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1 THE AMERICAN SOCIETY OF MECHANICAL ENGINEERS 345 E. 47th St., New York, N.Y The Society shall not be responsible for statements or opinions advanced in papers or discussion at meetings of the Society or of its Divisions or Sections, or printed in its publications. Discussion is printed only if the paper is published in an ASME Journal. Papers are available from ASME for 15 months after the meeting. Printed in U.S.A. Copyright 1994 by ASME 94-GT-378 ASSESSMENT OF POWER GENERATION CONCEPTS ON OIL PLATFORMS IN CONJUNCTION WITH CO2 REMOVAL Yngvil Bjerve Kywrner Engineering as. Environmental Sandefjord, Norway Olav Bolland Norwegian Institute of Technology (NTH) Trondheim, Norway ) ABSTRACT The introduction in 1991 of a CO 2-tax on offshore combustion of natural gas has lead to an increased interest in both energy conservation and the possibility of separating CO, from gas turbine exhaust In this paper, several power generation concepts based on natural gas combustion by existing technology have been assessed in order to find the concept best suited for CO, removal. An important factor when developing processes for offshore implementation is that space and weight are very expensive offshore. The suggested process consists of a power generation unit, a CO2 absorption unit and a CO, compression unit. The power generation concepts have been evaluated in order to find the concept which combines the factors low exhaust gas flow, high CO, concentration, high efficiency and low weight in the best possible manner. The result of the assessment is that a combined cycle with recycling of 40% of the exhaust volume back to the compressor inlet, is best suited for CO 2 removal among the options studied. INTRODUCTION The Norwegian Government established in 1989 the objective that the total CO 2 emissions in Norway in the year 2000 shall be stabilized on 1989 level. This lead to the introduction of the CO 2-tax in 1991, which in turn motivated the Norwegian oil companies to study new methods and technologies in order to reduce the total CO, emissions. At present, the CO 2-tax for offshore utilization of natural gas is 0.80 NOK/Sm 3. This is equivalent to 50 Shonne CO 2 generated. The CO,-tax presently being discussed within the EC-countries is approximately 24 Shonne CO, generated. There are several special considerations that must be taken into account when developing a CO 2 removal process intended for offshore installation. The most crucial constraint is that space and weight are very expensive offshore, the equipment must therefore be as compact and light weight as possible. The second constraint is that the CO 2 removal process must be installed such that maintenance of the separation plant does not interfere with the availability of the oil production process on the platform. Thirdly, there are good possibilities for deposition of the pure CO 2 from offshore installations. The CO 2 can be compressed and injected either into deep seawater, aquifers, depleted oil/gas reservoirs or into reservoirs still in production. The latter could lead to enhanced oil recovery. At the First International Conference on Carbon Dioxide Removal, several studies related to CO 2 removal from power generation systems were presented. De Ruyck (1992) proposed a combined CO 2 and steam cycle which is an extension of the humid air turbine (HAT) cycle. Bolland and Sather (l992)proposed several alternatives for simplifying the removal of CO2. Several studies were published by the lea Greenhouse Gas R&D Programme during 1992, but most of them were focused on CO 2 abatement from coal fired power plants. Yantovskii et. at (1992, 1993) described two different concepts for power plants without emissions of CO, to air. These concepts are however nowhere near commercial realisation. Two concepts which require development of new technology were suggested at an early stage of this development project. Both of them will involve an air separation unit and due to near stochiometric combustion, they will in principle emit only CO, and water vapour. They will have an efficiency of 45-50% when utilized for power generation followed by CO, removal and injection. Two-shaft hieh mess= ratio reheat ass turbine in a combined steam process cycle Exhaust gas leaving the turbine is recycled back to the compressor inlet with a recycle ratio of approximately 90%. The turbine is divided into a high pressure and low pressure spool with a combustor in between (reheat). This is done to limit the recycle flow rate. Steam injected gas turbine with inteprated air separation unit The gas turbine compressor is used to compress the air for a cryogenic air separation unit. At the compressor discharge, air is taken out of the machine and oxygen is put back into the combustor. The volumetric loss of nitrogen is compensated by steam injection in front of the turbine. Presented at the International Gas Turbine and Aeroengine Congress and Exposition The Hague, Netherlands June 13-16, 1994 Downloaded From: on 11/26/2017 Terms of Use:

