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Investment roadmap: Planning for carbon capture and storage

12.01.2011  |  Ferguson, S.,  Foster Wheeler Energy, Reading, Berkshire, UK

Reducing emissions can be approached with a similar method to any other new capital project

Keywords: [carbon dioxide] [carbon capture and storage] [CCS] [greenhouse gas] [refining] [power generation] [combustion] [environment legislation]

There is mounting worldwide concern over potential climate change due to anthropogenic carbon dioxide (CO2) emissions. Global power generation and processing industries are CO2 contributors. There are a number of drivers for the process industry to manage and reduce its CO2 emissions.

Manufacturing sites have opportunities for additional income from the sale of CO2 credits or to mitigate the risk of penalties imposed by future legislation. Remember: Management of CO2 emissions is growing in importance. To be successful, applying a rigorous investment planning approach to projects that minimize or reduce the carbon footprint of a new or existing facility, or a portfolio of sites is a favorable strategy. Whatever the scale and however far reaching the emission reduction aims may be, applying an appropriate roadmap tool ensures that the best project is implemented to achieved set goals.

This article introduces the concept of an investment planning roadmap and outlines the steps involved. Many available technologies to reduce CO2 emission will be discussed. Each step in the investment planning roadmap will be discussed, noting in particular how it can be applied to CO2 emission reduction and carbon-capture projects.


The goal of investment planning is to support companies in selecting the right projects to achieve their strategic goals. This involves determining if the projects are both economically and technically feasible, ensuring the optimum usage of capital and determining the most appropriate timeframe for the project. To reach the best project for meeting the client’s needs, it is necessary to follow a simple but rigorous roadmap process, as shown in Fig. 1.

  Fig. 1. The investment planning roadmap.  

Agree objectives.

It is fundamental to define what is desired to be achieved by the project. This can range from a simple plant debottleneck to achieving an overall CO2 emissions target for a global corporation. There may also be a number of stakeholders involved, so this stage is key in ensuring alignment between the parties involved.

Market analysis.

This step is essential to drive the feedstock, product slate and plant configuration to the optimum economic solution, maximizing the plant margin. Market analysis will determine product demand and price (including CO2 pricing and feedstock price and availability).

Plant configuration studies.

For most applications, linear programming (LP) is used to develop a model of the project incorporating product yield, capital and operating cost data for each potential unit operation. The results of the market analysis are also input into the model that is then run to determine the best performing configuration on a net present value (NPV) basis. The LP model generated can then also be used to rapidly explore a number of “what if” scenarios, thus enabling the project’s economic sensitivity to key product or feedstock price variations to be understood.

Site selection.

The suitability of the proposed location (or locations) can be assessed by considering four key factors:
• Site—Land availability, ground conditions, structures and obstructions, severe weather protection and earthquake zonal rating
• Port—Already existing, dredging requirements, jetty location, existing facilities and suitability of surrounding waterways
• Infrastructure—Local and national road network, heavy haul routes, rail network and regional and national airports
• Local area—Towns and industry nearby, construction resources, schools and emergency services, prevalent health hazards, landfill materials and local labor.

This assessment not only looks at the suitability of prospective sites but it also allows the cost of infrastructure development, ground remediation, etc., to be factored into the total cost estimate.

Offsites and utilities.

The scope of the utilities and offsite requirements will be based on data from process unit technology providers. Major equipment lists for all utilities, tankage and other offsite requirements will be identified, including intermediate tankage based on the high-level shutdown philosophy and marine facility requirements.

Constructability studies.

It is crucial to consider the constructability during the investment planning stage of a project to determine issues that could impact the design. Such issues include access routes for large or heavy equipment and cost benefits of modular rather than stick-built fabrication. At this stage, a high-level schedule for the full project through to startup can be developed allowing the contracting strategy to be planned.

Cost estimates.

The cost estimates, based on current market data for the plant location, are based on all of the proceeding stages in the investment planning process. High-level operating costs, including maintenance, insurance, labor, feedstocks, catalysts and chemical requirements, are developed along with the total capital cost estimate.

