Bugok 3: Bringing the H Class Gas Turbine to Korea Reprint from: Modern Power Systems, September 2011 Authors: Alfred Kessler, Thomas Hagedorn Siemens AG, Erlangen, Germany Answers for energy.
The first deployment of Siemens new path-breaking H class gas turbine and combined cycle technology in Asia will be at the LNG-fuelled Bugok site of GS EPS (Electric Power and Services) Ltd., project director, Siemens, Erlangen, Germany, and, VP, sales management Asia Pacific, Siemens, Offenbach, Germany S EPS, Korea s first independent power producer, founded in 1996 as an offshoot of LG, and now owned 70% by GS Holdings and 30% by Oman Oil, is continuing its track record of innovation. Unit 3 at the company s Bugok site will be one of the first power plants in the world to employ the new Siemens H class gas turbine, which makes possible a combined cycle efficiency of over 60% (LHV basis) but also provides considerable operational flexibility, enabling cycling and frequent and rapid starts/stops. Siemens, in consortium with GS E&C, is supplying the complete H class single-shaft combined cycle plant for unit 3, rated at >415 MWe gross, to GS EPS on a turnkey basis, with a scheduled commercial operation date of 31 August 2013. The turnkey contract was signed on 11 January 2011 and the groundbreaking ceremony for the new project, which represents an investment of about 460 billion won ($420 million), was held on 19 April 2011. Units 1 and 2 at the site (both 550 MWe multi-shaft (2-on-1) combined cycle plants, which entered commercial operation in July 2001 and March 2008, respectively) also employ Siemens gas turbines, of the earlier F class type.
alignment of disks and hollow shaft sections to allow free radial expansion and contraction, and transmit the generated torque. The turbine rotor is internally air-cooled. The platform combustion system (PCS) consists of 12 baskets with air cooled transitions. The annular arrangement provides excellent uniformity of exhaust-gas temperature field over the full cross-sectional area of the turbine inlet. This is attributable to the fact that the 12 burners in the PCS form a continuous ring, thus eliminating hot and cold spots. The ultra low NO x technology suppresses thermal NO x formation without the need for injection of steam or water. The fuel for all three units at Bugok is LNG, and they all employ seawater cooling. Unit 3 will have an efficiency of >55% HHV basis, equal to >60% LHV basis. The scope of the unit 3 project, which employs a single shaft combined cycle configuration, includes the following: 60 Hz version of the Siemens H class gas turbine, SGT6-8000H (a direct aerodynamic scaling from the 50 Hz version, the SGT5-8000H, now in commercial operation at Irsching 4 in Germany, but with 12 can-combustors rather than 16). Irsching 4 has recently set a new world record for combined cycle efficiency, for the first time breaking the 60% efficiency barrier, see pp 00-00. Hot commissioning of the lead SGT6-8000H machine, installed on the Siemens test bed in Berlin, started on 21 July 2011. As well as the Bugok 3 order, a further six SGT6-8000H machines have been ordered by US utility FPL. SST6-5000 steam turbine with laterally installed condenser, coupled to the generator by SSS clutch. Common hydrogen cooled generator, SGen6-2000H type, for the steam and gas turbines. Triple pressure reheat heat recovery steam generator with HP once through (Benson type) boiler and natural circulation LP/IP boiler design, supplied as an indoor design within a boiler house. SPPA-T3000 plant control system with operator station integrated in the existing control room. Power control centres and electrical equipment such as isolated phase bus duct, generator circuit breaker, DC components and LV switchgear. Main and auxiliary transformer. New 345 kv grid connection employing GIS. New LNG connection including new gas pressure governor station. The fuel gas is delivered from the KOGAS terminal point via LNG piping, gas filtering, metering and preheating equipment, to the gas turbine fuel gas skid. The gas pressure at the terminal point to the power plant is >40 bar(g). New cooling water structures. New lifting and circulating water pumps. Extension of ancillary systems such as demineralised water and chlorination plant. The gas turbine (see also pp 23-27) The fully air-cooled model SGT6-8000H gas turbine, like the 50 Hz version, the SGT5-8000H, is a single-shaft machine of singlecasing design. The basic design, adopted from previous gas turbine models, includes the following features: disc-type rotor with central tie bolt and radial serrations; two journal bearings and one thrust bearing; generator drive at compressor intake end; and axial exhaust diffuser The rotor is supported by two journal bearings and one thrust bearing. The journal and thrust bearing are located at the compressor side, and the second journal bearing at the exhaust side of the turbine. The rotor is an assembly of disks, each carrying one row of blades, and hollow shaft sections, all held together by a pre-stressed central-tie bolt. Hirth serration provides