Environ. Sci. Technol. 2005, 39, 6860-6870
Reducing CO2 Emissions and Energy Consumption of Heat-Integrated Distillation Systems M A M D O U H A . G A D A L L A , * ,† ZARKO OLUJIC,† PETER J. JANSENS,† MEGAN JOBSON,‡ AND ROBIN SMITH‡ Laboratory for Process Equipment, TU Delft, Leeghwaterstraat 44, 2628 CA Delft, The Netherlands, and Center for Process Integration, School of Chemical Engineering and Analytical Science, The University of Manchester, P.O. Box 88, Manchester M60 1QD, U.K.
Distillation systems are energy and power intensive processes and contribute significantly to the greenhouse gases emissions (e.g. carbon dioxide). Reducing CO2 emissions is an absolute necessity and expensive challenge to the chemical process industries in order to meet the environmental targets as agreed in the Kyoto Protocol. A simple model for the calculation of CO2 emissions from heat-integrated distillation systems is introduced, considering typical process industry utility devices such as boilers, furnaces, and turbines. Furnaces and turbines consume large quantities of fuels to provide electricity and process heats. As a result, they produce considerable amounts of CO2 gas to the atmosphere. Boilers are necessary to supply steam for heating purposes; besides, they are also significant emissions contributors. The model is used in an optimizationbased approach to optimize the process conditions of an existing crude oil atmospheric tower in order to reduce its CO2 emissions and energy demands. It is also applied to generate design options to reduce the emissions from a novel internally heat-integrated distillation column (HIDiC). A gas turbine can be integrated with these distillation systems for larger emissions reduction and further energy savings. Results show that existing crude oil installations can save up to 21% in energy and 22% in emissions, when the process conditions are optimized. Additionally, by integrating a gas turbine, the total emissions can be reduced further by 48%. Internal heat-integrated columns can be a good alternative to conventional heat pump and other energy intensive close boiling mixtures separations. Energy savings can reach up to 100% with respect to reboiler heat requirements. Emissions of these configurations are cut down by up to 83%, compared to conventional units, and by 36%, with respect to heat pump alternatives. Importantly, cost savings and more profit are gained in parallel to emissions minimization.
Introduction Carbon dioxide as a greenhouse gas plays a vital role in global warming. Studies show that it is responsible for about two* Corresponding author phone: +31(15)278-8901; fax: +31(15)278-6975; e-mail:
[email protected]. † TU Delft. ‡ The University of Manchester. 6860
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thirds of the enhanced greenhouse effect (1, 2). A significant contribution to the carbon dioxide emitted to the atmosphere is attributed to fossil fuel combustion, which accounts for almost 98% of total CO2 emissions in the U.S. for the year 1999 (1) and 95% of total CO2 emissions in the U.K. for the year 2000 (3). Note that CO2 emissions, considered in this work, are those from anthropogenic sources and not from any natural cycles. To meet the environmental regulations as agreed in the Kyoto Protocol (4), the chemical process industries are challenged to reduce their greenhouse emissions, in particular CO2 emissions. Reducing CO2 emissions is expensive, because industries are required to implement capital-intensive technologies to reduce energy consumption and therefore emissions. Distillation, which is the workhorse of chemical process industries, is an energy-intensive process, and therefore it is the first to be addressed regarding the energy savings oriented efforts in the short and long term. Energy consumption in distillation and CO2 gases produced in the atmosphere are strongly related. The higher the energy demands are, the larger the CO2 emissions to the atmosphere are. Therefore, to reduce CO2 emissions from distillation systems, efforts should be focusing on energy savings techniques and modifications. Several researchers worked on improving the energy efficiency and hence emissions of heat integrated distillation systems, especially crude fractionation units. Most modifications and research efforts were aimed principally at increasing the heat integration within the distillation unit; some were directly made to the heating device systems, while others were performed with the main distillation columns. Sittig (5) suggested the use of intermediate reboilers in crude towers to reduce the heat load on the furnace, and thus the energy efficiency of the system can be increased. Similarly, Harbert (6) advised that the installation of preflash units or prefractionator columns to existing crude oil distillation installations can save energy and allow the furnace to reduce its utility consumptions. Rivero and Anaya (7) concluded that using more trays in existing towers and strippers as well as the installation of reboilers in stripping columns improve the performance of crude oil towers. Dhole and Buckingham (8) published a methodology based on pinch analysis for saving energy in distillation units. They increased the heat recovery in the heat exchanger network (HEN) in order to reduce the utility consumption in the process furnaces which consequently provides an opportunity for emissions reductions. Bagajewicz (9) extended the approach of Liebmann et al. (10) for optimizing an existing crude oil distillation column based on pinch analysis principles and rigorous model-based simulation. This approach applies for reducing energy consumption and atmospheric emissions. Jegla et al. (11) described a procedure for furnace retrofit based on an advanced furnace integration approach using some principles of pinch analysis and considering furnace limitations. It can bring surprising results; besides, it leads to energy efficiency improvements. This method combines principles of an effective design of both processes and equipment. An efficient methodology for furnaces retrofit, using optimization of both a stack temperature and an air preheating system, is applied. Smith and Delaby (12) presented an approach for targeting flue gas emissions (i.e. relating minimum energy consumption to emissions) from utility systems (e.g. furnace, boiler, and turbine) for a given process with fixed conditions. Furthermore, Delaby and Smith (13) proposed a methodology to minimize the flue gas emissions through changing fuels or utility system design, process changes, improved heat 10.1021/es049795q CCC: $30.25
2005 American Chemical Society Published on Web 07/23/2005
FIGURE 1. Sources of CO2 emissions from a crude distillation unit (HEN: heat exchanger network) (22). recovery, and chemical treatment of flue gases. On the other hand, Manninen and Zhu (14) integrated a gas turbine with an existing refinery site to cut down the flue gas emissions and reduce the operational costs. Also, Townsend and Linnhoff (15, 16) and Dhole and Linnhoff (17) developed graphical tools to analyze the integration of a gas turbine to an existing process and estimate the size of the gas turbine required for process requirements. Furthermore, Shonnard and Hiew (18) proposed an assessment methodology, including environmental, health impact indices, transport model, air emissions, etc., for evaluating chemical process case studies. This methodology was applied for a technology selection of the adsorption and absorption processes for the recovery of toluene and ethyl acetate from gaseous wastes. More recently, Chen and Shonnard (19) presented a systematic method for considering environmental impacts and heat integration with an early stage of design and a detailed phase of chemical processes. They showed that for a specific case study, the approach yielded a reduction of 80% in utility costs and 13% in environmental index with respect to the base case. The work by Shonnard and co-workers (18, 19) included the effect of volatile organic emissions from refinery processes on CO2 emissions. In this work, a model, based on previous work (12-14), is proposed for estimating carbon dioxide emissions from refining industry plants, without accounting for the effect of volatile organic. The new model is combined with a shortcut design method for distillation columns (20, 21) in an optimization approach to minimize operation costs and CO2 emissions. This model basically aims at reducing the energy consumptions and utility costs of existing distillation units and accordingly decreasing the emissions. The model is then applied specifically to reduce the emissions of an existing crude oil distillation unit with its exchanger network and of a new design of an internally heat-integrated distillation column (HIDiC). The possibility of integrating a gas turbine with these distillation processes for additional emissions reduction and energy savings is also discussed.