Economic and financial modeling.

The capital and operating cost estimates are fed into models to ensure that the plant economics are sufficiently robust and achieve the objectives specified by the company at the beginning of the investment planning process. The assumptions within the models should reflect the company’s long-term outlook and consider a number of scenarios. The project’s internal rate of return (IRR) should be considered, along with the NPV to determine the magnitude of the reward for the estimated investment costs.

Investment planning process.

Investment planning can be an iterative process, and while changes are frequently made in later design stages, the earlier they occur within the project development then the cost for changes and iteration is substantially lower.

A well-conceived investment plan, based on real data and tested against real scenarios gives a sound basis upon which to progress the project. The plan should focus on all the issues affecting the project cost and development—not just the configuration of the process units.


A well-developed design, utilizing the optimal feedstocks, energy integrated flow schemes and high-value product slate, is inherently likely to be efficient, minimizing energy demand and waste streams. However, there are almost always some unavoidable energy demands and carbon emissions. This section introduces some key options for greenhouse gas (GHG) emission abatement.

This article will focus only on CO2 since it is the largest and most high-profile single GHG. For other industries, it may also be appropriate to consider management of carbon monoxide (CO), methane, nitrous oxide, CFC and HCFC emissions.

Greenfield development projects have the advantage of being able to design their processes for reduced CO2 emissions through process selection and choice of primary energy supply. However, both new and existing plants can consider these options:
• Efficiency improvements
• Fuel substitution
• Feedstock substitution
• Configuration modifications
• Carbon capture and storage (CCS).

Efficiency improvements.

The most cost-effective approach to carbon abatement is efficiency improvement that can be potentially applied to both existing and planned assets. By maximizing efficiency, the inherent carbon emissions and energy requirements of the process will be minimized. A study of process efficiency will focus on those emissions, which are generated by the process itself, such as CO2 resulting from chemical reaction, as seen in the coal-to-liquids processes. A study of energy efficiency will then look at minimizing the requirement for heat and electrical energy input to the process so that emissions from the utility supply can also be minimized.

Onsite power generation can be significantly more efficient than standalone power generation since it can be integrated within the process. A number of potential integration options include:
• Power generation from steam raised in wasteheat boilers
• Boiler feedwater preheating against process-generated low-grade heat
• Cooling water cooling against a cold process stream
• Use of onsite fuel sources.

Energy integration across the site can reduce the need for energy input to the facility. For example, adding new process units may provide sources for waste heat that can eliminate the need for continuous use of a process heater elsewhere. It is important to consider that the plant must still be able to start up and maintain availability, so the capital expense may not be significantly reduced by energy integration. However, if the plant is able to run for a significant proportion of its operating hours with fewer process heaters in operation, then plant-wide energy demand will be reduced. If both power and heat are needed by the process, then co-generation of electricity and steam (or hot water) in a combined heat and power (CHP) plant should be considered.

Fuel substitution.

CHP plants can be highly efficient. However, if the CHP plant can accept a number of different feedstocks, including low-carbon or “carbon-neutral” fuel, such as refuse-derived fuel or a range of locally produced biomass feeds, then the site’s carbon footprint can be further reduced. This also applies to power generation without simultaneous heat generation.

The addition of renewables to supplement the power generation portfolio can increase the diversity of generation and significantly reduce the carbon footprint for utility systems. However, the likely load factor, or the availability, of each type of renewable generation, which could be considered for each location, should be considered. Renewables include wind, solar and, potentially, tidal power, as well as the previously mentioned biomass.

Feedstock substitution.

In some applications, it may be possible to wholly or partially substitute a high-carbon content, or a high embedded-carbon feedstock, for conventional feedstocks that are closer to being carbon neutral. For example, if part of the plant includes the gasification of coal or petcoke to produce a syngas, partial or full substitution with an appropriate biomass may be feasible to reduce the total carbon footprint, or increase production without increasing CO2 emissions.

