within the facility, including boiler feed water heating, carbon capture and compression plant heating and cooling requirements. A novel technique for reuse of ...
Efficiency improvements in fossil-fired power generation with post-combustion carbon capture via improved heat integration and reuse of low grade heat
By Tim Bullen, Manager, CCS and Gasification and Suzanne Ferguson, Carbon Capture Technical Lead
Business Solutions Group, Foster Wheeler, UK
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Abstract Adding CO2 capture to fossil-fuelled power generation results in significant plant efficiency penalties, impacting the performance and economics of the plant. This paper evaluates energy recovery and heat integration options targeted to improve the overall efficiency of power generation schemes with post-combustion CO2 capture. The paper considers post-combustion CO2 capture from a new-build pulverised coal plant, although several suggested improvements may also be applied to other power generation schemes. The methods applied include application of pinch analysis to a number of areas within the facility, including boiler feed water heating, carbon capture and compression plant heating and cooling requirements.
A novel technique for reuse of low grade heat and
minimisation of cooling water is also included.
The potential for a 2.2 %-point efficiency improvement (on an LHV basis) is demonstrated for a coal-fired power plant with 90% carbon capture via process engineering improvements and application of currently available technologies and equipment items.
Introduction Climate change resulting from increased levels of atmospheric greenhouse gases such as carbon dioxide (CO2) could, many believe, be a serious threat to the environment and the world economy. A significant portion of these CO2 emissions are emitted into the atmosphere when hydrocarbon fuels are burned to produce energy, particularly in the power sector. One emerging technology, or set of technologies, that has been proposed to mitigate future CO2 emissions is carbon capture and storage (CCS).
Carbon capture can be applied to oil-, coal- or natural gas-based electricity generation, and there are three main process routes that can be considered. These are: •
pre-combustion capture
•
post-combustion capture
•
oxyfuel combustion
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This papper is focussed on post--combustionn carbon caapture poweer plants. Inn an earlier paper(1), Foster Wheeler W ideentified effiiciency impprovements which coulld be anticiipated in the future, due to parasitic looad reductioons in a nuumber of key k areas annd quantifiied their im mpact on overall efficiency of the pow wer plant. The papeer showed that t improvvements in solvent regeneraation parasitic load, optimum o CO O2 compresssion route and optimuum heat inttegration betweenn major plant p units could bee anticipateed to achiieve 3.2 % %-point effficiency improveement (LHV V basis) relaative to the current statte of the art overall projject designss.
This paaper investiggates these possible saavings in more m detail, with the exxception off solvent regeneraation, as significant efffort is alreeady being devoted to this area bby a broad range r of groups, including existing CO C 2 capturee technolog gy providerrs.
The sccope of thiis paper
includess the calculaation of heaat and materrial balancees and outlinne equipmennt sizing forr the full plant annd includes quantificattion of the overall cosst impact foor each casee relative to o a Base Case.
Base Caase The posst-combustioon carbon capture c pow wer generatio on system base b case coonsidered within w the scope of this paperr is an ultra--supercriticaal pulverised d coal-firedd steam cyclle plant.
Ultra-S Supercriticaal Pulveriseed Coal (USCPC)
Figure 1: Pulverissed Coal Simplified Fllowschemee
ominally 8000 MWe cappacity was assumed. a For thiss case a singgle pulveriseed coal-fired unit of no The boiiler was sim mulated as raaising steam m at 275 barra/600°C with w single reeheat to 600 0°C, and incorporating selective catalyytic reducttion (SCR) for nitrouus oxides ((NOx) remo oval, an electrosstatic precippitator (ESP P) for particculate remo oval, and a flue gas deesulphurisattion unit (FGD) utilising lim mestone scrrubbing forr sulphur dioxide d (SO O2) removall. An amin ne-based 3
post-combustion carbon capture process was applied to capture 90% of the CO2 emissions of this plant, followed by CO2 compression to 150 barg with CO2 dehydration.
