Low NOx platform for small GT series 175MW China 6F ...gasturbineworld.com/assets/july_august_2013_issue.pdf · 175MW China 6F cogeneration plant page 22 Repowering coal site with

July – August 2013 www.gasturbineworld.com

Low NOx platform for small GT series page 14

175MW China 6F cogeneration plant page 22

Repowering coal site with SGT-800 plant page 26

Through a continued focus on combustion R&D, Siemens has achieved best-in-class levels of NOx emissions. In addition to achieving 9 ppm on natural gas, our F-class gas turbines can now meet 25 ppm NOx on fuel oil when gas isn’t available. What’s more...this achievement has been proven in operating plants, not just in the lab or on the test bed.

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July – August 2013

Gas Turbine World (USPS 9447600, ISSN 0746-4134) is published bimonthly in addition to the GTW Handbook annual by Pequot Publishing Inc. 654 Hillside Rd., Fairfield, CT 06824. Periodicals postage paid at Fairfield, CT 06824 and at additional mailing offices. Canada Post International Mail Product (Canadian Distribution) Sales Agreement No. 0747165. Printed in U.S.A.

Gas Turbine World • Vol. 43 No. 4

On the Cover. 2x1 Fr 6F combined cycle-power block with optional bypass stacks

2 Project engineering and industry news M501J turnkey 2,600MW Taiwan project, $2.7 billion for 9GW Algerian program, Malaysia 1GW H-8000 combined cycle

10 Estimating combined cycle plant cost Cost estimates for the same size plant can vary by as much as 30 percent depending on choice of design parameters and tradeoffs

14 GT6 design series NOx cut 60% to 10 ppm New premix combustor technology is capa-ble of limiting NOx to less than 10 ppm over a range of 100% to 50% part-load operation

22 Nanxun 175MW industrial cogen plant Cogen plant built around two 6F gas tur-bines to supply electricity and process steam for Nanxun economic development zone

26 67MW cogen replacement for coal plant SGT-800 combined cycle cogeneration unit is replacing old coal-fired steam plant near retirement at Marl chemical complex

32 IGCC power and gasification technology Kemper on track for 2014 startup, 416MW Hydrogen Energy project status, database for assessing low value coals

Single-digit NOx Premix combustion technology upgrade for 6MW-class gas turbine is capable of less than 10 ppm NOx down to 50% part-load, page 14

Cogen in China Bare bones plant will supply indus-trial steam and power to economic development zone in China at 70% cogeneration efficiency, page 22

Pre-packaged powerCombined cycle power plant has lots more flexibility, lower $/kW cost, much higher efficiency than old coal plant it will replace, page 26

Editor-in-Chief Robert Farmer

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2 GAS TURBINE WORLD July – August 2013

INDUSTRY NEWS

approximately 14 percent, rising from about 12GW to 20GW by 2017. The government is committed to boosting energy capacity through its investments in the power sector.

MalaysiaH-class gas turbines to power 1GW combined cycle stationSamsung has awarded Siemens a contract to supply two single-shaft power trains, each consisting of an SGT5-8000H gas turbine, 3000W SGen- water-cooled generator and an SST-5000 triple-pressure steam turbine plus auxiliary systems. Destined for a TNB Prai power station being built at Seberang Perai in the Malay-sian state of Penang. Siemens has also en-tered into a long-term maintenance contract for technical support and replacement com-ponents. In a 1x1 configuration, each 8000H com-bined cycle plant is ISO rated at 570MW net plant output and 6001 kJ/kWh heat rate (60.0% efficiency) on natural gas fuel and 15°C sea level site conditions. With a site-rated generating capacity of about 1GW, TNB Prai’s new station report-edly will be the most powerful and efficient gas-fired generating plant in the Southeast Asian region. Samsung is constructing the combined cycle station under a lump sum turnkey con-tract. It is expected to begin commercial operation in early 2016.

Saudi Arabia900MW CHP projectvalued at $650 millionSaudi Aramco has announced plans to build three combined heat and power (CHP) facili-ties, with a combined value of $650 million at different oil processing and refinery fa-cilities located in Abqaiq, Hawiyah, and Ras Tanura. The project is being developed as a joint venture that is 50 percent owned by Saudi Aramaco with the balance funded by outside investors. Project partners include Japanese engi-neering company JGC Corporation with 15 percent, Aljomaiah Holding with 10 percent and Japanese conglomerate Marubeni Corpo-ration with 25 percent. The new CHP plants will make Saudi Ar-amco’s facilities more independent by allow-ing them to generate their own steam while purchasing electric power from the Saudi Electric Company. The more efficient cogeneration facilities are part of a Saudi Aramco drive to enhance energy efficiency. Saudi company Aljomaih Holding Co has

AlgeriaJoint venture to add 9GW to power gridGE announced three contracts totaling ap-proximately $2.7 billion with SPE, Algeria’s national electricity and gas company, to sup-ply heavy frame combined cycle and aero derivative gas turbine technology for nine power plants. Will add nearly 9GWs of generating ca-pacity to help strengthen Algeria’s power sector and meet the growing requirements of the country. The three agreements include six new combined cycle power plants that will ulti-mately increase Algeria’s generating capacity by 70%, adding more than 8GW of electric-ity. In addition, two fast-track projects will add 528MW of capacity for summer peak demand and a new simple cycle plant will add 370MW to the grid. Under the first agreement for the six com-bined cycle power plants, GE will provide 26 x 9F 3 series heavy frame gas turbines, 12 x steam turbines and 38 x generators. Using natural gas from local Algerian gas fields, the turbines will be equipped with GE’s latest Dry Low NOx dual-fuel combus-tion technology to reduce emissions. GE’s 2x1 9F 3-series combined cycle plant is ISO rated at 798.7MW net plant output and 6260 kJ/kWh heat rate (57.5% combined cycle efficiency) on natural gas fuel and 15°C sea level site conditions.

For the second agreement, GE deliv-ered 24 trailer-mounted TM2500+ aero gas turbines and services for two “fast-track” projects in northern Algeria to produce more than 528MW of site-rated power to support Algeria in meeting its summer peak electric-ity demand. The mobile TM2500+ genset is ISO rated at 27.6MW for 50Hz power genera-tion (29.5MW for 60Hz) and at 37% simple cycle efficiency. To date, 16 units are available to gener-ate 352MW of site-rated power (22MW each) for the provinces of Oum el Bouaghi (F’Krina) and M’Sila, with an additional eight units and 176MW of power generation scheduled to join the grid this year. Under the third agreement, GE’s order is valued at over $150 million to supply power generation equipment to Société Algérienne de Production de l’Electricité (SPE Spa) for the Hassi R’mel simple cycle gas turbine plant. The new plant will add approximately 370MW of power for Algeria’s electricity grid. In addition to supplying equipment for the new Sonelgaz affiliates plants, GE power generation services include new unit spares, technical direction and installation services and training to help increase the performance, flexibility and reliability of operations at the power plants. Energy demand in Algeria is estimated to be growing at an average annual rate of

TaiwanM501J gas turbines to power 2,600MW combined cycle plantMitsubishi Heavy Industries (MHI), jointly with EPC contractor CTCI Corporation, has received a full-turn-key order from Taipower to construct a natural gas-fired combined cycle power station site rated at around 2,600MW. To be powered by three 2x1 M501J combined cycle power islands ISO rated at 942.9MW net plant output each and 61.7% combined cycle ef-ficiency. The plants are slated to go onstream sequentially between Sep-tember 2016 and June 2017. Each power island will consist of two 322MW M501J gas turbines, one 298.9MWsteam turbine, two HRSGs and three generators. MHI will be responsible for manufacture and supply of the gas and steam turbines. CTCI will handle construction and installation at the plant site and also EPC work for balance of plant. The station is being built in Miaoli County, approximately 150 km southwest from central Taipei. Power produced by the plant will meet the country’s increasing demand for electricity, which is expected to soar along with economic growth.


Industry News

signed an Energy Conversion Agreement for the plants under which Marubeni and part-ners will operate the CHP plants to provide 900MW of power and around 1,500 tons of steam per day to the three complexes for 20 years. JGC Corporation and its partners expect the plants to be completed in 2016.

New Jersey700MW Flex 60 project valued at $842 millionProject developers have announced financial closing for the 700MW $842 million CPV Woodbridge Energy Center in New Jersey. Under a $260 million equipment and services contract, GE Energy will supply a 2x1 FlexEfficiency 60 combined cycle and balance-of-plant equipment package. GE also will support the plant’s long-term availability through a 16-year contrac-tual services agreement. Plant is designed around two fast-start 216.1MW 7F 5-series gas turbine genera-tors, two duct-fired, triple-pressure, reheat HRSGs and one D-11A steam turbine gen-erator. Without supplementary duct firing, GE’s 2x1 7F 5-series combined cycle is ISO rated at 656.4MW gross plant output and 5783 Btu/kWh heat rate (59.0% efficiency) on natural gas fuel. With duct firing, the plant is nominally rated at 700MW output. Assuming start of construction this year, the completed combined cycle plant could enter commercial operation as early as the first quarter of 2016. The project is owned by Competitive Power Ventures, ArcLight Capital Partners and Toyota Tsusho, and will be operated by an affiliate of co-owner ArcLight. It is expected to sell its capacity through 15-year Standard Offer Capacity Agreements with New Jersey utilities. GE’s two fast-start 7F-5 series gas tur-bines will be manufactured in Greenville, SC, while the D-11A steam turbine and three electric generators will be produced in Sche-nectady, NY.

Maryland Co-op to build M501GAC combined cycle power plantMitsubishi Heavy Industries reports that it has been selected by Old Dominion Electric to supply two M501GAC gas turbines for the Co-op’s nominally rated 1,000MW Wild-cat Point combined cycle project. Proposed GTCC plant, to be built five miles west of the Town of Rising Sun, Mary-land on a site adjacent to two simple-cycle peaking units, is scheduled to go online in

2017. Old Dominion is expected to sign a con-tract with Mitsubishi Power Systems Ameri-cas in the near future for the two gas turbines along with a separate long-term gas turbine service agreement once the plant is opera-tional. The combined cycle power genera-tion system for ODEC will consist of two 273.6MW M501GAC gas turbines, an un-fired HRSG and a 278.9MW steam turbine and generator. In a 2x1 configuration, the M501GAC combined cycle is ISO rated at 826.1MW net plant output and 5726 Btu/kWh heat rate (59.6% efficiency) on natural gas fuel. The gas turbines will be manufactured at MPSA’s Savannah Machinery Works in Savannah, Georgia. The generators will be supplied by Mitsubishi Electric Corporation. LTSA scope of supply includes compre-hensive turbine maintenance and manage-ment services, replacement parts supply, and dedicated remote turbine monitoring. To date, says MHI, it has received or-ders for more than 80 G-series gas turbines worldwide, including more than 40 in North America, and 13 of those units are the M501GAC. ODEC is a mem-ber-owned power gen-eration and transmis-sion cooperative feder-ation headquartered in Glen Allen, Virginia. It supplies electricity to 11 member electric distribution coopera-tives in Maryland, Vir-ginia and Delaware.