the The generator The two-pole SGen6-2000H generator has direct radial hydrogen cooling for the rotor winding and indirect hydrogen cooling for the stator winding. The hydrogen filled generator casing is of pressure-resistant and gas-tight construction and is equipped with two end shields. The hydrogen cooler is divided into four sections, two arranged at each generator end. The three-phase winding inserted in the stator core slots is a two-layer transposed-bar design. The winding is vacuum pressure impregnated together with the stator core. The high-voltage insulation employs a proven proprietary epoxy-mica system. The generator rotor shaft is a vacuum-cast forging and has two end-shield sleeve bearings. The hydrogen is circulated in the generator interior in a closed circuit by axial flow fans arranged on the rotor shaft journals. A gas system contains all necessary equipment for filling, removal and operation of the generator with purging gas, hydrogen or air. A static (thyristor based) excitation system, including transformer, is used to take the excitation current from the auxiliary power system. A start-up frequency converter is provided for start-up of the turbine generator unit. The generator acts as a motor in the converter mode to start the gas turbine set without an additional rotating prime mover. Features of the generator include high efficiency and low maintenance costs. Steam turbine The tandem-compound steam turbine comprises one combined HP/IP casing and one double-flow low-pressure casing, with all components being standardised modules. With the compact design of the HP/IP turbine, hot steam conditions are confined to
the middle of the casing. On the other hand the glands at the casing ends are in regions of relatively cool steam conditions. Temperature decay is much slower when compared to a design with individual turbine casings. Consequently, the start-up times of such a compact turbine are significantly shorter, saving precious fuel. The design also requires less space, leading to savings with respect to the civil structures. The main feature of the LP turbine is the double shell inner casing, which can be displaced axially by means of pushrods. The differential expansion between rotor and casings is thus minimised under all operating conditions. Clutch To support flexible operation as well as the start-up procedure for the single-shaft combined cycle plant a self-synchronous clutch (SSS) is installed between the generator and steam turbine. With the gas turbine only driving the generator (during start-up) and the steam turbine at rest, the clutch is disengaged. Then, the steam turbine is accelerated and at the instant the steam turbine speed overtakes the generator, the relay clutch is engaged and transfers the steam turbine torque. Condensing plant The condenser is a box type surface condenser. The steam space is of a rectangular cross section in order to achieve optimum utilisation of the enclosed volume for the necessary condensing surface, formed of titanium tubing. The condenser is installed laterally at the LP turbine and forms an integral part of it. The steam dome, shell, hotwell, and the water boxes are steel fabrications. The condenser is fixed to the foundation beneath, with thermal expansion accommodated by means of Teflon pads. The double flow LP turbine outer casing is connected to the condenser via the steam dome. The steam dome is welded to the exhaust casing of the turbine with the result that the LP turbine cylinder and the condenser form one unit. Two water ring pumps with air jets (ELMO units) are installed for evacuation. During normal operation, only one pump is in operation. To shorten the evacuation time during start up both pumps can be put into operation. The heat recovery steam generator (HRSG) is located downstream of the gas turbine diffuser and as already mentioned produces steam in three pressure stages: high pressure; intermediate pressure; and low pressure. The exhaust gas flows horizontally through the HRSG. The plant features advanced steam conditions, with 150 bar and 585 C in the HP stage at the steam turbine nozzle. The HP steam generator is of the Benson type, with a once-through evaporator in the HP section, and natural circulation, drumtype evaporators in the IP and LP sections. A condensate preheater is integrated into the HRSG. This arrangement contributes to increasing the efficiency of the combined cycle plant by using exhaust gas energy to preheat the condensate before it passes towards the feed water pump and into the LP system. The boiler casing is made of steel plate as dictated by the prevailing exhaust gas temperatures. The HRSG is of the cold casing design with inside insulation. The HRSG is equipped with an outlet duct and steel stack at the end. The stack is fitted with a damper and a silencer. The top-supported heating surfaces consist mainly of finned tubes, which are suspended from a support structure. The heat recovery steam generator is designed to be located indoors and is contained in a boiler house, which also encloses the main working platforms. Each steam