High Efficiency, Zero Emission Power Generation Based on a High-Temperature Steam Cycle

Most of the electric power produced worldwide is based on fossil fuel combustion, largely in plants operating with low efficiency cycles. The large amounts of fuel consumed in this process release harmful emissions including toxic nitrogen and sulfur oxides, mercury, and greenhouse gases such as carbon dioxide. The necessity to reduce the negative impact of power generation on the environment, together with economic considerations are leading a concerted effort to modernize this crucial technological field. While the shape of the power plant of tomorrow is not yet well defined, it is well accepted that existing technologies will undergo significant changes. At the same time, rising oil and natural gas prices require efficient use of the most abundant, readily available fuels – coal, biomass, petroleum residuum etc. This paper presents evaluations of new power generation concepts, designed to simultaneously address efficiency and environmental concerns. The power plant is capable of using a wide variety of fuels, including coals and low quality organic wastes or by-products. By releasing essentially pure components (carbon dioxide and water), the proposed concept can be combined with carbon sequestration technology, and therefore lead to a “zero emission power plant.” The fuel is processed prior to its introduction in the power generation cycle using proven gasification technologies. Once the solid fuel is gasified and cleaned, the resulting gaseous fuel is combusted with oxygen essentially stoichiometrically in a high-pressure gas generator in the presence of large amounts of recirculated water or steam. This produces nearly pure steam and carbon dioxide (CO2) at appropriate high temperature, high pressure, and flow rate. These gases are expanded in one or more turbines and the residual heat is recovered in heat exchangers. The power generation scheme requires an air separation unit, whose products are used such that the overall efficiency of the cycle is maximized. Depending on turbine inlet temperatures and the nature of the cycle, the overall efficiency of the power plant, including the air separation process, may exceed 60%. Various power generation schemes are analyzed in this paper, using advanced process simulators, namely ASPEN Plus and HYSYS. Each block is analyzed in detail including the gasification block, the air separation unit and the power generation island. It is concluded that the envisioned plant is a preferred solution for future power generation. INTRODUCTION The economic growth of society goes hand-in-hand with the increase in power consumption. Since the beginning of civilization we have burned fuels for various reasons, and for more than 100 years, coinciding with the industrial revolution, huge amounts of fossil fuels have been used to generate power. Today, traditional power plants use roughly the same amount of fuel as the transportation sector. In spite of technological advances, a large proportion of power is still generated in old coalfired plants with low efficiencies – 25 to 45%. Thus, roughly 2/3 of the calorific value of the fuels is lost. Together with wasting large amounts of heat, these plants continue to pollute our environment. Noxious compounds are contaminating our air and water, with shortand long-term impact. Thus, sulfur and nitrogen oxides lead to acid rain, nitrogen oxides and carbon monoxide present health hazards, and mercury pollutes our air, soil and water. These components are becoming increasingly regulated, because their impact on the environment and public safety has been clearly demonstrated. Yet, by far, CO2 is the largest by-product of fossil fuel combustion. Each MWh-electricity produced releases tons of CO2 into the atmosphere. While part of it is consumed in natural processes, the rest accumulates in the environment, primarily in the air. This is the reason why the CO2 content in air has increased from 260 to 320 ppm in the last 40 years, and for a high probability of its reaching 500 ppm in the next decades. The increase in atmospheric CO2 levels is believed to be responsible for a greenhouse effect in the atmosphere, contributing to global warming of the Earth. Carbon dioxide is one of the gases which absorbs/emits strongly in the infrared spectrum and, therefore, inhibits heat dissipation from the atmosphere. Rapid global warming may have a strong impact on our civilization, from geographical changes (rising sea levels flooding low-lying areas) to