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Reducing CO2 emissions
Several long-term challenges and opportunities face refiners after the introduction
of the European Union ETS. These include emissions monitoring, operational
improvements, emissions forecasting and economic emission reduction
Ian Moore
AspenTech UK Ltd
A
s if refineries were not under
enough pressure to optimise
operating performance, 2005 saw
additional worries introduced for all
refiners in the European Union. New
legislation came into effect that will
directly impact bottom-line profitability
and will bring increased focus (and
costs) to managing CO2 emissions.
The European Union Greenhouse Gas
Emissions Trading Scheme (EU ETS)
became reality on 1 January 2005. This
scheme covers over 12 000 installations,
accounting for approximately half of
Europe’s CO2 emissions. Under the EU
ETS, member states are responsible for
issuing allowances in accordance with
the final allocation, as indicated in their
National Allocation Plans (NAPS).
Companies covered by the scheme must
track their emissions and produce
verified annual emissions reports. They
must also ensure they have a sufficient
number of allowances to be surrendered
year-by-year
to
avoid
financial
sanctions, and additional local and
national pressures may yet drive true
site reductions as opposed to purchasing
allowances from the market.
Many refiners have battled just to
obtain the current state of emissions
measurement. Baseline data reflecting
previous emissions performance has been
collected and verified independently.
Procedures for monitoring and verifying
future emissions are being put in place
and approved, although there is still
some uncertainty as to the final
allocations for the 2005–2007 time frame.
Without this basis, the likely cost of
purchasing allowances is unclear. While
the main focus for refiners has been to
establish baseline emissions and to set up
systems for CO2 emissions tracking, the
purpose here is to discuss some of the
challenges that lie ahead for refiners once
these systems are up and running. These
include:
— Emissions monitoring
— Emissions forecasting
— Operational changes
— Emissions reduction.
The cost of the EU ETS to refiners will
not be simply about purchasing
allowances, but will include costs for
manpower, improved instrumentation,
more frequent laboratory analyses (and
possibly laboratory accreditation), thirdparty verification and the overhead
costs of trading allowances. An estimate
of the cost of purchasing allowances
alone can be made for UK refiners, based
on public domain information as shown
in Table 1. It is assumed that the basis of
the allowances granted under the UK
NAP represents 95% of the current CO2
emissions.
In the unlikely event that the refiners
do not purchase CO2 allowances to meet
actual emissions production, the cost of
exceeding the allowance for 2005–2007
is €40/tonne. It is almost certain that
the refiner would avoid this punitive
situation by purchasing CO2 allowances
at the market price, which is taken to be
€10/tonne in this example. On this
basis, the total cost for a typical large
refinery would be around €1–1.5
million per year. When averaged over
the total refinery energy cost, this
represents an increase in energy cost in
the region of 1%. However, the rise in
marginal energy cost is much higher,
around 20% (depending on CO2 and
fuel prices). This increase in marginal
costs represents another significant
incentive for refiners in the EU to focus
their attention on overall energy
consumption efficiency and reduction.
Emissions monitoring
The EU ETS monitoring and reporting
guidelines require high levels of
accuracy for the calculation of
emissions. A particular challenge for
refiners is the wide variability in
composition of one of the main fuels:
refinery fuel gas. Not only does this
impact upon measurements of calorific
value and carbon content, but it can
also introduce large errors into flow
meter readings if not corrected properly.