stage consists of an economiser (HP and IP), evaporator and superheater. The feedwater is heated in the economiser almost up to boiling temperature and fed into the superheater (HP section) or in the drum (IP section). From the IP drum, water is fed into the evaporator, where a portion is evaporated. The resulting water-steam mixture flows back to the drum where it is separated. The saturated steam is fed to the IP superheater where it is superheated up to main steam outlet temperature. The HP evaporator system is of the Benson forced flow design, so an HP drum is not needed. Instead a combined separator/water vessel is employed. During start-up and low load, a mixture of water and steam from the evaporator is introduced to the separator. Within the separator, the two phase flow is separated into water (fed to the water vessel) and steam (routed to the super-heaters). In the LP system, the condensate preheater heats the condensate to approximately the boiling temperature of the LP system. The LP feed water therefore goes directly from the condensate preheater to the LP drum. The HP steam is fed to the HP section of the steam turbine. The steam expands in the HP turbine and is fed back as cold reheat steam to the HRSG. There it is mixed with the superheated IP steam, superheated further in the reheater and then fed to the intermediate pressure section of the steam turbine. The HP and IP steam temperature is controlled by attemperation control. The generated LP steam is fed to the connection line from the outlet of the intermediate to the LP section of the steam turbine and the entire steam flow is completely expanded to vacuum in the LP steam turbine. For redundancy reasons the water steam cycle is furnished with 2 x 100% main condensate pumps and 2 x 100% feedwater pumps. The feedwater pumps are equipped with Voith variable speed couplings. A 2 x 50% condensate polishing plant is included. This is to prevent potential pollutant concentration, thus reducing corrosion and scaling/fouling in the turbine and superheater areas. The turbine exhaust steam is condensed by a seawater cooled condenser. The condensate and demineralised water accumulated in the condenser hotwell is discharged by one of the 2 x 100% condensate extraction pumps to the condensate preheating system. One condensate extraction pump operates during full load operation and a stand-by pump is ready to cut in automatically in case of failure of the operating pump. Deaeration of the condensate is mainly performed in the condenser under vacuum. The condensate extraction pump delivers the condensate from the condenser hotwell to the LP drum and to the suction side of the feedwater pumps via the condensate preheater of the HRSG. The condensate quality required for proper operation of the once through type heat recovery steam generator is ensured by the condensate polishing plant. Depending on the condensate quality the entire or only a part of the condensate mass flow can be supplied by the 2 x 50% condensate polishing pumps to the condensate polishing plant. The treated condensate is directly discharged to the suction side of the condensate extraction pumps.
COMBINED CYCLE Schematic process diagram A connection from the demineralised water distribution system is installed for filling of the pump discharge side and pressurising the condensate system during standstill. Downstream a line for the injection cooling of the intermediate pressure and low pressure bypass stations branches off. The feedwater is routed downstream of the HRSG condensate preheater in separate suction lines to the feedwater pumps via a strainer located upstream of each pump. An automatic recirculation check valve for the pump minimum flow requirement is located downstream of each feedwater pump. The minimum flow is returned to the condensate preheating system upstream of the condensate preheater. The HP pump discharge lines are connected to a common header, which delivers feedwater to the HP part of the HRSG. IP feedwater is tapped from a specific pump stage. The tapping lines are connected to a common header, which delivers the feedwater to the IP part of the HRSG. Another tapping point of the feedwater pump is used to recirculate feedwater via a common header to the condensate preheating system. Under normal operating conditions, feedwater is discharged by one of the two feedwater pumps via the HP/IP economisers of the HRSG into the HP evaporator and into the IP drum. The other pump is in stand-by. In case of failure of the operating feedwater pump, the standby pump cuts in automatically. The HP, IP and LP steam generated in the HRSG is fed to the steam turbine via the related steam piping system. The expanded HP steam is fed back to the boiler via the cold reheat line and is mixed with the superheated IP steam. All of the IP steam is superheated further in the reheater and fed to the IP section of the steam turbine. In order to achieve short start-up times and to control turbine trips a turbine bypass system is provided. The bypass system consists of the HP bypass connected to the cold reheat as well as the