climatic changes (excessive droughts, precipitation, devastating storms etc.). While scientists, politicians and almost everybody else argue whether recent climate changes are attributable to greenhouse gases such as CO2, there is a consensus that human activity is impacting nature. This is the reason for a public demand for a change in the way business is conducted. Governments are investigating ways to regulate greenhouse emissions (Norway already has carbon tax in place and other countries are following), and commit to research in this area (US-DOE through the Vision 21 Program, European Community, Japan, etc.). Fossil fuel-based energy is expected to continue to be dominant in the coming decades, as the known reserves (primarily coal) are plentiful. Nuclear power in certain regions will continue to play an important role, although today it is unpopular in several countries including the US and Germany. Regardless of the way energy is produced, it must be “green” so its impact on the environment is minimal. Thus, nuclear wastes have to be properly contained, and the fossil fuel plants have to be much more effective in terms of emissions. A tremendous effort has been in place in the recent years to reduce priority pollutants such as NOx, SOx, mercury, etc. Today there is a trend to also reduce greenhouse gas emissions, requiring an overhaul of traditional power generation processes. Greenhouse emissions are reduced through increased plant efficiency. Efficiency increases have been achieved in the recent years through cogeneration, gasification, material breakthroughs, etc. but that approach has only limited effectiveness. It is a growing sentiment that greenhouse gases must be eliminated – at least to a large degree. The significant reduction/elimination of greenhouse gases can be achieved through sequestration, a concept gaining more and more acceptance. Different sequestration methods are envisioned today, such as injection into the deep-ocean, saline aquifers, oil-bearing strata, and coal seams. Ninety percent of the estimated U.S. coal resources are unmineable due to the depth. The two latter approaches have special appeal because they can substantially enhance oil recovery and the recovery of methane from deep unmineable coal beds. In all cases, the sequestration methods must ensure the permanent storage of large amounts of CO2. Many studies are in progress to assess the issues critical to CO2 storage. In any event, carbon sequestration is strongly related to the issue of CO2 capture. Thus, the power generation schemes to be developed must include technologies providing a relatively pure stream of CO2. Several schemes are envisioned today for capturing CO2, all requiring significant investment, and several requiring an overhaul of the current power generation cycles. This overhaul is nevertheless necessary, if electric power is to be generated at higher efficiencies and with major reductions in the emission of pollutants and CO2. This paper presents a novel power generation concept designed to operate with increased efficiencies, and capable of economically capturing the CO2 effluent for sequestration. In this respect, the power plant presented qualifies as a “zero emission power plant,” and it may efficiently replace existing generating units. The proposed design is extremely flexible in terms of the fuel required, thus reducing the growing dependency on natural gas. Although the power generation scheme is highly integrated to make it very efficient, it is believed that its operation may be more reliable and efficient than the existing IGCCs. This paper describes in detail the concept, and the results of the process simulations performed on the selected schemes, for a variety of fuels such as natural gas and coal. An economic analysis shows that, using available hardware, the scheme is attractive today, with significant potential for tomorrow. ZERO EMISSION POWER PLANT CONCEPT The concept of the envisioned power plant consists of three blocks: i) air separation, ii) fuel processing (if necessary, particularly for solid fuels), and iii) power generation. The Air Separation Unit (ASU) supplies different gaseous products with a high level of purity – such as oxygen, nitrogen, argon, etc. The ASU can be designed in such a way as to produce the desired flows of products at required pressures, purity, etc. The fuel pre-processing block is designed to transform different solid and possibly liquid fuels, including waste fuels, into gaseous fuels, used in the third block – the power generation