Saudi ArabiaNominal 4,000MW syngas fired 5000F power stationSiemens recently an-nounced a $966.8 mil-lion contract from Sau-di Aramco to supply key components for a nominal 4,000MW combined cycle power station. The power station is designed to deliver electricity to the Jazan Industrial city area in the southwest of Saudi Arabia and to the re-finery of Jazan, which will additionally be supplied with process

steam. The combined cycle power blocks will be fueled with gasified refinery residues. Siemens scope of supply includes ten 232MW SGT6-5000F gas turbines (specially designed for synthesis gas and diesel fuel), six of which will be manufactured in the Kingdom of Saudi Arabia, ten HRSGs, five steam turbines and fifteen generators. Presumably, the station is designed around five combined cycle blocks each powered by two uprated 232MW syngas-fired gas turbines, two HRSGs and one steam turbine generator. On natural gas fuel, each block (powered by two 206MW gas turbines) would be ISO rated at 620MW and 57.2% combined cycle efficiency. On syngas fuel, however, the higher 232MW power rating of the gas turbines and increased mass flow into the HRSGs should increase combined cycle output to over 700MW. Specific syngas performance is not available. Commissioning of the first two blocks is scheduled for spring of 2016. The next block will follow in spring 2017. The other units will go online successively at intervals of a few months each. It is anticipated that Saudi Arabia´s

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November 2013 Update

n Validated record breaking turbine inlet temperature of 1,600°C (2,912°F)

n First commercial J-Series unit, in operation since 2011, with more than 12,400 AOH and 136 starts to date

n Eight M501J units now in commercial operation

n First unit of the 2,919 MW Himeji No. 2 C/C Plant went commercial early, and the second unit is in advanced stage of commissioning.

n New turnkey order (6x501J) – Taiwan Power Company C/C power islands totaling 2,600 MW

n Global 60 Hz fleet, now 24 units

J-Series Gas Turbines

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Successful implementation of the M501J continues around the world...


Industry News

population will increase from its current 26 million to about 28 to 34 million by 2020. To meet the predicted annual rise in pow-er demand of about six percent per year, the installed power generation capacity will have to at least double within 10 years from 67GW in 2012 to an estimated 140GW in 2020.

MississippiTVA closes deal to buy 774MW Southaven plantThe Tennessee Valley Authority recently completed a lease-purchase transaction that provides $400 million in financing to acquire the 774MW Southaven combined cycle plant in Desoto County, Mississippi. This deal will give TVA sole ownership of the natural gas-fired facility near Mem-phis that is has been operating under joint ownership with Seven States Power Corp. since 2008. In return for the $400 million, TVA will grant Southaven Combined Cycle Genera-tion LLC a 90% ownership interest in the plant. TVA will operate the plant under lease for 20 years and continue to pay for its main-tenance and fuel. Seven States will use proceeds from TVA’s acquisition of Southaven to develop load management programs benefiting local power companies and TVA. Southaven is powered by three GE 7FA duct-fired combined cycle plants nominally rated 260MW each. The plant has been in service since 2003, is capable of cycling on and off daily for mid-range power generation 12 to 16 hours a day.

ArgentinaTurnkey project for 4000F580MW simple cycle plantSiemens has been awarded a turnkey con-tract to supply and build a nominally rat-ed 580MW Guillermo Brown simple cycle power plant. New plant will be powered by two SGT5-4000F gas turbines ISO rated at 292MW base load each and 8567 Btu/kWh heat rate (39.8% efficiency) on natural gas fuel. Contract scope includes power transmis-sion, fuel supply solutions and a “full service maintenance” contract for 10 years. In addition, Siemens is also delivering the infrastructure works at the port to offload fuel, high-voltage transmission lines, switch-yard, and fuel pipelines for the power plant. Plant is to be built near the city of Ba-hia Blanca in the province of Buenos Aires, about 650 km southwest of Argentina’s capi-tal. Commissioning is scheduled for 2015.

MichiganAir permit approved for 700MW combined cycleConsumers Energy has received an air per-mit for its proposed 700MW gas-fired com-bined cycle project in Thetford Township, Michigan that will replace seven old coal plants. This marks the first major step before Consumers Energy proceeds with the $750 million project. Additional steps include ap-proval of a certificate of necessity filed July 12 with the Michigan Public Service Com-mission and suitable financing. Planned Thetford plant would reduce site carbon emissions about 50 percent and help Consumers Energy reach its greenhouse gas reduction target of 20 percent by 2025. Current project schedule calls for con-struction to begin in 2014 and for the new combined cycle power plant to begin serving Consumers Energy’s electric customers in 2017.

MarylandPanda planning 859MW BOO combined cycle plantPanda Power Funds announced that it in-tends to build, own and operate an 859MW Mattawoman combined cycle power plant in an industrial-zoned area of Brandywine, Maryland. The natural gas-fired combined cycle plant will be powered by two 274MW Sie-mens H-class gas turbines, two duct-fired heat recovery steam generators (HRSG) and a single steam turbine generator. Without supplementary duct firing of the HRSG, the Siemens 2x1 combined cycle configuration would be ISO rated at 822MW net plant output and 5691 Btu/kWh heat rate (60.0% efficiency). The gas turbines will use low-NOx com-bustion technology and be equipped with selective catalytic reduction (SCR) to control NOx emissions. Add-on oxidation catalyst will be employed to control carbon monox-ide and volatile organic compounds emis-sions. The Mattawoman plant will also be a “zero-liquid-discharge” plant, returning no waste water to a treatment facility, thereby preventing any discharge of harmful nutri-ents into the Chesapeake Bay. In addition, the generating station will in-stead use recycled municipal waste water for cooling purposes in order to help conserve the state’s natural supply of drinking water. Construction of the Mattawoman project will take approximately 30 months and is dependent upon financing, regulatory ap-provals and other conditions.

California550MW combined cycle Flex-Plant dedicationNRG Energy and Siemens dedicated the 550MW El Segundo Energy Center located near Los Angeles, California. This is the second Flex-Plant to open in California after the nation’s first in Lodi that went into com-mercial service last year. El Segundo is powered by two Siemens power islands, each featuring a 206MW SGT6-5000F gas turbine, 101MW SST-800 steam turbine, two generators, unfired HRSG and an air-cooled heat exchanger. Siemens also supplied the complete elec-trical equipment, power plant instrumenta-tion and control system, engineering services and plant commissioning. With the SGT6-5000F gas turbines, the two units can generate 300MW in less than 10 minutes, allowing the plant to back up in-termittent renewable power generation, such as wind and solar power.

UzbekistanM701F4 orders for two combined cycle plantsMitsubishi Heavy Industries has received an order from Daewoo International Corp. of Korea to supply two M701F4 gas turbine and generators. To be installed at two combined cycle plants under construction at the existing Tali-marjan Thermal Power Plant in Uzbekistan. Hyundai Engineering & Construction Co. of Korea has been selected as the plant’s engineering, procurement and construction contractor. Each of the two combined cycle power plants to be built at the site will consist of a 320MW M701F4 gas turbine, 158MW steam turbine, HRSG and generator. MHI will manufacture and supply the gas turbines, and Mitsubishi Electric Corporation is to provide the generators. Once completed, the two plants at the Talimarjan TPP will support Uzbekistan’s robust electricity demand now undergoing rapid expansion in tandem with the country’s steady economic growth. Each 1x1 combined cycle plant is ISO rated at 477.9MW net plant output and 5687 Btu/kWh heat rate (60.0% efficiency) on natural gas fuel. Both plants are slated to go on-stream in 2016.

South AfricaIPP peaking plants total over 1000MWA consortium led by GDF Suez has awarded Ansaldo Energia a contract for the turnkey supply and construction of 670MW Avon

Change-O! Efficiency.........................................................40% PlusEmissions....(42 MW, ISO; Natural Gas; Water Injection) NOx.............................................37 Lb/Hr (25ppmv) CO...............................................14 Lb/Hr (15ppmv) Particulates....................................2 Lb/Hr (2ppmv)Heat Rate.......................................8,670 BTU/KWH-LHVDry Low Nox Combustors...............................AvailableMaintenance Contract...................................AvailableSpare Engine Lease Program........................AvailableStaff Requirements............Simple-Cycle Gas Turbine

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Industry News

and 335MW Dedisa peaking power plants in South Africa. The plants are being developed as inde-pendent power projects following a power purchase agreement with state-owned power utility Eskom. Both plants will burn diesel oil. The 670MW Avon plant will be powered by four Ansaldo AE94.2 gas turbines and be located in the Durban area. The 335MW Dedisa plant will be powered by two AE94.2 gas turbines and be located in the Port Eliza-beth area. On natural gas fuel, the AE94.2 model gas turbine is ISO rated at 170MW base load output and 10,365 kJ/kWh heat rate (34.7% simple cycle efficiency) at 15°C ambient and sea level site conditions. On diesel oil, it will have 2-3% lower power and 1-2% higher heat rate as compared to natural gas. Ansaldo scope of supply includes the gas turbine driven electric generator, auxil-iary systems and civil works for both sites, in addition to transport, erection and com-missioning. Local contractors will provide mechanical and electrical plant equipment as well as construction of the substation and the interface with the electric grid, fuel storage and distribution, and water treatment.

Total cost of the projects is valued at around US$1 billion, to be supplied on a project finance basis following a loan agree-ment between the project companies and South African lenders. Commercial date of operation is expected to start in the third quarter of 2015 for the 335MW Dedisa plant and first quarter of 2016 for the 670MW Avon plant.

North Dakota135MW peaking stationsynchronous condenserBasin Electric is building a 135MW peak-ing station northwest of Williston, N. Da-kota that will be powered by three natural gas-fired LM6000 gas turbine plants rated 45MW each. Phase I construction of the first 45MW plant, built at an estimated cost of $64 mil-lion, began commercial operation this sum-mer. Phase II, for two identical 45MW plants, is being built at an estimated cost of $102 million, should be completed on time to start commercial operation in January 2014. All three peaking plants will operate with SCR for NOx control and catalytic oxida-tion reduction to limit CO. They will also

be equipped with synchronous clutches to uncouple the gas turbine from its electric generator. In this synchronous condenser mode, the generator serves as a motor to provide fast-acting reactive power and help stabilize the transmission system in the area. Basically, the Pioneer Generation Station will be used primarily to support the local transmission system.

