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Evaluation of different CHP options for refinery integration in the context of a low carbon future
international journal of greenhouse gas control 3 (2009) 152–160
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Evaluation of different CHP options for refinery integration in the context of a low carbon future Christian Solli a,*, Rahul Anantharaman b, Anders H. Strømman a,b, Xiangping Zhang a,b, Edgar G. Hertwich a,b a b
Industrial Ecology Program, Norwegian University of Science and Technology, Norway Department of Energy and Process Engineering, Norwegian University of Science and Technology, Norway
article info
abstract
Article history:
This study presents a comparison of different concepts for delivering combined heat and
Received 18 January 2008
power (CHP) to a refinery in Norway. A reference case of producing high pressure steam from
Received in revised form
natural gas in boilers and electricity in a combined cycle power plant, is compared to a: (1)
21 July 2008
natural gas fueled CHP without any CO2 capture; (2) hydrogen fueled CHP with hydrogen
Accepted 30 July 2008
produced from steam methane reforming (SMR); (3) hydrogen fueled CHP with hydrogen
Published on line 7 September 2008
produced from autothermal reforming (ATR); and finally (4) natural gas fueled CHP with
Keywords:
emissions of CO2 and a simplified cash flow evaluation. Results show that in terms of
Combined heat and power (CHP)
efficiency the standard natural gas fueled CHP performs better than the reference case as
Autothermal reforming (ATR)
well as the options with carbon capture. The low carbon options in turn offer lower
Steam methane reforming (SMR)
emissions of greenhouse gases while maintaining the same efficiency as the reference
CO2 capture
case. The cash flow analysis shows that for any option, a certain mix of prices is required to
Hydrogen energy
produce a positive cash flow. As expected, the relationship between natural gas price and
postcombustion CO2 removal. The options are compared on the basis of first law efficiency,
electricity price affects all options. Also the value of heat and CO2 emissions plays an important role. # 2008 Elsevier Ltd. All rights reserved.
1.
Introduction
The carbon emissions from Norwegian refineries constitute some of the largest point sources on the Norwegian main land (Statens Forurensingstilsyn, 2007). Efforts to reduce these emissions are therefore of interest. Simultaneously there is an increasing trade deficit with respect to electricity. Until recently Norway had a surplus of hydropower generation, facilitating low electricity prices and industrial development. As much as 99% of all electricity generated in Norway is hydropower. Investment in large hydropower plants did, however, come to a major hold at the end of the 1980s. The remaining large waterways were preserved to ensure biodiversity and recreational quality.
As with other countries, the Norwegian obligations under the Kyoto protocol are based on emissions in 1990. This constraint on emissions growth is challenging for Norway since virtually no (on-shore) electricity generation has been based on fossil fuels. A strong political commitment of the Norwegian government to comply with Kyoto obligations through actual emission reductions has led to carbon capture requirements being imposed on recent power plant projects. In this context we have investigated options for the integration of a combined heat and power (CHP) plant as a means to reduce emissions from a refinery as well as providing electricity to the Norwegian grid. Refinery operation requires significant amounts of energy, mostly as heat, but also electricity. Refineries therefore have a
* Corresponding author. Tel.: +47 73 59 89 40. E-mail address: [email protected] (C. Solli). 1750-5836/$ – see front matter # 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2008.07.008
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international journal of greenhouse gas control 3 (2009) 152–160
steam utility system to provide the necessary qualities of heat to the various processes. The steam can be produced in many ways; usually a number of boilers and furnaces operating on refinery waste products or imported fuels, are used. A combined heat and power plant (CHP) can provide heat for steam production in such a system. In addition it can produce electricity, thereby optimizing the total utilization of the resources in refinery waste gas and imported fuel.1 In this paper, we have investigated four different configurations of a CHP co-located with a refinery in western Norway: (1) a natural gas fueled CHP without any CO2 capture; (2) a hydrogen fueled CHP with hydrogen produced from steam methane reforming (SMR); (3) a hydrogen fueled CHP with hydrogen produced from autothermal reforming (ATR); and (4) a natural gas fueled CHP with postcombustion CO2 removal. The proposed solutions are projected to replace about 350 MW of steam production in the refinery, through shut down of boilers. The CHP is dimensioned to deliver 270 MW of high pressure steam, and 76 MW of crude oil pre-heating in all the configurations. The electricity production can vary between alternatives since the plant is connected to the grid. We assume that the plants are dimensioned solely based on heat demand in the refinery, making the electricity output base load in the grid. In light of a low carbon future, any new configurations for producing heat and electricity to a refinery have to be evaluated not only on an efficiency basis, but also considering emissions of CO2 and other pollutants, preferably in a life cycle context. The economic potential of the process is also a key variable. The possibility of co-producing low carbon fuels in the future (e.g. hydrogen from fossil feed stocks) or to integrate the process with other suitable processes, should also be valued or at least be given a mention in the evaluation. For instance, the refinery in question is expected to have a deficiency of hydrogen in the future; the co-production of hydrogen for the refinery provides an additional bonus. Many different approaches to evaluating CHP performance have been put forth (Nesheim and Ertesva˚g, 2007). The disadvantage of these methods is that they do not consider the alternative(s) to building the CHP and can only be used to compare CHPs of similar technology. In order to compare them in a wider context, we need to establish an alternative reference. This is similar to the concept put forward by Ertesva˚g (2007), but differing in the fact that this will not be on a second law basis. For this study we use as reference that heat is produced by combusting natural gas in boilers with an efficiency of 93% (lower heating value, LHV). The choice of electricity reference is harder since part of the electricity produced in the CHP is meant to replace off shore gas turbines in the North Sea through electrification from shore. The present average electricity mix in Norway is almost entirely hydro power. However, considering the increase in electricity demand, and the current energy debate in Norway, it is likely that the long-term marginal (the next power plant to be built) electricity production in Norway will come from natural gas 1 For consistency among the different options, this study assumes natural gas as the only fuel input, i.e. it is assumed that the refinery waste gas is utilized in the refinery for other purposes.
based combined cycle (NGCC) power plants, with and without CO2 capture. We choose as reference an NGCC without CO2 capture with an efficiency of 59% (Kvamsdal et al., 2007). The separate production of heat and electricity by a boiler and NGCC is termed the reference case in the following. It should not be confused with the base case, which is the term used for the CHP w/o CO2 capture. Some related work has previously been done in this area, focussing on energy integration across larger sites and not just within companies. Klemesˇ et al. (1997) and Mare´chal and Kalitventzeff (1998) use total site composite curves and total site pinch methodology to increase efficiencies on a multiprocess site. The focus is on system performance, rather than the performance of individual components.
2.
Methods
2.1.
Modeling
The level of detail in the modeling of the systems is important. Since the overall objective is to evaluate the system performance, we need a model that can solve the entire system simultaneously, fulfilling the dimensioning demands of heat delivery. We chose to build models of the systems in HYSYS (Aspentech, 2004), allowing for easy convergence of the reactors as well as including an idealized heat integration. Parameter variations can be performed to investigate the sensitivity of the performance to uncertain variables as, e.g., the heat requirements for CO2 removal. The system description section gives more detail on assumptions regarding the models. The Peng-Robinson equation of state has been used.
2.2.
Economic evaluation
Economic evaluation is essential to any proposed solution. As for environmental evaluation, ideally we want to connect economic evaluation directly to the models of the different systems, so that we can look beyond the proxy indicators of specific CO2 emissions and efficiency of the processes. It is not the intention of this paper to provide a detailed cost analysis for the investments required in the different options. As a minimum, however, the low carbon options have to provide a larger cash flow in the operation to defend higher investment costs. We therefore limit our economic analysis to a simplified cash flow assessment. The cash flow is described as CF ¼ Value of productðsÞ Cost of fuel Cost of emissions O&M
(1)
To develop a useful description of the cash flow for our systems, given different mixes of prices, we start by defining some technical parameters specific to each configuration,
htot ¼
Wel þ Q heat ; Q fuel
g el ¼
Wel ; Wel þ Q heat
eCO2 ¼
m ˙ CO2 Q fuel
(2)
where htot is the overall energy efficiency of the configuration, gel is the electricity share of the useful energy delivered and
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eCO2 is the specific CO2 emission in kg per kWh (LHV) of fuel input. If we neglect O&M costs, assuming this is small compared to other variables, or at least the difference between systems is small, we get the following expression for the cash flow, as described by Eq. (1) CF ¼ Wel Pel þ Q heat Pheat Q fuel Pfuel eCO2 Q fuel PCO2
(3)
where P denotes price. We assume constant prices and operation over time, canceling out the time dependency of the CF. In order to evaluate the cash flow under different price mixes, we define price ratios as
rh ¼
Pheat P PCO2 r ¼ el r ¼ Pfuel el Pfuel CO2 Pfuel
(4)
where rh is the ratio of steam price to fuel price, rel is the ratio of the electricity price to the fuel price and rCO2 is the ratio of the cost of CO2 quota per kg emitted CO2 to the fuel price per kWh. Dividing both sides of Eq. (3) by QfuelPfuel and rearranging yields an expression for the cash flow per monetary unit of fuel input CF ¼ htot ðg el rel þ ð1 g el Þrh Þ 1 eCO2 rCO2 Q fuel Pfuel
Value
Unit
Air/cooling water temperature High pressure steama Crude oil pre-heatingb Electricity Air compression adiabatic efficiencyc Turbine adiabatic efficiency CO2 and O2 compression adiabatic efficiency Low pressure steam for reboilerd Air separation energye
15/8 270 76 Variable 88
8C MW MW MW %
92 85
% %
133/3 0.25
Reforming temperaturef and pressureg Turbine inlet pressurec Turbine inlet temperature low/highc HTS reactor inlet temperaturef LTS reactor inlet temperaturef CO2 removal CO2 regeneration duty (pre/post)h Fan work (for postcombustion capture of CO2)i Amine pumping worki
900/25
8C/bara kWh/kg oxygen 8C/bara
17.6 1270/1370 350 200 90 1.2/3.8 0.094
bara 8C 8C 8C % MJ/kg CO2 kWh/kg CO2
0.014
kWh/kg CO2
a
(5)
We can now evaluate the cash flow from each unit of fuel spent for a wide range of configurations and price mixes.