section. The three blocks are integrated, such that the overall process efficiency is maximized. This effort presents two different configurations, based on the same advanced power generation concept. A first scheme based on gaseous fuels is analyzed in detail and optimized, followed by a scheme using solid fuels. Figure 1 presents the principle of the design. The gaseous oxygen is introduced into a gas generator where it is mixed with the gaseous fuel in essentially stoichiometric proportions along with a relatively large amount of recycled water/steam. The gas generator ensures that the fuel burns completely, and the exiting products have the required pressure, temperature and composition (H2O, CO2, and trace by-products). The gas temperature and pressure at the outlet of the gas generator are determined by the turbine, in which the drive gases are expanded. In this case the turbine is a hybrid steam/gas turbine, which implies that, at least in principle, it can capitalize on the advantages of each system. The products of combustion can have high pressures (characteristic of steam turbines), and high temperatures (as gas turbines), with beneficial effects on the cycle efficiency. Following expansion in the high-pressure turbine, the drive gas is reheated by firing with additional fuel and oxygen, and expanded through a second turbine, which closely resembles a gas turbine. The residual thermal energy of the discharge from this turbine is recovered by high-pressure water in a heat exchanger. For corrosion purposes, the gases are kept above the dew point, and water is condensed in a subsequent condenser. This condenser separates the water from the other combustion products, primarily CO2 and excess oxygen (around 2%, dry basis) (plus other contaminants from the fuel and oxygen). Carbon dioxide can be further purified, liquefied, etc. The condensed water is pumped, heated in recovery heat exchangers, and redirected to the high-pressure gas generator. Finally, the cycle contains a nitrogen stream. Since modern ASUs could produce high-pressure nitrogen as well as oxygen, the large nitrogen flow can be used to increase the cycle efficiency and power throughput. The nitrogen flow is further compressed to the desired pressure, then heated to the desired temperature in the heat recovery exchanger (where additional fuel can be used), and expanded in a nitrogen turbine. The residual thermal energy of the nitrogen can be recovered in an additional heat exchanger. The nitrogen stream is very clean, thus the turbine, heat exchangers, etc. can be expected to operate without extensive maintenance, unlike traditional flue gas equipment. The scheme in Fig. 1 has full heat recovery potential, such that the end products leave the power generation cycle at low pressures and temperatures. On the other hand, the cycle is very flexible regarding the physical parameters of the products, in order to accommodate requirements downstream. Thus, if the CO2 recovery scheme requires a higher inlet pressure, the outlet pressure of the low-pressure turbine can be adjusted to address this issue. A similar adjustment can be applied to the nitrogen outlet parameters. Clean Energy Systems (CES) propose similar type advanced power generation schemes using both natural gas and gaseous fuels derived from coal, bio-mass, etc. The present effort considers several alternative schemes, including integration of the power generation cycle with the air separation cycle. These schemes show significant increases in the overall process efficiency, as is illustrated below. The following sections will investigate several different plant designs using both natural gas and coal. The schemes presented below show different degrees of integration between the various islands, in order to clearly assess the impact of each element. The power generation island was evaluated by using the ASPEN Plus process simulation tool. Specifically, the power outputs of the various turbines were determined for selected input flows, temperatures, and pressures. Also, the internal power requirements of the plant, namely oxygen/fuel compressors, vacuum pumps, and water pumps were accounted for. The ASU has been modeled using the HYSYS process simulator, which has been custom-designed by and for Air Liquide, and the results from this simulation in terms of gas outputs, physical properties of the resulting gases and the power consumption have been used in the integrated process. NATURAL GAS-FIRED SCHEMES Case 1 (Baseline Cycle) The scheme depicted in Fig. 2 is treated as the