TurkeyFast-track project for 360MW GT capacityGE is supplying a mix of nine LM6000 gas turbine plants to the engineering, procure-ment and construction (EPC) firm, Çalik Energy, for a fast-track government project to install 360MW of gas turbine capacity. Çalik has the EPC contract to build three natural gas-fired power plants: two in Akhal and Mary provinces due to start commercial service by the end of 2013, and a third in Lehab for commercial startup in February 2014. Two LM6000PFs and one LM6000PC will power the Akhal plan; three LM6000PCs will power the Mary plant; three LM6000PFs the Lehab plant in Turkmenabat.

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Industry News

The LM6000PF is ISO rated at 43MW base load output and 41.7% simple cycle efficiency on natural gas fuel; the PC model is ISO rated at 48.8MW and 40.1% efficiency.

RussiaNominal 540MW SGT-800 power plant for LNG plantRussian engineering company Technopromexport (TPE) has awarded Siemens an order to supply eight SGT-800 industrial gas turbines for a power generation station at the Yamal LNG production facility in Northern Russia. Siemens scope of supply includes station design, gas turbine man-ufacture, factory test, delivery, installation and commissioning for all eight gas turbine plants. Four of these gas turbines will additionally be equipped with waste heat recovery units to generate process steam. The SGT-800 is ISO rated at 47.5MW base load output and 9556 kJ/kWh heat rate (37.7% efficiency) at 15°C sea level site conditions on natural gas fuel. At arctic temperatures, gas turbine power output and efficiency will be considerably higher. Located onshore, in the Arctic area of the Yamal Peninsula in the North of Western Siberia, the Yamal LNG project will develop the wet gas resources of the Yamal-Nenets region.

CaliforniaLarge scale gas turbine SCR performance test Mitsubishi Power Systems Americas has successfully completed verification testing of a large-scale selective catalytic NOx reduction (SCR) system. System is to be installed at the 800MW Marsh Landing Generat-ing Station in Antioch, California (site of four 208MW SGT6-5000F gas turbine plants). During test operation, the SCR system successfully reduced simple cycle gas turbine exhaust emissions within compliance limits, including nitrogen oxides (NOx) and ammonia,. SCR equipment on test featured a cooling system to lower the gas turbine exhaust gas temperature from around 577°C to below 460°C. The cooling is achieved by uniformly mixing the hot exhaust gas and air (the coolant) – and by protecting ducts through which air is directed to the exhaust gas from excessive thermal stress. Also adopted in the SCR system are new structural and control systems designed to accommodate quick starts and load changes, and an ammonia vaporization system that utilizes exhaust heat. Project engineers are confident that the SCR system design on test can be scaled up to meet emission limitations for much larger simple cycle gas turbine plant installations. The Marsh Landing Generating Station is situated in the San Fran-cisco Bay Area, where some of the world’s most stringent air quality control limits are imposed on emissions of NOx, ammonia, carbon monoxide (CO), volatile organic compounds and particulate matter. Mitsubishi says that the SCR system successfully demonstrated the ability to keep within emission limits during quick starts and load changes and with gas turbine loads across the entire 0% to 100% range.

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How much does a combined cycle cost? The only correct answer:

“it depends”. So when Vic deBiasi, GTW editor & publisher and my friend for many years, asked me to help quantify com-bined cycle costs in a brief and simple fashion, my initial reaction was that it can’t be done due to a large num-ber of parameters which cause wide variations in cost. However, a little persuasion by an old friend goes a long way, and so I found myself compelled to give it my best shot. A word of caution is in order: please read the caveats and commentary, and use the results and discussions only as an approximate guideline, not as a “bankable” num-ber. Depending on technical details of the design, and specific features and options which are included or exclud-ed, it is perfectly reasonable to see cost variations of 30 percent between plants that appear to be “the same”. The $/kW price charts deliberately avoid reference to specific gas turbine manufacturers and models. Instead, they show estimated average curve fits for combined cycles based on dif-ferent type gas turbines selected for plant design.

Cost depends on what’s includedFirst of all, the cost of a combined cycle depends on how we define it. Is it the cost of equipment only or does it include construction labor, manage-ment and supervision? Are engineer-ing and startup costs included? pro-visional operation and testing? long-

term spares? How about infrastructure such as connections to the utility grid or a natural gas pipeline? output stepup transformers and switchgear? cost of land on which the plant is sited? in-vestment financing and development? There are many components of es-timated cost that go into any given number. So, unless the definition of what’s included is made clear, that number does not mean much. We treat the $/kW cost in the pric-ing charts as the “contractor’s price”. This is our estimate of what an EPC contractor would charge to deliver a turnkey plant on the owner’s site. It includes design and detail en-gineering, procuring all equipment, materials and labor, all construction costs and initial startup. It is an “overnight price” that ex-

cludes escalation and interest during construction. It excludes all owner’s costs, such as land, legal, financing, and development costs and fees. And it excludes capitalized spares as well as provisional operating expenses be-yond initial startup.

Influence of locationIf the plant is in a high cost metro-politan region, labor and regulatory compliance costs will be much higher than average. If it is in remote and inhospitable area, the costs of temporary infra-structure like housing, mobilizing la-bor, moving heavy equipment and construction materials, will all add to its cost. In our $/kW cost charts, it is as-sumed that the plant is built in the US Gulf Coast region, and built with non-

Combined cycle plant costsdefined by design tradeoffs By Dr. Maher Elmasri

Whether evaluating a 100MW or 800MW combined cycle, estimates for either plant can vary by 30 percent depending ultimately on engineering design tradeoffs.

Estimated $/kW combined cycle costs

Rated output and efficiency are referenced to plant operation at 15°C ambi-ent temperature and sea level site conditions on natural gas fuel.

The estimates apply to a bare bones plant designed to run solely on gas (not dual fuel) without auxiliary fuel compressors, no duct burners, no by-pass stack and no inlet chilling or fogging.

It is also assumed that the plant is water-cooled with a mechanical draft cooling tower, no SCR or CO catalyst for emissions control, no special envi-ronmental mandates.

For large plants powered by more than one gas turbine, the combined cycle design is based on multiple gas turbines and a single steam turbine to ob-tain the higher outputs.

Finally, all design parameters are on the moderate side of sound engineer-ing practice without any heroics to squeeze the last dollop of efficiency out of the plant.


union labor. The US Gulf coast has a relatively benign cost and regulatory environment, with an excellent pool of contractors and labor skilled in the construction of energy-related infra-structure. Building a similar plant with union labor in a higher cost state such as California or New York can easily double the cost of labor and add 20% to total plant cost.

Influence of rating criteriaSince ambient conditions affect the power output of a combined cycle, its cost per rated kW will depend on the ambient design conditions at which the rating is defined. Combined cycles typically lose power output at the rate of roughly 1% per 100 meters elevation above sea level and at a rate of about 6% per 10°C (18°F) increase in ambient tem-perature. So, for example, a combined cycle plant rated at a 500-meter site eleva-tion (1650 ft) and 25°C ambient tem-perature (77°F) can be expected to cost about 11% more per kW than a similar plant rated at 15°C and sea level ISO conditions. This is because the same equip-ment will produce about 11% less out-put: 5% due to the site’s elevation, and 6% due to the site being warmer than ISO conditions. Although supercharging or cooling the gas turbine inlet air can be used to ameliorate these effects, such mea-sures will incur additional costs and in most cases also reduce efficiency.

Note: For rating purposes, the esti-mated $/kW charts for this article as-sume that the combined cycle plants are rated at 15°C ambient and sea level site conditions.

Environmental mandatesSite and environmental restrictions also affect costs by mandating the se-lection or inclusion of specific equip-ment.

Non-reheat combined cycle plants. Estimated costs based on modern aero derivative and moderate firing temperature heavy frame gas turbines (2000 to 2300°F class).

Source: Thermoflow, July 2013

– 1500

– 1300

– 1100

– 900

– 700

Contractor’s Price US $/kW

Net Combined Cycle Plant Output (MW)

50 100 150 200 250 300 350

Aeroderivative GTs

Heavy Frame GTs

Triple-pressure reheat combined cycles. Estimated costs based on high tem-perature heavy frame gas turbines (2500 to 2800°F class).

Source: Thermoflow, July 2013

– 1000

– 900

– 800

– 700

– 600

Contractor’s Price US $/kW

Net Combined Cycle Plant Output (MW)

200 400 600 800 1000 1200

Large Frame GTs 200 MW and higher

Medium Frame GTs 60-90 MW class


For instance, if water use is con-strained, the combined cycle may have to use an air-cooled condenser, which is much more expensive than a water-cooled condenser. Addition-ally, an air-cooled condenser will di-minish plant net output due to higher condenser pressure and increased auxiliary load. Thus, plant cost per net kW will likely be around 10% higher than a similar plant with a water-cooled con-denser and mechanical draft wet cool-ing towers. Another example, if the use of se-lective catalytic reduction for NOx and CO catalyst is mandated, the plant is likely to cost about 5% more per kW than a similar plant without such emissions controls. This takes into account the cost of the catalysts and their various ap-purtenances, as well as the additional HRSG cost due to longer duct and increased foundation costs. Environmental mandates may also require a taller than normal stack for plume dispersion, or waste water treatment prior to discharge, or noise abatement on some equipment, etc.

Note: For environmental purposes, the $/kW cost charts assume that the plants are water-cooled with a me-chanical draft cooling tower, have no SCR, no CO catalyst, and no special environmental mandates.