Configuration modifications.

Configuration modifications can mean swapping one or several process units for more efficient alternatives or debottlenecking part of the plant to minimize carbon losses to atmosphere. While this is much easier during the design of a new plant, it is not impossible for existing plants. For example, performing pinch analysis on a refinery’s crude preheat train may enable it to be reconfigured for improved total energy efficiency.


Most of the mentioned options will be very specific to the location and plant. However, CCS could be applied to almost all processes in some form. CCS is the process of removing or reducing the CO2 content of streams normally released to atmosphere and transporting that captured CO2 to a location for permanent storage. CCS can be applied to a wide range of large single-point sources, such as process streams, heater and boiler exhausts, and vents from a range of high CO2 footprint industries including: power generation, refining, natural gas treating, chemicals, cement production and steel production. There are three main classifications of technologies applied:
• Pre-combustion capture
• Post-combustion capture
• Oxy-fuel combustion capture.

Once captured, the CO2 is compressed, dried and transported to a suitable storage location such as a saline aquifer, a depleted oil field (where enhanced oil recovery could be applied) or a depleted gas fields. Each CCS route here is a group of technologies based on similar process circumstances.

Pre-combustion CO2 capture.

A solid or gaseous feedstock is fed to an oxygen or air-blown pressurized gasifier or reformer, where it is converted to syngas. The syngas is then passed through a shift reactor to increase the hydrogen (H2) and CO2 content of the syngas. This high-pressure (HP), high-temperature syngas is cooled before being washed with a solvent to absorb the CO2 leaving an essentially pure H2 stream and a CO2-rich solvent stream. The solvent regeneration process then releases a CO2 stream that can be dried and compressed for export. This process offers a high degree of integration potential as it generates a pure high-pressure H2 stream, and the syngas cooling train can be used to raise a significant quantity of HP, medium-pressure (MP) and low-pressure (LP) steam, as shown in Fig. 2. Pre-combustion variations include:
• A range of coals, petcoke, fuel oils, municipal solid waste and biomass can be used as gasifier feedstock.
• Natural gas and light liquid feedstocks can be used with a reformer.
• A range of CO2 solvent removal systems are available along with methyl-diethanolamine (MDEA) as well as alternative technologies such as membranes and pressure-swing absorption (PSA).

  Fig. 2. Pre-combustion flow scheme.  

Pre-combustion applications. The most obvious application of pre-combustion carbon capture would be a new-build power plant in which the H2-rich stream is combusted in a gas turbine, and the steam raised during syngas heat recovery is used, along with heat recovered from the gas turbine exhaust, in a steam turbine to form a combined cycle plant such as an integrated gasification combined cycle (IGCC) facility. This scheme could similarly be used on a refinery for co-generation of low embedded-carbon hydrogen and heat to be supplied to other refinery units or with a steam turbine to raise power.

The acid-gas removal step is typically characterized by its HP syngas feedstock composed of mainly H2, CO2 and CO. The same acid-gas removal process can also be applied to similar syngases in processes such as steam methane reformer (SMR) H2 production, natural gas treating and ammonia production—even decarbonization of refinery fuel gas could be considered. The pre-combustion scheme can also be used for repowering an existing gas turbine power island or any burner that is capable of switching to decarbonized syngas, with or without burner modification.

Post-combustion CO2 capture.

Combustion flue gas is cooled by direct water contact before entering a blower designed to overcome the absorption system pressure drop. The flue gas enters the absorption column where it is washed with a physical solvent such as monoethanolamine (MEA). The flue gas is scrubbed of up to 90% of its CO2 content and is returned to the combustor stack and released to atmosphere. The CO2-rich solvent is then heated against lean solvent and regenerated in a stripping column. The solvent returns to the absorption column while the released CO2 is dried and compressed for export. The highlight of the post-combustion process is that it is suited not only for new installations but also for retrofitting existing plants, as shown in Fig. 3. Post-combustion variations include:
• A range of processes exists utilizing different solvents: MEA, ammonia, sterically hindered MEA and even sea water.
• For high-sulfur feeds, the process may be coupled with a flue-gas desulfurization unit allowing the direct contact cooler to be eliminated.