where x and y denote the number of carbon, C, and hydrogen, H, atoms, respectively, present in the fuel compositions, and where complete oxidation of carbon is assumed. Figure 1 shows an existing crude oil distillation unit (22); the utility devices used are a fired heater (furnace), a boiler, and a gas turbine. These devices are possible sources of CO2 emissions. Typical fuels used in these heating devices are light and heavy fuel oils, natural gas, and coal. However, coal is replaced in most heating devices with fuels of higher heating value and lower carbon contents such as natural gas or fuel oil. A big fraction (up to 80%) of the total process heating is supplied by heavy and light fuel oil which is burnt in fired heaters or furnaces. The remaining process heat is given by burning heavy fuel oil in steam boilers. On the other hand, electricity demands are provided by gas turbines which use natural gas or light fuel oil. In the combustion of fuels, air is assumed to be in excess to ensure complete combustion, so that no carbon monoxide is formed. CO2 emissions, [CO2]Emiss (kg/s), are related to the amount of fuel burnt, QFuel (kW), in a heating device as follows
[CO2]Emiss )
( )( )
QFuel C% R NHV 100
(2)
where R ()3.67) is the ratio of molar masses of CO2 and C, while NHV (kJ/kg) represents the net heating value of a fuel with a carbon content of C% (-). Equation 2 shows that the types of both the fuel used and the heating device affect the amount of CO2 produced. The heating device influences emissions through the amount of fuel burnt, which is directly related to its efficiency or performance. However, the effect of the fuel can be seen in the terms C%, NHV, and R. These effects can be lumped in a so-called fuel factor, FuelFact (kg/kJ), defined as
FuelFact )
R C% (NHV )( 100 )
(3)
Model for the Calculation of CO2 Emissions In distillation systems, such as crude oil distillation units, carbon dioxide is generated mainly from furnaces, gas turbines, and boilers. These utility devices are the energy consumers in the refining plants and are used to provide heat, steam, and power to the process by burning a fuel. Therefore these units are key drivers in energy savingsoriented projects and reducing environmental emissions impacts. Fuel is combusted when mixed with air, producing CO2 according to following stoichiometric equation
(
CxHy + x +
y y O f xCO2 + H2O 4 2 2
)
(1)
CO2 Emissions from Furnaces. The combustion of fuels with air produces hot flue gases that can be used for heating the process feeds such as crude oil. Theoretical flame temperatures of the flue gases are usually in the region of 1800 °C (23). The heat provided by flue gases is the heat released when they are cooled from the flame temperature (TFTF) to the stack temperature (TStack). The stack temperature should not be lower than the corrosion limit; a typical stack temperature of 160 °C is adopted (12). The amount of fuel burnt in a furnace can be related to the heat duty required by the process, QProc (kW), and the efficiency of the furnace, ηFurn (-), as follows: VOL. 39, NO. 17, 2005 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
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QFuel )
QProc ηFurn
(4)
The furnace efficiency is defined as the ratio of the useful heat delivered to the process to the amount of fuel burnt
TFTF - TStack ηFurn ) TFTF - To
(5)
where TFTF (°C) is the theoretical flame temperature of the furnace flue gases, TStack (°C) is the stack temperature, while To (°C) is the ambient temperature. The carbon dioxide emissions from the furnace can then be calculated from eqs 2, 4, and 5 for the given heat demand of the process. CO2 Emissions from Steam Boilers. Boilers produce steam from the combustion of fuel. This steam is delivered to the process at the temperature required by the process or obtained at a higher temperature and then throttled. In distillation systems, steam is used either for heating purposes, indirectly in reboilers, or as a direct stripping agent in socalled steam distillations, such as crude oil units. The flame temperature is lower in a boiler than in a furnace because the heat of combustion is removed immediately to the steam. However, the same theoretical flame temperature of 1800 °C may be still used (12). The stack temperature of 160 °C is also used in the calculations. The amount of fuel burnt can be calculated from (12)
QFuel )
QProc TFTB - To (h - 419) λProc Proc TFTB - TStack
(6)
where λProc (kJ/kg) and hProc (kJ/kg) are the latent heat and enthalpy of steam delivered to the process, respectively, while TFTB (°C) is the flame temperature of the boiler flue gases. The above equation is obtained from a simple steam balance around the boiler to relate the amount of fuel necessary in the boiler to provide a heat duty of Qproc; the boiler feedwater is assumed to be at 100 °C with an enthalpy of 419 kJ/kg (12, 13). Smith and Delaby (12) provide a detailed derivation for eq 6 and state all employed basic assumptions. Equations 2 and 6 can calculate the CO2 emissions from steam boilers. Note that the duty, QProc, in eq 6 includes the heat duty required by the process and that provided by the stripping steam. CO2 Emissions from Gas Turbines. A gas turbine is used in refineries either as a stand-alone unit or in an integrated context with a process. In both cases, the gas turbine provides heat to the process and delivers power. Fuels such as natural gas and light fuel oil can feed gas turbines. Integration of a gas turbine with a process enables refineries to produce electricity for the same heat requirement. The generated power can be either consumed in the refinery site or exported to other consumers. The integration of gas turbines then leads to a reduction in the operating costs due to fuel savings, and it also provides flexibility for importing and exporting power. Two different models will be used in modeling CO2 emissions from gas turbines. The model of Smith and Delaby (12) is used when a gas turbine is used separately to provide the process heat duty. On the other hand, when a gas turbine is integrated with a process, a more detailed model is used (14). When a gas turbine is used to supply the process heat duty, QProc, the amount of fuel burnt can be calculated from the relationship between the efficiency of a gas turbine, ηGT (-), and the Carnot factor, ηC (-) (12, 13):