UK refinery preliminary CO2 allocations
Refinery
BP Oil
BP Oil
COP
Esso
Total
Innogy Cogen
LOR + Cogen
Petroplus
Shell
ChevronTexaco
Total
Location
Grangemouth
Coryton
Killingholme
Fawley
LOR, Killingholme
Killingholme
Killingholme
Teeside
Stanlow
Pembroke
Milford Haven
Annual allocation
tonnes CO2/yr
1 616 960
2 255 071
2 639 008
3 505 874
2 113 916
304 356
2 418 272
300 226
2 926 576
2 033 647
1 175 557
5% above alloc
tonnes CO2/yr
85 103
118 688
138 895
184 520
—
—
127 277
15 801
154 030
107 034
61 871
Table 1
1
P T Q Q2 2005
w w w. e p t q . c o m
5% at 40/tonne
million/yr
3.40
4.75
5.56
7.38
—
—
5.09
0.63
6.16
4.28
2.47
5% at 10 tonne
million/yr
0.85
1.19
1.39
1.85
—
—
1.27
0.16
1.54
1.07
0.62
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33.5
33
32.5
32
31.5
31
30.5
30
29.5
29
28.5
28
15
20
25
30
35
40
Feed API gravity
Figure 1 FCC regenerator CO2 emissions vs feed gravity
Historically, many refiners do not
routinely correct off-gas purge and fuel
gas flows for changes in specific gravity
(molecular weight), which also makes it
difficult to establish reliable hydrogen
and fuel gas balances.
With the EU ETS in place, many
refiners will use on-line gas density
analysers to accurately calculate fuel gas
mass flows. However, correlations
between density and calorific value
break down when there is more than
10% hydrogen and/or olefins in the fuel
gas, and this is normally the case.
Therefore, regular laboratory analyses of
fuel gas composition are required to
establish the emissions factor for fuel
gas, to allow CO2 emissions to be
calculated accurately.
More accurate flow meter correction
around the fuel gas system, and more
regular gas sampling, opens up the
opportunity for refiners to more closely
monitor their hydrogen and fuel gas
networks. AspenTech’s experience (PTQ
Spring 2003, pp83–90) is that closer
monitoring of these systems can
identify inefficiencies and losses with
high economic returns. These have
included large letdowns of hydrogen gas
to fuel gas, bypasses around LPGrecovery units and even open valves to
flare. In a recent study for a European
refinery,
AspenTech’s
proprietary
hydrogen planner software was used to
reconcile data around the refinery’s
hydrogen system. The hydrogen
content of the fuel gas routinely
measured around 50 mol%, yet the
simulated hydrogen content based on
metered purge flows to fuel gas was
around 30 mol%. Further investigation
identified that up to 12 000Nm_/h of
hydrogen-rich gas was being purged to
the fuel gas without metering.
AspenTech is now working with the
refinery to improve instrumentation,
flow meter calibration and update
control strategies to reduce this loss of
hydrogen. These improvements are
complementary to those being made for
CO2 monitoring.
Once emissions-monitoring systems
have been set up to comply with the EU
ETS, it is expected that more attention
will be given to how this information is
available to refinery personnel, head
office staff and the CO2 traders. The
components of the emissions calculations are likely to include oil accounting
reports, process data within the data
historian, laboratory information and
utility reports. The need to pull this
information together may lead to the
introduction of role-based visualisation
systems, allowing different personnel to
access on-line the data they require in
the context they need to fulfil their
functions quickly and consistently.
Operational changes
The introduction of the EU ETS and
associated marginal CO2 emissions costs
has the potential to change economic
decisions within the refinery operation.
Outside of the utility system, the major
refinery process unit operations that
impact refinery CO2 emissions are the
FCCU and the hydrogen plant.
Hydrogen demand for a site is
particularly high if the refinery has a
hydrocracker unit as part of its
configuration. Conventional wisdom is
that yield economics in the FCC and
hydrocracker process units always
outweigh utility considerations, and this
may still be the case at lower CO2 prices.
“CO2 prices approaching
€40/tonne can alter the
optimum FCC feed rate and
feed selection, as well as
process conditions affecting
conversion such as riser
outlet temperature”
2
P T Q Q2 2005
However, analysis using the proprietary
Aspen RefSYS refinery simulation
software shows that CO2 prices
approaching €40/tonne can alter the
optimum FCC feed rate and feed
selection, as well as process conditions
affecting conversion such as riser outlet
temperature.