  Fig. 3. Post-combustion flow scheme.  

Post-combustion applications.

Post-combustion carbon capture is typically associated with large retrofit power projects or new build, high-carbon footprint power plants. Post-combustion CO2 capture is a simpler system than the pre-combustion described earlier and it can be bolted on to the back of almost any combustion system. Very large single-point sources, such as power plants, present a challenge in terms of maximum scale up in a single leap, but once demonstrated at scale, this technology has the potential to be used to capture approximately 90% of the CO2 emissions from any carbon-combustion-based power plant (including coal, oil, natural gas, municipal solid waste and biomass).

As shown in Fig. 3, the scheme has already been demonstrated for many years in smaller applications, for CO2 production used in the food and chemicals industries. Some smaller scale plants may already be at an appropriate size to capture CO2 from point sources similar to the size of refinery fired heaters.

Depending on the specific site, post-combustion carbon capture could be applied to a number of refinery flue gas sources (such as fired heaters, fluid catalytic crackers, hydrogen production units) with the cooler, blower and absorber located as close as possible to each source (or group of sources) with the rich solvent, then pumped to one or multiple solvent regeneration units and one or multiple compression units. This offers flexibility to fit in around the plot plan of existing process plants as much as possible.

Oxy-fuel combustion CO2 capture.

In this process, the fuel is combusted with oxygen from an air separation unit. The temperature in the boiler is moderated by recycling a portion of the flue gas back to the combustion chamber. The flue gas passes through particle removal by an electrostatic precipitator, sulfur removal by limestone scrubbing, and water removal by cooling and condensation. The remaining flue gas has a high CO2 concentration that can then be purified, dried and compressed for export. Steam from the boiler is used to generate power via a steam turbine, as shown in Fig. 4. Oxy-fuel variations include:
• A range of fuels can be used in an oxy-fuel flowscheme.
• A similar scheme has also been proposed for the conversion of gas turbines to substitute oxygen for air.

  Fig. 4. Oxy-fuel flow scheme.  

Oxy-fuel applications.

The most discussed application of oxy-fuel carbon capture is for new-build, large-scale power production. However, adding an air separation unit and sealing the system against air ingress can allow any boiler or fired heater to be converted to oxy-firing. Careful consideration must be made with respect to design temperatures and pressure of the existing boiler or heater when applying oxy-fuel carbon capture as a retrofit.

Oxy-fuel carbon capture aims to increase the partial pressure of the combustion flue gas by effectively eliminating the large volume flow of nitrogen found in systems fired using air as their oxidant. This is done to remove the process step in both the pre- and post-combustion carbon capture flow scheme in which CO2 must be separated from a stream largely composed of other gases. This results in smaller sized equipment and fewer processing steps. However, an air separation unit must also be included.


A carbon footprint reduction project requires each of the steps identified in the investment planning roadmap just as in any other project. Applying the investment planning approach ensures that the objectives are well defined, the project is appropriate for the market, the configuration of the solution is optimal; the costs are well defined, and the economic and financial case is robust.

Agree objectives.

In this stage, the exact targets at which the project is aimed and the scope to which they apply should be determined. For example, a company may wish to reduce the CO2 emissions across its full portfolio of process plants to meet an internal company goal, or it may wish to focus on one location in which there is a specific driver, such as an emissions trading scheme. Likewise, the project may be intended to develop in stages, such as a refinery planning to reduce its carbon emissions by a set amount annually over a number of years.

As for any investment project, there will be a number of stakeholders involved, and it is important to keep them all positively engaged, particularly if a new technology such as CCS is to be applied. Non-governmental organizations (NGOs) and local residents may be concerned about the new technology and require reassurance that risks to the environment and safety are mitigated responsibly; they may also wish to know what other options were considered during the project development.