QFuel ) 6862
9
QProc 1 ηGT 1 - ηC
(7)
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The Carnot factor for a gas turbine is defined as (12, 13)
ηC )
Tinlet - Toutlet Tinlet + 273
(8)
The temperature at the inlet (Tinlet; °C) of the gas turbine (combustion temperature) and the temperature at the outlet (Toutlet; °C) of the gas turbine (flue gas temperature) vary according to the turbine design. However, a value of 1027 °C for the inlet and 720 °C for the outlet temperatures may be used (12). Any correlation that calculates the outlet temperature can be used, as will be seen for the case of integrated gas turbines. The efficiency of the gas turbine (ηGT) is defined as the ratio of the useful heat delivered by the gas turbine to the total heat available in the exhaust (12, 13):
ηGT )
Toutlet - TStack Toutlet - To
(9)
The power (electricity) delivered by a gas turbine, WGT (kW), is obtained from the Carnot factor and the amount of fuel burnt in the gas turbine, as follows (12, 13):
WGT ) 0.90ηCQFuel
(10)
The carbon dioxide emissions from a gas turbine can then be calculated from eqs 2, 7, and 8. When a gas turbine is integrated with a process utility system (e.g. furnace), power is generated for the same heat requirement. Furnaces have a high combustion temperature and low heat losses but do not produce power. On the other hand, gas turbines have a large power output, but the exhaust temperatures are too low to satisfy most process heat requirements. Thus, integrating a gas turbine with a process furnace combines the advantages of both units. The exhaust gas from the gas turbine is partially fired in the furnace, together with extra fuel. In this case, the process heat duty is partially provided by the gas turbine by burning a certain amount of fuel. The rest of the heat duty to the process is provided in the furnace. To model the integration of a gas turbine with a process furnace, the exhaust gas is assumed to provide the heat duty from the theoretical flame temperature after firing in the furnace to the stack temperature (24). The power generated in the gas turbine, WGT, is correlated with the flow rate of flue gases (MFG; kg/s), as follows (14):
WGT )
1000MFG 2.9
(11)
The flow rate of the flue gases required can be calculated from (24)
MFG )
QProc CP(TFTF - TStack)
(12)
where CP (kJ/kg °C) is the heat capacity of the flue gases, which can be taken to be equal to that of air (≈1.1) (24). This assumption is not critical since most of the hot flue gases can be considered as hot air (24). The part of heat duty provided by the gas turbine, QGT (kW), is calculated from (14)
QGT ) CP(TExhaust - TStack)MFG
(13)
where TExhaust (°C) is the outlet temperature of the exhaust gases from the gas turbine, which can be calculated from (14):
TExhaust ) 0.4(10)-3WGT + 493.42
(14)
Then, the heat duty required from the furnace, QFurn (kW), can be calculated from an enthalpy balance:
QFurn ) QProc - QGT
(15)
The fuel equivalents consumed in the gas turbine (QFuelGT; MW) and furnace (QFuelFurn; kW), respectively, are calculated as follows (14):
QFuelGT ) 2.84(10)-3WGT + 7.33 QFuelFurn )
QFurn ηFurn
(16) (17)
Then, the total fuel consumption (QFuel; kW) in the gas turbine and furnace, assuming that there is no heat loss, is (14)
QFuel ) QFuelGT + QFuelFurn
(18)
The CO2 emissions from the gas turbine integrated with the process furnace can be calculated from eqs 2 and 11-18. In the above calculation of CO2 emissions, we considered only the process plant including the furnace, boiler, and the gas turbine. The emissions calculated in this case are called local emissions (12, 13), since we account only for the process plant. The power generated from the gas turbine is either consumed at the site itself or exported to other consumers. In both cases, the central power station, which is situated outside the plant boundaries, has the possibility of reducing electricity production by the amount that can be generated by the gas turbine. Thus, certain amounts of fuels can be saved at the central power station. This leads to a reduction in the CO2 emissions or, in other words, a saving in the emissions at the central power plant. Therefore, integration of a gas turbine with a process enables the central power station to reduce its emissions. So, we should consider the central power station together with the process plant as one unit in emission calculations. The CO2 emissions calculated in this case are called global emissions (12, 13). The reduction in fuel consumption at the central power station (∆QFuelPS; kW) is related to the amount of electricity generated by the gas turbine (WGT) and the power station efficiency, ηPS (-), as follows (14):
∆QFuelPS )
WGT ηPS
(19)
The efficiency of the central power station is assumed to be 30% (12, 13). The reduction in CO2 emissions at the power station can then be calculated from eqs 2 and 19, for a given type of fuel. Coal is used in the majority of power stations as a fuel. The global CO2 emission from the process plant and the central power station is defined as
global emissions ) emissions from process plant emissions saved at power station (20) Although the integration of a gas turbine with a process furnace reduces the operating costs by reducing fuel consumption, it incurs a substantial capital investment. There is a tradeoff between the capital cost of the gas turbine and the benefits obtained. The capital cost of the gas turbine, CostGT (k$), can be calculated from (14)
CostGT ) 195.1(10)-3WGT + 2529.2
(21)
The gas turbine enables the process plant to increase its profit by producing electricity; the value of electricity
generated (CostPowerGT; $/h) is a function of the unit cost of electricity (PUnitCost; $/kW h):
CostPowerGT ) PUnitCostWGT
(22)
So, when a gas turbine is to be integrated with a process, the CO2 emissions can be calculated locally or globally, and, at the same time, the capital investment and the value of the power generated are evaluated. For an existing crude oil distillation plant, the CO2 emissions are calculated individually for each heating device, i.e. process furnace, steam boilers, and gas turbine. Then, the total (or global) emissions can be determined for the process plant and for the process together with the central power station. The capital expenses and process income can also be evaluated.
Method Applications for Energy Savings and Emissions Reduction The proposed method can be applied to minimize energy consumption and utility costs or the emissions from heatintegrated distillation systems. The method is valid for both retrofitting existing refining distillation units and designing new equipment. The model is applied to two systems: the first case is an existing crude oil distillation unit with its heat exchanger network, while the other example is an internally heat-integrated distillation column. An Existing Refinery Crude Distillation Unit. In the refining industry, crude oil distillation units consist of interlinked columns, using pump-arounds, and contain different types of energy inputs such as stripping steam and reboilers. The distillation columns are directly connected to heat recovery systems (preheat trains or heat exchanger networks). The crude oil feed is heated to an intermediate temperature in the exchanger network in which the distillation heat sources reject heat to the heat sinks (e.g. crude oil feed). Then, the feed is heated further to the processing temperature in a furnace or fired heater. The heat sources in crude oil distillation columns include the overhead condenser, the hot liquids recycled in pump-arounds, and the hot distillation product streams. The heat sinks are the crude oil feed, the stripping steam, the cold liquids recycled in side-heaters, and the reboilers. CO2 emissions are produced in refining distillation systems from furnaces and boilers or due to importing electricity from power stations. Although substantial amounts of emissions are generated from such systems, a large number of degrees of freedom can be manipulated so that the emissions to the atmosphere can be reduced. For example, the process conditions of the distillation process can be changed to increase the energy recovery and hence reduce the energy consumption of the overall system. As a result, the emissions will be reduced; examples of these process changes are as follows: 1. When the feed preheating temperature in a reboiled column increases, the hot utility required in the reboiler reduces. The feed heater is a heat sink at a lower temperature than the reboiler, which will benefit heat recovery. In the case of steam distillation columns, increasing the temperature of the feed preheating will require less stripping steam for the same separation, and hence the bottom product temperature increases. This higher temperature creates opportunities for recovering heat from the bottom product and reduces hot utility requirements. 2. As the reflux ratio in the distillation column increases, energy consumption increases, with condenser and reboiler duties. As a result, the stripping steam flow rate needs to be increased as the condenser duty and the reflux ratio increase. This reduces the bottom product temperature, and therefore poorer opportunities for heat recovery exist. VOL. 39, NO. 17, 2005 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
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FIGURE 2. Atmospheric crude oil distillation column (numbers refer to sections). 3. Decreasing the flow rate of the stripping steam heat recovery opportunities because of the higher temperature of the bottom product. 4. The pump-arounds reject heat at temperatures higher than that of the condenser, creating opportunities for heat recovery. When the temperature difference across the pump-around decreases, the pumparound will operate at a higher temperature level, which improves heat recovery opportunities. On the other hand, if the pump-around duty increases for a fixed liquid flow rate, the temperature difference across the pump-around will increase. Therefore, the pump-around outlet stream will operate at a lower temperature level, downgrading the quality of the heat source for heat recovery. In addition to the above process changes, there is also the possibility of changing the working utility fuels and installing additional equipment in the overall system such as a gas turbine, flash drum, prefractionator, etc. To carry out a study on refinery distillation systems in which the emissions are to be reduced, the emission models presented can be used. The process conditions of the distillation column can be optimized in order to minimize the emissions. This can be done by incorporating the emissions models into an optimization framework developed based on models that can account for the existing designs of distillation columns and heat exchanger networks. Shortcut models for design of existing distillation columns were developed by Gadalla et al. (20), while an optimization-based approach for refinery distillation systems, that considers the details of the distillation columns together with the exchanger network, was proposed for energy reduction (21). The optimization objective can be minimizing the total annual costs including operation costs and capital expenses or minimizing CO2 emissions from an existing crude oil distillation system; i.e. the separation system, associated heat exchanger network, and integrated gas turbine, by changing the process conditions simultaneously. The objective function can also account for carbon taxes imposed by governments or for emission regulations (22). This method can thus be used to save energy and reduce variable costs as well as to reduce emissions of petroleum refining plants. Case Study s An Atmospheric Crude Oil Tower. The purpose of this case study is to select the operating conditions of an existing crude oil distillation unit to decrease the process energy demands and carbon dioxide emissions (atmospheric pollution). The existing column configuration, shown in Figure 2, uses three side-strippers (SS) and three pump6864