Base Case Gross Power Generated
MWe
741
Power Island
MWe
-29
CO2 Capture
MWe
-10
CO2 Compression
MWe
-54
Others
MWe
-35
Total Auxiliary Loads
MWe
-128
Net Power Export
MWe
613
Net Efficiency (LHV basis)
%
33.7
Total carbon in feeds
tpd
3981
Total carbon captured
tpd
3582
Total CO2 emissions
tpd
1465
CO2 emissions
g CO2/kWhNet
100
Table 1: Base Case Performance Data
Efficiency Improvement Options
Case 1 – Improved CO2 Compression Route – Recently much work has been done to investigate means of reducing the power requirement for CO2 compression. In a recent paper by GE(2) savings of up to 20% are anticipated by varying the compression route by alternatively using a combination of CO2 compression,
liquefaction and pumping, and
achieving liquefaction at the lowest possible pressure for the available cooling medium. Further savings could be achieved by introducing refrigeration cycles as a means of further reducing the liquefaction pressure; however, the power requirement of the refrigeration cycle was shown to offset the benefit of increased CO2 compression chain efficiency.
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For our example plant the lowest available temperature cooling media is sea water. However, previous study work has shown in some circumstances that the overall project economics are favoured by use of the slightly higher temperature sea water cooled fresh cooling water loop, thus enabling carbon steel to be selected for the material of construction on the water side, rather than titanium. This choice should be made on a case by case basis.
Initially, for the first step in improving the overall plant efficiency, we have therefore kept the compression inter-cooling media as fresh cooling water, unchanged from the base case plant.
Case 1 Performance results: Using 14°C fresh cooling water the corresponding pressure for condensation of our CO2 product stream is 65 bara. The base case total power for achieving 150 barg CO2 was 54.1MWe via compression.
To move to the optimum balance of
compression and pumping, the outlet pressures of the first five stages of compression were then modified to achieve a 5th stage outlet pressure of 66 bara. After condensation a single stage of pumping was added, with performance data supplied by an experienced CO2 pump vendor.
The pump efficiency was quoted as 80% (83% efficiency was used for the
compressor, based upon Foster Wheeler’s previous project experience) and resulted in a total power requirement of 48.5 MWe, a saving of 10.4% on the power required to deliver CO2 at 150 barg, and a total improvement in the plant efficiency of 0.31% points. This improvement could be increased if it were possible to use a lower temperature cooling media and hence reduce the pressure at which CO2 condensation occurs. Case 1 Cost results: The cost impact of making this change was also assessed, using Foster Wheeler’s internal cost database and estimating software. The impact of this change on the total installed cost was a very slight decrease of 0.8% on CAPEX compared to the base case. The efficiency improvement and CAPEX change combine to reduce the levelised cost of electricity from the base case cost of £76.9 /MWh to £75.9/MWh (based upon zero value for CO2 and a 30-year plant life). Case 2 – Increase Heat Integration – Many of the post-combustion CO2 capture process technology units already include a significant degree of heat integration in order to minimise the need for hot and cold utilities. In this case options to improve this integration have been investigated along with heat integration with other areas of the plant, such as CO2 compression and the power island. 5
As well as the large quantity of heat required for solvent regeneration there is a significant requirement for cooling in the amine-based post-combustion carbon capture flow scheme. This heat is challenging to recover since it is at a relatively low grade – ranging from maximum temperatures in the range of 90°C to 50°C with cooling to 30°C or 24°C needed for process reasons. A significant degree of heat integration also exists within the power island. In the design assumed in this paper the coal boiler system consists of a once through, wall-fired, balanced draft, ultra-supercritical pulverised coal-fired plant. Forced draft fans supply air to the burner system via air preheaters in which the air is heated against the boiler flue gas. This air is distributed to the burner windbox as secondary air. Air from the primary air fans is also preheated against flue gas and is used as combustion air, a portion of this air bypasses the preheaters and is used for tempering the pulverisers’ fuel-air mixture outlet temperature. The hot combustion products rise to the top of the boiler and pass horizontally through the secondary superheater and reheater.
The gases then pass downwards over the primary
superheater, economiser and air preheater. The flue gases then pass through the SCR and ESP. Before being fed to the FGD, heat is recovered between the still hot flue gas and the cool, treated flue gas from the top of the absorber in the CO2 capture unit in order to ensure sufficient buoyancy for dispersion and prevention of a visible plume from the stack. The cooled flue gas then passes through the FGD before being fed to the CO2 capture system. By extending the boundaries for heat integration to consider the power island, CO2 capture unit and the CO2 compression unit as one complete system it is usually possible to increase the total amount of recoverable heat and hence reduce the overall parasitic load of the plant.
