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
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.
INVESTMENT PLANNING 101
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 clients needs,
it is necessary to follow a simple but rigorous roadmap
process, as shown in Fig. 1.
1. The investment planning
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.
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
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
projects economic sensitivity to key product or feedstock
price variations to be understood.
The suitability of the proposed location (or locations) can
be assessed by considering four key factors:
ground conditions, structures and obstructions, severe weather
protection and earthquake zonal rating
dredging requirements, jetty location, existing facilities and suitability of
national road network, heavy haul routes, rail network and
regional and national airports
Local areaTowns 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
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.
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
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 companys long-term
outlook and consider a number of scenarios. The projects
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 developmentnot 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
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
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:
Carbon capture and storage (CCS).
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
Boiler feedwater preheating against
process-generated low-grade heat
Cooling water cooling against a cold process
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.
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 sites 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.
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 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 refinerys crude preheat train
may enable it to be reconfigured for improved total energy
CARBON CAPTURE AND STORAGE
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:
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
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
A range of coals, petcoke, fuel oils, municipal
solid waste and biomass can be used as gasifier
Natural gas and light liquid feedstocks can be used with a
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).
2. Pre-combustion flow
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
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 productioneven 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
A range of processes exists utilizing different
solvents: MEA, ammonia, sterically hindered MEA and even sea
For high-sulfur feeds, the process may be coupled
with a flue-gas desulfurization unit allowing the direct
contact cooler to be eliminated.
3. Post-combustion flow
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
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
A similar scheme has also been proposed for the
conversion of gas turbines to substitute oxygen for air.
4. Oxy-fuel flow scheme.
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.
INVESTMENT PLANNING FOR
CARBON FOOTPRINT REDUCTION
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.
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
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.
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
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
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
projects 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
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.
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
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.
For a CCS project, the physical size of the
equipmentparticularly for the large-scale post-combustion
schemepresents 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
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
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. 45, 2010, London, 1st Green Refining & Petrochemicals Forum.
1 Carter, D., Investment PlanningA
roadmap to success, The Chemical Engineer, July
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,
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.
||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 Wheelers Italian operation
in Milan. Ms. Ferguson is now Carbon Capture Technical head
in Foster Wheelers Business Solutions Group, UK,
where she has worked on a range of CCS studies, FEED and