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arounds (PA). Steam at 4.5 bar and 260 °C is used for stripping at the bottom of the main column and in the bottom sidestripper, while reboiling is employed in the top and middle side-strippers. The distillation aspects of the case study are based on a textbook example of an atmospheric crude oil distillation tower; the crude oil mixture is the assay of Tia Juana Light (Venezuela) (25). The existing heat exchanger network is shown in Figure 3. Two hot utilities, flue gases from a fuel oil-fuelled fired heater and high-pressure steam, are used for heating purposes. The production capacity of the existing distillation tower is 100 000 barrels per day (589 t/h) of crude oil. The unit delivers five products: light naphtha (LN), heavy naphtha (HN), light distillate (LD), heavy distillate (HD), and residue (RES). The feed preheating temperature is 365 °C. The existing numbers of stages in each section of the atmospheric distillation tower and in side-strippers are given in Table 1; the actual column diameters are also provided. The energy consumption of the process, i.e. hot utility consumption, is 99 MW, while the cold utility requirements are 83.3 MW. The total operating costs, including hot utilities, steam, and water are 16.3 million dollars per year. Boiler provides a steam equivalent of 9.4 MW for heating process streams, while flue gases in the furnace supplies the remaining 89.6 MW of heat energy. Note that the flue gas in the furnace provides part of the heat load required by the stripping steam, while the process streams provide the other part. The reason is that the stripping steam is produced at the refinery site from the heat recovered from the distillation process and heat supplied by flue gas. Therefore, the heat load on the flue gas includes that load required by the stripping steam. So, the emissions from steam heat loads are calculated in a similar way to those from flue gas. The CO2 emissions for the existing tower are calculated from the model presented previously and are summarized in Table 2. The heating fuel used is heavy fuel oil; the net heating value and carbon content are given in Table 3. Total CO2 emissions are calculated for the steam boiler and the furnace. Table 2 indicates that the existing unit emits 32.8 t/h of CO2 from the furnace and steam boiler. The current operating conditions of the existing crude oil distillation tower are optimized to decrease carbon dioxide emissions and energy consumptions. These operating conditions are the temperature of the feed, reflux ratio, stripping steam flow rates, temperature difference of each pumparound, and the flow rate of the liquid through each pumparound. Integration of a gas turbine with the process furnace is considered as a design option in this context. The objective is typically minimizing the total annualized cost, including utility consumption, stripping steam, carbon tax, and the capital costs of the gas turbine and exchanger modifications, less the value of the power generated by the gas turbine. A carbon tax of 15 $/ton of CO2 is assumed (26). Heavy fuel oil is utilized in the steam boiler and central power station, while natural gas is burned in the central power station. A summary of the results is presented in Table 2; the economic parameters can be seen in Table 4. Note that when the gas turbine is integrated, the initial total heat load of 73.7 MW in the furnace, which includes stripping steam load, is distributed into two parts. The gas turbine provides a heat of 15.6 MW, while the furnace supplies the remaining 58.1 MW heat. As shown in Table 2, the current energy requirement of the current processing unit is decreased significantly from 99 to 79.8 MW for the optimum unit. The energy savings of the optimum unit are 20%, compared to the base case unit. The resulting savings in the operation costs are 3 M$/yr and a reduction of 19%. The cost savings are in the fuel consumption, stripping steam use. In addition, the modified unit with a gas turbine has a power production, equivalent to about a 3.9 M$/yr of electricity
FIGURE 3. Structure of existing heat exchanger network.
TABLE 1. Number of Stages and Existing Diameters of Distillation Tower Sections parameter
1
column sectiona 2 3 4
5
top middle bottom SS SS SS
number of 5 9 10 8 9 6 real stages existing 5.5 8.0 8.0 7.5 7.0 3.0 diameter (m) a
TABLE 2. CO2 Emissions from Existing Crude Oil Distillation Tower (Base Case) and Optimized Unit with an Integrated Gas Turbine
7
5
3.5
3.0
See Figure 2; SS: side-stripper.
costs. This is an extra profit to the refining site. On the other hand, the total carbon dioxide of the refinery site reduces by 7% from 32.8 t/h, for the base case to 30.3 t/h, for the optimized unit with gas turbine. This local reduction in emissions is relatively small, knowing that the emissions of the central power station will be reduced by 13.4 t/h of CO2 because of the decrease in the power demand of the site. Overall, the reduction in global CO2 emissions is considerable: 48.3%. In addition to the emissions reduction, the refinery can increase profit by producing electricity of 14.0 MW. This power can be consumed within the refinery or exported. The reduction in total operating cost, including the value of generated power, is about seven million $/yr. Less than a year is required to pay back the capital investment required for the gas turbine and exchanger network modifications. Necessary column changes are only those to the operating conditions of the distillation column, for example the feed preheating temperature is to be increased by 5 degrees, while the liquid circulation rate across the middle pump-around is to be decreased by 12%. Similar changes are to be done to steam flow rates, pump-arounds temperature differences, reflux ratio, etc. The exchanger network modifications required are additional heat transfer area and relocation of one existing unit. If a gas turbine is not to be integrated, the existing crude unit can still be optimized to reduce the energy consumptions and CO2 emissions. The objective in this case will be minimizing the total annualized cost, including utility consumption, stripping steam, carbon tax, and the exchanger network modifications. The results for this case are summarized in Table 5 and compared with those of the base case and the optimized unit integrated with a gas turbine. Table 5 illustrates that the energy consumption of the new optimum
base case
parameter total energy consumption utility steam heat load flue gas total heat loada heat load on gas turbine heat load on furnace CO2 emissions from steam boiler CO2 emissions from gas turbine CO2 emissions from furnace total local CO2 emissions CO2 emissions saved at power station total global CO2 emissions power generated in gas turbine capital cost of gas turbine value of power generated stripping steam flow rate total operating costsb exchangers capital investment total operating cost savingc total capital investment payback a
MW MW MW MW MW t/h
optimum unit
99.0 9.38 89.62
79.78 6.09 73.70 15.59 58.11 2.70
80.3 4.26
t/h
9.09
t/h t/h t/h
25.63 32.77
18.55 30.34 -13.41
t/h MW MM$ MM$/yr kmol/h MM$/yr MM$
16.93 14.0
1450 16.26
5.26 3.92 1255 13.23 0.43
MM$/yr MM$ yr
Includes stripping steam load. value of power generated
b
6.95 5.69 0.82
Includes utilities and steam.