In order to ensure that optimum heat integration has been achieved it is necessary to use a rigorous method, such as pinch analysis, in order to determine the maximum degree of energy integration possible. This then needs to be tempered with practical considerations such as process complexity and operability impact, pressure drop and cost impact.
Table 2, below, shows the major streams which require heating and cooling within the overall pulverised coal post-combustion case. (The flue gas streams to and from the CO2 capture
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plant have been excluded from this list as they must exchange heat with each other in order to ensure minimum temperature feed to the CO2 capture plant and maximum reheating of the treated flue gas to ensure it has sufficient buoyancy to be emitted through the stack whilst simultaneously minimising the pressure drop of both streams.)
Stream Name
Type
Heat Load
Source Temperatur e
(MWth
Target
Notes
Temperature
(°C)
(°C)
) A Rich solvent to
Cold
356
46
93
stripper B Rich solvent to
Higher temperature would reduce reboiler load
Cold
230
46
103
Phase change present
C Stripper reboiler
Cold
491
116
118
Phase change present
D BFW heating
Cold
270
25
200
Or as high as possible
E Lean solvent
Hot
654
118
30
F Semi-lean solvent
Hot
132
103
48
G Absorber
Hot
163
54
36
H Flash vapour
Hot
67
103
35
Phase change present
I
Hot
98
86
30
Minimise ΔP here, phase
flash
extraction
Stripper OH condenser
J
change present
DCC Water
Hot
73
49
30
K CO2 compressor
Hot
47
93
24
inter-cooling
Lower temp. would increase compression efficiency, minimise ΔP
L CO2 condensation
Hot
38
104
24
Phase change present
Table 2: Process Stream Heat Integration Characteristics It should be noted that the power island boiler feed water (BFW) eventually needs to be heated up to a temperature of approximately 300°C. Without heat integration the entire BFW stream would be heated from its condensation temperature of 25°C up to 300°C by extracting 7
steam from the power island steam turbine at various pressure levels. By achieving as much of this heating as possible via integration with the CO2 capture process, these steam extractions can be reduced, hence increasing the power output of the steam turbine and overall plant efficiency.
Table 2, above, shows that the total quantity of cooling required (1272 MWth) exceeds the total quantity of heating required (1347 MWth). Plotting the streams individually shows that many of them are in the same temperature range, and hence may be suitable for heat integration:
Figure 2: Temperature – Enthalpy Graph of Individual Streams
Immediately it is clear that there is no process stream which can supply the heat required for Stream C, the stripper reboiler, hence this duty must be supplied externally, using steam and should be minimised. In Table 2 it was noted, however, that increasing the temperature of the
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stripper feed (Stream A) by a few degrees (if possible without using external utilities) reduces the heat load of Stream C.
In order to see the maximum quantity of heat which can be reused the 12 trends shown in Figure 2 should be combined into composite curves for hot streams (those which need cooling) and cold streams (those which need heating). Composite curves are formed by summing the product of the mass flow rate and mass heat capacity of all the streams which appear in a given temperature range(3).
For example, between 104°C and 103°C hot streams E and L are present hence,
hot composite curve heat capacity (104°C to 103°C) = mCpE + mCpL The composite curves for our process, assuming a pinch of 3°C, are shown below (it should be noted that the calculation of mCp in the graph below has been simplified to only include the stream inlet Cp, rather than including its variation with temperature, and that phase changes are assumed to occur at a single temperature):
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ΔΗhot ΔTmin
ΔΗcold c
ΔΗreecoverable
Figure 3: Compossite Curves t minimum amount of o hot utilityy required, ΔHhot, is From thhese curves we can connclude that the approximately 6500 MWth annd the minnimum amo ount of colld utility rrequired, ΔH Δ cold, is approximately 6000 MWth. The T maxim mum heat which w can be b recovereed between process streams was found to be approoximately 6440 MWth. The nexxt step is to determine the t optimum m network of o heat exchhangers in oorder to get as close as possible to the target figuure of 640 MW M th heat.. A numbeer of potenttial heat ex xchanger mple heat trransfer calcculations baased in Exccel. The networkks were devveloped, ussing the sim most prromising weere then verrified in Asspen HYSY YS® to ensuure that thee simplified d method had nott arrived att a solutionn which thee Aspen HYSYS® H m more accurrate heat ex xchanger models could not match. m
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It was identified that, by modifying several of the exchanger inlet or outlet temperatures it was possible to increase the temperature of the stripper feed from 93°C to 98°C as well as incorporating significant heating of the power island boiler feed water, to 101°C against the semi-lean flashed vapour and solvent.
Figure 4: Case 1 Heat Exchange Network
Figure 5: Case 2 Heat Exchange Network
Case 2 Performance results: Incorporating these modifications into the overall power plant model resulted in 10 MWe increased power output from the steam turbine (due to reduced reboiler load as well as reduced boiler feed water heating load) and 1 MWe less total power 11
demand (due to reduced cooling water pumping requirements) compared with Case 1. This translates to an efficiency improvement of 0.6 % points (LHV basis), or 11 MWe increased net power output (or, when combined with the Case 1 CO2 compression route modifications an efficiency improvement of 0.9 % points (LHV basis), and 16 MWe increased net power output compared to the original base case).
Case 2 Cost results: As for Case 1, the cost impact of making this change was assessed, using Foster Wheeler’s internal cost database and estimating software. The impact of this change on the total installed cost was an increase of 4.0% in CAPEX relative to Case 1. The efficiency improvement and CAPEX change combine to reduce the levelised cost of electricity from the Base Case cost of £76.9 /MWh to £76.2/MWh (based upon zero value for CO2 and a 30 year plant life). Case 3 - Low Grade Heat Recovery – The heat exchanger network developed in Case 2 above still leaves a significant quantity of low grade heat which cannot be usefully recovered via heat integration within the CO2 capture process, power island or CO2 compression and pumping unit. The total remaining cooling load in Case 2 is approximately 600 MWth, which is rejected to cooling water and ultimately to the environment via the sea-water cooling system. In order to make use of this heat, a heat pump or a heat engine could be used.
Systems such as organic rankine cycles (ORCs) use the heat engine theory to produce power from waste heat at efficiencies as high as 20%(4).
However, the efficiency decreases
significantly for very low-grade heat (low temperature difference between heat source and available cooling media). The benefit of using such a system would be to generate some useful power instead of losing all of this energy directly to the environment.
A simple propane based ORC loop was added to our process simulation by removing the cooling water from the four largest, low-grade coolers (the DCC cooler, lean solvent cooler, extraction cooler and stripper condenser). The working fluid is vaporised in the process coolers, passed through a turbine, producing mechanical power, condensed against sea cooling water and pumped back to complete the loop. Of the four working fluids considered (propane, ethane, butane and LPG – 70% propane, 30% butane) propane showed the most favourable characteristics.
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Our ORC is constrained firstly by the temperature of the coolest available cooling media, sea water. This temperature determines the operating temperature and pressure of the condenser. The second constraint is the maximum overall temperature to which the propane can be heated and vaporised by our process streams, and hence the pressure at the inlet of the turbine. It was found that, allowing one bar pressure drop through the exchangers and associated pipework, the propane supply pressure to the process coolers was limited to 13.5 bara, with the condenser operating at 7.2 bara.
Figure 6: Case 3 Heat Exchange Network
Figure 7: Propane Cooling Loop Flow Scheme
This simple propane loop system was able to supply the required 500 MWth of cooling to the four largest cooling media users while generating 23.5 MW of mechanical power, based on an 13
assumed turbine efficiency of 75% (the CO2 compressor intercoolers and the CO2 condenser, totalling approximately 100 MWth, are smaller individual loads and, for simplicity, were kept on the fresh water cooling system). This power could be transformed into electrical power via a generator, but a neater solution would be to utilise this power as a mechanical helper motor on the CO2 compressor (whose duty is approximately 48 MWe). Case 3 Performance results: Incorporating the propane loop into the overall power plant model resulted in 2 MWe parasitic power increase due to the propane pump, an approximately 23.5 MWe reduction in electrical power required for the CO2 compressor and a 3 MWe reduction in power requirements for the fresh cooling water system. Overall, an additional 24MWe was added to the plant’s net power output, compared to Case 2, an efficiency increase of 1.3 % points (LHV basis) (or, when combined with the improved CO2 compression route and heat integration improvements, an efficiency improvement of 2.2 % points (LHV basis), and 41 MWe increased net power output compared to the original base case).