Market analysis.

There is a wide range of available schemes aimed at incentivizing high-energy efficiency and reduced CO2 emissions that augment the natural economic drivers for the process industry to minimize waste and maximize quality and output.

Understanding what incentives are available in the region in which a project will operate could enable the project to be significantly more economic if it can take advantage of such schemes. Examples include regional emissions trading and grants for new or clean technology demonstrations. Likewise, the reverse can apply, particularly with the currently uncertain future in terms of GHG emissions regulation where taxes or levies may be brought into force in the near future. Being at a transition point in legislation can make it particularly difficult to predict and select a firm basis for the investment, thus making market analysis particularly invaluable for this project.

There may be the opportunity to utilize captured CO2 for enhanced-oil recovery or enhanced-gas recovery, either by the project company, or sold over the fence to a neighboring operator, thereby generating a significant additional revenue stream. A refinery may be well placed for this application once commercial movement of CO2 by ship has been more widely demonstrated. Understanding the market and legislative context into which the project will fit will help mitigate the risks of being locked into expensive carbon penalties or high electricity or fuel prices while identifying any additional revenue streams not traditionally encountered.

Plant configuration studies.

Once the project objectives are defined and the applicable market and legislative framework are understood, then potential process routes and technologies can be identified. LP is extremely useful for determining the optimum configuration for energy efficiency and CO2 emissions minimization. The ability to run a number of “what if” scenarios, once the LP model has been developed, allows a picture of the project’s sensitivity to volatile fuel, electricity or carbon prices to be understood. It also allows the cost benefit of building in relatively capital-intensive, carbon-reduction options to be quantitatively assessed as well as assessing how to configure the plant for optimal conversion of feedstocks into highest margin products.

Just as the product yield and energy demand of each process unit is built into the LP model, so can be the CO2 emitted, immediately enabling the minimum CO2 emissions case to be identified. If the minimum emissions case is not economic without carbon capture due to a high anticipated carbon emissions penalty, then carbon capture units can be added to the model in the same way as any other process unit to understand if this improves the project margin despite the additional capital and operating cost.

Example. A hydrogen production unit (HPU) in a refinery produces a significant portion of the total site CO2 emissions and it can be the ideal candidate unit for a relatively quick win in terms of CO2 emissions reduction. A number of capture techniques can be applied:
A. Pre-combustion capture on HPU syngas between the shift reactor and the PSA unit.
B. Post-combustion capture on the HPU reformer itself (where the reformer is fired on PSA tail-gas).
C. Post-combustion carbon capture on other refinery fired heaters, fired on natural gas.

In this particular study, both of the hydrogen unit carbon capture options (A and B) delivered significant CO2 emissions reductions at a lower project cost (both capital and operating) than applying post-combustion capture to the other refinery fired heaters on the site.

Site selection.

While the market analysis will have dealt with locally applicable drivers and the price and availability of primary fuels and feedstocks, there are several additional points to be considered with respect to site location. Most critically, for a project to even consider CCS as an option for CO2 emissions management, a suitable storage location and transport route to that location must be identified in the earliest stages of the project.

While some projects may be conveniently located close to a depleted oil or gas field, others may be comparatively “stranded” until such a time as regional infrastructure, such as a CO2 collection and transportation hub, becomes available (if this is foreseeable within the planned lifetime of the plant). Options such as CO2 shipping can also be considered, although alternative technology selection or alternative site location may be the more appropriate choice. The site selection stage should also consider if renewables would be advantageous, particularly for coastal sites, sites with strong prevailing wind, high solar potential, or access to geothermal energy for water preheating.

For both new and existing sites, availability of extra plot space should be considered. Many countries are requiring that power generators prove that their new plant is carbon capture ready (CCR), which usually translates to ensuring there is sufficient additional space onsite to locate the capture plant.

Offsites and utilities.