Figure 1 shows the impact of varying
API gravity on CO2 production from the
regenerator, although it is important to
also consider the overall utility balance
for the unit. While CO2 emissions
calculation alone is unlikely to give
sufficient justification for building
such simulation models, it provides
additional justification for having these
models available to refinery staff.
The site economic (LP) model can be
updated to represent FCC unit CO2
emissions over a range of feeds and
operating conditions. Emissions from
hydrogen plant production (process and
fuel) can be estimated based on the
overall site hydrogen balance. Therefore, the impact of marginal CO2 costs
on optimum operation may be
evaluated easily within the LP model, if
CO2 emissions are represented correctly.
This will become more important in the
longer term as CO2 costs inevitably
increase. While ideally suited to the
evaluation of marginal economics, the
site LP is not the ideal tool to accurately
estimate the gap between emissions
allocation and actual production. Due
to the sensitivity of this calculation, it is
not normally practical to achieve the
fidelity of hydrogen, fuel and steam
balances required within the site LP
model.
Higher CO2 emissions costs will also
drive operational changes to reduce
energy consumption and to improve
overall energy efficiency across the
refinery. Areas likely to attract particular
attention are process furnace efficiencies, use of higher carbon content fuels,
and losses of hydrocarbons to flare.
A typical refinery fuel gas header
consists of multiple off-gas streams,
imported make-up gas (for volume
balancing), one or more enrichment
gases, fuel gas consumption in boiler
and furnaces, and pressure relief to the
flare. Enrichment gases such as propane
are periodically added to ensure fuel gas
quality is high enough for all furnaces,
although at times quality cannot be
controlled due to its effect on the
volume balance. Unstable fuel gas
header pressure and quality is a
common problem throughout the
industry, leading to flaring, excessive
enrichment costs and unstable furnace
operations. Flare losses and the use of
higher carbon content fuels relates
directly to increased CO2 emissions.
AspenTech has developed an on-line
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fuel gas optimisation (FGO) technology,
which includes inferential fuel gas
quality and volume imbalance prediction, non-linear dynamic optimisation,
and a furnace-monitoring and advisory
system.
Implementation of FGO applications
has typically given a 50% reduction in
flaring and a 20% drop in enrichments
costs. Additional benefits are improved
furnace efficiencies, more consistent
product qualities (for example, where
the process furnace is a feed heater or
reboiler) and more reliable process
operation. The FGO will always aim to
minimise operating costs, and in some
cases reductions in enrichment gas will
lead to higher carbon content fuel oil
being combusted. However, this is just a
function of refinery economics: refiners
will not switch to lower carbon content
fuels unless it is economical to do so.
Losses of fuel gas to flare are often not
metered within a refinery. Although an
estimate of hydrocarbon losses (and
hence CO2 emissions) can be made from
an overall carbon balance for the
refinery, this calculation is highly
inaccurate. In many cases, the refiners
can apply a “de minimis” approach to
flare emissions (less than 1% of total)
subject to approval of the competent
authority. This allows flare CO2
emissions to be calculated by use of
non-intrusive ultrasonic flow meters. It
may well be the case that the
requirement under the EU ETS to
quantify hydrocarbon losses to flaring
will allow refiners to more accurately
quantify the benefits from reducing
such losses, and provide the economic
justification to install improved fuel gascontrol systems and flare gas-recovery
systems.
CO2 emissions forecasting
It can be expected that the price of CO2
allowances will be most volatile after the
end of each yearly period (January to
March) when CO2 emissions accounts
will be finalised and audited. Refiners
are unlikely to wait for this period
before
making
any
purchasing
decisions, and will look to make these
decisions over the year in line with the
predicted gap between actual emissions
and owned allowances. One of the
challenges refiners are therefore facing is
to develop methodologies and tools for
prediction of CO2 emissions ahead of
time (demand forecasting), to reduce
the level of uncertainty and support
more economic trading decisions.