Optional equipment and featuresThere are many options that may be added to a bare bones plant. Some, such as fuel compressors, may be necessary; others may be discretion-ary to improve plant performance or flexibility. Some of the more common options are discussed below. But bear in mind that this list is by no means exhaustive.Fuel compressors. Some plants are located along a high-pressure gas pipeline that can feed the gas turbine directly without an auxiliary fuel compressor. Many plants, however, need extra compressors which add

cost and reduce net output due to their power consumption. Fuel compressor specs are very plant-specific since they depend on pipeline pressure at the fence and on gas turbine choice (different models can have very different fuel pressure requirements). If we must mention a typical ball park number, we’ll say that including fuel compressors, with two full-ca-pacity units for redundancy, can add around 4-5% to plant cost per net kW. Oil backup. Many plants that oper-ate principally on natural gas will add oil fuel as a backup, and this raises the price of the gas turbines due to the need for dual fuel burners and controls. Additionally it requires that oil tanks, pumps and piping be added to the plant, along with oil heaters and heat tracing to facilitate oil flow in cold environments. Furthermore, oil firing may neces-sitate water injection for NOx control, which adds more equipment and cost. Extra costs associated with includ-ing oil as a backup fuel will depend on site specifics and on how much oil tankage is included on-site. But, for a ballpark number, figure an extra 2-3%. HRSG firing. For greater flexibility, many combined cycles include sup-plementary firing in the HRSG which increases its cost well beyond the duct burners themselves. The HRSG needs to be longer, and this requires additional foundation work and costs. Also, the internal lin-ing and insulation in the duct burner need to have greater temperature re-sistance. In addition, HRSG tubes in the vicinity of the duct burner must be made of higher grade alloys to cope with higher firing temperatures, which may require a tube design with fewer and shorter fins. This reduction in fin surface area, along with the fact that many heat re-sistant alloys have lower thermal con-ductivity, requires more tubes to pro-

vide the same thermal performance when the duct burner is off. All this means a significant in-crease in HRSG cost, on top of the cost for additional fuel piping and controls, especially with a dual fuel duct burner. Domino effect. The extra costs for supplementary firing don’t stop at the HRSG. High energy steam piping may need upsizing to accommodate an increase in steam production when duct burners are used. The steam turbine and its generator and switchgear have to be larger to cope with the additional steam flow and power production. The condens-er and its cooling system may also need to be enlarged if design back-pressure is to be maintained with duct burners at maximum firing. The combined costs for all these features depend on the extent of sup-plementary firing, and on the design and operating philosophy of the plant. In light of these uncertainties, the cost increase with supplementary firing cannot be quantified in a general way. As a typical ballpark number for a reasonable design scenario, figure on adding an extra 10-15% to total plant cost. This implies a similar increase in $/kW if the plant is rated on an un-fired basis. However, if rated on its fully-fired basis, the plant will likely be less ef-ficient as well as less expensive; its $/kW will likely be around 5% below an unfired design, due to the addi-tional kW generated when fully fired. Bypass stack. Some plants are equipped with a diverter damper and bypass stack to allow starting and running the gas turbine somewhat au-tonomously from the HRSG. These systems are expensive. Un-like the HRSG final stack, they are subject to the full exhaust temperature of the operating gas turbine, which requires premium materials and in-sulation as well as high temperature acoustic controls. The diverter damper and bypass stack along with the requisite foun-


dations and associated construction costs can add about 3% to total plant cost. A few plants go even farther by adding a draft fan and fresh-air firing system to the HRSG, which enables HRSG steam production without run-ning its gas turbine. Needless to say, this adds considerable complexity and cost. Inlet air chilling. Plants operating in a hot ambient sometimes include a gas turbine inlet air chilling system, with or without chilled water storage tanks. These systems are very effective at raising net output during periods of hot ambient operation when spot prices for power are highest. Again, the additional costs of these systems vary widely depending on spe-cifics, but will typically increase plant cost by something in the 3%-6% range.

Note: To standardize on equipment scope, the $/kW estimates are based on ‘bare bones’ plants designed to run solely on natural gas, without any auxiliary fuel compressors, no duct burners, no bypass stack, and no inlet chilling system.

Cost vs. efficiency tradeoffsThere are many technical design pa-rameters that can be chosen to im-prove a plant’s efficiency, but which also increase its cost; and vice versa. Most parametric design tweaks to raise efficiency are subject to a rule of diminishing return; the trick is to identify the values of design param-eters that do not go past this point, i.e. at which the gains in efficiency are still justified despite the increase in cost. Naturally, this depends on the ratio of cost of fuel to cost of capital equipment, so no general rule can be made. Over the many years of describing “cost vs. efficiency” in seminars and software classes, and upon asserting that we have to choose between high efficiency or low cost. I occasionally get the quip: “But we want both, high efficiency and low cost”.

To which my answer has always been the axiom that it is quite feasible to have high cost and low efficiency (with poor design choices), but gener-ally infeasible to have high efficiency and low cost!

Ripple effect of tweakingA commonly cited example of tweak-ing a design to increase efficiency is designing the HRSG with smaller pinch point temperature differences. This can improve heat recovery effec-tiveness but exponentially increases heat transfer surface area. Less common is designing the HRSG for a smaller gas-side pressure drop, which helps gas turbine output and efficiency. But at the expense of a larger HRSG duct cross section with lower gas velocities and heat transfer coefficients, and hence a larger total surface area -- and greater cost. Another example is increasing the steam turbine exhaust annulus area by using a longer last-stage bucket. This reduces steam turbine exhaust veloc-ity and losses, but raises the cost of the steam turbine, particularly if the increased exhaust area requires tita-nium last-stage buckets that otherwise would not have been necessary. Yet another example is using larger diameter piping to reduce pressure drops in the main steam pipes, which

results in better output and efficiency, but greater cost. In a similar vein, even cooling water piping design can be tweaked, with larger pipes reduc-ing velocity and hence auxiliary pow-er consumed by the circulating water pumps, but of course with higher cost.

Big ticket design choiceFinally, the selection of cooling sys-tem parameters in a combined cycle can have significant impact on cost. Naturally, the closer the condens-er saturation temperature gets to the ambient heat sink temperature, the greater the plant’s efficiency and the higher its cost. For each design value of condens-er saturation temperature (and hence condenser pressure), there are several cooling system internal design vari-ables that affect net output and effi-ciency as well as gross cost. The cooling system cost-efficien-cy tradeoff are quite extensive, with several key variables for each of the many types of cooling systems that are used in combined cycles. For the estimated $/kW cost charts shown in this article, all design pa-rameters were selected to be on the moderate side of sound design prac-tice, without any engineering heroics to squeeze the last dollop of efficien-cy out of the plant. n

About the authorDr. Maher Elmasri, is founder & president of Thermoflow Inc, a company which produces software for the design and simulation of power plants. He wrote its original GT PRO & GT MASTER products in the late 1980’s and has supervised their maintenance and upgrades ever since. The PEACE cost estimation module was developed by Dr. Elmasri and his team in the late 1990’s. Its philosophy is to estimate cost as the sum of the parts, with the parts being based on physical equipment models, generated as a function of the many hundreds of technical assumptions used to con-figure and specify the plant’s design. Thermoflow’s software products are used by several thousand engineers worldwide and are updated and expanded annually, currently in their 23rd version since 1988. The results shown in this article were derived using Thermoflow’s GT PRO & PEACE software modules. In addition to software development, Dr. Elmasri has spent much of his career as an educator, first on the faculty at MIT, then through teaching a combined cycle design seminar which has been attended by over 2000 en-gineers in the nearly seventy times it has been held.


MAN Diesel & Turbo has up-graded its single- and twin-

shaft 6MW-class MGT6 gas turbine series to operate with single digit NOx levels (ppm) on natural gas fuel. Upgraded performance:

o Genset. Single-shaft design for powergen is ISO rated at 6530kW base load and 10,660 Btu/kWh heat rate (32.0% efficiency).

o Steam. Waste heat recovery steam for cogen is produced by 62 lb/sec gas turbine exhaust flow at 870°F ex-haust temperature.

o Mech drive. Twin-shaft mechani-cal drive design is rated at 9250 shp continuous and 7480 Btu/hp-hr heat rate (34.0% efficiency).

o Emissions. Test units have dem-onstrated less than 10 ppm NOx for the generator drive down to 50% load and 70% load for the mechanical drive.

The first single-shaft generator drive was installed recently at a SolVin chemical products production com-plex in Rheinberg, Germany. It began commercial service in June 2013 to supply SolVin with 6MW of base load electric power and

11MW of thermal power for process steam at a nominal steam termpera-ture of 257ºC and 12.3 bar pressure (495ºF and 178 psig). Firing natural gas fuel, the cogen-eration plant has been operating at better than 80% CHP efficiency in the full 6MW power and 12.8 ton/hr steam production mode.

Single digit NOxThe new MGT gas turbine series has achieved extremely low NOx levels in test stand runs. “In addition to high efficiency, one of our primary development aims was that the new gas turbine family had to be equally economic and environ-mentally-friendly all the way down the line,” says Dr. Sven-Hendrik Wi-ers, Vice President Gas Turbines. “The single digit NOx values now realized in the load range between 50 and 100 percent with the MGT 6100 (single-shaft version of the new MGT family) prove that we have achieved this aim.” Less than 10 ppm of nitrogen ox-ide were measured in the exhaust gas on the test stand in Oberhausen dur-ing all operating conditions between half and full load performance of the gas turbine, he notes. In comparison, The German Fed-eral Emission Control Act currently

specifies a limit value of 36.5 ppm of NOx (equivalent to 75mg/Nm3) in the Technical Instructions on Air Quality Control. “We are convinced that we can repeat this excellent result in further versions of the same type. We plan on guaranteeing very low nitrogen oxide values based on the test results,” says Frank Reiss, Head of Combustion Technology. According to the engineering de-velopment department, these extreme-ly low emission values were achieved with an Advanced Can Combustor (ACC) design modified and further developed for the new upgraded gen-eration of MGT 6 gas turbines. (Edi-tor’s note: The initial ACC design was originally developed for the cur-rent THM gas turbine family of 10 to 13MW machines.) These can-type combustors work on the principle of premix technol-ogy. The fuel is already premixed ho-mogeneously with the combustion air before entering the combustion chamber. As a result, fuel-rich hot strands which generate a lot of NOx are avoided. The Dry Low Emission burners operate in diffusion mode for start-ing. At very low loads, they change automatically to premix mode with increasing power demand as dictated

6.5MW GT6 gas turbine series NOx cut 60% to under 10 ppm By Robert Farmer

GT6 series has been upgraded by new premix combustor technology capable of limiting NOx to less than 10 ppm over a range of 100% to 50% part-load output.


by the digital engine control.

Design architectureThe MGT 6 designs are heavy frame gas turbines with cast iron and steel casings, horizontally split at the com-pressor section to allow top or bottom casing removal for complete rotor ac-cess to compressor blades and vanes. The output power shaft for the twin-shaft gas turbine is located at the hot exhaust end of the engine. It has a nominal 12,000-rpm shaft speed that is suitable for direct coupling to the latest range of high-speed centrifugal and axial type gas compressors. On the single-shaft model, power output is out the cold compressor end with engine shaft speed reduced by an integral load reduction gearbox. The cast iron air intake casing is located at the front end of the gas generator rotor and supports the front of the compressor section. The inlet casing houses the thrust bearing and the forward journal bearing of the gas generator shaft. The machine is designed so that the hydrodynamic tilting pad type

bearings can be directly accessed without dismantling the casing or compressor. The auxiliary gearbox is directly connected to the front flange of the air inlet casing and houses the main lube oil mechanical pump. The aux-iliary system gear unit forms an inte-gral part of the gas generator and is mounted to the machine base frame to take up thermo elastic expansion. An electric starting motor drives through the gearbox to the compres-sor shaft. Additionally, the auxiliary gearbox is used as a front end support for the gas turbine.

Compressor sectionThe MGT 6100/6200 engines share an 11-stage axial-flow compressor with an overall pressure ratio of 15.0 to 1. This is an advanced design com-pressor based on aero engine com-ponent design, capable of producing over 60 lb/sec air flow out of only eleven stages. It is a very compact unit – short and stiff – featuring variable inlet guide vanes at the compressor entry,

followed by three stages of variable geometry vanes to control part-load airflow and surge. This feature also provides smooth engine control for cycling, variable load following and extended part load operation. It also keeps the exhaust temperature high at lower loads for good heat recovery boiler perfor-mance in cogeneration and combined cycle operating modes.

CombustorSix individual combustion chambers are installed around the circumference of the engine. These large reverse flow can-type units are inclined at a 35° angle rel-ative to the centerline of the shaft. They are flanged to the integral inter-mediate casing which is a heavy-duty single piece casting. The combustion chamber design contains a vortex-stabilized burner section within a large internal volume to provide for uniform temperature profile at the combustor exit and inlet of the first stage turbine nozzle. Of modular design, individual

CHP installation. First MGT 6 began commercial service in June 2013 at the SolVin chemical products production plant in Rhein-berg, Germany, supplying 6MW of base load electric power and 11MW of thermal power from exhaust heat at over 80% cogeneration thermal efficiency.


combustors and flame tubes (includ-ing fuel injectors, liners, transition ducts and cooling sleeves) are easily accessed, removable and exchange-able in the field, note MAN design engineers. The flame tubes and the associated transition ducts are provided with an impingement cooling system. High-temperature alloy flame tube walls are cooled by high-pressure bleed air from the compressor to ensure long combustor liner life. The rotationally symmetric ar-rangement of the six combustion chambers results in a nearly even temperature distribution, according to MAN combustion engineers. “The burner has a swirl chamber and two different fuel injectors which are used in the diffusion mode (pilot gas), in the pre-mixture mode, or in the combined diffusion and pre-mix-ture mode as required by the overall operation.” During start-up and in low-load operation, the burners are operated in the diffusion mode. They automati-cally switch over to the pre-mix mode

as power increases. “Operating con-tinuously with a small portion of pilot gas enables the gas turbine to perform even very rapid load changes safely.” As with the compressor rotor, ex-tensive access for borescope inspec-tion is easy for the entire combustor section and for the turbine nozzles and blades. Ignition of the flame is through individual high-energy torch ignit-ers, one for each combustor can. This eliminates the need for more conven-tional crossfire tubes connecting the combustors.

Turbine sectionThe intermediate casing structure is a single piece casting which supports the combustors and high-pressure tur-bine section. The HP turbine driving the gas generator compressor is a two-stage axial flow design. Like the compres-sor forward rotor stack, the two tur-bine discs fitted to the downstream end of the compressor shaft are as-sembled and held in place with the same type Hirth couplings and center

tie-bolt. All HP turbine stationary vanes and rotating blades have internal air cool-ing using compressor discharge air to maintain material temperatures at all running conditions for long compo-nent life. The turbine discs are also externally air-cooled. The first row rotor blades are un-shrouded and have an internal cool-ing serpentine channel and a pin fin matrix in the coolant air outlet re-gion. Their tip area is provided with a rubbing edge to reduce tip clearance losses. The second row blades have a clamped interlocking tip shroud. Clearance control systems on the blades are designed to ensure high ef-ficiency over the entire load range. The aft (outlet-end) gas generator bearing is supported by a rear-end structure which is a single piece unit without casing splits. “Arranging the bearing location downstream of the HP turbine offers the advantage of minimizing air leakage into the bear-ing housing and keeping the bearing out of the hot section area,” explain MAN design engineers. “At the same time, the bearing area is more easily accessible.”

Two turbinesOn the MGT 6200, the free power tur-bine is a two-stage axial design, close coupled to the gas generator and op-timized for two-shaft variable speed operation. This aerodynamically coupled low-pressure turbine (LPT) has a wide op-erational speed range from about 45 to 105% of design speed. Specific speed range is 5400 rpm to 12,600 rpm, the latter being the maximum continuous power turbine speed. The two turbine discs in the over-hung rotor design are fitted to the front end of the shaft by Hirth ser-rations, which transmit mechanical power to the driven unit. The shroud-ed and interlocked blades, which are not air-cooled, are anchored to the discs by ‘fir-tree’ roots. The discs are

Single-shaft engine. Generator drive core engine module with MGT 6100 gas turbine cantilevered off the integral inlet duct/planetary gearbox assembly. Output shaft is at front (compressor) end with exhaust out diffuser (right) for close coupling to heat recov-ery equipment with minimum thermal energy losses.


cooled by compressor air. The power turbine shaft is sup-ported by two tilting pad bearings, the rear one being combined with a pivot shoe type thrust bearing to balance the axial thrust. An additional function of the LP turbine bearing casing is to house the outlet diffuser. This outlet casing is a welded structure. Its geometry and the turning channel directing exhaust gases from axial to radial direction was aerody-namically optimized with CFD design parameters. On the single-shaft MGT 6100, a three-stage turbine section is connect-ed directly to the aft compressor rotor section forming the single gas turbine shaft, with no free power turbine. This rotor provides the load-driv-ing power out the front end of the en-gine through a power coupling at the front of the compressor shaft. Essentially, the 6100’s design con-cept shares most of the parts with the two- shaft machine, except parts of the turbine and the drive concept. In essence, a third turbine stage is added to the two stages of the HP turbine, replacing the overhung free power

turbine. This single-shaft version is specifi-cally designed for power generation, says MAN. In contrast with the hot-end drive arrangement of the two-shaft engine, the MGT 6100 design allows cold-end drive and a longer turbine exhaust diffuser to optimize connection with a boiler for best com-bined heat and power generation per-formance.

Construction and materialsThe compressor rotor assembly is a drum-type design, built up of three rotor discs, a front hub and a rear hub (these contain the bearing surfaces). The Hirth coupling splines—toothed rings machined into each face of the disc and hub bodies—mesh with the adjacent disc or hub to form a fully ‘locked’ assembly. These rugged designs maintain

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13,200 –

12,800 –

12,400 –

12,000 –

11,600 –

11,200 –

10,800 –

10,400 –

MGT 6100 power and heat rate. Nominal power output and heat rate versus inlet temperature at sea level on natural gas fuel with zero inlet and exhaust pressure losses.

Power MW

Power

Heat rate

Heat rate kJ/kWh

Inlet temperature (°C)

-20 -10 0 10 20 30 40

– 34– – 32– – 30– – 28– – 26– – 24– – 22

520 –

500 –

480 –

460 –

440 –

420 –

400 –

MGT 6100 exhaust flow. Nominal gas turbine exhaust gas flow and temperature versus inlet temperature for operation on natural gas and sea level site conditions.

Flow kg/s

Gas tempera

ture

Flow

Temp °C

Inlet temperature (°C)

Generator Drive Mech Drive

Design Parameter MGT 6100 MGT 6200

ISO base load 6530 kWe 6900 kWs (9250 shp)

Heat rate (LHV) 11,250 kJ/kWh 10,590 kJ/kWh

10,660 Btu/kWh 7480 Btu/shp-hr

Efficiency 32.0% 34.0%

Pressure ratio 15.0 to 1 15.0 to 1

Turbine speed 12,920 rpm 5,400 to 12,600 rpm

Exhaust flow 28 kg/sec (62 lb) 28 kg/sec (62 lb)

Exhaust temperature 465°C (870°F) 451°C (844°F)

Source: MAN Diesel & Turbo, July 2013

Single- and two-shaft MGT 6 design performance. Gas turbines on test have achieved less than 10ppm NOx down to 50 percent load for the genset and 70 percent load for the mechanical drive.


MGT 6100 generator set. Complete genset is contained in a two-tier enclosure design. Top level houses all the air handling equipment, includes gas turbine air intake, electric generator cooling air, filters and silencers, all the ductwork. Bottom level houses skid-mounted gas turbine, reduction gearbox, start motor, electric generator and auxiliaries. Turbine exhaust stack is not included.

Enclosure air ventilation. Enclosure air enters the Base module via a separate filter arrangement by means of 2x50% pressurizing fans. Simultaneously, 2x50% fans (located in the Top module) suck out the enclosure air.

GT intake air filtration. Several filter options are available (including cartridge and cassette type) with different levels of efficiency to filter gas turbine intake air (Top module) for compression and combustion.

Fuel gas system. Primary components of fully integrated fuel gas module include electrically driven fuel metering valves (for main and pilot gas) and a shutoff-vent valving combination.

Base frame. Designed as a “single lift” assembly, has six spring-loaded support pads that provide decoupling from the foundation and facilitate onsite installation. Also houses lube oil tank.

Integrated load gear. The gas turbine is started by a frequency controlled electrical motor connected to the load gear which also drives the main lube oil pump.

Lube oil system. Includes the main lube oil pump and two electrically driven pumps for backup and post lubrica-tion. Additional components (heater, control valve, separator, etc.) are located within the Base and Top modules.

Electric generator. Air cooled generator is driven by the gas turbine through a planetary type load gear which is an integral part of the gas turbine design.

Local control. Base module compartment includes gas turbine and generator control systems as well as low-volt-age distribution for the secondary systems and variable frequency drive (VFD) panel for the starting system.

A

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GH

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concentricity and axial position and can transmit very high torque loads without any slippage. A center tie bolt holds the entire hub and disk assem-bly together. Rotor discs are in stainless steel, forward stator vanes (and IGV) and rotor blades are in ferritic steel on stages one through five, and these components are treated with a Serme-tel protective coating. Rear stages of compressor stator vanes and rotor blades are in CrNiMo alloy on stages six through eleven. The intermediate combustor case is a casting that connects the air com-pressor to the rear turbine structure of the gas generator. It contains the axial compressor diffuser and two nozzle guide vane carriers of the high-pres-sure turbine. It also houses the hot gas transition ducts and supports the six combustion chambers.

Hot sectionSingle-piece casings are applied to the combustion and HP turbine hot sections as well as to the free power turbine assembly to ensure long life alignment. Combustor can liners are of high temperature nickel-based al-loy. The transition ducts are single-piece, high-temperature alloy sheet metal fabrications. These pieces direct the hot gases from each individual flame tube to the high-pressure tur-bine nozzle guide vanes. The outer surface of the transition duct is impingement air-cooled. The air flows through the annular space between the transition duct and an im-pingement cooling sleeve. Both sides of the transition duct are protected by a patented MCrAlY coat-ing to ensure long lifetime durability of this high-temperature component. High-pressure turbine guide vanes on all stages are in MarM 509, while the HP rotating blades are Inconel 792 superalloy on stage one. HP blades on stage two are in CM 247DS, which is a directionally solidified production

technique. On the single shaft engine, the third stage HP blades are Inconel 792. All blades and vanes are made by equi-axed technique with exception of HP2 blade that is directionally solidi-fied. All the turbine section (HP and LP) rotor discs are Inco 718 alloy. The low-pressure turbine nozzles are Inco-nel 939 with a Sermaloy J protective coating while the LP rotor blades in Inco 792 with a chromized coating. The diffuser, located within the power turbine casing downstream of the power turbine, features an addi-tional sheet metal cladding made of high-temperature alloy for extra heat insulation of the cast iron casing. The exhaust collector box is made of welded sheet metal. The design is aerodynamically optimized to achieve a high static pressure recovery and minimize parasitic losses. The turbine is connected via this box to either an exhaust gas stack or a heat recovery steam generator. While the component designs re-main fixed, project design engineers explain that the materials and coatings can be subject to change or modifi-cation, reflecting latest metallurgical developments, engineering and field operational experience.