2.3.
Table 1 – Model assumptions and data Parameter
System description
Delivered at 31.4 bars and 335 8C. Return condensate at 125 8C. This heat is taken out by a cooler in the model, since the exchange with crude oil is projected to be at the start of the exhaust gas heat recovery system. c Estimated from GTPRO (2007). d Return condensate at 120 8C and the steam is superheated to 140 8C. e Assuming this oxygen is supplied at a pressure of 1 bara and 95% purity. Compression to 25 bara is included in the model. f From Ertesva˚g et al. (2005). g Reforming pressure set by turbine inlet pressure. h Estimate based on range given in Appl (1999). i Estimate from Bolland and Undrum (2003). b
This section describes the different CHP concepts in more detail. The models have been built in HYSYS (Aspentech, 2004). They are not, by any means, detailed models of the processes, but show the potential of the different concepts on a systems level. Table 1 sums up assumptions and key data that apply to the cases. Table 2 shows the average composition of the natural gas feedstock used. Figs. 1 and 2 show an overview of the options.
pressure steam (270 MW) for the refinery utility system. The demand for heat is the dimensioning factor of the plants. No steam turbine is considered in the configuration.
2.4.
2.5.
Turbine
The assumed properties of the gas turbine are summarized in Table 1. The adiabatic efficiency of the air compression and gas turbine is set to 88% and 92%, respectively, based on values from GTPRO (2007). A pressure ratio of 1:17.6 is assumed. The turbine inlet temperature is set to 1370 8C for all cases. The models are conceptual and are not constrained by equipment size consideration. However, combusting hydrogen in a turbine increases the heat transfer to the turbine blades, since a larger fraction of water is present in the exhaust gas. The turbine inlet temperature (TiT) of hydrogen fired turbines may hence be lower. Chiesa et al. (2005) and Oluyede and Phillips (2007) estimate a lowering of TiT of approx. 20 8C and 100 8C, respectively. The sensitivity of the performance to TiT is therefore tested with an alternative TiT of 1270 8C using the choked nozzle equation to adjust the pressure ratio. The hot exhaust gas from the turbine is utilized to pre heat crude oil entering the refinery (76 MW) and to produce high
Reforming- and shift reactors
Introducing options with reforming and precombustion CO2 removal has several motivations: First, precombustion
Table 2 – Average composition of natural gas feedstock (LHV = 48 MJ/kg) Compound Methane Carbon dioxide Nitrogen Ethane Propane i-Butane n-Butane i-Pentane n-Pentane n-Hexane
Percent (molar) 93.28% 0.29% 1.69% 3.60% 0.57% 0.32% 0.08% 0.06% 0.02% 0.11%
international journal of greenhouse gas control 3 (2009) 152–160
removal of CO2 has a lower energy requirement per kg of carbon dioxide captured. Second, considering a future deficiency of hydrogen in the refinery, being able to divert some hydrogen rich gas to the refinery may place an additional value on the reforming options. Finally, the possible future integration with other processes at the site, such as fish farming or drying processes, might change the desired mix of co-products, favoring a system with more options of products, and more energy levels.
2.6.
Pre-reforming
Natural gas and steam is fed at 500 8C to the pre reformer. To avoid carbon formation in process equipment, excess steam is required, resulting in an energy penalty due to the need for heating the excess water (Sperle et al., 2005). A higher steam concentration also favors the conversion of methane in the reforming. It is assumed that a molar steam to carbon (S/C) ratio of 3.1 for the steam methane reforming case is sufficient to avoid carbon formation. For the autothermal reforming, oxygen is supplied in addition to steam, lowering the required amount of steam. Here we assume a S/C-ratio of 1.5 for the ATR case. In the pre-reformer, longer hydrocarbons are converted to methane, hydrogen, CO and CO2 through the following reactions: m H2 Cn Hm þ nH2 O ! nCOþ n þ 2 CO þ 3H2 @ CH4 þ H2 O DH ¼ 206kJ=mol CO þ H2 O @ CO2 þ H2
DH ¼ 41kJ=mol
The resulting gas, including the majority of the steam supplied, is re-heated to 500 8C and sent to the reformer.
2.7.
Steam methane reforming
The steam methane reforming is fed with the gas from the prereformer to produce a gas rich in hydrogen and CO, syngas. The reforming process operates at 900 8C and 25 bar, and is assumed to reach equilibrium. The main reactions in the reforming process are: CH4 þ H2 O @ 3H2 þ CO DH ¼ 206KJ=mol CO þ H2 O @ CO2 þ H2
DH ¼ kJ=mol
Since the net reforming reaction is endothermic, the reactor needs to be externally fired by natural gas. The exhaust gas temperature is assumed to be 1000 8C. The exhaust is then sent to heat recovery after which it is vented to the atmosphere at a temperature of 100 8C. The syngas is cooled and fed to water gas shift reactors.
2.8.
Autothermal reforming
The gas from the pre-reformer enters the autothermal reformer together with oxygen. Operating conditions are 900 8C and 25 bar (Ertesva˚g et al., 2005). The oxygen is produced by air separation. The air separation unit (ASU) is
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modeled as a black box.2 The oxygen production is assumed to require 0.25 kWh/kg O2, not including compression to reformer pressure. This is in line with numbers found in the literature (cf. CO2 Norway As (2004), Go¨ttlicher and Pruschek (1997) and Bolland and Mathieu (1998)). The oxygen compressor is assumed to have an adiabatic efficiency of 85%. Modeling the ASU as a black box is appropriate since the ASU is highly integrated in itself and the integration potential with the other processes is very limited or non-existent. In the autothermal reformer, partial combustion of methane provides the heat for the endothermic reforming reaction shown above. No external firing is needed, hence CO2 emissions from a furnace are avoided. Similar to the SMR, the resulting syngas is cooled and fed to water gas shift reactors.
2.9.
Water–gas shift
The syngas is fed to water–gas shift reactors (high temperature shift, HTS and low temperature shift, LTS) where CO reacts with water to form CO2 and hydrogen, CO þ H2 O @ CO2 þ H2
DH ¼ 41kJ=mol
The lower temperatures in these reactors shifts equilibrium to the right. Inlet temperatures are 350 8C and 200 8C, respectively (Ertesva˚g et al., 2005). The use of two reactors is due to a trade-off between reaction kinetics and equilibrium. The gas is then cooled and water is condensed out before the gas is sent to CO2 capture.
2.10.
CO2 capture
For the reforming options, a gas mixture consisting of mainly CO2, hydrogen and small amounts of methane, CO and water, enters the amine separation plant. CO2 is absorbed in the lean amine solution in the absorption tower. The rich solution is sent to a regeneration tower. The almost pure hydrogen is sent to the gas turbine. In the regeneration tower the pressure is lowered and the amine solution is heated resulting in the release of CO2 from the solution. The amine is then pumped back to the absorption section to capture more CO2. To reflect different values given in the literature, the effect of the low pressure steam (LPS) demand for the CO2 regeneration column in the amine capture plant has been investigated. We assume 1.2 MJ/kg CO2 as the base case value at a capture rate of 90%. In the supplemental information, we include analysis where the CO2 capture duty has been varied between 0.5 and 2 MJ/kg CO2 to reflect approximate lower and upper estimates of the stripping reboiler duty (Appl, 1999). For the postcombustion capture, the cooled exhaust gas enters the absorption plant. The capture rate is assumed to be 90%. The clean exhaust gas is vented from the top of the absorber. CO2 is released in the regeneration tower as in the precombustion case. As a base case estimation 3.8 MJ/kg CO2 is assumed as the stripper reboiler duty. In the supplemental information, we include analysis where the reboiler energy 2 Black box here means that no other details than major inputs and outputs are known. The major input in this case is electricity for air compression.