The most obvious tools for doing this
work are the refinery planning and
scheduling tools. It is unlikely that
refiners will wish to make short-term
predictions based on scheduling tools. It
is more likely that the site LP planning
Production planning and
scheduling
aspenONE Energy Management
for petroleum
Hydrogen
Manager
Utilities
Planner
H2 network
& fuel gas
model
Utilities
plant
model
Simplified
H2 plant
model
Simplified
FCC CO 2
model
Data historian
DCS
Figure 2 Architecture for demand forecasting solution
model will be considered for CO2
emissions forecasting. However, as the
cost of CO2 emissions only applies at the
margin of yearly production, small
errors in the prediction of emissions
have a big impact on the requirement to
buy or sell emissions. For example, if the
allowance allocation is 95% of expected
emissions, then a 1% error in predicted
emissions will change the required
credits purchase by 20%. As already
stated, while the LP model is the ideal
tool for evaluating marginal economics,
it is not normally practical to achieve
the level of fidelity required for
hydrogen, fuel and steam balances
required within the site LP model.
There is an obvious balance to be
made here between the accuracy of the
models used for prediction and the
uncertainty in the assumptions made
about long-term plans in the first place.
A high degree of rigour in the models
adds little value if accuracy improvements are swamped by uncertainties in
the base data. However, it is our
experience from utility demand
forecasting that there are substantial
benefits from using rigorous utility
models to establish future demands,
3
P T Q Q2 2005
based on production plans provided by
the LP tool. Therefore, the components
of accurate CO2 emissions forecasting
should include:
— Production plans for the major
process units (from the site LP model)
— FCC emissions (from the site LP
model, calibrated from reactor models
— Hydrogen network and fuel gas
balance simulation
— Hydrogen plant model
— Utility system simulation.
These components are combined in
the Utilities Planner module of the
aspenONE Energy Management for
Petroleum solution. The software
architecture for this solution is shown in
Figure 2.
Almost all refiners import some
utilities, whether these are power, steam
and/or hydrogen from a third-party
supplier. Under the EU ETS, responsibility for the CO2 emissions associated
with the production of these utilities lies
with the provider, not with the
purchaser. However, it is anticipated
that the CO2 costs will ultimately be
passed on to the purchaser as part of the
utility price. Hence, the cost of CO2
associated
with,
say,
hydrogen
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production will ultimately depend on
whether or not the refiner generates
hydrogen itself or imports it as a utility.
One interesting point, though, is that
the supplier is likely to average this
emissions cost over the whole import
load, whereas the refinery is paying for
CO2 purely at the margin of the gap
between actual emissions and owned
allowances. This could potentially have
an impact on utility operations and
purchase decisions if CO2 prices are
high. For example, the economics of
running a condensing turbine depends
upon the import power price, the
internal fuel price and the site CO2 cost.
CO2 reduction
With already high-energy costs and the
introduction of the EU ETS, refiners are
under increasing pressure to develop
strategies to reduce CO2 emissions and
energy costs. Normally, this challenge is
passed down from the refinery manager
to the site energy co-ordinator, as the
most cost-effective way to reduce
emissions is seen as energy efficiency
improvements. It is tempting to
consider CO2 emissions reduction as
only an energy performance issue,
which is understandable but may lead to
some opportunities through process
operational changes being missed.
Developing the optimum strategy to
meet CO2 emissions targets requires the
evaluation of many different options,
which can include:
1. The scope for refinery-wide energy
efficiency: improved energy efficiency
will lead to reduced fuel usage and
hence CO2 reduction. Any study needs
to consider both operational improvements (for example, improved furnace
operation and capital projects, addition
of heat exchanger surface and
conversion of steam turbine drives to
electric motors)
2. Reducing CO2 emissions through
improvements
in
production
processes: for many refiners, the FCCU
catalytic cracking operation can
contribute to over 50% of refinery CO2
emissions.