Complete packageThe gas turbines are delivered as pre-mounted units on a steel base frame, complete with lubrication and aux-iliary systems. Fully packaged units can include enclosure, inlet and ex-haust system modules, and engine and driven equipment controls. The package is preassembled as far as possible within shipping con-straints, so that site erection and en-gine installation work is minimized, says MAN. The core turbine can be removed within 24 hours. Package supply can include the acoustic enclosure with thermal and sound silencing, combustion inlet and exhaust ductwork with filters and si-lencers, enclosure ventilation inlet

and exhaust and fire detection/sup-pression system. On the twin-shaft mechanical drive models, driven equipment (pump, compressor, etc.) can be supplied on a separate heavy frame base plate. The MGT6200 is specifically matched to MAN’s own series of gas compressors, including direct drive of the popular RVS40/RV50 pipeline compressor models and the RB28/35 barrel type centrifugal compressor units.

Fully enclosed gensetFor the MGT6100 generator sets, a completely enclosed ‘box type’ pack-age contains all the equipment. Essen-tially a ‘two tier’ structure, the lower level, or base module, contains the base plate with integrated lubricating oil tank. The heavy-duty steel base frame is designed as a ‘single lift’ module for ease of installation. It is fully support-ed on six heavy spring elements that provide a decoupling from the foun-dation for very low vibration trans-mission and resistance to any torque motions such as imparted on offshore platforms. The gas turbine, reduction gear, start motor, direct air-cooled electric generator and generator auxiliaries are mounted on the base skid. Axi-al turbine exhaust diffuser exits one end of the package enclosure. Turbine exhaust stack is not included in the standard scope of supply, but can be offered if needed. The integral load gear assembly contains the planetary main reduction gearbox, auxiliaries gearbox and main lube oil pump mechanical drive. On one end, it supports the front of the gas turbine which is cantilevered off the gearbox assembly and on the other it supports the frequency-controlled electric motor start system. The main gas turbine driven lube oil pump is backed up by two elec-trically driven pumps also used for post lubrication during cool down. Lube coolers and heaters, filters and


oil mist separators complete the lube oil system. Base module houses the fully inte-grated fuel gas module that contains the electrical fuel metering valves for pilot and main gas and a shutoff vent valve combination. At the front of the base module is the local control compartment. This control room includes all the control systems for the gas turbine and the generator as well as the low-voltage distribution for auxiliaries and the VFD panel for the starting system. All connections between the con-trol room and the other package sys-tems are pre-assembled and factory tested prior to shipment, says MAN. The air handling equipment is located in the top module. This includes gas turbine and en-closure ventilation air, filters and si-lencers for generator and gas turbine inlet air, and all ductwork. The air in-lets are protected by external weather hoods. Overall, the complete external genset package dimensions are 14.3 meters long by 3.0m wide by 7.4m

high to the top of the enclosure (47 x 9.8 x 24.3 feet). This does not include the exhaust stack. The base module weighs 63 tonnes (126,000 lbs.) and the top module weight is 13 tonnes (26,000 lbs.) for a total overall weight of 76 tonnes, or 152,000 pounds.

Onsite performanceTo meet the latest requirements for gas turbines operating as backup gen-eration for wind and solar renewables, company design engineers specifical-ly optimized the MGT 6100 for fast start, load following, and extended part-load operation. Startup to full load is possible within 10 minutes and the four-stage variable geometry vane network on the compressor allows close match-ing to grid-required partial loads with maximum efficiency. Dependent on the application, large transients to full/part load operations and low emissions for a wide operating range can be met where required. Engines and packages are de-signed for applications and site con-

ditions from installation in desert ar-eas with peak temperatures beyond 50°C through offshore installations to remote sites in Arctic regions with ambient temperatures as low as -60°C. As with all MAN Diesel & Tur-bo gas turbine engines, including the larger ‘THM’ series, the MGT 6 ma-chines have a modular design for easy dismantling and inspection and com-ponent replacement. Extensive borescope inspection ports have been integrated throughout the engine flow path as an integral part of the design. Company engineers note, “The maintenance cycle will be the same as the existing THM range, i.e. 35,000 to 40,000-hr intervals before inspection of the hot gas path section.”

More to comeCurrently, MAN is performance test-ing the new single-shaft engine that is intended specifically for 50/60Hz electric power generation. Planetary (epicyclical) type reduction gearing is used to bring nominal 12,920 rpm engine output shaft speed down to match 1500 or 1800-rpm continuous generator speed. Series production is planned start-ing next year, following the comple-tion of extensive MGT 6100 proto-type testing at the Oberhausen facility. Instrumentation on the test ma-chine is currently focused on the cool-ing flow path to verify part load op-eration based on compressor variable guide vane adjustments. The opera-tional behavior of the compressor had already been verified on the rig com-pressor at the Anecom test facility in Wildau, outside Berlin. The MGT6 units are the first in a planned series of in-house designed and developed gas turbine projects that have been in the works for nearly ten years. The new series constitutes a technology platform for further devel-opments to create a new family of gas turbine models covering a wide range of applications, reports MAN. n

Two-shaft mechanical drive. Skid mounted production MGT6 driver has free power turbine (right) output shaft which operates at maximum 12,600 rpm full load to directly drive high speed gas compressors. Auxiliaries gearbox and cast iron engine inlet air duct at left act as main support for front of the engine.


General Electric and Nanjing Turbine & Electric Machinery

Company (NTC) are supplying China Guodian with two Frame 6F gas tur-bines and balance-of-plant equipment for a 175MW gas turbine based co-generation facility. The facility is designed around two cogen power blocks each con-sisting of a 77.6MW gas turbine, un-fired dual pressure HRSG and steam turbine. One cogen plant has an ex-traction steam turbine and the other a backpressure steam turbine, with a combined output of 20MW:

o Electric Power. Facility is rated at 175MW base load output generated by the gas turbine and steam turbine gensets.

o Cogeneration. Around 70% co-gen efficiency for 205 ton/hr, 15 bar(a) and 330°C steam flow (230 psig and 625°F).

o Emissions. DLN emissions of 15 ppm or less NOx and 9 ppm CO from full load down to 50% part-load out-put.

The cogeneration facility is being built to supply electricity and process steam to companies in the Nanxun economic development zone near Hu-zhu city in Zhejiang province. De-pending on grid demand, excess elec-tricity generated will be fed to the grid during periods of reduced indus-trial load.

In the past, the power and heat re-quirements of economic development zones like Nanxun were met by coal fired steam plants. Recently, however, many of the old, small and inefficient boiler plants are being replaced with gas turbine based cogeneration plants.

Nanxun project The Nanxun cogen facility will be owned and operated by Guodian Di-anli, a subsidiary of the state-owned power generator, China Guodian Corp., which engages in power plant development, investment, construc-tion, operation and management. According to Steven Rahm, Exec-utive Product Manager at GE Power

& Water, the Nanxun plant is stereo-typical of several projects that have been springing up over the past three or four years. “We sold ten 6F gas turbines last year, in groups of two, for economic development zones around China. “Power companies primarily sup-ply not only power for the industrial parks but also various levels of steam for process. These development zones are typically made up of small indus-tries such as chemical plants, refiner-ies, paper mills, etc.”

Scope of supply The turnkey contract for Nanxun will see GE supply key components of

175MW Nanxun cogen plant to power industrial zone and grid By Junior Isles

Utility in China is building a cogeneration plant powered by two 6F gas turbines to generate electricity and process steam for the Nanxun economic development zone.

GE partnership with Nanjing Turbine

General Electric and Nanjing Turbine & Electric Machinery Compny (NTC) have been working together to supply 6B and 9E gas turbines to customers in China for nearly 30 years. Recently the two companies signed a technol-ogy transfer agreement for 6F gas turbines.

Compared to previous technology, the 6F power range, high efficiency and low emissions are said to be well suited for economic developments zones in China like the Nanxun plant being built to produce electricity and process steam.

“NTC was our earliest partner for gas turbine manufacturing in China,” said Victor Abate, president and CEO, Power Generation Products for GE Power & Water; “and that relationship was key to winning this Nanxun contract award.

“It demonstrates long-term commitment and our local capabilities to provide products and technology that will produce the reliable power needed to sup-port China’s continuing growth and progress.”


the 6F gas turbines (flange-to-flange), installation services, spare parts, gas turbine training, distributed control system and steam turbine controls. NTC will provide the steam tur-bines, generators and supervise instal-lation of the cogeneration plants. Rahm noted: “We will do the in-stallation of the gas turbine as well as the control systems for the gas and steam turbines. We will also partici-pate in commissioning of the plant.” The plants will have a cogeneration efficiency of around 70%, say com-pany project engineers, which will enable Guodian Dianli to meet indus-try steam and electricity loads at rela-tively low costs with low emissions.

Cogeneration efficiency That 70% efficiency level is based on 51 bar/16 bar steam from the HRSG, 120 ton/hr steam flow for backpres-sure steam turbine power generation, 85 ton/hr steam at 15 bar from the extraction steam turbine for process. Guodian’s choice of the 6F gas tur-bines was based in part on its power rating and on the steam load available from the gas turbine exhaust flow and temperature, says Rahm. “The fact that the 6F power blocks can be arranged in a 2-bay configura-tion to provide redundancy is critical. If there is an issue with one of the gas turbines, basic electricity and steam demands can still be met from a sin-gle gas turbine and steam turbine.”

GT design featuresThe 6F gas turbine is a direct down-scaling of the 7F 3 gas turbine design. It has a single-shaft, bolted rotor with the generator connected to the gas turbine through a speed reduc-tion gear at the compressor or ‘cold’ end. This feature allows for an axial exhaust, which helps enhance plant arrangements for combined cycle and waste heat recovery applications. It has an 18-stage, axial flow com-pressor with a 15.7:1 pressure ra-tio and 213 kg/sec (469 lb/sec) air flow. The first eight stages are high

Fr 6F unfired HRSG steam profile. Typical steam production curves for 1107°F gas turbine exhaust and 469 lb/sec air flow at base load output.

Source: Gas Turbine World, August 2013

– 190

– 180

– 170

– 160

– 150

– 140

– 130

Steam Flow (t/h)(tons/hour)

Steam Pressure (psia)

0 200 400 600 800 1000 1200

400°F500°F

600°F

saturated

700°F

800°F

900°F

Skid-mounted Fr 6F. Rated at 77,577kW output and 9574 Btu/kWh heat rate (35.6% efficiency) including inlet, exhaust and shaft-driven auxiliary system losses, at 59°F ambient and sea level site conditions, on natural gas fuel.


strength, corrosion resistant GTD-450 stainless steel, with the remaining air-foils made of 403+Cb steel alloy. The reverse flow, six-chamber, second generation Dry Low NOx (DLN) 2.6 combustion system has six fuel nozzles per chamber, includes two retractable spark plugs and four flame detectors as part of the system. Crossfire tubes connect each com-bustion chamber to adjacent cham-bers on each side. For ease of main-tenance, each chamber, liner and transition piece can be individually replaced. The DLN combustion system lim-its NOx emissions to 15 ppm and CO emissions to 9 ppm, which can be sustained down to around 50 per cent load.

Turbine The turbine section has three stages with air-cooling on each of the three nozzle stages, as well as on the first and second bucket stages. The buckets are designed with long shanks to isolate the turbine wheel rim from the hot gas path, and integral tip shrouds are incorporated on the second and third stages to re-duce bucket fatigue and improve heat rate. The rotor is a single shaft, two-

bearing design with high torque capa-bility, incorporating internal air-cool-ing for the entire turbine section. The shaft rotates counter-clockwise when facing the gas turbine output flange and the load gear reverses the rotation as it drives the generator rotor. To facilitate field change-out, the gas turbine rotor can be handled as one piece, and the turbine buckets (rotating blades) can be changed in sets or individually, without the need to field-balance the rotor. The five turbine and compressor casings are horizontally split to fa-cilitate inspection and maintenance. Borescope access holes, located in the compressor and turbine sections, also facilitate visual inspections. Long-term service agreements for the turbines at Nanxun are under dis-cussion. “We expect there will be the typical 24,000-hr hot gas path and combustion inspection intervals,” said Rahm.

OperationThe cogen facility will run on natural gas supplied from China’s West to East Pipeline II. Inasmuch as the facility is de-signed to deliver power and steam, the units will operate primarily in base load service to meet industrial

demand, probably operating in excess of 6,000 hours a year. However, there may be times dur-ing the weekend when they don’t operate, depending on electric grid and industrial steam demand. Ex-cess power will be fed to the grid and steam supply vary according to indus-trial needs. There is an extraction steam tur-bine on one of the gas turbines and a backpressure steam turbine on the other (used when high quality steam is required). Power production of the backpressure steam turbine is propor-tional to process steam demand.

TimetableThe first 6F gas turbine for the Nanx-un project will be shipped from GE’s factory in Belfort, France in October of 2013 while the second machine will be shipped in December 2013. Site construction is already under way. Both should arrive on site within about one month of shipping. Installa-tion is likely to be carried out during the first quarter of next year so that the new cogeneration plant can be-gin operation in the second quarter of 2014. Based on the increase in sales over the last three years, Rahm believes there will continue to be further or-ders for 6F gas turbines for similar installations in the future. “We see the demand continuing. In some cases it will not be for new installations; sometimes they will be replacing existing coal-fired steam boilers in some of these economic zones. We see a robust market for this machine going forward.” He summed up: “This is one of the reasons we reached an agreement with NTC last year to license the 6F gas turbine. As we move forward with them, eventually we will be just ship-ping the rotor and the hot gas path combustion and control components and NTC will begin to manufacture more of the gas turbine casing, etc. in the country.” n

6F gas turbine. Design features cold-end drive, 18-stage compressor (with a 15.7 to 1 pressure ratio and 469 lb/sec flow), six DLN 2.6 second generation combustors and a 3-stage turbine.

Stay Ahead of the Curve

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For Project Planning,Proposals, Engineering,Evaluation and ProcurementJanuary - February 2013

Volume 43 No. 1

2013 Performance Specs29th Edition

July - August 2012 • Volume 42 No. 4

Can CLN really reach zero CO? page 10

30MW at 41% with low NOxpage 14

ISI adds 6MW to Trent rating page 24May – June 2012 • Volume 42 No. 3

Saturn 110 MW upgrademay use nanotechnology page 14

200MW with 15-minute start and 38% efficiency page 19

Shale gas boom fueling electrical load demand page 24 November – December 2012 • Volume 42 No. 6

Wind energy beingstored as hydrogen page 12

IGCC cutting COE price levels by 20%page 20

SGT-300 mech drive ready to make debut page 25


Enovik Industries is partnering with E.ON to build a natural gas-

fired Siemens SGT-800 combined cy-cle plant at its Marl Chemical Park in Germany that will replace a coal-fired 60MW generating unit nearing the end of its useful operating life. E.ON will plan, finance and build the new Marl combined cycle plant as well as provide services related to its operation. Enovik will have op-erational responsibility once it is in service. Project highlights:

o Combined cycle. Design rated at 66.6MW net plant output and 6693 kJ/kWh heat rate (53.8% efficiency) on gas fuel without duct firing.

o GT emissions. Gas turbine emis-sions limited to 15 ppm NOx and 5 ppm CO on natural gas from 100% full load to 50% part-load operation.

o Carbon footprint. Switch from coal to gas fired combined cycle is expected to reduce CO2 emissions by about 280,000 tons annually.

In reference to the project, Ingo Luge, CEO of E.ON Deutschland noted: “The construction of a new CCGT at Marl Chemical Park is another ex-ample of how E.ON is systematically propelling the expansion of distribut-ed generation in Germany and doing so in a customer-oriented manner. “Distributed generation is an im-portant aspect of the transforma-tion of Germany’s energy system, to

SGT-800 cogen plant replacing coal-fired unit at chemical park By Junior Isles

A new 66.6MW SGT-800 combined cycle cogeneration plant will help deliver electricity and steam for the Marl chemical plant in Germany.

Combined cycle plant will replace coal-fired unit

The Marl Chemical Park in North Rhine-Westphalia is the third largest inte-grated industrial site in Germany and also the largest site within the Chem-Site Initiative.

More than 4000 chemicals are produced at the chemical park – ranging from high volume materials such as, styrene, polystyrene, acrylic acid and PVC, to speciality products like polyamides and polyesters, plasticizers and surfac-tants.

Around 30 companies currently produce products from the 650 ha site of which, roughly 60 ha of industrial land are available to new investors. The facility is also the largest production site of chemical giant Evonik Industries that is headquartered in Essen, Germany.

Electricity and steam for the park is currently supplied by three power plants, consisting of a total of five generating units producing 300MW of electricity and 1000 t/h of steam.

The oldest of these is unit 3, a coal fired unit (designed for 62.6MW electric-ity and 160 t/h steam) in operation since 1966, which will reach the end of its useful operating life in a few years.

In June of this year, a decision was taken to replace the coal-fired unit 3 with a new natural gas-fired 1x1 SGT-800 combined cycle plant to be built by E.On that is nominally rated at 66.6MW net plant output and 53.8% ef-ficiency, without supplementary duct firing.

Evonik will control and have operational and legal responsibility for the power plant once it is in service. E.On Energy Projects will plan, finance and build the new power plant and provide a number of services related to its opera-tion.

According to Evonik, the switch from coal to gas combined cycle will offer greater flexibility, lower level of investment, much improved efficiency and reduced carbon footprint, as well as a broader energy mix.

Company executives expect that it will enable Evonik to reduce carbon emis-sions at Marl by about 280,000 metric tons annually.


which we intend to make a substantial contribution.” The SGT-800 is available in two versions with ISO ratings of 47.5MW (the Marl unit) or 50.5MW. For en-hanced performance at high ambient temperatures above 33°C (90°F) a hot match compressor is available with increased power output and higher ef-ficiency. According to Siemens, with more than 180 units sold, the CHP unit will deliver high flexibility and proven reliability. “It perfectly fits to the cus-tomer’s energy demand. Even bal-ancing power can be provided by the gas and steam turbine combined cycle unit,” the company said. In addition to supplying the equip-ment for the combined cycle plant, Siemens was also awarded an 11-year service contract to maintain the gas turbine and ensure that it meets high standards for performance, availabil-ity and reliability.

Plant configurationDepending on economic conditions and energy demand within Marl Chemical Park, the new power plant is scheduled to operate in base- or mid-load. According to Evonik, the unit is optimized for steam production from part-load up to full load. Exhaust gas leaving the SGT-800 gas turbine at 541°C (1006°F) is fed into a two-pressure heat recovery steam generator (HRSG) with auxil-iary firing. Steam generated by the HRSG is used to drive an SST-300 backpres-sure steam turbine. Generated electricity will be fed into the 110kV grid via a two-winding main transformer.

Gas turbineThe SGT-800 at the heart of the com-bined cycle unit is a single-shaft gas turbine optimized for combined cycle operation. Originally known as the GTX100, its development began in 1994.

Design parameter 47.5MW version 50.5MW version

ISO base load 47,500 kW 50,500 kW

Heat rate (per kWh) 9555 kJ (9058 Btu) 9405 kJ (8916 Btu)

Gross efficiency 37.7% 38.3%

Pressure ratio 20.2 to 1 20.8 to 1

Flow (per second) 132 kg (292.8 lb) 134.2 kg (295.8 lb)

Turbine speed 6608 rpm 6608 rpm

Exhaust temperature 541°C (1006°F) 552.8°C (1027°F)

Source: GTW 2013 Performance Specs

Design rating 47.5MW version 55.5MW version

Net CC plant output 66,570 kW 71,400 kW

Heat rate (LHV) 6693 kJ/kWh 6530 kJ/kWh

6344 Btu/kWh 6189 Btu/kWh

CC plant efficiency 53.8% 55.1%

Gas turbine power 46,300 kW 49,100 kW

Steam turbine power 21,000 kW 23,100 kW

Source: GTW 2013 Performance Specs

Simple cycle SGT-800 design ratings. Marl gas turbine is ISO rated at 47,500kW and 37.7% simple cycle efficiency with a 541°C exhaust tem-perature (1006°F) and 132 kg/sec flow (292.8 lb/sec).

SGT-800 gas turbine. The 47.5MW gas turbine for Marl has a cold-end drive, 15-stage axial flow compressor (with three stages of variable guide vanes), 3-stage turbine and DLE combustion system that limits NOX to less than 15 ppmv on natural gas fuel.

Combined cycle SGT-800 design ratings. Based on 1x1 plant configu-ration operating on natural gas fuel at 15°C (59°F) ambient and sea level site conditions.


The introductory rating was 43MW power output with a 37% electrical efficiency (ISO) in open cycle, and 64MW with 53% efficiency in com-bined cycle. The first unit was in-stalled in 1999. Since its introduction, the turbine

has been continually improved. Based on operating experience in the field, both its power rating and electrical ef-ficiency have been improved over the years. Notably, improvements have also been made to extend mainte-nance intervals – an area that is very

important for industrial gas turbines.

Turbine. The turbine has a three-stage design. First- and second-stage blades and vanes are cooled, third-stage blades and vanes are uncooled, all three turbine disks are cooled. Key design features: turbine stator has a cooling arrange-

ment that provides radial clearance control turbine section is designed as a mod-

ule to support high maintainability first- and second-stage blades are

not shrouded. Single crystal blades on the first stage have a film and con-vective cooling system; blades on the second stage have a convective cool-ing system third-stage blades are shrouded first-stage guide vanes have a film

and convective cooling system. Inner and outer platforms of the guide vane are coated with a thermal barrier coat-ing (TBC) and have an impingement cooling system second-stage guide vanes have a

convective cooling system. Inner and outer platforms of the guide vane are coated with TBC and have an im-pingement cooling system all blades and vanes are coated with

oxidation-resistant coatings to minimize the leakages on the third

stage, third-stage vanes are integrated into segments, each segment consist-ing of two vanes.

Compressor. Features a 15-stage axial compressor. electron-beam welded compressor

rotor (for low vibration; straightfor-ward torque transfer; good control of blade tip clearances while still allow-ing the possibility of replacing indi-vidual blades in-situ) stator rings above the rear-stage

blades are made from material with low heat-expansion coefficient and are coated with an abradable coating

-30 -20 -10 0 10 30 40 40 50

– 54

–

– 50

–

– 46

–

– 42

–

– 38

–

Power Generation. Nominal power output of 47.5MW SGT-800 genset at zero inlet and outlet duct losses and 6,600 rpm power turbine speed.

9,600 kJ

ISO rated point

Base load

10,000 kJ/kWh Heat rate

10,600 kJ

Output MW

Compressor intake air temperature (°C)

Unfired HRSG. Steam profile curves for 47.5MW SGT-800 base load operation at 15°C ambient and sea level site conditions.

kg/sec

Steam pressure (bar)

Saturated steam

10 20 30 40 50 60 70 80

– 26

– 24

– 22

– 20

– 18

300°C

200°C 250°C

350°C

400°C

450°C

500°C

March-Apirl 2013.indd 17 5/23/13 5:16 AM


to provide smooth rubbing and mini-mum radial clearance. Casings in the front stages are also coated with an abradable coating for the same rea-sons compressor casing has a vertical-

split plane to provide good access to the compressor components for in-spection variable guide vanes on 3 stages five compressor extractions, at stag-

es 3, 5, 8, 10 and 15.

Combustion system. The combustor has single-fuel and dual-fuel capabil-ity, It represents Siemens’ third gen-eration of Dry Low Emission (DLE) combustors with low emission levels in the range of 50 to 100% load: on natural gas fuel, gas turbine ex-

haust emissions are limited to 15 ppm NOx and 5 ppm CO, or less on diesel #2 fuel, limited to 42 ppm

NOx and 5 ppm CO, or less, without water or steam injection. Lean pre-mixAnnular combustion chamber design also means it requires less cooling air due to less hot-surface area and bet-ter flow inlet into the turbine; simple cross-ignition during start-up. (The low-emission combustor has a con-vective cooling system and is coated with a TBC.) The technology used is lean, pre-mixed fuel in a four-slotted cone burner. The combustion system has a simple design, with no moving parts and just two control valves for pilot gas and main gas. No staging is used for the combustion. There are 30 burners of a retract-able design, which allows easier com-bustor maintenance, To provide reli-able operation and to avoid damage to combustor components, the combus-tor is also equipped with a pulsation-monitoring system.

Plant maintenanceAs with any industrial facility, avail-

ability, reliability and ease of mainte-nance are critical at the Marl chemical facility. The latest SGT-800 engine and hot gas components modifications enable not only the enhancement of power output and efficiency, but also the ex-tension of components’ life and, as a result, extension of the time between overhauls. According to Siemens, the engine can now run for up to 60,000 equiva-lent operating hours (EOH) between major overhauls. Accumulated experience and anal-ysis of performed inspections, main-tenance and overhauls of the SGT-800 fleet also show that maintainability and, as a result, maintenance down-time could be further improved by means of maintenance tools develop-ment and modernization.

Onsite accessTo provide good access to compres-sor components during inspection and maintenance, the compressor casing

has been designed with a vertically split plane. Since the compressor casing is a part of the supporting structure, one of the two vertical halves of the com-pressor casing always has to remain assembled during compressor mainte-nance. As a result, the attachment of the rear inner stator requires the compres-sor casing to be disassembled and as-sembled repeatedly during the mainte-nance and repair of the compressor. To avoid this, a dummy compres-sor casing has been designed. During maintenance this replaces one of the halves of the compressor casing and enables work with the rear inner stator. This allows for a reduction of downtime during level C/D inspec-tion by approximately 1 day. More-over, the compressor-casing dummy reduces the risk of damage to blade and guide vanes. The new combined cycle unit at Marl is expected to enter commercial operation in 2015. n

SST-300 turboset. Single-casing backpressure steam turbine for 66.6MW Marl com-bined cycle plant is rated at 21MW. Package is designed around pre-engineered mod-ules including the turbine, gearbox, generator and auxiliaries installed on a base frame that incorporates the complete oil system.

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IGCC and Gasification

MississippiKemper IGCC power plant on track for 2014 startupContrary to news that the Kemper IGCC project has been terminated (see May-June IGCC News), Mississippi Power announced recently that Southern Company has reached several major construction milestones. Initial firing of the first gas turbine was completed Aug. 28 with plans for scheduled startup of the second gas turbine the following week. “Firing the gas turbines is an important milestone in both the construction and startup phases of the Kemper County energy facility,” said John Huggins, vice president of generation development. “Employees safely and successfully executed the first fire process and completed all necessary checks and tests to ensure the gas turbine’s capabilities,” continued Huggins, “further indication that we are one step closer to startup of the plant.” In the first week of August, the company completed first fire of the plant’s auxiliary steam boiler ahead of schedule. Also in early August, the final 230 kilovolt transmis-sion line was energized and is now capable of receiving electricity from the plant. Five new transmission lines and five new substations are being built to carry elec-tricity from the Kemper facility to Mississippi Power customers. The transmission con-struction phase of the Kemper project is scheduled to be completed by early 2014 when the final 115kV line is completed.

Mississippi Kemper plant cost may rise to over $4.5 billionSouthern Co figures that the cost to finish building the 582MW coal-gasification power plant may take at least $160 million and raise the cost of the completed plant to $4.5 billion, more than double initial estimates. In a monthly report to the PSC, Mississip-pi Power said it has spent $3.14 billion so far on the Kemper project. Projected $4.5 billion for the final cost includes a $250 million grant from the U.S. Dept of Energy. Apparently, the PSC put a cap on the Kemper project, saying the utility can recover no more than $2.88 billion from customers for the IGCC plant. The company can also re-cover costs for the lignite mine and a pipeline to move captured carbon dioxide emissions.

California Hydrogen Energy IGCC power and CCS project DOE announced the availability of the draft environmental impact statement for the 416MW Hydrogen Energy California’s inte-grated gasification combined cycle and car-bon capture and sequestration project in Kern County, Calif. for public review and comment. Total project cost is estimated to be over $4 billion. DOE proposes to provide limited financial assistance of approximately $275 million through the American Recovery and Reinvestment Act and $133 million through the Clean Coal Power Initiative program. The HECA project would demonstrate IGCC and carbon capture technology on a

commercial scale in a new power plant. The plant would consist of a single gasifier with gas cleanup, gas turbine, HRSG, steam tur-bine and associated facilities. The IGCC technology would turn a fuel blend consisting of 75% western sub-bitu-minous coal and 25% petroleum coke into a hydrogen-rich syngas to fuel the combined cycle plant and manufacture fertilizer. Captured CO2 would be transported via pipeline to a neighboring oil field for en-hanced oil recovery injection and sequestra-tion. At full capacity, the plant is expected to use about 4,600 short tons of coal and about 1,140 short tons of petcoke per day. HECA would design and construct the plant to capture approximately 90% of the CO2, equivalent to about 3.4 million tons per year. During the demo phase of the plant’s operation, the project would sequester about 2.6 million tons of CO2 per year in EOR op-erations.

Australia Experimental approach forassessing gasification coalsCommonwealth Scientific and Industrial Re-search Organization (CSIRO), Australia’s national science agency, has developed an experimental database and modeling toolkit for assessing the suitability of low value coals for gasification technologies. “Traditionally, coals have been selected for their tendency to not slag or foul boiler tubes in combustion power stations,” senior research scientist at CSIRO Dr Alexander Ilyushechkin said.

Recent study by CSIRO for the Austra-lian National Low Emissions Coal Research and Development agency showed slags pro-duced from gasification are apt for product manufacturing such as concrete production. Also that their environmental impact in terms of leaching of heavy metals is miniscule. Using its database of coal slag viscosity, CSIRO can analyse and assess coal in terms of its slagging behavior and assist coal pro-ducers in valuing their resources by matching them to different gasification technologies. It is based on measurements of slag vis-cosity behavior for hundreds of different coals and artificial ashes. It can be used to gauge the behavior of a particular fuel’s min-eral matter under conditions relevant to the leading gasification technologies. CSIRO can directly measure the viscosity of slags at temperatures up to 1600°C, giving an insight into how the slag will behave in a gasifier and pinpointing the cause of any problematic behaviour.

China SES Yima joint venture producing 180,000 tons per year of methanolSynthesis Energy Systems (SES) reports that its Yima Joint Venture project in Henan Province, China, recently ramped up metha-nol production to 60 percent of total design capacity of 300,000 tonnes per year and is now selling its methanol product to a local industrial company. Robert Rigdon, President and CEO of SES, stated that the Yima JV plant is achiev-ing important methanol production rate mile-stones as well as proving out the capabil-ity and flexibility of the SES gasification systems operating there, including the first gasifier system, which is now operating at 90 percent of capacity. “We expect the Yima Joint Venture to continue this positive operating trend and transition from its commissioning and startup phase into full commercial operation over the summer, with sales ramping up accordingly.” Mr. Rigdon continued, “Our accomplish-ments at Yima have occurred simultaneously with the strong progress we are making to complete the commercial agreements that will allow us to restart the ZZ Joint Venture unit later this year and produce methanol and generate sales there as well.”

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