Since the requirements for utilities and offsites are specific to the process configuration, these will be developed specifically for the configuration selected and included in the LP model. If carbon capture is to be included in either the initial design or added at a later date, the major utility requirements for CCS (i.e., power and cooling requirements for CO2 compression and heating requirements for solvent regeneration) will need to be included in the design capacity of the utility systems and/or integrated with the other process units where possible. Facilities for solvent storage and loading will also be required as suitable routing and metering for CO2 export facilities.

Constructability studies.

For a CCS project, the physical size of the equipment—particularly for the large-scale post-combustion scheme—presents real challenges in terms of ensuring constructability. In the largest cases envisaged (large-scale power generation schemes), the factor determining the number of CO2 absorption trains required is fixed by the capacity of the largest possible physical size of vessel that can be shipped to the site, proposed to be a 20-m-diameter column. Panel constructed square absorbers may avoid this limitation, in which case, other equipment items such as heat exchangers and direct contact cooler become the limiting train-size items.

For the solvent regeneration part, the train size is likely to be determined by the maximum physical size of reboilers that can be installed around the stripper to meet its needs. The constructability studies will also determine the plot space required for equipment laydown, along with the heavy lift cranes and other logistics of moving these large items of equipment to their final site locations.

Cost estimates, economic and financial modeling.

Economic modeling, when designing for minimum carbon footprint, may be made more complex than other projects due to considering a greater number of scenarios and the need to do additional sensitivity analysis to certain key variables such as impact of various legislation, taxation and subsidy regimes. Likewise, the impact of a particularly uncertain value revenue stream such as CO2 should be explored in depth to determine the scenarios in which different project options become economic.


This article has outlined the method and justification for following an investment planning roadmap to ensure that the optimum project is developed. With an investment planning roadmap, project objectives are well defined; the project is appropriate for the market; the configuration of the solution is optimal; the costs are well defined and the economic case is robust. This rigorous and staged process is particularly critical for projects in which there are a wide range of unknowns (such as future CO2 price or penalty and volatile fuel prices) coupled with an array of potential mitigation options. Breaking the investment planning process into manageable stages allows a clearer picture to be drawn and recorded with respect to which options have and have not been considered and how they compare against each other and against the overall objectives. HP


Updated version of the original presentation at the Green Forum, Oct. 4–5, 2010, London, 1st Green Refining & Petrochemicals Forum.


1 Carter, D., “Investment Planning—A roadmap to success,” The Chemical Engineer, July 2009.
2 Bullen, T. and M. Stockle, “Integrating Refinery CO2 Reduction into your Refinery,” Hydrocarbon Processing, November 2008.
3 Carter, D. and E. Petela, “Developing and Implementing the most appropriate energy management strategy,” ERTC, November 2008.
4 Bullen, T. and M. Stockle: “CO2 Infrastructure Development: CCS Options,” PTQ, October 2008.
5 Stockle, M., “Optimising Refinery CO2 Emissions,” ERTC, November 2007.
6 Ferguson, S., “Energy Security and Greenhouse Gas Management,” Lovraj Kumar Memorial Trust Annual Workshop, New Delhi, November 2009.

The author 

  Suzanne Ferguson is a chartered chemical engineer with an MEng (Hons) degree in chemical engineering from the University of Surrey. She joined Foster Wheeler in 2004 and has worked on refinery and hydrogen unit front-end engineering design (FEED) projects and performed basis of design, FEED and EPC-phase dynamic simulation for LNG projects. She has also worked on power island design at Foster Wheeler’s Italian operation in Milan. Ms. Ferguson is now Carbon Capture Technical head in Foster Wheeler’s Business Solutions Group, UK, where she has worked on a range of CCS studies, FEED and pre-FEED projects. 

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Lorax, you might be right.I think that inter-EU aivotian is either already in, or likely to be included in the next round of the EU ETS. Not sure if they're applying a multiplier though.

Rohit Joshi


Ghulam Shabbir

Good Effort and nice article on CCS

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