Catalytic
cracking
is
therefore a CO2-intensive operation,
while other processes such as delayed
coking capture the carbon and prevent
its release as CO2. Delayed coking is
therefore a CO2 non-intensive process
and may perhaps be regarded as the
only proven process for carbon
sequestration. Opportunities to redirect
streams from CO2-intensive to nonintensive processes are therefore
important, particularly if CO2 prices
increase in the longer term
3. Reducing carbon concentration in
fuel gas: most refinery fuel gas streams
contain relatively large amounts of C3+
material. By improving the level of LPG
“The cost of CO2 associated
with, say, hydrogen
production will ultimately
depend on whether or not
the refiner generates
hydrogen itself or imports it
as a utility”
recovery, the refinery fuel gas can be
made lighter, which in turn results in
fewer CO2 emissions. Fuel lost by the
removal of LPG components is normally
made up by natural gas. As already
discussed, use of enrichment gases can
also be minimised to lower fuel carbon
content
4. Cogeneration: for those refineries
that currently import power, there is an
overall benefit in moving to highefficiency, gas turbine-based cogeneration
systems.
While
installing
cogeneration means increased CO2
emissions at the refinery, the overall
benefits in CO2 emissions reduction are
large when taking into account the
much lower thermal efficiency of a
conventional power plant that would
otherwise supply the refinery’s power
needs
5. Reduced losses: issues such as
reduced flaring through improved
control and flare gas recovery need to be
considered.
6. Processing of lighter crudes: while
the processing of lighter crudes may
have an adverse effect on refinery
margins, the use of lighter crudes can
provide an option to refiners. This is
only likely to be an option in extreme
circumstances purely based on marginal
CO2 prices
7. Removal and recovery of CO2 from
furnace flue gases: various technologies
are available for CO2 removal such as
absorption and membranes. Several uses
can be made of the CO2 recovered:
typically, as feedstock (for example, in
urea production), in food and drink
manufacture, and for enhanced oil
recovery in oil reservoirs.
It is clear that some of these options
involve very large capital investment
decisions. If global emissions are
considered in preference to local
emissions, CO2 costs will increase the
attractiveness of cogeneration projects,
but no refiner will go ahead with a
cogeneration project solely for CO2
savings. Similarly, one cannot see a
refiner installing a non-intensive CO2
process unit or CO2-removal technology
without strong process reasons or an
almost unimaginable increase in CO2
price.
4
P T Q Q2 2005
Options 2 and 6 can be considered
from an operational perspective using
the site LP model, as long as CO2
emissions production is correctly
represented in the model. Option 7 is
unlikely to be considered seriously by
most refiners, unless a cap on CO2
emissions is threatened. Therefore, the
main focus of most CO2-reduction
strategies will include options 1, 2 and
5, with consideration given to planned
cogeneration schemes and process unit
operational changes.
Recently, AspenTech and Air Liquide
Italia completed a Phase 1 CO2
emissions-reduction study for Saras SpA.
Italy, which illustrates some of the points
previously discussed. The scope of the
study included both energy reduction
and hydrogen management. The
duration of this study was around six
months and focused on the Sarroch
refinery located in Sardinia, Italy. While
the refinery has its own power plant, it
also imports steam and hydrogen from
the adjacent Sarlux plant. Sarlux is an
integrated gasification combined cycle
(IGCC) plant taking residual oil from the
refinery and producing 550MW power
for the Sardinian grid. Sardinia does not
currently have a natural gas supply,
although this may be available in the
future if a pipeline is installed from
Algeria to mainland Italy via Sardinia.
The main objectives of this study were to:
— Establish a baseline for current
refinery CO2 production
— Identify the scope for reducing these
emissions through technically feasible
projects
— Assess the impact of hydrogenrecovery projects on these emissions,
both for current operation and for autooil projects
— Develop a preliminary roadmap for
refinery investment to reduce CO2
emissions.
After data collection, the first step in
the analysis was to build heat balances
for the individual process units, an
overall steam balance, and a model of
the hydrogen network and fuel gas
system. These balances then allowed a
baseline for current CO2 emissions to be
established.