baseline case. There is very limited interaction between the air separation unit and the power generation block – oxygen is considered an input into the power generation block, with its corresponding impact on the energy output, as shown in Table 2. In the scheme, fuel, oxygen, and recycled water/steam are delivered to a high-pressure gas generator that produces a high enthalpy gas to drive a high-temperature steam turbine. The discharge from the steam turbine is reheated by firing with additional fuel and oxygen. This stream drives an intermediate pressure turbine and a low-pressure steam turbine. The final discharge is cooled in a heat exchanger before entering the condenser. Recycled water is used to recover energy in the heat exchanger, before being fed to the high-pressure gas generator. Table 1 contains the key assumptions. Table 1. Key Assumptions of the base-case. HP, IP, LP Turbine inlet pressures 103.4, 11.4, 1.17 bar LP Turbine outlet pressure 0.145 bar HP, IP, LP Turbine inlet temperatures 816, 1204, 566 C Turbine efficiencies (HP, IP, LP) 93% Fuel and oxygen compressor efficiency 75% Compressor intercooling temperature 32 C Outlet stream temperature (before condensor) 54 C Fuel delivery pressure 1.38 bar Oxygen delivery pressure 2.07 bar Pressure drop through combustor and reheater 10% Vacuum pump efficiency 90% CO2 compressor efficiency 90% Intercooling temperature for CO2 train 32 C Liquefied CO2 Pressure 144.8 bar Fuel composition 100% CH4 Fuel lower heating value (LHV) 50 MJ/kg The choice of the inlet conditions for the HP turbine (816 C, 103bar) is based on the results of a turbine development project carried out by Solar Turbines, under a US DOE program (Duffy and Schneider). The IP turbine inlet temperature of 1204 C represents a value that can is attained with current gas turbine technology, while the LP turbine inlet temperature of 620 C is attainable with current steam turbine technology. The outlet stream temperature of ~177°C (before condenser) is above the dew point, ensuring that condensation only occurs in the condenser. The oxygen and fuel supply pressures are assumed the same as the following Case 2, as are the pressure drops through the gas generator and reheater. Fuel and oxygen are compressed to the required pressures in stages, using a pressure ratio of roughly 2.5 per stage, and an intercooling temperature of 32 C. The CO2 liquefaction pressure of 144.8 bar is typical for enhanced oil recovery (EOR) applications, and is considered by many to be an acceptable sequestration pressure [3]. CO2 liquefaction is accomplished by staged compression with 32 C intercooling. Table 2 contains the results of an analysis of this cycle. A plant with a 400 MWe (net) output was considered. Table 2. Efficiency analysis of the base-case. Thermal input (LHV) 958.9 MW HP Turbine output 154.8 MW IP Turbine output 256.5 MW LP Turbine output 137.1 MW Gross power output 548.4 MW Internal power consumption Compressors and vacuum pumps 55.6 MW CO2 compressor (for liquefaction) 17.7 MW Water pumps 5.6 MW ASU power 69.4 MW Net power output 400 MW Net efficiency (LHV) w/ sequestration 41.7% Net efficiency (LHV) w/o sequestration 43.6% The purpose of the condenser vacuum pump is to maintain the LP turbine outlet pressure (0.145 bar(abs) for this case) i.e. it raises the pressure of the non-condensable discharge stream to atmospheric pressure. The CO2 compressor raises the pressure of the CO2 discharge stream to a sequestration operating pressure of 144.8 bar. The net efficiency w/sequestration includes the CO2 liquefaction step, while the value w/o sequestration refers to the case where it is excluded (in this case CO2 is released as gas from the installation). The results in Table 2 show that the efficiency of the cycle is around 42% with sequestration, and around 43% without sequestration. Case 2 (Optimized Baseline Cycle) The scheme depicted in Fig. 3 represents an optimization of the baseline scheme. The heat exchanger placed between the IP and LP turbines is removed, and the inlet pressure of the IP turbine is optimized. A natural gas supply pressure typical for gas-fired power plants (12.4 bar) is assumed, while the oxygen supply pressure is taken to be 27.6 bar (E. Hanninen). The outlet pressure of the lower pressure turbine is set to 0.04 bar, a value used in current state-of-the-art GE combined cycle systems (R.W. Smith et a.l). Three different IP turbine inlet temperatures are considered: 1204 C, which represents a temperature easily attainable with current gas turbine technology, 