IP and LP bypass, both dumped to the condenser, and with related attemperation systems. The bypass control valves are equipped with hydraulic drives. A fuel gas preheating system preheats the fuel gas to approximately 215 C in order to increase the efficiency of the power plant. Accordingly, IP feedwater is extracted from the IP economiser and routed via the fuel gas preheater to the condensate preheating system upstream of the HRSG condensate preheater. Downstream of the fuel gas preheater a mass flow control valve is provided to control the fuel gas temperature at the outlet of the fuel gas preheater. To guarantee a sufficient mass flow through the preheater at part load and during preheater start-up conditions and to limit the temperature gradient at the preheater a recirculation pump is installed. This pump returns cold condensate from the outlet of the preheater to the inlet via a recirculation control valve. Auxiliary steam is supplied to the seal steam system of the steam turbine and to the evaporators of the HRSG for warming during plant standstill. The auxiliary steam piping system receives saturated steam either from the LP drum steam header or from the auxiliary boiler of the existing units depending on the operation mode of the plant. During normal combined cycle operation the auxiliary steam is delivered from the LP steam generating system. The cooling water system consists of 2 x 50% seawater lift pumps, 2 x 50% circulating water pumps as well as a 1 x 100 % seawater cooling pump. The circulating water system absorbs the heat from the steam surface condenser of the steam turbine, and transfers this heat to the seawater. Also, there is an additional seawater cooling pump which enables holding of vacuum and remaining cooling of the closed cooling water coolers during short downtimes of the power plant without the main cooling water pumps running. The service cooling water system Cutaway of Bugok 3
COMBINED CYCLE absorbs the heat from the closed cooling water system. The closed cooling water system, equipped with plate type heat exchangers, cools the equipment and components of the gas turbine, the steam turbine and the water/steam cycle. Electrical system The generator is connected to the generator transformer via an isolated phase busduct. A generator circuit breaker is installed between the generator and the tee-off connections to the unit auxiliary transformer, excitation transformer and static frequency converter transformer. The low voltage transformers and large motors are supplied from the medium voltage switchgear. An emergency AC supply system is provided ensuring the supply of AC power to essential loads in case of complete loss of the main AC power system. The uninterruptible power supply consists of 220 V DC battery and chargers, 125 V DC battery and chargers, 24 V DC (220/24 V DC/DC converters) and 460 V AC (inverter), 208/120 V AC (inverter) systems. The 220 V DC and 125V DC system provides power for designated consumers (eg, emergency oil pumps, protection, control voltage, inverter infeed). The 220V DC and 125V DC system consists of 2 x 100% battery chargers connected via individual fuses to one 100% battery. One battery charger is supplied from the normal AC system, the other one is supplied from the emergency diesel AC bus. The battery has an adequate capacity to supply the emergency loads for 1 hour. The 24 V DC system is powered via 2 x 100% redundant DC/DC converters. Their in-feed is taken from the 220 V DC battery system. Main consumers of 24 V DC are the DCS cabinets. The main control and monitoring functions of the electrical equipment are integrated into the DCS in order to minimise the required local control and monitoring activities. Also the main automatics and interlocks are realised in the DCS. Safety relevant interlocks, eg, grounding switches and protection, are hardwired. The DCS system automatic control program ensures that there is minimal need for manual intervention in the control of the electrical system. During start-up, the unit auxiliaries and the relevant station service loads are fed by the HV grid via the generator transformer and unit auxiliary transformer. The generator circuit breaker is open. The start-up sequence is automated by the main DCS. The gas turbine is accelerated by the start-up frequency converter with the generator in motor operation and minimum required excitation. After reaching synchronisation conditions and closing the generator breaker, the generator takes over the auxiliary power supply of the unit and provides power to the network. If the unit is in island operation (with the HV breaker open), it can be reconnected to the grid by closing the HV breaker under the supervision of the synchronisation equipment. During normal operation of the power plant, the auxiliary power will be provided by the generator via the unit auxiliary transformer. 