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Fig. 1 – Simplified flowsheet of a natural gas fired CHP with and without CO2 capture.
Fig. 2 – Simplified flowsheet of reforming options combined with a CHP.
demand of the regeneration tower is varied between 2.5 and 5 MJ/kg CO2 approximately reflecting lower and upper estimates in the literature (Appl, 1999). CO2 capture is modeled as a grey box;3 the only (significant) integration option is the delivery of LPS to the reboiler in the regeneration column. The model is therefore a component splitter with LPS proportional to CO2 separated. This greatly improves the ease of converging the models, maintaining the integration with the rest of the system through the LPS demand. It also makes it easy to evaluate the performance under uncertain information about actual regeneration energy requirements. Further we assume co-absorption of hydrogen to have negligible impact on system performance, hence this is not included. The CO2-product is dried, compressed to 200 bara and piped to the North Sea for injection.
3
Grey box here means that we have some knowledge of what is going on in the process, but the only significant stream to integrate with the rest of the system is low pressure steam used in the solvent regeneration.
2.11.
Heat integration
Detailed heat integration has not been performed; it is assumed that the hot resources are utilized in the theoretically best way using a DTmin = 20 8C. In practice this means that we assume no constraints in which streams can be exchanged, and no constraints on the number of heat exchangers. This is sufficient to get an idea of the potential of the process. Exhaust gas outlet temperature(s) are set to 100 8C for all cases. For the crude oil pre-heating (from 250 to 370 8C) this is projected to be at the start section of the heat recovery unit to ensure maximum driving force. This heat is hence taken out with a cooler in the models and is not included further. Although no constraints are assumed on the heat integration, particular attention has been given to the problem of metal dusting. This corrosion phenomenon is known to occur in materials exposed to streams with a high content of CO (Appl, 1999), and as a consequence the hot syngas can only be used to produce saturated steam by fast quenching against boiling water. We therefore ensure that the pre-heating of reactants (to 500 8C) can be performed with
international journal of greenhouse gas control 3 (2009) 152–160
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Table 3 – Overview of the performance Turbine inlet temperature = 1370 8C (1270 8C) a
Energy efficiency Compared to reference case Electricity share Electricity output (MW) HP steam output (MW) Crude oil pre-heating (MW) Natural gas input (MW LHV) CO2 emissions (Mt/year)f Compared to reference casef Compared to reference case (%reduction)f CO2 product (Mt/year)f Capture rate (% of fuel carbon)
b
Boiler + NGCC
BC
SMRc
ATRd
93%/59% ... 0%/100% 0/As alternative 270/0 76/0 372/Variable 0.65/Variable ... ... 0 0/0
85.3% +13.1% 49.8% 343 270 76 807 1.42 0.26 Mt 15.3% 0 0
75.4% (74.4%) +0.1% (1.2%) 40.6% (40.1%) 237 (231) 270 76 773 (776) 0.70g (0.70) 0.66 Mt (0.64 Mt) 48.6% (47.8%) 0.66 (0.66) 48.5% (48.5%)
72.8% (71.6%) 0.5% (2.1%) 46.6% (45.5%) 302 (290) 270 76 889 (889) 0.33 (0.33) 1.22 Mt (1.19 Mt) 78.5% (78.5%) 1.23 (1.23) 78.6% (79.1%)h
Postcombe 66.2% 3.2% 58.8% 493 270 76 1267 0.22 1.90 Mt 89.5% 2.01 90%
a
Natural gas fired boiler with 93% efficiency (own calculation). Adapted from Kvamsdal et al. (2007), ignoring mechanical losses and auxiliaries for comparability between options. c Assuming a reboiler duty of 1.2 MJ/kg CO2 removed and a S/C ratio of 3.1. d Assuming a reboiler duty of 1.2 MJ/kg CO2 removed and a S/C ratio of 1.5. Also note that for the case with TiT=1270 8C the pre-heating temperature of the reactants is lowered to allow a DTmin of 20 8C between the exhaust gas and pre-heating. e Assuming a reboiler duty of 3.8 MJ/kg CO2 removed. f Numbers refer to an availability of 100%. g Of which 75% is from firing the reformer. h The reason for this not being 90% is unconverted methane and CO going through the capture process. The effective capture rate is then far less than 90%. b
the exhaust gas only. In the case of too low exhaust gas temperatures (after crude oil heating), the pre-heating temperature is lowered to allow a minimum temperature difference of 20 8C. In the SMR this is not an issue since there is plenty of high quality heat available from the external firing of the reformer. For all carbon capture options, the CO2 is compressed to 200 bara. Heat from compressor intercoolers is not integrated, since the temperatures are under the pinch point, and will have no effect on overall performance. This may change if the required temperature in amine regeneration is lowered, as done in Peeters et al. (2007).
3.
Results
Table 3 shows an overview of the performance for the systems. They are all compared to an alternative of providing heat with a natural gas fired boiler with an efficiency of 93%, and electricity produced with an NGCC with efficiency of 59% (Kvamsdal et al., 2007), using the same composition of natural gas as the other options. Note that the reference mix changes between alternatives to provide the exact same mix of heat and electricity as the CHP options, which vary significantly in this respect. The numbers in parentheses are for an alternative case with a turbine inlet temperature of 1270 8C. Rows one and two show the overall energy efficiency comparison for the alternative methods of providing heat and power. We clearly see that the base case is capable of delivering the desired product at a significantly higher efficiency (+13%) than the separate production in the reference case, while reducing CO2 emissions by 15%. The only option
that has a notable reduction in energy efficiency is the CHP with postcombustion capture of CO2; the penalty is about 3%. The ATR and SMR options actually have similar efficiencies to the reference system. This means that for the low carbon options, the benefits of combined production more or less balance the penalty of CO2 capture. Remember that the comparison is performed with respect to a reference situation of identical product mix; that is, any mix of heat/electricity produced by the CHP would otherwise be produced in a NGCC and boiler. The results clearly show that there is potential to construct low carbon alternatives with approximately the same energy efficiency as the reference scenario. Especially the ATR and postcombustion capture options have a large decrease in CO2 emissions (80–90%) with a minor penalty in efficiency. The postcombustion CHP needs a turbine about 60% larger in capacity to deliver the required heat to the refinery. The reason is that all the steam is produced downstream the turbine, whereas in the precombustion cases more heat is available upstream, reducing the amount of gas required in the turbine and subsequent heat utilization. Electricity also constitutes a larger fraction of the output from the postcombustion capture CHP. Similarly the SMR system has a higher fraction of heat product than the others, lowering the required amount of natural gas and reducing the turbine size. This is due to the external firing needed to fuel the reforming process. The exhaust gas from this firing represents a large heat source that can be used to produce steam for the refinery. The electricity output, however, is correspondingly lower and CO2 emissions higher due to no CO2 capture from the externally fired SMR. As seen in Table 3, the ATR is more sensitive to a lowering of the turbine inlet temperature, than the SMR based plant. In
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Fig. 3 – Economic (cash flow) performance of the different configurations for various combinations of prices.
the ATR a lower TiT results in less pre-heating of reactants to the reformers,4 and as a consequence more use of electricity to produce oxygen, making the ATR more sensitive to the TiT. The pre-reforming happens at a slightly lower temperature, while the temperature in the reformer is fixed. The relatively small decrease in efficiency for both these cases can be explained by the fact that the lower pressure ratio induced by lower TiT,5 results in higher exhaust gas temperatures. This heat can then be utilized in the rest of the system, partly outweighing the penalty from lower TiT. The decrease in efficiency is hence not dramatic for any of the cases. The effect of capture duty on the performance of the systems has also been investigated. The results are enclosed in the supplemental information. Higher efficiency is not a goal in itself; it merely serves as a proxy indicator of the more abstract values of economic- and environmental performance. The link between efficiency and those values is not always clear; not on a first law basis, and as far as the authors can see, not on a second law basis either. In our opinion, efficiency can only be used properly as a proxy indicator if the intended use is to improve an already existing 4 5
See the system description under ‘‘heat integration’’. Calculated by the choked nozzle equation.
configuration, or compare configurations of the same type using the same input to produce similar outputs.6 In our comparison we partly get around this issue by comparing to an alternative reference and not in absolute terms, accounting for the differences in product mix. Additional factors that need to be addressed are economic performance, and how to evaluate the reduction in carbon dioxide emissions.
3.1.
Economic performance
Fig. 3 shows the cash flow per monetary fuel input for a selected set of prices ratios for the main outputs and inputs in the systems. The four figures show different valuation of the heat produced. On the x-axis is the ratio of CO2 emission costs (per kg) to the natural gas price (per kwh (LHV)); the y-axis
6 Take the use of solar photovoltaic cells. It gives no meaning to compare their low efficiency in converting solar energy to electricity with other energy conversion techniques (sunlight is free, a more useful comparison would be to compare efficiency in land use to e.g. biofuel production). But, as a means of recording PVpanel design improvements, efficiency can serve as a good indicator.
international journal of greenhouse gas control 3 (2009) 152–160
Table 4 – Technical parameters used for the cash flow assessment CHP configuration SMR + CHPa ATR + CHPb CHP with postcombustion capturec Base case CHPd
htot
gel
0.754 0.728 0.662 0.853
0.406 0.466 0.588 0.498
eCO2 0.103 0.043 0.020 0.201
htot is overall energy efficiency, gel is electricity’s share of total product, and eCO2 is kg CO2 emissions per kWh fuel input. a TiT = 1370 8C, reboiler duty = 1.2 MJ/kg CO2. b TiT = 1370 8C, reboiler duty = 1.2 MJ/kg CO2. c TiT = 1370 8C, reboiler duty = 3.8 MJ/kg CO2. d TiT = 1370 8C.
represents the ratio of electricity price (per kwh) to the natural gas price (per kwh (LHV)). The different colored areas show where the respective solutions (legend) for the CHP perform best on a cash flow basis. The figures can be read as a map where the included contour lines show the value of the cash flow per monetary unit spent on fuel. The technical parameters used are shown in Table 4. The results show that for low prices of CO2 (compared to natural gas), the base case CHP without any CO2 capture performs best. From the contour lines we can see how sensitive the base case solution is to the price of CO2. For the postcombustion case the contour lines indicate a much lower sensitivity to the cost of emitting CO2. We also note that the ATR concept needs a higher valuation of heat in order to be more profitable in any region of the figure. For lower prices of electricity none of the solutions seem attractive, producing a negative cash flow. The SMR option does not become attractive except at very high valuation of heat (such high valuations are not included in the figure). The ATR and postcombustion solutions are quite similar in performance; small changes in any technical parameters may hence shift large areas in the figure. This also applies to the valuation of heat where the slightly higher fraction of heat product makes the ATR solution better at high heat prices. The valuation of heat is site dependent as supply and demand profiles are different from site to site, and heat is not easily transported. If we assume a lock-in on natural gas for new heat supply, a heat price of about 25% higher than the natural gas price does not seem unreasonable, given the efficiency and investment in boiler. This is, however, highly uncertain. The electronic supplement contains results from more configurations; looking at different combinations of TiT and CO2 capture duties. In this assessment we have assumed the value of the compressed CO2 product to be zero. However, for the company this can have a value ranging from negative to positive, all depending upon how incentives for emissions reductions are distributed by the government. If necessary, recompressing the gas off shore will cause some additional energy penalty, and transportation infrastructure causes larger investments. This is not considered here. One dimension of the economic analysis that has yet not been explored, is the possibility of diverting some hydrogen to the refinery, or some syngas to other processes, in the future. This could be viewed as investing in flexibility. Larger
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investments in the reforming equipment will be required, but it has a possible economic value. The value of such flexibility is hard to assess, but deserves a qualitative mention.
4.
Discussion and conclusions
From the analysis it is clearly seen that in terms of efficiency i.e. converting natural gas into any mix of heat and electricity, the base case CHP without any CO2 removal, performs best. Of the low carbon solutions, the SMR configuration scores high on efficiency, followed by the ATR and postcombustion solutions. The reason that the SMR performs better is due to the fact that it has a larger share of heat output compared to the other solutions. This also limits the need for additional supplies of natural gas to the site, in exchange for a lower electricity output. When compared to an alternative reference scenario with separate production of electricity and heat, the options with CO2 capture end up with approximately the same efficiency as the reference case. This is a bit surprising, but can be explained by the benefits of co-production outweighing the penalty of CO2 capture. In addition we account for the difference in production mix, so that even if the postcombustion option has an energy efficiency of only 66%, it profits from having a high el. to heat ratio, reducing the penalty compared to a reference case. The use of natural gas fired reference technologies, producing the exact same energy mix, makes a comparison on efficiency basis meaningful to some degree. If we, however, assume that electricity would otherwise be produced by hydro power, the efficiency comparison would loose all meaning. Then, only the economic and CO2 comparisons will make sense. This of course means that the assumptions regarding the reference production mix has a large influence on conclusions. So, efficiency is not the only criterion for evaluation of the systems. Considering the emissions of CO2, the base case CHP performs the worst, even though it represents a reduction of about 260 kt CO2 compared to the reference. This is purely a result of increased efficiency due to the combined production of heat and electricity. For the SMR, a reduction of about 50% from the reference is achieved. This is significant, but compared to the ATR, the performance in efficiency is almost similar, and the ATR has significantly lower CO2 emissions. The postcombustion option has even lower emissions, in exchange for a penalty in efficiency. Ideally the alternatives’ environmental performance should be compared on a full life cycle basis. This is outside the scope of this study, but we can consider greenhouse emissions from producing natural gas, as the input of natural gas is significant and varies between the alternatives. The greenhouse gas emissions connected to extraction and production of natural gas amount to about 0.015 kg CO2 equivalents/kWh natural gas delivered (Ecoinvent Centre, 2007). From Table 3 we see that this would represent about 7– 8% of the direct emissions in the base case CHP. As efficiency drops and direct CO2 emissions are reduced, the relative significance of the natural gas production gets higher for the low carbon options. This does not, however, significantly affect the relative performance of the options.
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From the economic assessment, the base case CHP is the best option when CO2 prices are low. Increasing electricity prices and lower CO2 emissions prices relative to the price of natural gas, benefit all configurations. The base case CHP is, however, more vulnerable to higher costs of CO2 emissions quota. The postcombustion and ATR—options stand out as the best options at higher CO2 prices. Higher electricity prices benefits the postcombustion option more than the ATR option, due to the high share of electricity output. The opposite is true for the value of heat. The SMR option only becomes better at very high valuation of heat, and does not seem attractive compared to the other systems. If there is economic value connected to the CO2 product, for instance through use in enhanced oil recovery, this may further benefit the low carbon alternatives. The capture rate in precombustion CO2 capture might be increased to 95% without large increase in specific energy requirements. This shifts performance in favor of precombustion options when it comes to emissions and economics. See the supporting information for more parameter variations, and their effects on the performance of the systems. In conclusion, the cash flows of the ATR and postcombustion options are quite similar for most of the price mixes, so given uncertainty about technical parameters, it is hard to rank one above another. However, these two solutions stand out as attractive alternatives to the reference case with a small penalty in efficiency, but large decrease in emissions.
Acknowledgements This work is a part of the Mongstad Pilot Project and was funded by StatoilHydro ASA. Thanks to Line Kjellevold and Truls Gundersen for useful inputs to the study.
Appendix A. Supplementary data Supplementary data associated with this article can be found, in the online version, at doi:10.1016/j.ijggc.2008.07.008.
references
Appl, M., 1999. Ammonia—Production and Industrial Practice. Wiley-VCH, Weinheim. Aspentech, 2004. Aspen Hysys Version 2004.2. www.aspentech.com.
Bolland, O., Mathieu, P., 1998. Comparison of two CO2 removal options in combined cycle power plants. Energy Conversion and Management 39 (16–18), 1653–1663. Bolland, O., Undrum, H., 2003. A novel methodology for comparing CO2 capture options for natural gas-fired combined cycle plants. Advances in Environmental Research 7 (4), 901–911. Chiesa, P., Lozza, G., Mazzocchi, L., 2005. Using hydrogen as gas turbine fuel. Transactions of ASME 127, 73–80. CO2-Norway AS, 2004. Zero Emission Norwegian Gas (ZENG) Phase-1: Concept & Feasibility Study Final Report. Tech. rep., CO2-Norway AS, http://www.co2.no/ download.asp?DAFID=20&DAAID=3 Accessed 09.10.2007. Ecoinvent Centre, 2007. Ecoinvent data v1.3. Swiss Centre for Life Cycle Inventories. Ertesva˚g, I.S., Kvamsdal, H.M., Bolland, O., 2005. Exergy analysis of a gas-turbine combined-cycle power plant with precombustion CO2 capture. Energy 30, 5–39. Ertesva˚g, I.S., 2007. Exergetic comparison of efficiency indicators for combined heat and power. Energy 32 (11), 2038–2050. Go¨ttlicher, G., Pruschek, R., 1997. Comparison of CO2 removal systems for fossil-fuelled power plant processes. Energy Conversion and Management 38, S173–S178. GTPRO, 2007. Gtpro gas turbine combined cycle design program. Thermoflow Inc., www.thermoflow.com. Klemesˇ, J., Dhole, V.R., Raissi, K., Perry, S.J., Puigjaner, L., 1997. Targeting and design methodology for reduction of fuel, power and CO2 on total sites. Applied Thermal Engineering 17 (8–10), 993–1003. Kvamsdal, H.M., Jordal, K., Bolland, O., 2007. A quantitative comparison of gas turbine cycles with CO2 capture. Energy 32, 10–24. Mare´chal, F., Kalitventzeff, B., 1998. Energy integration of industrial sites: tools, methodology and application. Applied Thermal Engineering 18, 921–933. Nesheim, S.J., Ertesva˚g, I.S., 2007. Efficiencies and indicators defined to promote combined heat and power. Energy Conversion and Management 48, 1004–1015. Oluyede, E.O., Phillips, J.N., 2007. Fundamental impact of firing syngas in gas turbines. In: Proceedings of GT2007. ASME Turbo Expo 2007: Power for Land, Sea and Air. Vol. GT200727385. Peeters, A.N.M., Faaij, A.P.C., Turkenburg, W.C., 2007. Technoeconomic analysis of natural gas combined cycles with post-combustion CO2 absorption, including a detailed evaluation of development potential. International Journal of Greenhouse Gas Control 1 (4), 396–417, doi:10.1016/S17505836(07)00068-0. Sperle, T., Chen, D., Lødeng, R., Holmen, A., 2005. Pre-reforming of natural gas on a Ni catalyst. Applied Catalysis A: General 282 (1–2), 195–204. Statens Forurensingstilsyn, 2007. Company specific environmental information (in norwegian). www.sft.no/ bmi.
available at www.sciencedirect.com
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Evaluation of different CHP options for refinery integration in the context of a low carbon future Christian Solli a,*, Rahul Anantharaman b, Anders H. Strømman a,b, Xiangping Zhang a,b, Edgar G. Hertwich a,b a b
Industrial Ecology Program, Norwegian University of Science and Technology, Norway Department of Energy and Process Engineering, Norwegian University of Science and Technology, Norway
article info
abstract
Article history:
This study presents a comparison of different concepts for delivering combined heat and
Received 18 January 2008
power (CHP) to a refinery in Norway. A reference case of producing high pressure steam from
Received in revised form
natural gas in boilers and electricity in a combined cycle power plant, is compared to a: (1)
21 July 2008
natural gas fueled CHP without any CO2 capture; (2) hydrogen fueled CHP with hydrogen
Accepted 30 July 2008
produced from steam methane reforming (SMR); (3) hydrogen fueled CHP with hydrogen
Published on line 7 September 2008
produced from autothermal reforming (ATR); and finally (4) natural gas fueled CHP with
Keywords:
emissions of CO2 and a simplified cash flow evaluation. Results show that in terms of
Combined heat and power (CHP)
efficiency the standard natural gas fueled CHP performs better than the reference case as
Autothermal reforming (ATR)
well as the options with carbon capture. The low carbon options in turn offer lower
Steam methane reforming (SMR)
emissions of greenhouse gases while maintaining the same efficiency as the reference
CO2 capture
case. The cash flow analysis shows that for any option, a certain mix of prices is required to
Hydrogen energy
produce a positive cash flow. As expected, the relationship between natural gas price and
postcombustion CO2 removal. The options are compared on the basis of first law efficiency,
electricity price affects all options. Also the value of heat and CO2 emissions plays an important role. # 2008 Elsevier Ltd. All rights reserved.
1.
Introduction
The carbon emissions from Norwegian refineries constitute some of the largest point sources on the Norwegian main land (Statens Forurensingstilsyn, 2007). Efforts to reduce these emissions are therefore of interest. Simultaneously there is an increasing trade deficit with respect to electricity. Until recently Norway had a surplus of hydropower generation, facilitating low electricity prices and industrial development. As much as 99% of all electricity generated in Norway is hydropower. Investment in large hydropower plants did, however, come to a major hold at the end of the 1980s. The remaining large waterways were preserved to ensure biodiversity and recreational quality.
As with other countries, the Norwegian obligations under the Kyoto protocol are based on emissions in 1990. This constraint on emissions growth is challenging for Norway since virtually no (on-shore) electricity generation has been based on fossil fuels. A strong political commitment of the Norwegian government to comply with Kyoto obligations through actual emission reductions has led to carbon capture requirements being imposed on recent power plant projects. In this context we have investigated options for the integration of a combined heat and power (CHP) plant as a means to reduce emissions from a refinery as well as providing electricity to the Norwegian grid. Refinery operation requires significant amounts of energy, mostly as heat, but also electricity. Refineries therefore have a
* Corresponding author. Tel.: +47 73 59 89 40. E-mail address: [email protected] (C. Solli). 1750-5836/$ – see front matter # 2008 Elsevier Ltd. All rights reserved. doi:10.1016/j.ijggc.2008.07.008
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international journal of greenhouse gas control 3 (2009) 152–160
steam utility system to provide the necessary qualities of heat to the various processes. The steam can be produced in many ways; usually a number of boilers and furnaces operating on refinery waste products or imported fuels, are used. A combined heat and power plant (CHP) can provide heat for steam production in such a system. In addition it can produce electricity, thereby optimizing the total utilization of the resources in refinery waste gas and imported fuel.1 In this paper, we have investigated four different configurations of a CHP co-located with a refinery in western Norway: (1) a natural gas fueled CHP without any CO2 capture; (2) a hydrogen fueled CHP with hydrogen produced from steam methane reforming (SMR); (3) a hydrogen fueled CHP with hydrogen produced from autothermal reforming (ATR); and (4) a natural gas fueled CHP with postcombustion CO2 removal. The proposed solutions are projected to replace about 350 MW of steam production in the refinery, through shut down of boilers. The CHP is dimensioned to deliver 270 MW of high pressure steam, and 76 MW of crude oil pre-heating in all the configurations. The electricity production can vary between alternatives since the plant is connected to the grid. We assume that the plants are dimensioned solely based on heat demand in the refinery, making the electricity output base load in the grid. In light of a low carbon future, any new configurations for producing heat and electricity to a refinery have to be evaluated not only on an efficiency basis, but also considering emissions of CO2 and other pollutants, preferably in a life cycle context. The economic potential of the process is also a key variable. The possibility of co-producing low carbon fuels in the future (e.g. hydrogen from fossil feed stocks) or to integrate the process with other suitable processes, should also be valued or at least be given a mention in the evaluation. For instance, the refinery in question is expected to have a deficiency of hydrogen in the future; the co-production of hydrogen for the refinery provides an additional bonus. Many different approaches to evaluating CHP performance have been put forth (Nesheim and Ertesva˚g, 2007). The disadvantage of these methods is that they do not consider the alternative(s) to building the CHP and can only be used to compare CHPs of similar technology. In order to compare them in a wider context, we need to establish an alternative reference. This is similar to the concept put forward by Ertesva˚g (2007), but differing in the fact that this will not be on a second law basis. For this study we use as reference that heat is produced by combusting natural gas in boilers with an efficiency of 93% (lower heating value, LHV). The choice of electricity reference is harder since part of the electricity produced in the CHP is meant to replace off shore gas turbines in the North Sea through electrification from shore. The present average electricity mix in Norway is almost entirely hydro power. However, considering the increase in electricity demand, and the current energy debate in Norway, it is likely that the long-term marginal (the next power plant to be built) electricity production in Norway will come from natural gas 1 For consistency among the different options, this study assumes natural gas as the only fuel input, i.e. it is assumed that the refinery waste gas is utilized in the refinery for other purposes.
based combined cycle (NGCC) power plants, with and without CO2 capture. We choose as reference an NGCC without CO2 capture with an efficiency of 59% (Kvamsdal et al., 2007). The separate production of heat and electricity by a boiler and NGCC is termed the reference case in the following. It should not be confused with the base case, which is the term used for the CHP w/o CO2 capture. Some related work has previously been done in this area, focussing on energy integration across larger sites and not just within companies. Klemesˇ et al. (1997) and Mare´chal and Kalitventzeff (1998) use total site composite curves and total site pinch methodology to increase efficiencies on a multiprocess site. The focus is on system performance, rather than the performance of individual components.
2.
Methods
2.1.
Modeling
The level of detail in the modeling of the systems is important. Since the overall objective is to evaluate the system performance, we need a model that can solve the entire system simultaneously, fulfilling the dimensioning demands of heat delivery. We chose to build models of the systems in HYSYS (Aspentech, 2004), allowing for easy convergence of the reactors as well as including an idealized heat integration. Parameter variations can be performed to investigate the sensitivity of the performance to uncertain variables as, e.g., the heat requirements for CO2 removal. The system description section gives more detail on assumptions regarding the models. The Peng-Robinson equation of state has been used.
2.2.
Economic evaluation
Economic evaluation is essential to any proposed solution. As for environmental evaluation, ideally we want to connect economic evaluation directly to the models of the different systems, so that we can look beyond the proxy indicators of specific CO2 emissions and efficiency of the processes. It is not the intention of this paper to provide a detailed cost analysis for the investments required in the different options. As a minimum, however, the low carbon options have to provide a larger cash flow in the operation to defend higher investment costs. We therefore limit our economic analysis to a simplified cash flow assessment. The cash flow is described as CF ¼ Value of productðsÞ Cost of fuel Cost of emissions O&M
(1)
To develop a useful description of the cash flow for our systems, given different mixes of prices, we start by defining some technical parameters specific to each configuration,
htot ¼
Wel þ Q heat ; Q fuel
g el ¼
Wel ; Wel þ Q heat
eCO2 ¼
m ˙ CO2 Q fuel
(2)
where htot is the overall energy efficiency of the configuration, gel is the electricity share of the useful energy delivered and
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eCO2 is the specific CO2 emission in kg per kWh (LHV) of fuel input. If we neglect O&M costs, assuming this is small compared to other variables, or at least the difference between systems is small, we get the following expression for the cash flow, as described by Eq. (1) CF ¼ Wel Pel þ Q heat Pheat Q fuel Pfuel eCO2 Q fuel PCO2
(3)
where P denotes price. We assume constant prices and operation over time, canceling out the time dependency of the CF. In order to evaluate the cash flow under different price mixes, we define price ratios as
rh ¼
Pheat P PCO2 r ¼ el r ¼ Pfuel el Pfuel CO2 Pfuel
(4)
where rh is the ratio of steam price to fuel price, rel is the ratio of the electricity price to the fuel price and rCO2 is the ratio of the cost of CO2 quota per kg emitted CO2 to the fuel price per kWh. Dividing both sides of Eq. (3) by QfuelPfuel and rearranging yields an expression for the cash flow per monetary unit of fuel input CF ¼ htot ðg el rel þ ð1 g el Þrh Þ 1 eCO2 rCO2 Q fuel Pfuel
Value
Unit
Air/cooling water temperature High pressure steama Crude oil pre-heatingb Electricity Air compression adiabatic efficiencyc Turbine adiabatic efficiency CO2 and O2 compression adiabatic efficiency Low pressure steam for reboilerd Air separation energye
15/8 270 76 Variable 88
8C MW MW MW %
92 85
% %
133/3 0.25
Reforming temperaturef and pressureg Turbine inlet pressurec Turbine inlet temperature low/highc HTS reactor inlet temperaturef LTS reactor inlet temperaturef CO2 removal CO2 regeneration duty (pre/post)h Fan work (for postcombustion capture of CO2)i Amine pumping worki
900/25
8C/bara kWh/kg oxygen 8C/bara
17.6 1270/1370 350 200 90 1.2/3.8 0.094
bara 8C 8C 8C % MJ/kg CO2 kWh/kg CO2
0.014
kWh/kg CO2
a
(5)
We can now evaluate the cash flow from each unit of fuel spent for a wide range of configurations and price mixes.
2.3.
Table 1 – Model assumptions and data Parameter
System description
Delivered at 31.4 bars and 335 8C. Return condensate at 125 8C. This heat is taken out by a cooler in the model, since the exchange with crude oil is projected to be at the start of the exhaust gas heat recovery system. c Estimated from GTPRO (2007). d Return condensate at 120 8C and the steam is superheated to 140 8C. e Assuming this oxygen is supplied at a pressure of 1 bara and 95% purity. Compression to 25 bara is included in the model. f From Ertesva˚g et al. (2005). g Reforming pressure set by turbine inlet pressure. h Estimate based on range given in Appl (1999). i Estimate from Bolland and Undrum (2003). b
This section describes the different CHP concepts in more detail. The models have been built in HYSYS (Aspentech, 2004). They are not, by any means, detailed models of the processes, but show the potential of the different concepts on a systems level. Table 1 sums up assumptions and key data that apply to the cases. Table 2 shows the average composition of the natural gas feedstock used. Figs. 1 and 2 show an overview of the options.
pressure steam (270 MW) for the refinery utility system. The demand for heat is the dimensioning factor of the plants. No steam turbine is considered in the configuration.
2.4.
2.5.
Turbine
The assumed properties of the gas turbine are summarized in Table 1. The adiabatic efficiency of the air compression and gas turbine is set to 88% and 92%, respectively, based on values from GTPRO (2007). A pressure ratio of 1:17.6 is assumed. The turbine inlet temperature is set to 1370 8C for all cases. The models are conceptual and are not constrained by equipment size consideration. However, combusting hydrogen in a turbine increases the heat transfer to the turbine blades, since a larger fraction of water is present in the exhaust gas. The turbine inlet temperature (TiT) of hydrogen fired turbines may hence be lower. Chiesa et al. (2005) and Oluyede and Phillips (2007) estimate a lowering of TiT of approx. 20 8C and 100 8C, respectively. The sensitivity of the performance to TiT is therefore tested with an alternative TiT of 1270 8C using the choked nozzle equation to adjust the pressure ratio. The hot exhaust gas from the turbine is utilized to pre heat crude oil entering the refinery (76 MW) and to produce high
Reforming- and shift reactors
Introducing options with reforming and precombustion CO2 removal has several motivations: First, precombustion
Table 2 – Average composition of natural gas feedstock (LHV = 48 MJ/kg) Compound Methane Carbon dioxide Nitrogen Ethane Propane i-Butane n-Butane i-Pentane n-Pentane n-Hexane
Percent (molar) 93.28% 0.29% 1.69% 3.60% 0.57% 0.32% 0.08% 0.06% 0.02% 0.11%
international journal of greenhouse gas control 3 (2009) 152–160
removal of CO2 has a lower energy requirement per kg of carbon dioxide captured. Second, considering a future deficiency of hydrogen in the refinery, being able to divert some hydrogen rich gas to the refinery may place an additional value on the reforming options. Finally, the possible future integration with other processes at the site, such as fish farming or drying processes, might change the desired mix of co-products, favoring a system with more options of products, and more energy levels.
2.6.
Pre-reforming
Natural gas and steam is fed at 500 8C to the pre reformer. To avoid carbon formation in process equipment, excess steam is required, resulting in an energy penalty due to the need for heating the excess water (Sperle et al., 2005). A higher steam concentration also favors the conversion of methane in the reforming. It is assumed that a molar steam to carbon (S/C) ratio of 3.1 for the steam methane reforming case is sufficient to avoid carbon formation. For the autothermal reforming, oxygen is supplied in addition to steam, lowering the required amount of steam. Here we assume a S/C-ratio of 1.5 for the ATR case. In the pre-reformer, longer hydrocarbons are converted to methane, hydrogen, CO and CO2 through the following reactions: m H2 Cn Hm þ nH2 O ! nCOþ n þ 2 CO þ 3H2 @ CH4 þ H2 O DH ¼ 206kJ=mol CO þ H2 O @ CO2 þ H2
DH ¼ 41kJ=mol
The resulting gas, including the majority of the steam supplied, is re-heated to 500 8C and sent to the reformer.
2.7.
Steam methane reforming
The steam methane reforming is fed with the gas from the prereformer to produce a gas rich in hydrogen and CO, syngas. The reforming process operates at 900 8C and 25 bar, and is assumed to reach equilibrium. The main reactions in the reforming process are: CH4 þ H2 O @ 3H2 þ CO DH ¼ 206KJ=mol CO þ H2 O @ CO2 þ H2
DH ¼ kJ=mol
Since the net reforming reaction is endothermic, the reactor needs to be externally fired by natural gas. The exhaust gas temperature is assumed to be 1000 8C. The exhaust is then sent to heat recovery after which it is vented to the atmosphere at a temperature of 100 8C. The syngas is cooled and fed to water gas shift reactors.
2.8.
Autothermal reforming
The gas from the pre-reformer enters the autothermal reformer together with oxygen. Operating conditions are 900 8C and 25 bar (Ertesva˚g et al., 2005). The oxygen is produced by air separation. The air separation unit (ASU) is
155
modeled as a black box.2 The oxygen production is assumed to require 0.25 kWh/kg O2, not including compression to reformer pressure. This is in line with numbers found in the literature (cf. CO2 Norway As (2004), Go¨ttlicher and Pruschek (1997) and Bolland and Mathieu (1998)). The oxygen compressor is assumed to have an adiabatic efficiency of 85%. Modeling the ASU as a black box is appropriate since the ASU is highly integrated in itself and the integration potential with the other processes is very limited or non-existent. In the autothermal reformer, partial combustion of methane provides the heat for the endothermic reforming reaction shown above. No external firing is needed, hence CO2 emissions from a furnace are avoided. Similar to the SMR, the resulting syngas is cooled and fed to water gas shift reactors.