1427 C, the rated temperature for GE’s H class gas turbines, and 1649 C, a gas turbine development goal of the US DOE Vision 21 program. The assumptions for this case are listed in Table 3, and the results of the efficiency analysis are shown in Table 4. Table 3. Key Assumptions of Case 2. HP, IP Turbine inlet pressures 103.4, 9.0 bar LP Turbine outlet pressure 0.04 bar HP Turbine inlet temperature 816 C IP Turbine inlet temperatures 1204, 1427, 1649 C Turbine efficiency 93% Fuel and Oxygen Compressor efficiency 90% Compressor intercooling temperature 32 C Fuel delivery pressure 12.4 bar Oxygen delivery pressure 27.6 bar Condenser Vacuum Pump Efficiency 90% CO2 Compressor Efficiency 90% Liquefied CO2 Pressure 144.8 bar Table 4. Efficiency Analysis of Case 2. IP Turbine Inlet Temperature 1204 C 1427 C 1649 C Thermal input (LHV) 791.9 MW 742.6 MW 703.7 MW HP Turbine output 129.9 MW 108.9 MW 91.6 MW IP Turbine output 365.9 MW 379.2 MW 390.1 MW Gross power output 495.8 MW 488.1 MW 482.2 MW Internal power consumption Compressors and vacuum pumps 18.5 MW 15.9 MW 13.8 MW CO2 compressor (for liquefaction) 14.4 MW 13.9 MW 12.9 MW Water pumps 4.6 MW 4.5 MW 3.9 MW ASU power 57.7 MW 54.0 MW 51.2 MW Net power output 400 MW 400 MW 400 MW Net efficiency (LHV) w/ sequestration 50.6% 53.9% 56.9% Net efficiency (LHV) w/o sequestration 52.4% 55.7% 58.7% These results indicate that cycle optimizations combined with the modified input conditions result in significant efficiency improvements. Case 3 (Cycle with Double Reheat and Nitrogen Integration) The scheme depicted in Fig. 4 employs two reheaters and includes integration with a HP nitrogen stream from the ASU. In certain ASU designs, nitrogen is available from the high-pressure column at approximately 6 bar. In this embodiment, the HP N2 stream is compressed further, heated, and expanded through a turbine. The residual heat in the nitrogen discharge is subsequently recovered by a feedwater stream. This case involves indirect heating of the nitrogen the nitrogen stream is heated in a heat exchanger placed after the first reheater. The key assumptions are shown in Table 5. Table 5. Key Assumptions of Case 3. HP, IP, LP Turbine inlet pressures 103.4, 51.7, 25.9 bar LP Turbine outlet pressure 0.04 bar HP Turbine inlet temperature 816 C IP, LP Turbine inlet temperatures 1204, 1427, 1649 C Turbine efficiency 93% Fuel and oxygen Compressor efficiency 90% Compressor intercooling temperature 32 C Fuel, oxygen delivery pressures 12.4, 27.6 bar Condenser Vacuum Pump Efficiency 90% CO2 Compressor Efficiency 90% Liquefied CO2 Pressure 144.8 bar HP Nitrogen supply pressure 6 bar HP Nitrogen mass flowrate Same as oxygen flowrate HP Nitrogen inlet temperature 21 C Nitrogen turbine inlet pressure 25.9 bar Nitrogen Turbine inlet temperatures 1204, 1427, 1649 C Turbine efficiency 93% Nitrogen compressor efficiency 90% Nitrogen discharge temperature 49 C Table 6. Efficiency Analysis of Case 3. IP, LP, N2 Turbine Inlet Temperatures 1204 C 1427 C 1649 C Thermal input (LHV) 742.2 MW 684.4 MW 641.7 MW HP Turbine output 37.5 MW 29.2 MW 23.0 MW IP Turbine output 60.2 MW 58.1 MW 56.3 MW LP Turbine output 352.2 MW 349.8 MW 347.6 MW N2 Turbine output 54.7 MW 58.5 MW 61.4 MW Gross power output 505.1 MW 496.0 MW 488.6 MW Internal power consumption Compressors and vacuum pumps 32.5 MW 29.6 MW 26.5 MW CO2 compressor (for liquefaction) 13.8 MW 12.6 MW 12.0 MW Water pumps 4.4 MW 4.0 MW 3.6 MW ASU power 54.3 MW 49.8 MW 46.6 MW Net power output 400 MW 400 MW 400 MW Net efficiency (LHV) w/ sequestration 53.9% 58.4% 62.3% Net efficiency (LHV) w/o sequestration 55.8% 60.3% 64.2% Case 4 (Scheme with Double Reheat, Nitrogen Integration, and no HP Combustor) Figure 5 depicts an embodiment in which the drive gas for the high-pressure turbine is produced in a heat exchanger (boiler) rather than a high-pressure gas generator. In this case, pure steam can be used for the high-pressure turbine, and no high-pressure gas generator is required. The discharge from the high pressure turbine is directed to a reheater, which produces drive gas for the lower pressure turbines, as well as generating steam, and heating the HP nitrogen stream from the ASU. The results are shown in Table 7. Key assumptions are the same as those used in Case 3. Table 7. Efficiency Analysis of Case 4. IP, LP, N2 Turbine Inlet Temperatures 1204 C 1427 C 1649 C Thermal input (LHV) 751.5 MW 690.9 MW 647.4 MW HP Turbine output 22.5 MW 17.9 MW 14.6 MW IP Turbine output 62.3 MW 59.8 MW 57.6 MW LP Turbine output 363.2 MW 358.1 MW 354.6 MW N2 Turbine