3-tier architecture of the SPPA-T3000 During a normal shutdown, the generated power is reduced steadily until the generator circuit breaker or the HV circuit breaker can be opened. The auxiliary power is provided via the respective unit auxiliary transformer from the HV grid without interruption. In the case of an emergency shutdown caused by a main failure in the auxiliary power supply, the required power for a safe shut down is provided by the battery and the emergency AC supply system. Instrumentation and control The Bugok 3 combined cycle plant will be equipped with an SPPA-T3000 (Siemens Power Plant Automation Teleperm 3000) distributed control system. The system uses continuous information flow, consistent data management and storage, flexible instrumentation and control concepts, and uniform human machine interface (HMI) platforms to perform necessary automation, operational control, and data monitoring for the plant. The SPPA-T3000 DCS has a hierarchical structure. Design features include: a plantoriented process control structure that provides operational functions, combined with monitoring and diagnostic capability; a redundant, modular structure capable of future expansion by adding equipment as required; and an open local area network (LAN) structure for interfacing to other automation systems and external computer networks. The SPPA-T3000 DCS consists of a threetier architecture based on a server/client networking structure. The 100 Mbit Ethernet bus system provides the communication between the human machine interface, the automation servers and the application server that provides all necessary functions for plant engineering, operation monitoring, diagnostics and storing of process data. A basic concept of the system is the use of what are called embedded component services, which means that all processrelevant data is embedded into every single component. This component-embedded approach allows all data to be intrinsically available for operation, engineering or diagnostics. An important advantage of this structure is keeping the user interfaces ( thin clients ) independent of other applications. The thin clients present information regarding engineering, operation, and diagnostics and standard industrial PCs running just a web browser perform this task. The web-based system structure allows the use of a wide range of hardware such as standard PCs or notebooks that can run a web browser. The server/client structure means that HMI applications are available at multiple locations. There is no need for special hardware or software for engineering and operation functions. Terminals are identical in access capability. Limitations need be defined only by the authorisation system where the access rights are configured. This approach allows for highly flexible configurations for a wide range of power plant process control applications. The main benefits of the SPPA-T3000 software architecture are: consistent views at any time; only one data management location; integrated I&C, plant display, alarm, diagnostics and engineering; no code generation and separate down-loading activities; no subsystems such as engineering stations, operating stations and diagnostics computers. The SPPA-T3000 control system is functionally and physically distributed and is subdivided into functional areas to create a modular configuration. The functional separation is by major systems: gas turbine; steam turbine; heat recovery steam generator; water/steam cycle; and ancillary and auxiliary systems. Technology showcase The 60 Hz Bugok 3 plant, now under construction, will embody some of the most advanced features available today in combined cycle technology, producing over 415 MW on one shaft. The plant is capable of an efficiency of over 60% (LHV basis), with very advanced steam conditions. But at the same time it has immense operational flexibility, able to hot start in less than 30 minutes (hot start on the fly conditions), to deload very quickly and also to provide excellent frequency response capabilities. The HRSG with Benson type HP stage contributes to the fast cycling performance characteristics. Overall, Bugok 3 represents an optimal balance between capital costs, plant performance and operation & maintenance factors. MPS
This article appeared in: Modern Power Systems September 2011, Page 14 20 Copyright 2011 by Modern Power Systems This reprint is published by: Siemens AG Energy Sector Freyeslebenstrasse 1 91058 Erlangen, Germany Siemens Energy, Inc. 4400 Alafaya Trail Orlando, FL 32826-2399, USA For more information, please contact our Customer Support Center. Phone: +49 180/524 70 00 Fax: +49 180/524 24 71 (Charges depending on provider) E-mail: support.energy@siemens.com Fossil Power Generation Division Order No. E50001-W220-A139-X-4A00 Printed in UK Dispo 05400, c4bs No. 7813 TH 224-110891 MPS 432045 SD 09112.0 Printed on elementary chlorine-free bleached paper. All rights reserved. Trademarks mentioned in this document are the property of Siemens AG, its affiliates, or their respective owners. Subject to change without prior notice. The information in this document contains general descriptions of the technical options available, which may not apply in all cases. The required technical options should therefore be specified in the contract. www.siemens.com/energy