It should be highlighted that this
baseline was not the same as that
reported by Saras to the Italian
authorities, and for deliberate reasons.
The “informal” baseline used in this
study included CO2 allocations for
imported power, steam and hydrogen.
This is because Saras wanted to look at
CO2 emissions from a global perspective
and not purely at local emissions within
the refinery. Partly this was because of
Saras’ partial ownership of Sarlux (and
hence its related emissions). More
importantly, however, Saras wants to
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— Reducing the average carbon
content of fuel (lower CO2 production
for fixed heat duty). For example,
reducing LPG content of fuel gas and
make-up with natural gas.
The primary emphasis in this phase
was on potential capital investment
projects, although opportunities for
fouling
reduction,
pumparound
optimisation and other operational
improvements were considered. For
each of the individual refinery process
units, Pinch analysis was applied to
establish targets for energy savings
through improved heat recovery.
The overall level of potential energy
savings within the process units
identified was 10%. A typical target
energy saving for an average-performing
refinery would be around 17%. Hence,
the lower savings potential for the Saras
refinery indicates that the process units
as a whole already have a good degree of
energy efficiency. This energy saving
represents a saving of 7.5% in emissions,
if emissions associated with imported
steam and power are included in the
baseline.
Further energy savings potential
through interaction between the
processes and the utility system were
identified using the proprietary Total
Site Analysis method. The two major
opportunities were a hot water loop to
recover low-grade heat for heating, and
heating feedwater to the main boiler
deaerators (DFW heating). More detailed
analysis and cost estimation is still
required to confirm the feasibility of
these projects. The weighted average
furnace efficiency for the refinery was
install projects that give global benefits,
rather than just exploiting local
boundaries of legislation. For example,
consider a refiner that imports hydrogen
rather than owning its own hydrogen
plant. Any internal hydrogen-recovery
project from fuel gas will inevitably
increase local CO2 emissions. This is
because the energy content of hydrogen
in the fuel gas will have to be replaced
by a carbon-containing fuel, probably
natural gas or fuel oil. Globally, the
saving from CO2 from reduced
hydrogen production should more than
offset the local increase, and so
improving hydrogen efficiency should
have a positive environmental benefit.
Similar arguments apply to cogeneration projects, and even simple
operational changes such as switching a
process drive from a steam turbine
(internal fuel) to an electric motor
(imported power).
With specific regards to energy
performance, the main focus of the
study was:
— Reducing absorbed process furnace
duties (saving fuel fired and hence CO2
produced). For example, increasing a
furnace inlet temperature by additional
preheat
— Reducing boiler steam demand (by
lowering process consumption or raising
process steam generation). For example,
increased steam generation from FCCU
pumparound streams
— Increasing furnace and boiler
efficiencies (saving fuel fired and hence
CO2 produced). For example, control
projects to reduce excess air, or capital
investment in air preheat
lower than that expected for a top
energy-performing refinery. Potential
savings through no- or low-cost furnace
efficiency improvement projects were
estimated, as well as savings from
projects requiring higher capital
investment for equipment items such as
air preheaters.
Other options for reducing refinery
CO2 emissions, including FCC yield
changes and replacing fuel oil firing by
natural gas (if available in the future)
were also briefly considered. The
improvement roadmap for the energy
portion of the Saras CO2-reduction
study is shown in Figure 3. Actual CO2
savings
are
not
shown
for
confidentiality reasons. The potential
switching of fuel oil firing to natural gas
is shown for comparative purposes,
should a natural gas supply become
available in the future.
In Figure 3, projects with lower
capital investment and those that can be
implemented quickly are given a higher
priority. The financial benefits of each
project depend upon both energy and
CO2 prices. The projects identified as
part of the hydrogen study are relatively
carbon-neutral if emissions from Sarlux
are considered. Therefore, they are not
detailed in this discussion. AspenTech is
now working with Saras to define a plan
for more detailed project identification
and implementation in line with the
expected turnaround plans for each
process unit.