output 54.7 MW 58.6 MW 61.3 MW Gross power output 502.7 MW 494.0 MW 488.1 MW Internal power consumption Compressors and vacuum pumps 29.7 MW 27.4 MW 25.5 MW CO2 compressor (for liquefaction) 13.8 MW 12.6 MW 11.9 MW Water pumps 4.6 MW 4.1 MW 3.6 MW ASU power 54.7 MW 50.1 MW 47.0 MW Net power output 400 MW 400 MW 400 MW Net efficiency (LHV) w/ sequestration 53.2% 57.9% 61.8% Net efficiency (LHV) w/o sequestration 55.1% 59.7% 63.6% COAL-BASED CASES To assess the feasibility of the above concepts for solid fuels, several embodiments were analyzed using synthesis gas in place of natural gas. The syngas could potentially be derived from coal, waste fuels such as petroleum coke, or biomass. For the purpose of this analysis, the gasification technology was assumed to be the Texaco process, using Illinois #6 coal. Additional assumptions are shown in Table 8, from Shelton and Lyons. In this configuration, the hot synthesis gas leaving the gasifier is cooled to 152 C in a radiant heat exchanger followed by a convective cooler. The cooled syngas subsequently enters a cold gas cleanup system for removal of H2S, COS, NH3, HCl, particulates etc. Energy is recovered from the hot syngas by producing steam and hot water in the heat exchangers, and feeding these streams to the high-pressure gas generator. This is described in Marin et al. Table 8. Characteristics of gasifier (based on Texaco process). Syngas Composition [molar%] H2 37.67 CO 49.86 CO2 10.45 Inerts (treated as N2) 1.94 Gasifier outlet temperature 1370 C Radiant, convective cooler outlet temperatures 815, 152 C Syngas temperature 38 C Syngas pressure 23.1 bar Oxygen required for gasification 0.78 kg/kg coal Analyses were carried out for Case 3. The results are presented in Table 9. Table 9. Efficiency Analysis of Case 3, with coal-derived syngas as fuel. IP, LP, N2 Turbine Inlet Temperatures 1204 C 1427 C 1649 C Thermal input (LHV) 812.1 MW 744.6 MW 686.1 MW HP Turbine output 31.6 MW 24.2 MW 18.7 MW IP Turbine output 52.2 MW 50.1 MW 48.2 MW LP Turbine output 363.2 MW 357.5 MW 353.0 MW N2 Turbine output 57.0 MW 60.6 MW 63.5 MW Gross power output 503.1 MW 494.5 MW 483.4 MW Internal power consumption Compressors and vacuum pumps 47.3 MW 41.6 MW 36.7 MW CO2 compressor (for liquefaction) 24.4 MW 22.3 MW 20.6 MW Water pumps 1.7 MW 1.4 MW 1.1 MW ASU power 54.1 MW 49.6 MW 45.7 MW Net power output (w/o CO2 liquefaction) 400 MW 400 MW 400 MW Net efficiency (LHV) w/ sequestration 46.3% 50.7% 55.3% Net efficiency (LHV) w/o sequestration 49.3% 53.7% 58.3% We can see that, overall, the efficiency results using coal are higher than typical IGCC efficiencies. At the same time, it is noted that the coal-based efficiencies are around 6 percentage points lower than the corresponding natural gas-based efficiencies. In any event, it is concluded that the proposed schemes are nearing Vision 21 goals on coal-based power generation of 60% efficiency. CONCLUSIONS This paper presents analyses on a series of advanced power generation concepts using oxy-combustion and carbon capture. The power generation schemes analyzed here integrate the power generation island and the air separation island. The results of the process modeling for the different concepts analyzed are presented, including the assumptions used and the efficiencies obtained. It is shown that, under certain circumstances, the efficiencies reached by these concepts equals and/or exceeds the performance of advanced combined-cycle systems. Table 10 summarizes the efficiency results for all cases discussed. These results are reported for cases with CO2 sequestration. Table 10. Summary of Efficiency Results (w/o sequestration) Turbine Inlet Temperature Case Fuel # Reheaters HP N2 Integration 1204 C 1427 C 1649 C 1 -Baseline CH4 1 No 43.5% 2 CH4 1 No 52.4% 55.7% 58.7% 3 CH4 2 yes 55.8% 60.3% 64.1% 4 CH4 2 yes 55.1% 59.7% 63.6% 3 syngas 2 yes 49.3% 53.7% 58.3% While several technical aspects have to be resolved, primarily in terms of advanced high-temperature steam turbines, the existing programs suggest that in up to 5 years many of the targets sought in this paper may be achieved and exceeded – such as a 1427°C (2600 ̊F) steam turbine. The plant integration concepts described indicate that this process can efficiently replace existing power generation schemes. In addition, by using a variety of low-priced fuels such as coals, biomass, etc., the overall economics will be dramatically improved. Future work will include a more detailed economical study, together with an engineering analysis of the integration challenges.