cIncludes
TABLE 3. Data for Heating Fuels to Determine CO2 Emissions heavy fuel oil natural gas a
NHVa (kJ/kg)
carbon %
39771 51600
86.5 75.4
NHV: net heating value.
unit is 78 MW, with a saving of 21 MW with respect to the base case. Also, the accompanied emissions from the existing unit are reduced by 22% without installing a gas turbine versus 7% (locally) or 48% (globally) when a gas turbine is adopted. The energy costs of the optimum unit are signifiVOL. 39, NO. 17, 2005 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
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TABLE 4. Cost and Economic Parameters for CO2 Emissions Calculation parameter
value
electrical power carbon tax gas turbine capital cost
$/MW.h $/t CO2 k$
power station efficiency furnace efficiency boiler efficiency atmospheric temperature flue gas temperature stack temperature operation time
% % % °C °C °C yr/h
a
35 15 195.1 × (powera) + 2529.2 30 90 80 25 1800 150 8600
In MW (6).
TABLE 5. CO2 Emissions from Optimum Unit with Gas Turbine versus Existing Unit base case
parameter energy consumption utility steam heat load flue gas heat load total CO2 emissions total global CO2 emissions total operating costs HEN additional area total capital investment payback a
MW MW MW t/h t/h
99.0 9.38 80.28 32.77 32.77
optimized unit with GT no GT 79.78 6.09 73.69 30.34 16.93
78.02 6.16 71.87 25.68 25.68
12.98 MM$/yr 16.26 9.31a m2 1459 1239 MM$ 5.69b 0.38 yr
Includes value of power generated.
0.82 b
0.12
Includes cost of gas turbine.
cantly decreased to 13 M$/yr, i.e. a variable cost savings of 3.3 millions dollars per year is gained with relatively little capital investment and low payback time. Note that the two scenarios for emissions reduction save approximately the same amount of energy; this is because energy costs are dominant in this problem. Summary and Conclusion of Crude Oil Tower Case Study. Changes to the operating conditions of an existing crude distillation plant can cut the current energy consumption down by 21% and the CO2 emissions by 22%. Significant savings in operational costs are also achieved; a 3.3 M$/yr of energy cost is a typical saving for the case study considered. The integration of gas turbine with the process furnace of an existing crude tower leads to a further reduction in emissions of up to 48%. Additional cost savings are gained due to electricity production. Nearly 4 million dollars per year are an extra earning for the existing plant by integrating a gas turbine. Note that the working fuel in the heating devices of the existing unit was not changed. Additional considerable reduction in CO2 emissions is expected when the fuel is changed to a better fuel with a higher net heating value and low carbon contents. An Internally Heat-Integrated Distillation Column. Since distillation columns separating close-boiling mixtures are highly energy intensive, vapor recompression (heat pumping) has been widely adopted in such applications. Indeed, heat pump assisted distillation proved to be an energy efficient technology (27-30). In direct vapor recompression columns (VRC), the vapor leaving the top of the distillation column is compressed and is then condensed in the reboiler of the same column, providing the heat needed for vapor generation at the bottom of the column. Further intensifications of this concept lead to the development of internally heat-integrated distillation columns (HIDiC). These column configurations, 6866
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FIGURE 4. A schematic representation of a HIDiC (22). which combine advantages of both direct vapor recompression and diabatic operation (31-33), can have significantly lower energy demands than common vapor recompression distillation columns (34-36). As illustrated in Figure 4, the HIDiC configuration contains two separate distillation columns, the stripping and rectifying columns. There is a pressure difference between the two columns; the overhead vapor of the stripping column is compressed and then enters the bottom of the rectifying column. The rectifying column operates at a higher pressure, i.e. a higher temperature. The liquid from the bottom of the rectifying column is fed into the top of the stripping column, as is the column feed. The pressure of the recycled liquid stream from the rectifying column is equalized with that of the stripping column through a throttling valve. The vapor leaving the top of the rectifying column is the light product, while the heavy product is the bottom stream of the stripping column. The two columns are configured in a particular way so that the energy of the hot rectifying column can be used to heat the stripping column. The amount of heat transfer between the two columns can vary, and correspondingly the reboiler duty will change. When no heat is transferred, the reboiler duty will be equivalent to conventional duty (maximum). Heat is transferred on each column tray through an indirect contact of the rectifying hot vapor and the stripping cold liquid streams. This implies that continuous condensation of the vapor phase occurs along the rectifying column and continuous evaporation, i.e. vapor generation, takes place in the stripping column. This heat transfer is achieved in an external medium (device), such as heat panels. These panels are placed either on the rectifying side or stripping side of the column trays. As a result of integrating the two columns, the energy requirement in the reboiler is reduced. The more heat that is exchanged, the less energy is consumed. HIDiCs can be partial, when the reboiler energy consumption is reduced, compared to that in a conventional column, or ideal, when the reboiler duty is reduced to zero. HIDiC was first introduced and evaluated by Mah and co-workers (37, 38) under the name ‘Secondary Reflux and Vaporization’ (SRV). Seader (39) and Glenchur and Govind (40) suggested different column configurations for HIDiCs implementation. A shell and tube-type packed column was introduced for HIDiC by Aso et al. (41). Recently, a group of Japanese researchers (34, 35, 42-44) studied HIDiCs, concentrating on theoretical evaluation and pilot plant testing. The research results indicate significant energy savings with respect to conventional columns.