Challenges and opportunities
Understandably, in the area of CO2
emissions, refiners have so far
FCC yield changes
Higher cost furnace
%
Low cost
furnace
Higher cost process
energy changes
Low-cost
process
DFW
heating
Hot water loop
Natural gas supply
Now
T1
Refinery CO2 reduction (ktonnes/yr)
Figure 3 Preliminary roadmap for CO2 reduction
T2
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Site-wide energy and CO2 reduction audit
No
No
Fuel gas
Utilities
optimisation
management
benefits clear? benefits clear?
Yes
Site-wide
energy-reduction
study
Hydrogen
Yes
optimisation
benefits clear?
No
Yes
Utilities
benefits
study
Fuel gas
study
Process
improvement
projects
Stop
Stop
Attractive
Attractive
Attractive
Aspen utilities
implementation
Hydrogen
study
Gas system
decision
support
Fuel gas
optimiser
Hydrogen
compsite LP
CO2 management
Figure 4 Suggested approach to refinery CO2 reduction
concentrated on achieving compliance
with the EU ETS and on putting systems
in place to be able to calculate CO2
emissions to the satisfaction of their
authorities. The speed at which each
refiner has proceeded with this work has
to some extent been determined by the
speed of movement at national levels.
Some refiners have verified systems
already in place, whereas others are still
working with the authorities for
verification and approval. However, as
the challenge of having these systems
up and running has largely been
overcome, refiners are now starting to
focus on the challenges ahead. As
described in this article, these will
include providing a greater visibility to
continuous emissions monitoring,
evaluating the impact of CO2 cost on
plant and utility operations, forecasting
of emissions to support trading
decisions, and ultimately a drive to
reduce emissions.
Although in many ways these
represent challenges refiners can do
without, there are also opportunities to
be captured. Hydrogen-, fuel gas- and
LPG-recovery systems often do not get
much attention within a refinery and, as
a consequence, losses to fuel gas and
flare are significant. Closer monitoring
of these systems through improved
instrumentation, flowmeter correction,
process control and operator support
tools will give high levels of return on
investment.
Looking at the business processes
around CO2 emissions as whole, there
are a variety of tools a refinery can use
for monitoring, identifying beneficial
operating changes, forecasting and CO2
Tools for refinery CO2 management
Tool
Monitoring
Yield accounting
LP planning
Utilities model
H2/Fuel gas model
Control/APC
FCC model
Process models
Pinch tools
Role-based visualisation
Event management
Table 2
✔
—
✔
✔
—
—
—
—
✔
—
Operational
changes
—
✔
✔
✔
✔
✔
—
—
—
✔
Forecasting
projects
—
✔
✔
✔
—
✔
—
—
—
—
Improvement
—
—
✔
—
—
—
✔
✔
—
—
reduction. These are shown in Table 2.
Increasing fuel prices, combined with
the EU ETS, will help to drive CO2
reduction projects. The question facing
refiners is “where to start?” An audit
process has been developed to quickly
identify areas within the hydrogen, fuel
gas and utility systems that offer the
most potential for economic savings
(Figure 4).
This approach considers a wide range
of opportunities for CO2 reduction, from
on-line optimisation of the hydrogen,
fuel gas and utility systems, through to
capital investment studies in preheat
trains and furnace efficiency improvement projects. In this way, the refiner
can identify the optimum long-term
strategy for CO2 reduction.
Aspen RefSYS simulator software, Total Site
Analysis, Fuel Gas Optimisation (FGO),
and the Utilities Planner module of the
aspenONE Energy Management for
Petroleum
solution
are
registered
trademarked products of AspenTech.
Ian Moore is a senior advisor in the
AspenTech UK Ltd, European services
organisation. He is based in the UK and is
responsible for managing process
modelling, energy improvement and
emissions reduction projects. Moore
graduated in chemical engineering from
Exeter University and holds a M Eng
degree from McMaster University in
Canada. Email: [email protected]