2.9.
Water–gas shift
The syngas is fed to water–gas shift reactors (high temperature shift, HTS and low temperature shift, LTS) where CO reacts with water to form CO2 and hydrogen, CO þ H2 O @ CO2 þ H2
DH ¼ 41kJ=mol
The lower temperatures in these reactors shifts equilibrium to the right. Inlet temperatures are 350 8C and 200 8C, respectively (Ertesva˚g et al., 2005). The use of two reactors is due to a trade-off between reaction kinetics and equilibrium. The gas is then cooled and water is condensed out before the gas is sent to CO2 capture.
2.10.
CO2 capture
For the reforming options, a gas mixture consisting of mainly CO2, hydrogen and small amounts of methane, CO and water, enters the amine separation plant. CO2 is absorbed in the lean amine solution in the absorption tower. The rich solution is sent to a regeneration tower. The almost pure hydrogen is sent to the gas turbine. In the regeneration tower the pressure is lowered and the amine solution is heated resulting in the release of CO2 from the solution. The amine is then pumped back to the absorption section to capture more CO2. To reflect different values given in the literature, the effect of the low pressure steam (LPS) demand for the CO2 regeneration column in the amine capture plant has been investigated. We assume 1.2 MJ/kg CO2 as the base case value at a capture rate of 90%. In the supplemental information, we include analysis where the CO2 capture duty has been varied between 0.5 and 2 MJ/kg CO2 to reflect approximate lower and upper estimates of the stripping reboiler duty (Appl, 1999). For the postcombustion capture, the cooled exhaust gas enters the absorption plant. The capture rate is assumed to be 90%. The clean exhaust gas is vented from the top of the absorber. CO2 is released in the regeneration tower as in the precombustion case. As a base case estimation 3.8 MJ/kg CO2 is assumed as the stripper reboiler duty. In the supplemental information, we include analysis where the reboiler energy 2 Black box here means that no other details than major inputs and outputs are known. The major input in this case is electricity for air compression.
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international journal of greenhouse gas control 3 (2009) 152–160
Fig. 1 – Simplified flowsheet of a natural gas fired CHP with and without CO2 capture.
Fig. 2 – Simplified flowsheet of reforming options combined with a CHP.
demand of the regeneration tower is varied between 2.5 and 5 MJ/kg CO2 approximately reflecting lower and upper estimates in the literature (Appl, 1999). CO2 capture is modeled as a grey box;3 the only (significant) integration option is the delivery of LPS to the reboiler in the regeneration column. The model is therefore a component splitter with LPS proportional to CO2 separated. This greatly improves the ease of converging the models, maintaining the integration with the rest of the system through the LPS demand. It also makes it easy to evaluate the performance under uncertain information about actual regeneration energy requirements. Further we assume co-absorption of hydrogen to have negligible impact on system performance, hence this is not included. The CO2-product is dried, compressed to 200 bara and piped to the North Sea for injection.
3
Grey box here means that we have some knowledge of what is going on in the process, but the only significant stream to integrate with the rest of the system is low pressure steam used in the solvent regeneration.
2.11.
Heat integration
Detailed heat integration has not been performed; it is assumed that the hot resources are utilized in the theoretically best way using a DTmin = 20 8C. In practice this means that we assume no constraints in which streams can be exchanged, and no constraints on the number of heat exchangers. This is sufficient to get an idea of the potential of the process. Exhaust gas outlet temperature(s) are set to 100 8C for all cases. For the crude oil pre-heating (from 250 to 370 8C) this is projected to be at the start section of the heat recovery unit to ensure maximum driving force. This heat is hence taken out with a cooler in the models and is not included further. Although no constraints are assumed on the heat integration, particular attention has been given to the problem of metal dusting. This corrosion phenomenon is known to occur in materials exposed to streams with a high content of CO (Appl, 1999), and as a consequence the hot syngas can only be used to produce saturated steam by fast quenching against boiling water. We therefore ensure that the pre-heating of reactants (to 500 8C) can be performed with
international journal of greenhouse gas control 3 (2009) 152–160
157
Table 3 – Overview of the performance Turbine inlet temperature = 1370 8C (1270 8C) a
Energy efficiency Compared to reference case Electricity share Electricity output (MW) HP steam output (MW) Crude oil pre-heating (MW) Natural gas input (MW LHV) CO2 emissions (Mt/year)f Compared to reference casef Compared to reference case (%reduction)f CO2 product (Mt/year)f Capture rate (% of fuel carbon)
b
Boiler + NGCC
BC
SMRc
ATRd
93%/59% ... 0%/100% 0/As alternative 270/0 76/0 372/Variable 0.65/Variable ... ... 0 0/0
85.3% +13.1% 49.8% 343 270 76 807 1.42 0.26 Mt 15.3% 0 0
75.4% (74.4%) +0.1% (1.2%) 40.6% (40.1%) 237 (231) 270 76 773 (776) 0.70g (0.70) 0.66 Mt (0.64 Mt) 48.6% (47.8%) 0.66 (0.66) 48.5% (48.5%)
72.8% (71.6%) 0.5% (2.1%) 46.6% (45.5%) 302 (290) 270 76 889 (889) 0.33 (0.33) 1.22 Mt (1.19 Mt) 78.5% (78.5%) 1.23 (1.23) 78.6% (79.1%)h
Postcombe 66.2% 3.2% 58.8% 493 270 76 1267 0.22 1.90 Mt 89.5% 2.01 90%
a
Natural gas fired boiler with 93% efficiency (own calculation). Adapted from Kvamsdal et al. (2007), ignoring mechanical losses and auxiliaries for comparability between options. c Assuming a reboiler duty of 1.2 MJ/kg CO2 removed and a S/C ratio of 3.1. d Assuming a reboiler duty of 1.2 MJ/kg CO2 removed and a S/C ratio of 1.5. Also note that for the case with TiT=1270 8C the pre-heating temperature of the reactants is lowered to allow a DTmin of 20 8C between the exhaust gas and pre-heating. e Assuming a reboiler duty of 3.8 MJ/kg CO2 removed. f Numbers refer to an availability of 100%. g Of which 75% is from firing the reformer. h The reason for this not being 90% is unconverted methane and CO going through the capture process. The effective capture rate is then far less than 90%. b
the exhaust gas only. In the case of too low exhaust gas temperatures (after crude oil heating), the pre-heating temperature is lowered to allow a minimum temperature difference of 20 8C. In the SMR this is not an issue since there is plenty of high quality heat available from the external firing of the reformer. For all carbon capture options, the CO2 is compressed to 200 bara. Heat from compressor intercoolers is not integrated, since the temperatures are under the pinch point, and will have no effect on overall performance. This may change if the required temperature in amine regeneration is lowered, as done in Peeters et al. (2007).
3.
Results
Table 3 shows an overview of the performance for the systems. They are all compared to an alternative of providing heat with a natural gas fired boiler with an efficiency of 93%, and electricity produced with an NGCC with efficiency of 59% (Kvamsdal et al., 2007), using the same composition of natural gas as the other options. Note that the reference mix changes between alternatives to provide the exact same mix of heat and electricity as the CHP options, which vary significantly in this respect. The numbers in parentheses are for an alternative case with a turbine inlet temperature of 1270 8C. Rows one and two show the overall energy efficiency comparison for the alternative methods of providing heat and power. We clearly see that the base case is capable of delivering the desired product at a significantly higher efficiency (+13%) than the separate production in the reference case, while reducing CO2 emissions by 15%. The only option
that has a notable reduction in energy efficiency is the CHP with postcombustion capture of CO2; the penalty is about 3%. The ATR and SMR options actually have similar efficiencies to the reference system. This means that for the low carbon options, the benefits of combined production more or less balance the penalty of CO2 capture. Remember that the comparison is performed with respect to a reference situation of identical product mix; that is, any mix of heat/electricity produced by the CHP would otherwise be produced in a NGCC and boiler. The results clearly show that there is potential to construct low carbon alternatives with approximately the same energy efficiency as the reference scenario. Especially the ATR and postcombustion capture options have a large decrease in CO2 emissions (80–90%) with a minor penalty in efficiency. The postcombustion CHP needs a turbine about 60% larger in capacity to deliver the required heat to the refinery. The reason is that all the steam is produced downstream the turbine, whereas in the precombustion cases more heat is available upstream, reducing the amount of gas required in the turbine and subsequent heat utilization. Electricity also constitutes a larger fraction of the output from the postcombustion capture CHP. Similarly the SMR system has a higher fraction of heat product than the others, lowering the required amount of natural gas and reducing the turbine size. This is due to the external firing needed to fuel the reforming process. The exhaust gas from this firing represents a large heat source that can be used to produce steam for the refinery. The electricity output, however, is correspondingly lower and CO2 emissions higher due to no CO2 capture from the externally fired SMR. As seen in Table 3, the ATR is more sensitive to a lowering of the turbine inlet temperature, than the SMR based plant. In
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Fig. 3 – Economic (cash flow) performance of the different configurations for various combinations of prices.