TABLE 6. HIDiC Problem Data and Specifications for Propylene-Propane Separation
TABLE 7. Energy Savings in Propylene-Propane Splitter
column specification feed composition flow rate pressure temperature rectifying pressure stripping pressure rectifying stages stripping stages top product purity bottom product purity
propylene mole % t/h bar °C bar bar propylene mole % propylene mole %
propylenepropane 50 111.6 12.2 31.7 19.2 12.2 154 57 99.6
heat transfer rate per stage (kW)
reboiler duty (MW)
energy savings (%)
compressor duty (kW)
0 (no heat integration) 100 200 400 600 800 1000 1100 1200 1300 1350 (ideal)
72.5 66.8 61.2 50.0 39.0 28.2 17.7 12.5 7.5 2.6 0
0 8 16 31 46 61 76 83 90 96 100
5066 5103 5141 5224 5316 5426 5552 5623 5706 5791 5830
1.1
As they are very energy efficient installations, internally heat-integrated distillation columns are expected to show a good opportunity for emissions reduction due to their potential for low utility consumptions. In an ideal HIDiC (i.e. with no reboiler), the energy of reboiler is zero, and no emissions are produced due to heating; however, there are still emissions from power production. The models for CO2 emissions presented above can be applied to HIDiCs to calculate the emissions produced and to estimate the potential of emissions reductions that can possibly be achieved by integrating gas turbines. Case Study s An Internally Heat-Integrated PropylenePropane Splitter. An internally heat-integrated distillation column is designed for separating an equimolar propylenepropane mixture (45). The problem data and design specifications given in Table 6 represent actual plant data for a state of the art heat pump assisted propylene-propane splitter. In this design, the stripping stages are integrated with the top stages of the rectifying column, i.e. the total 57 stripping stages are heated by the first top 57 stages of the rectifying section. The remaining part of the rectification column operates as a normal column. The ideal HIDiC requires 1.35 MW of energy to be transferred per stage from the rectifying column to the stripping column. The corresponding compressor load, i.e. power demand, is 5.84 MW. A conventional column with the same number of stages (basic data are given in Table 6) consumes 89.2 MW; a traditional heat pump assisted column consumes 75.8 MW of heat, and its compressor power demand is 8.1 MW. Note that in heatpumped columns, the reboiler does not require steam, since the compressed top vapors are used for heating purposes. These results are obtained by using Aspen Plus simulation (46), which uses a rigorous model for distillation design calculations. The physical and thermodynamic properties of feed, intermediate, and product streams are calculated by the Peng Robinson property model (46). In this case study to calculate CO2 emissions, different degrees of heat integration (levels) designs are considered, leading to different reboiler duties. The level of heat integration in HIDiC varies from zero heat integration, which corresponds to maximum reboiler duty, to full heat integration, which is equivalent to zero reboiler duty or ideal HIDiC. HIDiC is designed for the whole range of reboiler duties. Table 7 summarizes the results obtained for heat integration within HIDiC for the propylene-propane splitter. Each design transfers a certain amount of heat between the two columns. Therefore, the hot utility consumption in reboiler is reduced. The more the heat is transferred per stage, the lower the reboiler duty. As seen, the energy savings in HIDiC can reach a 100% compared to the base case where there is no heat
integration. Emissions are calculated for all ranges of reboiler duties, from zero (ideal HIDiC) to the maximum value. Two different fuels are used in the emissions calculation, heavy fuel oil, and natural gas; their data are shown in Table 3. Figure 5 shows the CO2 emissions calculated for HIDiC with different reboiler duties, compared with those from conventional and heat pump columns. These emissions are produced in the boiler that provides the required steam and in the power station. A conventional column (fueled by fuel oil) produces CO2 emissions of approximately 32 t/h. On the other hand, heat pump design (VRC using fuel oil) produces 8.7 t/h of CO2 globally. As shown in Figure 5, the reboiler duty is plotted on the X-axis. The plot starts on the right side with a maximum reboiler duty of 72 MW. This value corresponds to a HIDiC without heat integration. When increasing the heat integration level between the two columns, the reboiler duty will reduce. At zero reboiler duty (ideal HIDiC), complete heat integration is exploited; this requires an energy transfer of 1.35 MW of per stage. This case represents a full energy saving (100%). Note that by increasing heat integration, compressor loads are also increasing. This means that extra money will be spent on both the capital cost and electricity requirement of the compressor unit. Therefore, an optimization is required to select the best conditions of reboiler duty and heat integration level. However, further results showed that an ideal HIDiC (zero reboiler duty) has the minimum total annual costs for propylene-propane separation (45). Note that for the vapor recompression column, emissions are produced only in the power station. The local emissions in Figure 5 account for emissions from the boilers, while the global emissions include the emissions of the power station. Thus, the difference between the two emissions represents emissions produced in the power station. It is clear that the HIDiC emissions reduce significantly with reducing the reboiler duty. The local emissions start (equivalent to maximum reboiler duty) from the same emissions value produced by a conventional alternative and then reduce to zero when an ideal HIDiC is operated, i.e. with no reboiler. Along the local emissions line, the emissions from the power station are not considered. The global emissions start (no heat integration) at a value higher than that of the conventional column and then end at a value higher than zero, which is equivalent to the emissions of electricity production. It is clear that at the ideal HIDiC conditions, the emissions from HIDiCs are smaller than those from heat pumps (i.e. VRCs). This is because the HIDiCs consume less electricity than heat pumps. To operate a HIDiC in an environmentally friendly manner, the reboiler duty needs to be lower than 7.5 MW (see Figure 5); this value is equivalent to the emissions that are produced by heat pump designs. At this reboiler duty, HIDiCs will have the same environmental impact as heat pumps (VRCs). Below VOL. 39, NO. 17, 2005 / ENVIRONMENTAL SCIENCE & TECHNOLOGY
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FIGURE 5. CO2 emissions from a HIDiC without gas turbine integration; fueled by fuel oil or natural gas (column details are given in Table 6).