Case 3 Cost results: The impact of this change on the total installed cost was an increase of 7.7% on CAPEX compared to Case 2. The efficiency improvement and CAPEX change combine to reduce the levelised cost of electricity from the base case cost of £76.9 /MWh to £76.6/MWh (based upon zero value for CO2 and a 30-year plant life).
Conclusions Overall Performance: By incorporating each of the suggested improvements above into our base case flow scheme, an increase in the net power output of approximately 7% and consequently an increase of approximately 2.2 percentage points in overall efficiency (LHV basis) is achieved.
Overall Cost: The impact of this change on the total installed cost for our power plant was an increase of 10.9% on CAPEX.
The efficiency improvement and CAPEX change
combined to reduce the levelised cost of electricity from the plant from the base case cost of £76.9 /MWh to £76.6/MWh (based upon zero value for CO2 and a 30-year plant life). The key numerical results of this study are summarised in the table below:
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Base Case
Case 1
Case 2
Case 3
Improved
Increased
Low Grade
Compression
Heat
Energy
Route
Integration
Recovery
Gross Power Generated MWe
741
741
751
751
Power Island
MWe
-29
-29
-29
-29
CO2 Capture
MWe
-10
-10
-10
-12
CO2 Compression
MWe
-54
-48
-48
-25
Others
MWe
-35
-35
-34
-31
Total Auxiliary Loads
MWe
-128
-122
-121
-97
Net Power Export
MWe
613
619
630
654
Net Efficiency (LHV)
%
33.7
34.0
34.6
35.9
Total carbon in feeds
tpd
3981
3981
3981
3981
Total carbon captured
tpd
3582
3582
3582
3582
Total CO2 emissions
tpd
1465
1465
1465
1465
Carbon efficiency
g CO2/kWh
100
99
97
93
%
0
-0.80
3.22
10.90
Base Case
%
0
-0.19
0.78
2.45
Levelised CoE
£ / MWhNET
76.91
75.91
76.20
76.55
CAPEX change from Base Case OPEX change from
Table 3: Summary of Overall Results The aim of this paper has been to investigate the performance improvements which could be achieved using only process engineering improvements and currently available technology to reduce the efficiency penalty of adding post-combustion CO2 capture to a pulverised coal power plant. The cost impact of making these improvements has then been quantified. Further improvements may also be possible, such as switching the CO2 compressor and condenser cooling medium to sea cooling rather than fresh cooling, depending on individual site conditions and constraints.
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Several of the improvements proposed could be applicable to other types of power plant, particularly the use of a CO2 pump to replace the final compression stage, or stages, and application of an ORC for energy recovery from low grade heat.
The performance improvements suggested in this paper are not the only improvements which can be anticipated to fossil-fired power plants with post-combustion CO2 capture.
For
example, study work undertaken by the IEA GHG R&D Programme estimates that savings ranging from 27 to 40% on regeneration energy requirement can be made compared to conventional processes(5). This would significantly reduce the reboiler steam demand and hence significantly increase the steam turbine power output.
It can therefore be concluded that significant decreases in the currently anticipated 8 to 10 efficiency % point energy penalty of adding post-combustion carbon capture to fossil fired power generation can be expected though technology advancements, optimum heat integration and energy recovery.
© 2011 Foster Wheeler. All rights reserved
References
1) S. Ferguson, T. Bullen & G. Skinner, Foster Wheeler, “Opportunities for Efficiency Improvements in Power Plants with Carbon Capture”, PowerGen Europe 2010, Amsterdam, June 2010, 2) C. Botero & Co (GE Global Research Centre) & S. Bertolo & Co. (GE Oil & Gas), Thermoeconomic Evaluation of CO2 Compression Strategies for Post Combustion CO2 Capture Applications, GE Oil & Gas Technology Insights 2010. 3) R. K. Sinnott, “Coulson & Richardson’s Chemical Engineering”, Volume 6, 3rd Edition, 1999, Butterworth Heinemann. 4)
Pratt
&
Whitney,
“Organic
Rankine
Cycle Technology
Brochure”:
http://www.pw.utc.com/products/power_systems/organic_rankine_cycle.asp 5) IEA Greenhouse Gas R&D Programme (IEA GHG), “Evaluation of Novel PostCombustion CO2 Capture Solvent Concepts, 2009/14, November 2009”.
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