the ATR a lower TiT results in less pre-heating of reactants to the reformers,4 and as a consequence more use of electricity to produce oxygen, making the ATR more sensitive to the TiT. The pre-reforming happens at a slightly lower temperature, while the temperature in the reformer is fixed. The relatively small decrease in efficiency for both these cases can be explained by the fact that the lower pressure ratio induced by lower TiT,5 results in higher exhaust gas temperatures. This heat can then be utilized in the rest of the system, partly outweighing the penalty from lower TiT. The decrease in efficiency is hence not dramatic for any of the cases. The effect of capture duty on the performance of the systems has also been investigated. The results are enclosed in the supplemental information. Higher efficiency is not a goal in itself; it merely serves as a proxy indicator of the more abstract values of economic- and environmental performance. The link between efficiency and those values is not always clear; not on a first law basis, and as far as the authors can see, not on a second law basis either. In our opinion, efficiency can only be used properly as a proxy indicator if the intended use is to improve an already existing 4 5
See the system description under ‘‘heat integration’’. Calculated by the choked nozzle equation.
configuration, or compare configurations of the same type using the same input to produce similar outputs.6 In our comparison we partly get around this issue by comparing to an alternative reference and not in absolute terms, accounting for the differences in product mix. Additional factors that need to be addressed are economic performance, and how to evaluate the reduction in carbon dioxide emissions.
3.1.
Economic performance
Fig. 3 shows the cash flow per monetary fuel input for a selected set of prices ratios for the main outputs and inputs in the systems. The four figures show different valuation of the heat produced. On the x-axis is the ratio of CO2 emission costs (per kg) to the natural gas price (per kwh (LHV)); the y-axis
6 Take the use of solar photovoltaic cells. It gives no meaning to compare their low efficiency in converting solar energy to electricity with other energy conversion techniques (sunlight is free, a more useful comparison would be to compare efficiency in land use to e.g. biofuel production). But, as a means of recording PVpanel design improvements, efficiency can serve as a good indicator.
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Table 4 – Technical parameters used for the cash flow assessment CHP configuration SMR + CHPa ATR + CHPb CHP with postcombustion capturec Base case CHPd
htot
gel
0.754 0.728 0.662 0.853
0.406 0.466 0.588 0.498
eCO2 0.103 0.043 0.020 0.201
htot is overall energy efficiency, gel is electricity’s share of total product, and eCO2 is kg CO2 emissions per kWh fuel input. a TiT = 1370 8C, reboiler duty = 1.2 MJ/kg CO2. b TiT = 1370 8C, reboiler duty = 1.2 MJ/kg CO2. c TiT = 1370 8C, reboiler duty = 3.8 MJ/kg CO2. d TiT = 1370 8C.
represents the ratio of electricity price (per kwh) to the natural gas price (per kwh (LHV)). The different colored areas show where the respective solutions (legend) for the CHP perform best on a cash flow basis. The figures can be read as a map where the included contour lines show the value of the cash flow per monetary unit spent on fuel. The technical parameters used are shown in Table 4. The results show that for low prices of CO2 (compared to natural gas), the base case CHP without any CO2 capture performs best. From the contour lines we can see how sensitive the base case solution is to the price of CO2. For the postcombustion case the contour lines indicate a much lower sensitivity to the cost of emitting CO2. We also note that the ATR concept needs a higher valuation of heat in order to be more profitable in any region of the figure. For lower prices of electricity none of the solutions seem attractive, producing a negative cash flow. The SMR option does not become attractive except at very high valuation of heat (such high valuations are not included in the figure). The ATR and postcombustion solutions are quite similar in performance; small changes in any technical parameters may hence shift large areas in the figure. This also applies to the valuation of heat where the slightly higher fraction of heat product makes the ATR solution better at high heat prices. The valuation of heat is site dependent as supply and demand profiles are different from site to site, and heat is not easily transported. If we assume a lock-in on natural gas for new heat supply, a heat price of about 25% higher than the natural gas price does not seem unreasonable, given the efficiency and investment in boiler. This is, however, highly uncertain. The electronic supplement contains results from more configurations; looking at different combinations of TiT and CO2 capture duties. In this assessment we have assumed the value of the compressed CO2 product to be zero. However, for the company this can have a value ranging from negative to positive, all depending upon how incentives for emissions reductions are distributed by the government. If necessary, recompressing the gas off shore will cause some additional energy penalty, and transportation infrastructure causes larger investments. This is not considered here. One dimension of the economic analysis that has yet not been explored, is the possibility of diverting some hydrogen to the refinery, or some syngas to other processes, in the future. This could be viewed as investing in flexibility. Larger
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investments in the reforming equipment will be required, but it has a possible economic value. The value of such flexibility is hard to assess, but deserves a qualitative mention.
4.
Discussion and conclusions
From the analysis it is clearly seen that in terms of efficiency i.e. converting natural gas into any mix of heat and electricity, the base case CHP without any CO2 removal, performs best. Of the low carbon solutions, the SMR configuration scores high on efficiency, followed by the ATR and postcombustion solutions. The reason that the SMR performs better is due to the fact that it has a larger share of heat output compared to the other solutions. This also limits the need for additional supplies of natural gas to the site, in exchange for a lower electricity output. When compared to an alternative reference scenario with separate production of electricity and heat, the options with CO2 capture end up with approximately the same efficiency as the reference case. This is a bit surprising, but can be explained by the benefits of co-production outweighing the penalty of CO2 capture. In addition we account for the difference in production mix, so that even if the postcombustion option has an energy efficiency of only 66%, it profits from having a high el. to heat ratio, reducing the penalty compared to a reference case. The use of natural gas fired reference technologies, producing the exact same energy mix, makes a comparison on efficiency basis meaningful to some degree. If we, however, assume that electricity would otherwise be produced by hydro power, the efficiency comparison would loose all meaning. Then, only the economic and CO2 comparisons will make sense. This of course means that the assumptions regarding the reference production mix has a large influence on conclusions. So, efficiency is not the only criterion for evaluation of the systems. Considering the emissions of CO2, the base case CHP performs the worst, even though it represents a reduction of about 260 kt CO2 compared to the reference. This is purely a result of increased efficiency due to the combined production of heat and electricity. For the SMR, a reduction of about 50% from the reference is achieved. This is significant, but compared to the ATR, the performance in efficiency is almost similar, and the ATR has significantly lower CO2 emissions. The postcombustion option has even lower emissions, in exchange for a penalty in efficiency. Ideally the alternatives’ environmental performance should be compared on a full life cycle basis. This is outside the scope of this study, but we can consider greenhouse emissions from producing natural gas, as the input of natural gas is significant and varies between the alternatives. The greenhouse gas emissions connected to extraction and production of natural gas amount to about 0.015 kg CO2 equivalents/kWh natural gas delivered (Ecoinvent Centre, 2007). From Table 3 we see that this would represent about 7– 8% of the direct emissions in the base case CHP. As efficiency drops and direct CO2 emissions are reduced, the relative significance of the natural gas production gets higher for the low carbon options. This does not, however, significantly affect the relative performance of the options.
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From the economic assessment, the base case CHP is the best option when CO2 prices are low. Increasing electricity prices and lower CO2 emissions prices relative to the price of natural gas, benefit all configurations. The base case CHP is, however, more vulnerable to higher costs of CO2 emissions quota. The postcombustion and ATR—options stand out as the best options at higher CO2 prices. Higher electricity prices benefits the postcombustion option more than the ATR option, due to the high share of electricity output. The opposite is true for the value of heat. The SMR option only becomes better at very high valuation of heat, and does not seem attractive compared to the other systems. If there is economic value connected to the CO2 product, for instance through use in enhanced oil recovery, this may further benefit the low carbon alternatives. The capture rate in precombustion CO2 capture might be increased to 95% without large increase in specific energy requirements. This shifts performance in favor of precombustion options when it comes to emissions and economics. See the supporting information for more parameter variations, and their effects on the performance of the systems. In conclusion, the cash flows of the ATR and postcombustion options are quite similar for most of the price mixes, so given uncertainty about technical parameters, it is hard to rank one above another. However, these two solutions stand out as attractive alternatives to the reference case with a small penalty in efficiency, but large decrease in emissions.
Acknowledgements This work is a part of the Mongstad Pilot Project and was funded by StatoilHydro ASA. Thanks to Line Kjellevold and Truls Gundersen for useful inputs to the study.
Appendix A. Supplementary data Supplementary data associated with this article can be found, in the online version, at doi:10.1016/j.ijggc.2008.07.008.
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