example shown above is calculated as shown in Table 12.6. The present value of tonnes injected is calculated in a similar way.

Table 12.6 Calculating the present value of CO2 avoided in million tonnes

Annualised costs

Another way in which we might represent the costs of CCS per tonne of CO2 avoided is to calculate "specific annualised costs". In fact, this is the representation most often used in the literature.

Appendix 3 demonstrates that the specific annualised costs are exactly the same as the specific present value of costs when we make simplifying assumptions. However, the assumptions made in calculating specific annualised costs are restrictive and when any one of the assumptions does not apply, then the calculation becomes complex. It is simpler and more appropriate to use the specific present value of costs, which is a much less restrictive approach.

Our preference is to use the present value of project costs rather than annualised costs because it allows more flexibility. It allows us to spread capital expenditure over several years. It also allows us to have different operating costs in different years of the project. Further, it allows us to incorporate inflation. Finally, if we are deriving costs per unit of production, it allows us to vary the units of production each year. Additionally, if we need to incorporate tax and the receipt of carbon credits in the calculation, then this is relatively easy to do.

In contrast, annualised cost calculations rely on a simplification of project costs and might not be helpful if we want to represent costs accurately. The difficulties with using annualised costs are –

  1. If capital costs are spread over time, then we need to express them in terms of their present value before calculating their annualised equivalent using a "capital recovery factor" (see Appendix 3).
  2. It does not allow us easily to vary fixed or operating costs to over the life of the project. To do this, we would need to calculate the present value of operating costs and derive an "operating cost recovery factor" in a manner similar to the way in which we derive a capital recovery factor.
  3. It does not allow us easily to incorporate inflation. To do this, we would need to derive an operating cost recovery factor as mentioned above.
  4. It does not enable us to calculate costs per unit of production when production varies over the life of the project.
  5. It does not allow us easily to incorporate tax into the cost calculations. To do this, we would need to work out the taxes each year, calculate the present value of those taxes and derive a "tax recovery factor" in a similar way to the way in which we derive a operating cost recovery factor.
  6. It does not allow us easily to incorporate varying revenues, for instance from receipts of carbon credits or enhanced oil or gas recovery. To do this we would need to calculate the present value of revenues and derive an annual revenue equivalent in a manner similar to the way in which we derive a capital recovery factor.

Adding specific costs

In much of the literature, specific costs are quoted separately for capture on the one hand and transport and injection (= storage) on the other. However, that the CO2 avoided used to calculate the specific costs of capture is not the same as the CO2 avoided used in calculating the specific costs of storage. Therefore, to estimate the costs per tonne of CO2 avoided for the combined process, we cannot simply add the specific costs of capture and the specific costs of storage. We must adjust the calculations to derive the correct specific costs of the combined capture and storage process.

Table 12.7 shows the calculation of CO2 avoided using hypothetical, illustrative data.

Table 12.7 CO2 avoided for capture and storage in million tonnes per year

Footnotes

(a) Data assumed - CO2 emitted from the original (reference) plant before capture

(b) Data assumed - CO2 emitted after capture from the original plant and the capture plant.

(c) Data assumed - CO2 captured and stored from the original plant and the capture plant.

Given these data and relationships, we can now calculate the specific costs per tonne of CO2 avoided. Table 12.8 illustrates the calculation.

Table 12.8 Specific costs of CCS in $ per tonne of CO2 avoided

Footnotes

(a) Assumed annualised costs in $ million and (b) CO2 avoided in million tonnes per year

Table 12.7 and Table 12.8 show that the correct specific cost of the combined capture and storage process is $54.3 per tonne of CO2 avoided. It is not the sum of $37.8 plus $9.9 equals $47.7 per tonne avoided. The example demonstrates that we cannot simply add the specific costs of capture and the specific costs of storage to derive the correct specific costs of the combined capture and storage process.

Reference plant

CO2 avoided is the difference between the original CO2 emitted and the CO2 generated or lost during the CCS process. In the examples above, the original CO2 emitted is that from the industrial process that hosts the CCS project, but before CCS is applied. In other words, the reference plant is the same plant as is used for CCS. This is the assumption used in most of the CCS literature.

However, this is not the only assumption that we might make. We might instead assume that the reference plant is a different industrial process and, if so, this would give a different value for the CO2 avoided and also the specific cost. This is illustrated in the examples below.

In the first hypothetical example, we calculate the specific costs for a pulverised coal (PC) power station. The calculations are per megawatt hour (MWh) of electricity output. The reference plant is the same plant.

Table 12.9 PC power station - Reference plant = same plant

In the second hypothetical example, we calculate the specific costs for a natural gas combined cycle (NGCC) power station. Again, the calculations are per megawatt hour (MWh) of electricity output and the reference plant is the same plant.

Table 12.10 NGCC power station - Reference plant = same plant

Comparing the NGCC plant with the PC plant, the cost of CCS per tonne of CO2 avoided is higher for the NGCC plant.

However, from a comparison between Table 12.9 and Table 12.10, it is clear that the NGCC plant has lower emissions and is less expensive than the PC plant. If we recast the specific costs of the NGCC plant using the PC plant as a reference, then the costs of NGCC even without capture will be very different. The calculations are shown in Table 12.11.

Table 12.11 NGCC plant with no capture - Reference plant = PC plant

Table 12.11 shows that, by comparison with a PC reference plant, an NGCC plant avoids almost 0.5 tonnes of CO2 and is cheaper by $14 per MWh. The cost per tonne avoided is therefore negative $31, by comparison with $49 when the reference plant for NGCC was the same plant.

If we now include the costs of capture for the NGCC plant and calculate the costs of capture for the NGCC plant with the PC plant as a reference, then we avoid even more CO2 than we do without capture, but the costs are higher. The net result is a specific cost of $1.3 per tonne of CO2 avoided.

In some cases (for instance, natural gas processing plants), it might not be appropriate to show specific costs with a reference plant other than the same plant.

Table 12.12 NGCC plant with capture - Reference plant = PC plant

Capital costs

This section illustrates the general way in which we can make estimates of capital costs. An example of the build up of a generic compressor cost estimate is given in Appendix 4.

(a) Equipment and Materials costs (Procurement)

This is either the Free-On-Board (FOB) cost in local currency of importing equipment and materials from overseas or the cost of purchasing the equipment locally. These costs exclude both international and local freight.

(b) International freight

This is the cost of transporting the equipment and materials from the overseas location to the country hosting the CCS plant. When a specific estimate is not available, we assume that this is 10% of the FOB cost described in (a) above.

(c) Local freight

This is the cost of transporting the equipment and materials to the location of the CCS project from the loading port (for imported items) or the point of purchase (for items purchased locally). We estimate these costs depending on the project.

(d) Costs including freight (CIF)

These are the sum of the FOB cost plus the cost of international freight (where appropriate) plus the costs of local freight. In other words, it is the sum of (a) + (b) + (c) above.

(e) Construction and installation costs

Construction and installation costs are different for different items of equipment and are estimated using different methods.

(f) Base Plant Costs = Direct Costs

These are the sum of the cost including freight and the construction and installation costs. In other words, they are the sum of (d) + (e) above.

(g) Engineering and project management costs

These are the costs of designing and overseeing the construction of the CCS project. We generally assume that engineering and project management costs are 15% of the Base Plant Cost or the Direct Costs.

(h) Engineering, procurement and construction costs (EPC)

These are the sum of Base Plant costs (or Direct Costs) and Engineering and Project Management costs. In other words, they are the sum of (f) + (g) above.

(i) Owners' costs

These are the costs of obtaining approvals, including environmental approvals, land purchase, and of negotiations and legal processes. We assume that these are 7% of the EPC costs described above. This is the same assumption as is recommended by the IEA (reference 1).

(j) Total EPCO costs

These are the sum of EPC costs plus Owners' costs. In other words, they are the sum of (h) + (i) above.

(k) Contingency

This covers the costs of miscellaneous items not included in (j) above. We assume that these are 10% of the total Direct plus Indirect Costs in (j) above.

(l) Total plant/project capital cost

This is the final total cost and is the sum of items (j) + (k) above.

Generic fixed operating costs

The operating costs of a CCS process have fixed and variable components. The variable component consists of fuel or power costs and this is discussed in a later section. As regards fixed operating costs, for generic cases and as defaults in our economic model, we adopt the following rules of thumb set out in Table 12.13. For specific cases where we have better data, we use that better data.

Our rules of thumb for estimating operating costs are set out in Table 12.13 below.

Table 12.13 Fixed operating cost rules of thumb

Generic decommissioning costs

Unless we have better estimates, as a rule of thumb we assume that the real costs of decommissioning are 25% of the real EPC.

Cost translations

Our cost estimates are US$ dollars ($). The way in which we build up capital, operating and decommissioning costs estimates is described in above.

We adopt the following rules of thumb when translating local costs to costs in another country in a foreign currency. The rules of thumb used when translating to US$ are given in Table 12.14 below. Appendix 4 shows an example of a translation of compressor costs to US$.

Table 12.14 Cost translation rules of thumb for translation to costs in USA in US$

Assumptions

In this section we discuss the assumptions and conventions used in making estimates of the costs of CCS generally. We also make a comparison between our assumptions and those adopted by the International Energy Agency (IEA) in a paper called "Technical and Financial Assessment Criteria", May 2003, which makes recommendations for studies carried out in the IEA Greenhouse Gas R&D programme. This paper is referred to the "IEA Assumptions" in this report and is reproduced in Appendix 5. We follow the list of assumptions used in the IEA report.

Gas composition and CO2 recovery

We assume a 90% recovery of CO2 from chemical absorption and the following feed gas composition –

Gas compositions

Footnote

NOx is not included in this table because we assume that it has been pre-treated prior to capture.

If SOx pre-treatment is included in the analysis, we assume that the SOx content in the flue gas is 10 ppm.