FIGURE 6. Global CO2 emissions from a HIDiC with a gas turbine (fueled by fuel oil or natural gas). this reboiler duty, HIDiC is a competitive configuration to conventional column and heat pumps in both energy consumption and CO2 emissions. An ideal HIDiC can save 100% in hot utility demands, while the emissions are reduced by 83% compared to a conventional column and by 36% compared to a heat pump. When a gas turbine is integrated with a HIDiC, the local emissions are expected to rise compared to the original case (without turbine). This is due to extra quantities of fuel which are burnt by the gas turbine to provide the required compressor power and heat duty. It is assumed that the excess power produced by the turbine will be exported to the neighboring sites. In addition, the hot flue gases of the gas turbine have a surplus heat that can be exported to other processes and thus extra savings in steams will be gained. This is valid when HIDiC is ideal, i.e. no reboiler is used. Figure 6 illustrates the global CO2 emissions for a HIDiC integrated with a gas turbine, fueled either by fuel oil or natural gas. As shown, the emissions from the unit with a gas turbine reduce significantly compared to the base case (without gas turbine). It must be noted that the emissions in this case account for three devices, the steam boiler, gas turbine, and the power station. There is a sharp decrease in the global emissions below a reboiler duty of approximately 40 MW. This is because, below this reboiler range, the power generated in the gas turbine is exactly equal to that required by the compressor. Hence, there is no excess power, and 6868
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consequently not much fuel is burnt by the gas turbine, which reduces emissions. When the HIDiC is operated with no reboiler, the global emissions are theoretically negative, as shown in Figure 6 (-570 kg/h; for fuel oil). This is because no heat is required by the ideal HIDiC. Furthermore, the power required by the compressor is supplied by the gas turbine. Therefore, no emissions are produced locally by the HIDiC, from the steam boilers or globally due to power consumption. Moreover, the gas turbine has a surplus heat that can be exported. The exported heat provides an opportunity for other processes to save emissions at their sites. Therefore, the reductions in emissions for HIDiCs with turbines are estimated to be above 100%, compared to heat pumped designs (VRCs). When a HIDiC is to be operated with a reboiler, there should be an optimum value for the reboiler duty; this value could be economically driven, related to control issues or related to environmental consequences. For environment benefits, the results of Figure 6 may suggest that the reboiler duty should be below 22 MW. At these conditions, the emissions from HIDiCs will be less than or equal to those of the heat pumped alternative. Therefore, the environmental impact will be no greater than that for an efficient heat pumped design (VRC). The above discussions showed that HIDiCs provide large opportunities for energy savings and considerable potential for emissions reduction. On the other hand, the economics
respectively. In addition, process profit is improved extensively by creating an income out of exporting electricity. The proposed method can be applied to other complex distillation columns/systems for minimizing the energy consumptions and emissions and increasing profit.
Acknowledgments
FIGURE 7. Economic analysis of a HIDiC with a gas turbine.
Part of the model development of this work was done at the Center for Process Integration (The University of Manchester, U.K.). The application of the model to an industrial Propylene-Propane Splitter was carried out in the Laboratory for Process Equipment (TU Delft, NL). The authors thank the Economy Ecology and Technology (EET) Bureau (NL) for the financial support and the Borealis Group for providing the actual plant data. We also thank Dr. Lanyi Sun and Mr. Aris de Rijke from the laboratory of Process Equipment, for their work and efforts in providing the simulation results of the energy requirements for the conventional, heat pump, and HIDiC designs.
Literature Cited parameters of the HIDiC with gas turbine are shown in Figure 7. Electricity savings are equal to the power demand of the compressor, which will be provided by the gas turbine. Similarly, exported electricity is that in excess of the compressor power consumption. The net profit is the value of exported power and saved imported power less the annualized cost of the gas turbine (see eq 21; annalization factor ) 0.1). As shown, the net profit is relatively high when the reboiler duty is large (partial HIDiCs). This is because the power output of the gas turbine is large, and consequently greater amounts of electricity are to be exported, increasing income. The net profit is between 10.5 and 4 millions dollars per year. Further calculations showed that the payback time varies from 1.3 to 0.8 years. Summary and Conclusion of HIDiCs Case Studies. Studies showed that new heat integrated distillation columns HIDiCs can save energy with up to 100% compared to conventional units. Operating costs are also due to decrease. CO2 emissions can be reduced extensively compared to conventional and heat pump columns. Therefore, HIDiCs can compete very well with the traditional columns by saving energy and cutting down emissions. Integration of gas turbine with existing HIDiC designs leads to further savings in utility costs and emissions reductions and brings more income to the process by exporting electricity.
Concluding Remarks In this paper, an optimization model-based approach has been introduced that accounts for CO2 emissions from heat integrated distillation units. The approach optimizes all process conditions for saving energy and reducing emissions, considering changes to the existing structure. The model can consider different utility devices, which are common in most industrial applications. It has been shown by applying the new approach that crude oil atmospheric units can save energy by 21% and reduce emissions by up to 22%, while the existing structure is fixed. Significant savings in utility costs can reach up to 3.3 M$/yr for an existing crude atmospheric tower. Utilizing gas turbines is a key modification for cutting down operational costs and emissions further. When gas turbine is used, a typical reduction of up to 48% is achieved, and at least a profit of 4 million dollars per year is earned. It has been shown that new distillation columns with internal heat integration exhibits extreme energy savings compared to traditional configurations. Savings can reach up to 100% of reboiler duties. Accordingly, operation cost is reduced. On the other hand, the CO2 emissions of such configurations can be decreased by 83 and 36% compared to conventional alternatives and heat pumps designs,
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Received for review February 10, 2004. Revised manuscript received June 22, 2005. Accepted June 23, 2005. ES049795Q