2 Clotsror VENT CAS TO ATMOSPHERE TO INJECTION WELL 40 RECFCLI U OF EE4ATZT C EXMAUST CA wea '.iftrum'aignit EA WATER ji FEEDWATER LP STEAM ICA --- >. keiveiginger STRIMER FEEOWATER P STE FUEL AIR 0 TO SOS 111 FEEDWATER SUPPLY Fig. I. Total CO, removal process - simplified flowsheet Due to the fact that the development of these power generation cycles requires redesign of standard gas turbine parts and/or development of completely new units, these concepts are not investigated in detail. Contacts have however been made with the gas turbine vendors General Electric (Spector, 1993) and Rolls Royce (Reynolds, 1993), and they cannot at the moment foresee the development ofthese kinds of gas turbines. Their development is mainly aimed at gas turbines for use in aeroengines. On a worldwide basis, offshore power production represent only a minor market for these vendors. As long as the CO, tax is only introduced in a few countries, there is a limited demand for turbines ' which are suited for CO, removal. The objective of this project as summarized in this paper, has therefore been to evaluate the suitability of existing power generation concepts for' offshore separation of CO, from exhaust gas. The basis for these calculations has been an LM2500 PE gas turbine due to the fact that this' is the most commonly used in the Norwegian sector of the North Sea.. The composition of the fuel gas is a typical North Sea natural gas with. a lower heating value of 47.6 KJ/kg. This fuel gas produces approximately 2.34 kg CO, per Sm 3 natural gas assuming complete combustion. RECOVERY OF CO2 FROM NATURAL GAS FIRED POWER PLANTS Gas turbine exhaust is not particularly suitable for recovery of CO, due to a typical excess air ratio in the range which results in a CO, concentration of only mol%. The major objective of this project has therefore been to find a process which will produce a lower exhaust gas volume and/or a higher CO, content than conventional aeroderivative gas turbines. in atmospheric pressure exhaust gases are possible, depending on the CO, content of the feed gas. The ECONAMINE Ft process has been proven for onshore applications but the components are too large to make them feasible to install offshore without major modifications. Through 1993 the major effort of this study has been to search for more compact technology. A study performed by The Netherlands Organization for Applied ScientificResearch, TNO (Feron et al.,1992) showed the potential of using gas absorption membranes for CO, removal from exhaust gas. This technology has already been proven for SO 2 removal. Gas absorption membranes are used as contacting devices between a gas and a liquid flow. The separation is caused by the presence of an absorption liquid (MEA) on one side of the membrane which selectively removes certain components from the gas stream on the other side of the membrane. The replacement of conventional absorption columns with membranes could lead to a significant reduction both with regard to cost, size and weight of the absorption unit. Testing of these membranes for CO, removal is at the moment initiated at NO. In the absorption unit, CO, isabsorbed by the MEA in the temperature range C, it then enters the strippercolumn in which the CO, is released from the MEA in the temperature range I C. The CO, is then compressed for injection, and the MEA flows back to the absorption unit. The possibility of replacing the conventional stripping column with a rotating gas/liquid contactor called HIGEE is at the moment being investigated. This could lead to savings both with regard to cost, weight and in particular reduction of space requirement. A simplified flowsheet of the total CO, removal process suggested in this project is shown in Fig. I. A method for removing CO, from exhaust gas based on amine absorption patented as the Flour Daniel ECONAMINE FG process (Sander and Martz, 1992) has been recommended for this project. The ECONAMINE FG process was developed to remove relatively low concentrations of CO2, typically 3 to 10 volume percent, from low pressure gases with high content of oxygen. The solvent chosen for absorption is based on monoethanolamine (MEA) due to its ability to absorb high CO, volumes per MEA volume. Recoveries between 85% and 95% of the CO, present, Downloaded From: on 11/26/2017 Terms of Use:

3 POWER GENERATION CONCEPTS The following power generation processes have been investigated: EXHAUST GAS -COOLER TO ABSORPTION UNIT - Combined cycle with recycling of exhaust gas - Supplementary fired combined cycle - Steam Injected Gas Turbine (STIG) with recycling of exhaust - Combined cycle with spiking of oxygen - Conventional steam cycle - Gas engines STEAM TURBINE The main condition that the power generation unit must fulfil, is that the net power output from an -LM 2500sirnple cycle gas turbine (approximately 21 MW) shall be available regardless of the power and heat requirements of the CO 2 removal process. This introduced the necessity of a waste heat recovery unit (WHRU) where the exhaust heat is cooled down and at the same time generates steam that can be utilized for producing power and supplying the stripper reboiler with saturated steam. The WI-IRU must supply enough superheated steam to generate at least 3 MW electricity which is the power requirement for the absorption and injection unit. Electricity generation exceeding this level is available for use on the platform. In addition, the WHRU must supply saturated steam at 4 barn for utilization in the stripper rebolier. The temperature of the exhaust gas is lowered to approximately 125 C when recovering heat for steam generation with the present steam cycle. In the case of CO 2 removal by amine absorption it is necessary to cool the exhaust gas further. An exhaust gas cooler using seawater is needed to reduce the temperature to 30 C. This temperature is chosen to obtain optimum performance for the absorption unit. The exhaust gas dew point is approximately 42 C. Consequently a fraction of the water vapour in the exhaust East condenses through the exhaust gas cooler. Several Norwegian oil companies have earlier performed feasibility studies of installing a combined cycle on offshore platforms. So far, this has not proved to be cost effective, partly due to the large and heavy WHRU unit. A traditional steam generator for an LM 2500gas turbine has a weight of approximately 120 tonnes. A study of the possibility of decreasing this large weight was therefore initiated. The current conventional WHRU design practice does not reflect the philosophy of space and weight requirements established in the offshore oil industry. Emphasis was therefore made to design a compact and light weight dual pressure WHRU. Short tubes with a rather small tube diameter were applied together with the smallest possible fin thickness and tube spacing. The rather heavy steam drums were avoided by using the once-through principle commonly found in coal fired boilers with supercritical steam conditions. ASSESSMENT OF THE CONCEPTS The main data for the different concepts are shown in Table I. Combined Cycle with Recsalina of Waist Gm A combined cycle with partial recycling of the exhaust gas was suggested in order to reduce the exhaust gas volume for treatment in the absorption process. The exhaust gas leaving the WHRU is cooled to 30 C and a portion of the total exhaust gas volume is recycled and mixed with fresh air between the air filter and the compressor inlet, A simplified process flowsheet is shown in Fig. 2. Fig. 2. Combined cycle with recycling of exhaust gas EXHAUST GAS, CA RECYCLING The recycle ratio is mainly limited by the oxygen content of the combustion air. Flammability calculations of hydrocarbon fuels shows that approximately 13 mol% 0, is sufficient to keep a flame burning (SFPE, 1990). In the present study, the limit was set to 16.5 mol% 0 2 in the combustion air. This implies a recycle ratio of 40% of the total exhaust gas volume. Both General Electric (Spector, 1993) and Rolls Royce (Reynolds, 1993) have in general agreed that this recycle ratio will not significantly influence gas turbine performance, though detailed testing is necessary in order to verify this. Exhaust gas recirculation is a major method employed in NO, control from stationary sources (Wart and Warner, 1981). The additional gas acts as a thermal sink and reduces the overall combustion temperature. In addition the oxygen concentration is lowered. This effect will also be present in gas turbine combustion. There are however certain issues that must be taken into account when recycling, among these are: Recycled exhaust gas must be carefully mixed with air to ensure homogenous properties. In cases of low NO lean bum systems, redesign may be necessary due to more vigorous mixing requirements. Supplementary firing of the WHRU in a combined cycle, i.e. using a duct burner between the turbine and the WHRU, increases the power output from the steam turbine, but the efficiency will be somewhat lower compared to an unfired combined cycle. The CO 2 concentration of the exhaust gas will increase. Them is however also an undesirable effect of supplementary firing; the exhaust gas volume for treatment will increase due to reduced recycle ratio. This, compared with the fact that no requirement for the additional power output from the steam turbine has been identified, lead to the conclusion that supplemental). firing of the WHRU is not feasible for the CO, removal project. lakitatdsmigliru i zaawigukosilmg_difotilya A SIIG cycle has no steam turbine, condenser and cooling water demand, and may therefore offer a higher power output/space ratio and power output/ weight requirements ratio than a combined cycle. This would be a benefit for offshore applications. Experience shows that for smaller systems than 50 MW where the steam turbine and the beat rejection system represent a significant portion of the total costs, STIG may be more attractive than a combined cycle (Bolland and Stadaas, 1993). AIR 3 Downloaded From: on 11/26/2017 Terms of Use:

4 STIG has so far never been accepted for use in the North Sea mainly due to the large consumption of treated water. However, the feedwater for steam generation in connection with ST1G can be supplied by condensate from the exhaust gas cooler. There is a surplus of water caused by the internal generation of water vapour in the combustion process that is condensed in the exhaust gas cooler. The water for injection into the turbine must be treated to follow the specifications stated by the gas' turbine vendors. While steam injection is proven technology, water recovery from gas turbine exhaust has not been demonstrated in field installations. This is however necessary for offshore applications due to the disadvantages associated with treannent of large water amounts. NOVA Corporation in Canada have performed a study on this topic! which concludes that operation with a "closed water system" should not be a problem (Nguyen et al.,1992). The closed water system is based on that all steam injected into the gas turbine is condensed and separated from the exhaust gas, treated and reused. A limitation op16.5 mol% 0 2 in the combustion air was the assumption for the calculations, this lead to a maximum recycle ratio of 15% for the ST1G cycle concept. Combined Cycle with Spikine of Oxygen The recycled amount of exhaust gas is limited by the 02 content in the combustion air. If oxygen enriched air is mixed with the fresh air and the recycled exhaust gas upstream of the gas turbine compressor, the recycle ratio could be increased thereby increasing the CO, concentration of the exhaust gas and reducing the exhaust volume. The effect of adding an air separation unit (ASU) which supplies enough oxygen to enable a recycle ' ratio of 50% is shown in Table I. The data for the AS1J was obtained from Air Products plc. in England (Boococic, 1993). An ASU based on cryogenic separation is the most compact and light weight of the options available. Conventional Steam Cycle Fired boilers operate near stoichiometric conditions. This will lead to - reduced exhaust gas volumes as well as increased CO, concentration compared to a conventional gas turbine. No steam turbines are today installed offshore. In land based industry, the situation is completely different. Gas turbines are of minor importance and steam systems are widely used. A brief study of this concept was performed. The assumptions made were that the power plant should produce 25 MW electricity and also supply the stripper reboiler with a sufficient amount of saturated steam. Gas Engines Gas engines are normally operated at excess air ratios (ear.) considerably lower than found in gas turbines. Conventional engines run at ear, of approximately 1.2 and low-no engines run at approximately 1.8. The exhaust gas volume leaving a gas engine is therefore far less than that of a gas turbine. Only low-no engines are evaluated in this project due to the fact that a regulation concerning NO.-emissions from offshore installations is expected in the near future. 1)Istein Bergen delivers low-n0. engines with maximum power output 3 MW and Wartsila Diesel can deliver low-no. engines with electric output 2.7 MW. These can be packed into a power generation unit which provides 25 MW. The data in Table I is for a skid of five low-no. gas engines from Ulstein Bergen. Table I. Comparision of the power generation concepts with CO 1 removal. Comb, cycle w/ recycling STIG w/ recycling Comb. cycle w/ 0 2 spiking Conventional steam cycle Gas engine Output (MW)' ' El. efficiency (%) Net efficiency (%) Recycling (%) Gas flow (Sm 3/sf CO, conc. (mol%) Fteboiler duty (MW)' Total weight (tonne Approx. cost(mill Si g ' Electnc power produced by the power generation unit. The number marked with renrecerli electric 1111WPT nmrfinvoi by the steam turbine. The efficiency of the production of electric power. The generation of low pressure steam is not included in this efficiency. For the combined cycle with 0 2 spiking, 2.5 MW needed for air separation is included in the efficiency. The electricity required for compressors and pumps is included in the net efficiency Percentage of total exhaust gas volume being recycled to the compressor inlet. Exhaust gas now entering the absorption unit. The CO, concentration of the exhaust gas flow entering the absorption unit. The energy requirement for stripping the CO, from the MBA. The total weight and cost includes the equipment needed for power generation and the gas absorption membrane. The stripping and compression unit is not included because these weights will be approximately the same for all concepts. 4 Downloaded From: on 11/26/2017 Terms of Use:

5 CONCLUSION The objective of this assessment was to investigate which power generation concept would lead to the smallest exhaust gas volumes and hence the smallest CO 2 absorption unit. This objective is contrary; to the conventional development in the gas turbine industry which is focused primarly on increasing efficiency and/or reducing NO, and CO emissions regardless of exhaust gas volume. It can be seen from Table 1 that the combined cycle with 0 2 spiking has the smallest exhaust gas volume for treatment, but this cycle is not suited for offshore implementation due to the large and expensive air separation unit. The efficiency of this concept is also rather low due to the air separation power demand. The conventional steam cycle has smaller exhaust gas flow per MW electricity generated than the combined cycle with recycling due to the near stoichiometric combustion that is possible in filed boilers. The conventional steam cycle costs less than the combined cycle, but is not suited due to the large weight. The total cost and weight of the STIG unit is smaller than the combined cycle, but since the efficiency is smaller for STIG, the fuel consumption and hence the CO, tax is larger for STIG than for a combined cycle. The cost for water treatment in order to fulfill the requirements from the vendors is uncertain and is not included in Table I. As can be seen from Table I, the cost and weight of gas engines can be compared with the combined cycle with 0 2 spiking. The exhaust gas volume of a gas engine is smaller than from an LM 2500 without recycling, but larger than the exhaust gas volume from an LM 2500 with recycling. As long as the largest power output of current low-no, gas engines is 3 MW this concept will be too expensive and heavy to be feasible. Gas engines are mostly used when the required power output is much smaller than in this projeo. The result of the assessment is that the combined cycle with 40% recycling is the best power generation system of the options studied in conjunction with removal of CO, on offshore installations. As can be seen from Table I, the combined cycle with recycling has the highest efficiency and the second lowest weight. Recycling of exhaust gas will in principle imply reduced NO* emissions. REFERENCES Bolland 0. and Stadaas LF, 1993: "Comparative Evaluation of Combined Cycles and Gas Turbine Systems with Water Injection, Steam Injection and Recuperation", ASME, 93-GT-57. Rolland, 0. and Srether, S., 1992: 'New Concepts for Natural Gas Fired Power Plants which Simplify the Recovery of Carbon Dioxide", Energy Conyers. Mgmt., Vol 33, No. 5-8, pp Boocock It, 1993: Personal communication with Richard Boocock, Air Products plc., Surrey, England. De Ruyck J., 1992: "Efficient CO : Capture Through a Combined Steam and CO 2 Gas Turbine Cycle", Energy Conyers. Mgmt, Vol 33, No. 5-8, pp Feron P.H.M, Jansen A.E and Klaasen It, 1992: "Membrane Technology in Carbon Dioxide Removal", Energy Conyers. Mgint, Vol 33, No. 5-8, pp Nguyen H.B and den Otter A., 1992: "Development of Gas Turbine Steam Injection Water Recovery (SIWR) System", ASME, 92- GT-87. Reynolds G., 1993: Personal communication with Graham Reynolds, Rolls Royce Industrial & Marine Gas Turbines Ltd., Coventry, England. Sander M.T. and Mariz C.L., 1992: "The Fluor Daniel ECONAMINE FG Process: Past Experience and Present Day Focus", Energy Convere. Mgmt., Vol 33, No. 5-8, pp Society of Fire Protection Engineers (SFPE), 1990: The SFPE Handbook of Fire Protection Engineering, National Fire Protection Association. Spector R.B., 1993: Personal communication with Richard B. Spector, GE Marine & Industrial Engines, Cincinnati, USA, Warn K. and Warner C., 1981: "AIR POLLUTION Its Origin and Control", Second Edition, Harper & Row Publishers, New York. Yantovskii, El., ZvagolskyK.N. and Gavrilenko V.A., 1992: "Computer Exergonomics of Power Plants without Exhaust Gases", Energy Conyers. Mgmt., Vol 33, No. 5-8, pp Yantovskii, El., Wall G.,Lindquist L., Tryggstad J. and Malcsutov WA., 1993: "Oil Enhancement Carbon Dioxide Oxygen Power Universal Supply (OCDOPIJS project)", Energy Comers. Mont., Vol 34, No. 9-11, pp The cost and weight results are based on the use of gas absorption membranes. The impact of decreased exhaust gas volumes will be larger if a conventional absorption column is used. It is however assumed that the development of gas absorption membranes currently ongoing at TNO will be successful. An alternative to installation of CO, removal processes offshore would be to install high-efficiency gas turbines. The efficiency of gas turbines operating in the North Sea today is seldom higher than %. Replacing these gas turbines with new turbines with efficiencies exceeding 40% will therefore reduce the CO 2 emissions considerably. ACKNOWLEDGEMENTS The authors would like to thank Mr. PA1 Kloster from Norsk Hydro for valuable comments during the work. We would also like to thank Mr. Styria Sxther, SINTEF Applied Thermodynamics for assisting in the design of the WHRU internals, and to Scandinavian Energy Project for assisting in the development of the WFIRU and the evaluation of the conventional steam cycle. We would also like to thank the State Pollution Control Authorities as well as the oil companies Statoil, Phillips Petroleum Company Norway, Norsk Hydro and Amoco Norway Oil Company for financing this study. 5 Downloaded From: on 11/26/2017 Terms of Use: