fr 9f 3-series boost for 1600mw station open cycle gt plant with

March – April 2013 gasturbineworld.com

Fr 9F 3-series boost for 1600MW station page 15

Open cycle GT plant with CC performancepage 22

Recuperated semi-closed turbo cycle page 36

HitacHi Power SyStemS america, Ltd.645 Martinsville Road, Basking Ridge, NJ [email protected] Tel: 908-605-2800www.hitachipowersystems.us

HitacHi introduces new combustion turbine tecHnology

hitachi has developed several new models including a 100 MW

combustion turbine (Hitachi H-80), and several upgrades of the mature H-25 combustion

turbine technology, ranging from 32–42 MW. Hitachi’s combustion turbine lineup is ideal for

upgrading/replacing existing simple cycle and combined cycle combustion turbines. Nominal

combined cycle outputs of 140 MW or 285 MW are achievable with the H-80 combustion

turbine in 1x1 or 2x1 plant arrangements. Learn more from Hitachi Power Systems America.

HitacHi gas turbine Product line – 60 Hzitem unit H-15 H-25 H-80

Output MW 16.9 32 99.3

Efficiency %(LHV) 34.4 34.8 37.5

Heat Rate Btu/kWh 9,950 9,806 9,100

Exhaust Flow lb/h 420,000 767,000 2,262,000

Exhaust Temp ˚F 1,047 1,042 986

ISO Conditions (Sea Level, 59˚F, 60% RH), Natural Gas Firing

March – April 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. 2

On the Cover. One of the first M501GAC gas turbines produced in the USA by Mitsubishi’s Manufacturing and Service facility in Savannah

3 Project engineering and industry news O&M for 2,200MW 7FA station, 850MW GT26 order, Panda 760MW Flex 30 project, low cost LM6000 Sprint retrofit

15 Smelter 1,600 MW power plant upgrade Fr 9F 3-series combined cycle project will double production capacity of an aluminum smelter complex in Abu Dhabi

22 CC performance at simple cycle $/kW cost Low $/kW costs and fast full-load startup make Cheng cycle plants ideally suited for renewable energy backup

31 Zorya new 45 and 60MW design series GTE-45 GTE-60 gensets are expected to debut in 2015 for simple cycle, CHP and steam plant CC repowering

36 Proposed semi-closed recuperated cycle Offers CO2 capture readiness, 50% low-load efficiency, full power from idle in seconds, lower cost than GTCC

47 IGCC power and gasification technology Funding for 580MW Kemper project, Saudi tenders for 2400MW Jizan power plant, chemical looping test program

New 9F 3-series gas turbineAdvanced design features are being retrofitted to 9F-series gas turbines in service for 1% better efficiency and 1.5% more power, page 15

Cheng vs. combined cycle plants Simple cycle plants equipped for Cheng operation can be simpler, less costly and more flexible than com-bined cycles, page 22

Zorya’s nextgen gas turbineNew GTE-60 gas turbine for simple cycle generation and steam plant repowering is rated at 60MW and 37% efficiency, page 31

Editor-in-Chief Robert Farmer

Managing Editor Bruno deBiasi

European Editor Junior Isles

Engineering Editor Harry Jaeger

News Editor Margaret Cornett

Marketing Director James Janson

Publisher Victor deBiasi

Subscriptions Peggy Walker Facsimile (203) 254-3431 Email: [email protected]

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GAS TURBINE WORLD: March – April 2013 3

INDUSTRY NEWS

for turnkey supply and construction of the 758MW Temple II power project in Texas. This third order from Panda in less than a year follows the Temple I and Sherman power projects. All three plants are identical in size and when completed will be among the most efficient power plants in the U.S. The natural gas-fired multi-shaft combined cycle plant will be a Siemens Flex-Plant 30 consisting of two 208MW SGT6-5000F gas turbines, one SST6-5000 steam turbine, two SGen6-1000A generators, one SGen6-2000H generator, SPPA-T3000 instrumentation and control system. Without supplementary duct firing the SCC6-5000F 2x1 combined cycle reference plant is rated at 620MW net plant output and 57.2% net efficiency. Scope of equipment supply includes two Benson heavily duct-fired HRSGs manu-factured by NEM and a long-term service agreement for the main generation compo-nents. Bechtel will be responsible for BOP engi-neering and procurement as well as installa-tion, construction and commissioning. Temple II, located next to Temple I at the Synergy industrial park in Temple, Texas, is scheduled for completion by the end of 2015. Siemens claims all three gas-fired plants will be among the cleanest in the U.S. with emissions limited to less than 10 ppm CO and less than 2 ppm NOx. The gas turbines, steam turbine and gen-erators will be manufactured in the Siemens factory in Charlotte, North Carolina, which is the main production facility for the com-pany’s 60Hz power generation equipment.

USLM6000 retrofit for boosting hot and cold day performanceCR Energy Services and Caldwell Energy have collaborated on the development of an inlet ‘wet compression injection’ system that can be installed onsite as a replacement for LM6000 Sprint power augmentation. Mike Leon, Group President of CR En-ergy, says the system has been specifically designed for retrofitting LM6000 Sprint gas turbine installations. It will meet or exceed expected OEM power augmentation objec-tives at ambient temperatures ranging from 50°F to over 100°F, while reducing the risk of excessive blade erosion. Wet compression can be installed to com-pletely replace the current OEM compressor inter-stage cooling design with an equivalent performance guarantee, he claims, at a lower price than the component and repair cost of replacing the OEM nozzles. According to Leon, it also avoids the use of compressor

TurkeyIPP to build 600MW H-technology plantSiemens has won an order from independent power producer Cengiz Enerji Sanayi ve Ticaret for the supply of a single-shaft power island with H-Class technology for a nomi-nally rated 600MW combined cycle project in Samsun, Turkey. Siemens scope of supply includes a 375MW SGT5-8000H gas turbine, 195MW SST5-5000 steam turbine and SGen5-3000W generator, Benson triple pressure once-through HRSG, electrical system with SPPA-T3000 control, and combined cycle auxiliary systems. The single-shaft 50Hz SCC5-8000H com-bined cycle reference plant design is rated at 570MW base load output and 6000 kJ/kWh heat rate (60.0% efficiency) on natural gas fuel. It is designed for 250 starts per year and capable of producing full load output in as little as 30 minutes after six hours shutdown. Operationally, the plant is designed to re-act quickly to grid fluctuations and adapt its power output by more than 35MW within one minute to meet quickly changing power requirements. The IPP has also signed a long-term ser-vice contract with Siemens to ensure plant reliability and availability.

ThailandConsortium wins 850MW combined cycle contract Alstom, in consortium with Sumitomo Corp. of Japan, was awarded an EPC contract by Electricity Generating Authority of Thailand to build the site-rated 850MW North Bang-kok 2 power plant. Alstom scope of supply includes two GT26 gas turbines, generators, two triple pressure reheat HRSGs, two steam turbines and distribution control system for two 1x1 combined cycle power blocks. Contract is reportedly valued at around $300 million. Standard 50Hz KA26-1 combined cycle reference plant design is rated at 467MW net base load output at 15°C sea level ISO site conditions and 59.5% net efficiency (with losses) on natural gas fuel. Sumitomo scope of supply includes BOP equipment supply, such as the water treat-ment facility and substation system, and for overall civil works and installation. The North Bangkok 2 Power Plant is scheduled to start commercial operation in January 2016.

USTurnkey contract for 758MW combined cycle Panda Power Funds has awarded the con-sortium of Siemens and Bechtel an order

USO&M contract for 2,200MW IPP plantWood Group GTS has signed a four-year operations and mainte-nance contract with Entegra Power Group and Sundevil Power Hold-ings to operate the 2,200MW Gila River power station located on 1,100 acres near Phoenix, Arizona. The plant is one of the largest in-dependent power plants in the US. Gila River is comprised of four individual combined cycle plants powered by eight GE 7FA gas tur-bines (632MW with 58% thermal efficiency in combined cycle) with inlet air fogging, eight Alstom HRSGs with supple-mental duct-firing and four GE single case, single flow axial exhaust condensing steam turbines. Wood Group currently provides gas turbine upgrades, repairs and outage services to the facility and also recently secured a major maintenance inspection contract for two gas turbines and one steam generator at the site. The Gila River power station is equipped with Wood Group’s automated “Ecomax” gas turbine tuning technology currently installed on six of the eight gas turbines. Following installation of the initial six systems, power output at the station increased 1.5 - 2.0 percent, while heat rate decreased by up to 0.25 percent.

4 GAS TURBINE WORLD: March – April 2013

Industry News

bleed for water atomization. Results are im-proved gas turbine efficiency and consider-able future savings by eliminating repair and replacement cost of OEM spray nozzles. Benefits from CR Energy’s wet compres-sion can be especially effective in increasing output power on hot day operations. Tiny droplets are sprayed into the gas turbine inlet with enough volume to reduce compressor operating temperature. As a result, gas tur-bines can be driven to achieve higher pow-er output levels while not exceeding OEM compressor temperature limits. For now, CR Energy is targeting existing LM6000 Sprint owner operators. But the same wet compression upgrade also applies to non-Sprinted LM6000PC and LM6000PD gas turbines as well as GE LM2500, Rolls Royce RB211 and Pratt and Whitney FT8 gas turbines for power augmentation. At 90°F ambient temperature, base load power output of the LM6000PC gas turbine can be increased to 40,000kW from its cur-rent hot day rating of 30,000kW. Gas turbine efficiency increases by 3 percentage points to over 38% from 35%.

USRegulators reject proposal to build 300MW peaking plantIn a unanimous decision, the California PUC rejected SDG&E application to build the gas turbine powered Pio Pico Energy Center. Installed equipment and construction cost of the proposed 300MW gas-fired simple cycle peaking plant was estimated at close to $400 million or $1,300 per kW installed. Commissioners cited evidence that there was no need for the facility until at least 2018, four years after the plant would have come online. The commission did approve a 25-year contract extension and upgrade of the exist-ing Escondido Energy Center and directed SDG&E to procure up to 298MW of local electrical generation beginning in 2018.

USNY 1000MW Fr 7FA.05combined cycle stationState Public Service Commission granted a “Certificate of Public Convenience and Ne-cessity” to build a 1000MW natural gas-fired combined cycle Cricket Valley power station in Dover, New York. Station will be powered by three 1x1 GE Fr 7FA.05 combined cycle modules, each consisting of a 216.1MW 7FA.05 gas turbine plant, HRSG with supplemental duct firing, and 112MW steam turbine generator. Cost of project development and con-struction is estimated at close to $1 billion.

Each combined cycle power block is rated at 323MW net plant output and 58.2% effi-ciency on natural gas fuel. HRSGs will include selective catalytic reduction to control NOx emissions and an oxidation catalyst to control CO emissions. Water requirements will be minimized by use of air-cooled condensers. Project approval includes onsite construc-tion of two 700-ft long overhead 345kV lines which will help interconnect the facility with an existing Consolidated Edison trans-mission line. Construction work on the project is ex-pected to begin in 2014.

Malaysia8000H EPC services and 20-yr service agreementTenaga Nasional Bhd (TNB) has awarded Siemens, Samsung Engineering and Con-struction and TNB’s repair and maintenance arm Remaco a series of installation and ser-vice contracts for a 1,100MW development project in Seberang Prai, Penang. Siemens scope includes the supply of two 375MW SGT5-8000H gas turbines and a 20-year service agreement for the power island. The 2x1 SCC5-8000H combined cycle ref-erence plant is rated at 1,140MW net output and 60.0% net efficiency (5692 Btu/kWh heat rate). Samsung scope of supply includes en-gineering, procurement and construction (EPC) services. The 20-year operation and maintenance contract is being handled by Remaco. Commercial date of operation for full com-bined cycle service is scheduled for March 1, 2016.

USPreliminary approval grantedfor gas-fired power plantSupervisors in North Beaver Township, Pennsylvania approved a conditional use permit for LS Power of St. Louis to build a $750 million gas-fired combined cycle power plant. The 900MW Hickory Run Energy Sta-tion will replace some of the coal-powered generation plants that are going to be coming off-line in the next few years. The location of the new plant proved ap-pealing because of what is believed to be trillions of cubic feet of gas in the Utica and Marcellus Shale plays. The project remains in its early stages of development, and the company is moving through the process of securing appropriate land-use, zoning and environmental permits. The company hopes to break ground some-

time in 2014, and it would take another two years to construct the complex. Once the plant is operating, it would sell power to the regional grid operator PJM Interconnection which manages Ohio, Penn-sylvania and other parts of the Midwest.

Bangladesh225MW combined cycle power projectThe National Economic Council has ap-proved the construction of a dual fuel 225MW combined cycle power plant to be located near the existing Shikalbaha power plant in Chittangong. The project is being developed to ensure uninterrupted and reliable power supply to Chittagong region. Four development partners in the Middle-East will provide funds for the project: Saudi Arabia , Kuwait , UAE and OPEC fund. The Council also approved the construc-tion of a 31km transmission line and two substations to establish grid interconnection between Bangladesh and India.

Thailand110MW cogen priced at around $130 million Japan-based Electric Power Development (J-Power) reports that its 110MW gas-fired combined cycle cogeneration power plant in Thailand began commercial operation on April 1st as scheduled. The project was developed by a subsidiary Gulf NNK that will sell 90MW of electric power to the Electricity Generating Author-ity of Thailand (EGAT) under a 25-yr pow-er purchase agreement. Remaining electric power and chilled water will be sold directly to industrial customers. Industry observers estimate total develop-ment cost of the 110MW cogen facility at around £85 million ($130 million) or almost $1200 per kW. Natural gas for the combined cycle gas turbine plant is being supplied by the Petroleum Authority of Thailand under a 25-yr gas supply agreement. It is believed that the combined cycle plant is designed around two LM6000PF gas turbines rated at 42,260kW each, unfired HRSG and one 28,590kW steam turbine. General Electric’s 2x1 LM6000F com-bined cycle reference plant is rated at 110,970kW net base load output and 53.6% net plant efficiency on natural gas fuel.

USPUB buying into 800MW shale gas combined cycle Public Utilities Board in Texas has signed a development-and-purchase agreement to buy


Industry News

an ownership interest in a proposed 800MW 2x1 combined cycle generating station Te-naska plans to build in Brownsville, Texas. Under terms of the agreement, the PUB is to supply water and a gas interconnection to the plant. It will be entitled to receive 200MW of the plant’s generated electricity. Tenaska said the building site was chosen for its proximity to Eagle Ford shale gas sup-plies, ongoing transmission system improve-ments in the Rio Grande Valley, and growing demand for power in the region. Construction is contingent on contracting for the remaining capacity as well as secur-ing permits. Work could begin as early as 2014, with completion as early as 2016.

Indonesia6B 3-series simple cycle plant for Batam IslandMedco Power Indonesia estimates total cost of developing a site rated 70MW simple cycle generating station on Batam Island at close to $65 million. To be powered by two GE Fr 6B 3 series plants. The Fr 6B sets are each ISO rated at 43,000kW base load and 33.0% efficiency on natural gas fuel. Equipment supply order for the two gas turbine power plants, which were shipped by GE the end of 2012, is val-ued at $28 million, or around $325 per kW (equipment only at ISO rating). Medco signed a power purchase agreement with a subsidiary of the state electricity com-pany, PLN Batam in October of last year and is currently negotiating a 20 billion Btu/day natural gas fuel supply. The power station is scheduled to start commercial service in 2014. However, the operational schedule will depend on gas availability which is still being discussed with government agencies. The new gas-fired station will boost Med-co Power’s power generation capacity for Batam Island by 20 percent, while enabling a switch from fuel oil to cleaner gas fuel.

ThailandBang Bo GT26 combined cycle power plant upgrade Eastern Power and Electric Co. (EPEC) has signed a 10-year operations and maintenance contract with Alstom for its Bang Bo com-bined cycle plant in Samut Prakan Province, Thailand. Alstom built the site-rated 350MW Bang Bo combined cycle plant in 2000. This con-tract is an extension of an earlier 12-year service contract which expired at the end of March 2013. At that time, the simple cycle GT26 was ISO rated at 262MW gross output and 38.2%

efficiency with a 1238 lb/sec exhaust flow at 630°C. Today’s machine is ISO rated at 326MW gross output and 40.3% efficiency with a 1526 lb/sec exhaust flow at 603C. Alstom will station permanent employees onsite to operate the power plant and carry out all planned and unplanned maintenance including an upgrade of the existing GT26 gas turbine with MXL2 turbine blades and components. Bang Bo reportedly will be the first GT26 power plant in Thailand to receive this up-grade due to be installed in 2014.

USSGT6-2000E simple cycle peaking plantOklahoma’s Municipal Power Authority has awarded Siemens Energy an equipment or-der for the supply of an SGT6-2000E gas turbine for a peaking plant to be built at the Charles D. Lamb Energy Center. MPA says construction is scheduled to be-gin January 2014 with an estimated comple-tion date of April 2015. The natural gas-fired 2000E plant is rated at 112,000kW gross base load output and 34.7% simple cycle efficiency at 59°F sea level ISO conditions.

USOvation control system retrofit for Fr 6B plantEmerson Process Management has replaced Mark VI controls on the Nikiski Generation Plant’s Fr 6B gas turbine with its Ovation control technology. The plant owned and operated by Homer Electric Association is located southwest of Anchorage, Alaska. The controls replacement project was part of a two-phase initiative to convert the 40MW simple cycle power plant to a 60MW combined cycle facility. The resulting 45% increase in generation capacity will enable Homer to cost-effec-tively meet the electricity needs of the Kenai Peninsula. An additional 20MW capacity is available through the use of duct-firing capability built into the existing HRSG. This brings the total plant capacity to 80MW, but requires addi-tional fuel consumption. Emerson is further expanding the plant’s Ovation system, providing direct control and monitoring of the upgraded HRSG, burner management system, feed water and water treatment systems, substation equipment and balance-of-plant processes. The system will also provide supervisory control of the new steam turbine. In addition to replacing the Mark VI tur-

bine controls, Emerson integrated the gen-erator excitation system into the new Ova-tion system, thereby enabling it to remotely control its functionality. Emerson also provided a simulator that is used to test and verify control logic as well as train operators and a remote dispatch ca-pability that will provide greater operational flexibility and efficiency.

Uzbekistan$40 million pipeline order for three RB211 compressor setsAsia Trans Gas has awarded Rolls-Royce a contract to supply three RB211 gas turbine driven pipeline compressor units and related services valued at US$40 million for a com-pressor station on the Turkmenistan-China natural gas pipeline. These are RB211-G62s driving RFBB5 pipeline compressors. The mechanical drive RB211 GT62 gas turbine is ISO rated at 41,500 shp continuous with a heat rate of 6,600 Btu/hp-hr (38.6% efficiency) on natu-ral gas fuel. To be installed on the 530 km Uzbekistan section of the 1,830 km pipeline being built to transport 25 billion cubic meters per year of gas from Turkmenistan through Uzbeki-stan and Kazakhstan to China. Rolls-Royce says it will manufacture and package the equipment at its energy facili-ties in Montreal, Quebec and Mount Vernon, Ohio.

GlobalToshiba and GE sign MOU to develop 50/60-Hz Flex CCGTs GE and Toshiba Corp. recently signed a memorandum of understanding to form a global strategic alliance to jointly develop targeted 50Hz and 60Hz combined cycle power generation projects around the world. In addition, the two companies will ex-plore forming a strategic joint venture for the development of next-generation higher-efficiency combined cycle power projects. GE and Toshiba won a contract in 2012 to supply GE’s new FlexEfficiency com-bined cycle plants to Chubu Electric Pow-er’s 2,200MW Nishi Nagoya thermal power plant in Japan. Reportedly the Flex combined cycle plant design is being jointly configured to achieve the world’s highest thermal efficiency of 62% (at site conditions). Currently GE’s largest 1x1 50-Hz 9F 7-se-ries combined cycle has a net plant output rating of 512MW and 61.0% net efficiency (5,594 Btu/kWh heat rate). The largest Flex plant for 60-Hz operation is the 1x1 7F 5-series plant rated at 323MW

The 36 MWe SGT-750 is the latest gas turbine in the Siemens range. It is a design benchmark, incorporating the best of proven solutions from the Siemens fleet in order to meet customer demands for maximized uptime, reliability, and availability, whether in power generation

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Industry News

and 58.2% efficiency (5,863 Btu/kWh heat rate) net plant performance.

ChinaPetroChina order for anothersix RB211 compressor setsRolls-Royce recently announced a contract to supply PetroChina with an additional six 42MW RB211-driven pipeline compressor units and related services. They will help power the flow of natural gas through Line 3 of the West-East Pipeline Project (WEPP), the world’s longest pipe-line. The contract brings the total number of RB211 units sold for installation on China and Central Asia’s natural gas pipeline net-work to 56. When completed in 2015, the 7,000km WEPP Line 3 will link China’s western Xin-jiang autonomous region to Fujian province in the south-east, transporting up to 30 bil-lion cubic meters of gas per year.

NigeriaTo spend $1 billion on GTproduction and servicesNigerian Federal Government and General

Electric sealed a $1billion investment agree-ment on the establishment of a new manu-facturing and assembly facility in Calabar. New facility is being built to support GE’s power generation, oil and gas production and exploration activities in the region. The contract also provides funding to cov-er additional investment in the service work-shops in Port Harcourt and Onne. The deal, which comprises $250 million capital expenditure and over $800 million incremental spending on local sourcing of goods and services, is expected to create 2,300 jobs and make Nigeria the regional hub for GE’s manufacturing service opera-tions in Africa. Nigeria is seeking to meet a power demand that is more than double the country’s cur-rent output of around 4,000MW.

USMicroturbines for oil and gas explorationCapstone Turbine Corp. has a follow-on or-der for 30 C65 (65kw) microturbines for use in the Eagle Ford Shale Play. This latest order brings their total C65 fleet to approxi-

mately 150 microturbines. The Eagle Ford Shale is a hydrocarbon- producing formation rich in oil and natural gas fields. The oil reserves are estimated at 3 billion barrels with potential output of 420,000 barrels a day. In a separate contract, Capstone announced another follow-on order for five C1000 pow-er packages totaling 5MW that will also be installed in the Eagle Ford Shale play in Texas. This order increases this particular oil and gas producer’s total Capstone fleet to 10MW in the Eagle Ford play. The microturbines will be located at mul-tiple central gathering plants to generate electricity for all of the onsite equipment in-cluding heaters, pump motors, compressors and distribution panels.

CanadaMobile 25MW TM2500+ genset for use in hydraulic fracturing Evolution Well Services is deploying GE’s trailer-mounted 25MW TM2500+ mobile genset to demonstrate lower emissions and operational efficiency advantages over con-ventional diesel engines for hydraulic frac-turing in unconventional gas fields. The company recently signed a three-year rental contract to lease the TM2500+ unit for onsite power generation —first at a demon-stration project near Calgary and then to sup-port commercial operations in Alberta and British Columbia. The company provides mobile, modular, electric-powered high-pressure pumping sys-tems for use in hydraulic fracturing. USClean power plant withCO2 capture technologyUS-based Summit Power Group and The Linde Group have teamed to develop power plant technology that would capture about 90% of CO2 for injection into depleting oil fields. They propose to develop a gas-fired pow-er project that can produce about 250MW of electric power as well as capture about 750,000t of CO2 annually. Summit is currently developing two major coal gasification projects: the Texas Clean Energy Project in the US and the Captain Clean Energy Project (CCEP) in UK, both of which will capture 90% of the CO2 pro-duced. Linde will be the technology, engineering and construction contractor, as well as long-term operations and maintenance provider for the Texas project.

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Industry News

AustraliaMicroturbine power for coal seam gas exploration Capstone Turbine announced another fol-low-on order from a large Australian coal seam gas company for 36 x C30 (30kW) units increasing the total number of units sold to date to 234. These orders are part of a periodical sup-ply contract for the life of the project re-ceived from Capstone’s Australian distribu-tor, Aquatec-Maxcon. The microturbines are supplied as inte-grated packaged systems for use in remote coal seam gas exploration and production wells in the Australian Queensland outback. Coal seam gas is forming the basis of a major new liquefied natural gas export in-dustry in Australia that is expected to create many thousands of jobs.

US Contract to upgrade pump storage plant Los Angeles Dept. of Water and Power awarded Wood Group an $11.2 million contract to upgrade its Hitachi hydro tur-bine generator at the Castaic Power Plant, a pumped storage facility 50 miles north of Los Angeles. Overall work scope includes replacing dis-charge and wear rings, extensive stay vane modification, refurbishing the turbine shut-off valve and replacing the generator stator. This contract will complete the upgrade of the sixth and final hydro turbine genera-tor undertaken as part of the Castaic Power Plant modernization program. Wood Group has helped modify three sim-ilar turbines, increasing generating output by 21MW per unit, and boosting total plant capacity to approximately 1,260MW. The modernization project also delivered increased unit efficiencies of approximately 2.7 percentage points in pump mode and 1.2 percentage points in generation mode. Work on the final turbine package com-menced in late 2012 and is due for comple-tion at the end of August 2013.

Russia Fr 5 and Fr 7 service contract at LNG plantGE Oil & Gas has received a 16-year ser-vice contract extension for Sakhalin-2, one of the world’s largest integrated oil and gas projects. The contract covers four 88MW GE Fr 7EA gas turbines that drive the process trains for Sakhalin’s liquefied natural gas plant and five 30MW GE Fr 5 gas turbines

that are used for electricity production at the site. The agreement includes planned and un-planned outages, parts and repairs, an avail-ability guarantee, remote monitoring and diagnostics and an onsite GE team of techni-cians. GE also announced the signing of a mem-orandum of understanding with the Sakhalin provincial government to work together in developing power generation projects. The MOU covers a wide range of tech-nology options to meet the future energy needs of Sakhalin Island, including gas tur-bines, coal gasification and wind power. France LM2500+G4 to power Multi-purpose frigateGE Marine recently del ivered one LM2500+G4 marine gas turbine that will power the French Navy’s eighth FREMM frigate Lorraine. The frigate is designed to operate in anti-air, anti-submarine and anti-ship warfare, and be capable of carrying out deep strikes against land targets. The Italian-French FREMM program marks the first application in the marine sector of GE’s 35MW LM2500+G4 gas turbine, which has 17% more power than its LM2500+ predecessor. Eighteen of these gas turbines will provide propulsion for the current FREMM pro-gram, which includes six ships for the Ital-ian Navy, eleven ships for the French Navy, and one ship for the Royal Moroccan Navy. The LM2500+G4 marine gas turbine is rated at 47,370 hp continuous with an SFC of 0.352 lb/hp-hr (equivalent to 39.5% ef-ficiency) on liquid fuel.

US LM2500 syngas plants rated at 50 to 100MW Synthesis Energy Systems and GE Packaged Power have agreed to jointly evaluate and market a small scale power generation unit combining SES gasification technology with General Electric’s LM 2500 gas turbines. The two companies say they will focus on regions of the world where conversion of non-conventional feedstock sources such as lignite and coal wastes into synthesis gas fuel may have an advantage over conven-tional gas turbine fuel sources such as natu-ral gas and fuel oil. Over the past 12 months, SES and GE say that they have completed a preliminary eval-uation on the application of their combined technologies. They will now seek initial cus-

tomers on a non-exclusive basis worldwide. According to GE, its fuel-flexible LM2500+G4 aeroderivative gas turbine de-sign is ideally suited for small scale syngas-fired power plants rated at 50 to 100MW capacity. GE’s latest PGT25+G4 genset is ISO rated at 33MW base load output with a heat rate of 8530 Btu/kWh (40.0% efficiency) on natural gas fuel. Increased mass flow of low-Btu syngas fuels should boost gas tur-bine unit output by 10-20 percent. SES gasification technology is designed for small-scale gasification of solid fuels in-cluding inexpensive ultra-low quality coals, coal wastes and refuse-derived fuels into a synthesis gas.

InternationalCO2 heat recovery power generation GE Marine has signed an agreement with Echogen Power Systems to be the exclusive provider of Echogen’s heat-to-power system for use on commercial and military marine vessels worldwide. Echogen’s system captures the exhaust heat energy typically vented to atmosphere by gas turbines and diesel engines and con-verts that heat into electrical or mechanical power. Converting energy that traditionally gets exhausted out of a stack into useful power allows the overall system efficiency to in-crease by up to 30%. Use of supercritical CO2 as the working fluid allows for a more compact, lighter and economical heat recovery configuration than traditional steam systems. The heated CO2 can be expanded to create cooling or combi-nations of power and cooling. Echogen says it expects to begin testing a 7,000kW CO2 system early this year. Plans also call for developing a 2,000kW unit and 400kW unit both of which are to be avail-able in 2016.

USMHI completes acquisition of Pratt &Whitney Power Systems Mitsubishi Heavy Industries announced that is has completed its acquisition of Pratt & Whitney Power Systems. The acquired com-pany will now be known as PW Power Sys-tems. The acquisition will enable MHI to reach a broader range of customers through PW Power Systems small to medium sized pow-er generation packages and complement the company’s focus on large capacity systems. MHI’s president Shunichi Miyanaga ex-

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pects that “the synergistic effect of combin-ing the talent and resources of MHI and PW Power Systems will lead to the significant growth of ‘Energy & Environmental’, one of MHI’s four core corporate sectors.” “This will significantly extend MHI’s equipment offerings and dramatically ex-pand its service capabilities,” says Peter Christman, president of PW Power Systems which will be headquartered in Glastonbury, Connecticut. What should be of significant interest to the industry and end user community is that PWPS will continue to benefit from the cut-ting edge technology that Pratt & Whitney (aircraft engines) offers in the area of ad-vanced gas turbine engine design and devel-opment as well as the company’s manufactur-ing, engineering and supply chain expertise.

UKMT30 electric power for British aircraft carrier’s ship servicesRolls-Royce reports that first of two MT30 gas turbines has been installed at Babcock’s shipyard in Scotland for the Royal Navy’s new aircraft carrier HMS Queen Elizabeth. Two carriers are scheduled to enter service in 2016 and 2018 respectively. Twin MT30 generators drives will provide two thirds of the 109MW needed to power each of the 65,000 ton ships. The marine MT30 is rated at 53,640 hp continuous (40MW) and 40.1% shaft effi-ciency (0.344 lb/hp-hr heat rate) on 18,400 Btu liquid fuel, including 4-inch and 6-inch installation losses. Integrated as part of a gas turbine alterna-tor, the power generated by the MT30s will meet the carriers’ demand for energy such as propulsion motors, weapons and navigation systems, as well as the entire low-voltage requirements for lighting and power sockets. The MT30 currently powers the US Navy’s Freedom Class variant of the Littoral Com-bat Ship, will power their new DDG-1000 destroyers and was recently selected for the Republic of Korea Navy’s new FFXII frigate.

Canada Indirectly heated GT cyclewith supercritical CO2 flowDept. of Mechanical and Aerospace Engi-neering at Carleton University in Canada reports it has received a $1.44 million gov-ernment grant for a research project that will create a pilot-scale gas turbine facility to develop new technology. The funding is part of ongoing research and development efforts to reduce the capital and operating costs, and increase the energy efficiency, of cleaner coal and carbon cap-

ture and storage systems. The objective of the project is to con-struct a pilot-scale facility based on a closed, indirectly-heated gas turbine cycle using su-percritical carbon dioxide as the fluid circu-lating through the machinery. This is one of the options being developed as a key high-efficiency component for next generation cleaner coal systems. Activities will involve nearly all aspects of gas turbine design, including thermody-namic performance analyses, aerodynamic and structural design, heat exchanger and materials selection, dynamic modelling, and control systems design. Most of this work will be carried out by teams of undergraduate and graduate stu-dents in mechanical and aerospace engineer-ing, as part of their fourth year capstone design projects or their thesis research. The overall project is managed by Prof. Henry Saari, with students being supervised by fac-ulty members from the department.

Russia Gas turbine logs record 80 thousand hoursA 4MW Perm Engine Company GTU-4P gas turbine operating at OJSC Surgutneftegas as part of the power station at Kontilorskoye field has run for almost 81,000 hours and is ready for overhaul. During its operation time, the gas turbine plant has been overhauled twice, each time after 26-27,000 hours. The operating time of another GTU-4P gas turbine plant located at the same field has almost reached 80,000 hours and is still in operation. According to Perm Engine Company, these are the record results among Russian produced gas turbine plants.

Russia Upgrade of 800MW CHP combined cycleEmerson Process Management has upgraded the 800MW combined cycle Unit 3 during a four-month shutdown at the Surgut-2 power station that is owned and operated by E.ON Russia. The upgrade consisted of Emerson’s Plant-Web digital automation architecture with the Ovation control system which will enhance the manageability of station equipment, tighten control across all operating ranges, and improve the unit’s dynamic behavior. Scope of upgrade included Unit 3 plant’s control system, instrumentation, control valves, and other related equipment. Emerson also modernized controls for the fluid end of the turbine set, reconstructed and equipped the control room, provided en-

gineering and installation services, certified compliance with regulatory dispatch require-ments and assisted with unit startup. The Surgut-2 power plant supplies power and heat to Western Siberia and the Ural region, produces more than 35 billion kWh per year.

US6MW CHP plant for Army ammo plantBAE Systems awarded Lauren Engineering a design and construction contract to build a combined heat and power facility for the Holston Army Ammunition Plant in King-sport, Tennessee. Scope of supply includes a gas turbine genset, waste heat recovery boiler and aux-iliary systems plus all engineering and con-struction services necessary for installation of the new facility. The CHP project will generate up to 6MW of electricity, which will meet at least 90% of the Holston plant’s electricity requirements, and 70,000 lb/hr of process steam. Lauren expects to start construction during the second quarter of 2013.

Japan M501J verification testing and utility marketing debutThe first M501J gas turbine installed at Mit-subishi’s T-Point verification plant has ex-ceeded 10,000 fired hours of operation and more than 100 starts. Trouble-free and rigorous validation pro-cess has been supported by a successful mar-keting introduction resulting in sales of 16 additional units. MHI reports that several of these M501J gas turbines are currently undergoing opera-tional tests or being installed for subsequent commissioning over the next few months. For simple cycle generation the 60-Hz M501J is rated at 327MW gross output and 8325 Btu/kWh heat rate (41.0% efficiency) at 59°F sea level ISO conditions. Conservatively designed combined cycle 1x1 module (with 1.5 inch Hg condenser pressure) is rated at 470MW net plant output and 61.5% efficiency.

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In addition to a new phase 2 com-bined cycle plant, the Emirates

Aluminum Co. (EMAL) smelter com-plex is upgrading the Fr 9FA gas tur-bines that power the 2,100MW phase 1 plant which went into service the 1Q of 2010. Under contracts valued at around $500 million, General Electric will supply gas and steam turbines, gener-ators and a plant-wide control system for the Phase 2 expansion. Project contract scope:

o Phase 2 plant. Powered by two 2x1 9F 3-series combined cycle blocks each rated at 786.9MW net plant output and 57.1% efficiency.

o Emissions. New DLN2.6+ com-bustors will reduce plant emissions to 9 ppm NOx from about 30-35 ppm at base load output.

o Upgrade. Retrofitting new tech-nology will improve Fr 9FA heat rate by 1.0% and increase power output by about 1.5%.

EMAL, a leading supplier of alumi-num in the United Arab Emirates, is in the process of doubling its smelt-ing production capacity to more than 1.5 million tons per year. As a highly electricity-intensive process, the com-pany operates its own power plants to provide electricity for the smelting process. Currently, electricity for the smelt-er’s two potlines is supplied by a power plant defined as phase 1. The

original configuration for phase 1 was four 9FA gas turbines operating in combined cycle with two steam tur-bines, plus two simple cycle 9FA gas turbines on standby. Long term plans to add another potline to the smelter called for a new phase 2 combined cycle plant de-signed around three new 9F 3-series gas turbines, two new steam turbines, and one upgraded 9FA gas turbine no longer needed for phase 1 standby service.

Turbine reliabilityAccording to General Electric, the choice of turbine for the new plant was driven by the machine’s track re-cord in the region. Mohammed Azeez, GE’s Gen-eral Manager for Power Generation Services for Middle East and Africa, said: “When you look at the history of these units, we have about 45 million operating hours worldwide and they are proven in the harsh environments of the Middle East. “Also, it was a no-brainer for phase 2. With the synergies between the two phases, it didn’t make sense to invest in a different turbine. The possibility to share parts and main-tenance practices etc., offers a lower cost to the customer.” The 9F family of gas turbines has been used for 50Hz power generation applications for more than 20 years. It began in 1991 with the introduc-tion of the 9F gas turbine, which had a simple cycle output of 212MW at about 35.0% efficiency. This was

soon followed by the 9FA gas turbine version .01 which provided an ad-ditional 14.5 MW and slightly higher efficiency. The 9FA continued its evolution with the 9FA.02 version followed by the 9F 3-series design with better per-formance, operational flexibility, and availability. New proprietary systems include an enhanced compressor, dry low NOx (DLN) 2.6+ combustion system, enhanced hot gas path cool-ing, and blade health monitoring. In simple cycle operation, the Fr 9F 3-series gas turbine is ISO rated at 261.3 MW gross base load and 9649 kJ/kWh heat rate (37.2% efficiency) without duct losses, operating at 15°C sea level site conditions on natural gas fuel.

Phase 2 combined cycle The new plant will consist of two 2x1 combined cycle blocks each pow-ered by two gas turbine generators equipped with dual fuel DLN 2.6+ combustors to operate on natural gas as primary fuel or liquid distillate for backup. Exhaust gas from the two gas tur-bines will be fed through a common header into a single unfired, two-pres-sure level forced circulation HRSG design to power a single double-flow, reheat type steam turbine-generator. Phase 2 will be brought online in two stages. The gas turbines will first enter simple cycle operation dur-ing the third quarter of this year. The steam turbines will then be brought into operation in the first quarter of

1,600MW expansion project to double aluminum production By Junior Isles

EMAL is building a 1,600MW Fr 9F 3-series combined cycle plant addition that will help double production capacity of an aluminum smelter complex in Abu Dhabi.


2014, at which time the plant will be-gin full commercial combined cycle operation. GE is working with Samsung Heavy Engineering on construction of the new phase 2 plant, with Samsung in the role of EPC contractor. Good progress is being made; project engi-neers report that the gas turbines are already onsite and plant construction teams are installing them.

Phase 1 upgradesIn parallel to the construction of phase 2, a number of upgrades will be carried out on phase 1 which will enable one of the two gas turbines on standby to be allocated to phase 2. Located in an environmentally pro-tected area, emissions are of para-mount importance at the EMAL com-plex. One of the main upgrades on the phase 1 power plant is the replace-ment of each existing gas turbine combustion system with the advanced DLN2.6+ combustion system.

Combustion system: The combustor is the latest step in GE’s combustion system design evolution. The DLN 2.6+ combustion system has the same configuration as its DLN 2.6 prede-cessor: five outer fuel nozzles with a single center fuel nozzle. The center fuel nozzle ensures stable combus-tion across a wide range of operating conditions. The new design has an advanced center fuel nozzle called a swozzle that was introduced by the DLN 2+ and DLN 2.5H combustion system designs. The swozzle combines the fuel injection gas ports into swirl-er vanes (all within the fuel nozzle body) to provide a better mixed, more stable combustion zone. By utilizing a patented asymmetric fuel strategy, the DLN 2.6+ combus-tion system is able to maintain low emissions levels while extending the load range available for operation. Application of advanced materials, coatings and cooling technology has also enabled the combustion interval

to be extended beyond the standard 8,000 hours of operation. According to Azeez, the new com-bustion system brings several benefits and capabilities to gas turbine per-formance, basically in three areas of performance: • First is dynamics, which is re-lated to the noise of the machine and vibration. This has a direct impact on maintenance and life cycle of the components. • Second is turndown, for operation at low part-load instead of shutting down completely (for units that need to go in and out of service regularly). “Every time you turn a turbine on and off, it takes a hit. This will reduce the maintenance intervals,” explains Azeez. • Third area is emissions which typically increase as load decreases.

The new advanced dual fuel com-bustor addresses all three of these is-sues, Azeez notes. “It improves dy-namics in a manner that increases maintenance intervals to three years from 8,000 hours (roughly one year). Each maintenance shutdown can take 7-14 days – this is worth a lot of mon-ey in aluminum production. “With regards to emissions, by tuning the combustion system on a

real-time basis we can control NOx to levels that comply with local regula-tions.” GE says that emissions will be reduced to 9 ppm NOx from about 30-35 ppm NOx when running on natural gas. Although turndown capability is not important to EMAL’s operations, Azeez says the new combustor pro-vides a 5% improvement, allowing the turbine to run at about 35% of baseload while staying within speci-fied NOx limits.

Cooling optimization: The existing gas turbines are also being refitted with what GE calls a cooling optimi-zation package. The package reduces air leakage in the machine, allow-ing more cooling air to be distributed through the turbine for improved ef-ficiency and output. As explained by Azeez, gas tur-bines start up at relatively cold ambi-ent temperature and rapidly accelerate to reach working temperatures of more than 1200°C. “In designing a turbine, you must provide ample clearances to allow for thermal expansion. “But excessive clearances lead to leakage losses so you want to main-tain tight clearances throughout the thermal operating regime. The cool-ing optimization package in effect

Scope of expansion and upgrade project

Phase 1 plant. Built around two S209FA 2x1 combined cycle modules rated at 797.4MW gross output each and a simple cycle plant powered by two 255.6MW Fr 9FA standby gensets for a total installed capacity of 2,106MW.

Phase 1 upgrade. All six 9FA gas turbines powering the phase 1 plant are being upgraded to Fr 9F 3-series performance. One of the two standby gas turbine generators will be reassigned to help power the new phase 2 com-bined cycle plant.

Phase 2 plant. Designed around two 2x1 Fr 9F 3-series combined cycles gross rated at 808.4MW each for a total installed capacity of 1,616.8MW.

Phases 1 and 2. When fully operational, possibly by June 2014, the phase 1 and 2 plants should each contain two 2x1 nominally rated 800MW com-bined cycles (1,600MW per plant) and the phase 1 plant will have only one 260MW genset on standby.


provides a variable clearance control for high temperature operation.” To better manage clearances, the cooling optimization package imple-ments two technologies that work to-gether to reduce clearances on the first stage bucket: 1) abradable first stage shrouds and 2) case temperature management. An abradable coating applied to the surface of the shroud allows first-stage bucket tips to rub against the areas of tightest clearance without being damaged. In addition, the pat-ented surface texture of the coating is designed to reduce leakage flow where clearance gaps remain. Case temperature management technology allows active management of clearance on the first stage buck-et tips. During gas turbine startup, the buckets increase in length due to thermal expansion much faster than the gas turbine casing. Thus, design clearances between the rotating buck-et and stationary shroud must be large enough to accommodate this clear-ance pinch-point during the start se-quence.

Clearance controlAs the gas turbine case heats up and expands, the bucket tip clearances open up. Ambient air is used to cool the turbine case in the region of the first stage bucket to thermally shrink the case diameter and thereby close down clearances. This system is only activated once the gas turbine reaches a thermally steady state. To reduce the amount of compres-

sor bleed air used to cool hot gas path components, two more technologies are employed: 1) third-stage nozzle purge reduction and 2) compressor extraction air ejector mixing. In order to operate at extremely high firing temperatures, gas tur-bines such as the 9F 3-series require advanced air cooling technology to maintain the hot gas path components below required material property lim-its. Both internal air cooling and ex-ternal film cooling are used to limit hot gas path component metal tem-peratures. To cool second- and third-stage nozzles, air is extracted from the 13th and 9th compressor stages, respec-tively. To conserve energy, however, the compressor bleed air for cooling is mixed in an ejector to use less 13th stage and more 9th stage air. Since

less work is expended to compress 9th stage air, the trade-off improves overall efficiency of the gas turbine cycle. The extraction control system manages how much 13th stage air is mixed in the ejector, based on load and ambient conditions to maintain needed pressure ratios and ensure ad-equate cooling of the second stage nozzle. As part of this system, the overall cooling air needed for the third stage nozzle can also be re-duced, leading to further gains in cy-cle efficiency. This cooling optimization package can be retrofitted to all 9F-series gas turbines and has already been suc-cessfully implemented in several in-stallations worldwide. According to GE, the package improves heat rate by about 1.0% and power output by

ISO Gross LHV Heat Pressure Exhaust Exhaust Gas Turbine Model Base Load Rate/kWh Efficiency Ratio Flow/sec Temp

Fr 9FA series 255,600 kW 9759 kJ 36.9% 17.0 to 1 641 kg 602°C 2007 intro 9250 Btu 1413 lb 1116°F

Fr 9F 3-series 261,284 kW 9649 kJ 37.2% 16.7 to 1 665 kg 598°C 2013 intro 9146 Btu 1466 lb 1108°F

Simple cycle 9FA series design evolution. Phase 1 Fr 9FA gas turbines are being retrofitted with advanced 9F 3-series technology including DLN 2.6+ combustor upgrades to lower emissions plus compressor enhancements and cooling opti-mization packages to improve power output and efficiency.

Source: GTW Handbook, 2007 and 2013 Editions

General Electric 9F 3-design. Gas turbine is ISO rated at 261.3MW gross base load and 37.2% simple cycle efficiency. Advanced DLN combustor will limit emissions to 9 ppm NOx when operating on natural gas fuel.

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about 1.5%. This translates into 2.5 to 3.5 MW more power per gas turbine.

Compressor upgrade: In a move to improve reliability and availability of its gas turbine fleet, GE has been working to improve the design of its inlet guide vanes. The front-end section of the blades is being changed, as well as the front- and back-end sections of the station-ary vanes. Some aspects of the dis-charge casing have also been modi-fied to maximize airflow through the compressor and improve reliability. In addition, an OpFlex tuning sys-tem will be installed to mitigate the effects of combustion dynamics and minimize emissions and combustion hardware stress levels. Basically, the system optimizes gas turbine perfor-mance in response to fuel and envi-ronmental conditions. A number of smaller but signif-icant improvements are also being made. All upgrades at the EMAL plant are expected to be completed by the end of March 2014.

Project executionExecuting such an extensive upgrade calls for careful planning. “Planning has to be done way ahead of time,”

said Azeez. “In some cases, we plan for a year. We need to line up the supply chain to make sure we get all the parts in the country, on time, inspected and ready to go. “We also need to ensure we have the right amount of technical engi-neers and crew members [at site].” Crew members are sourced from Granite, a wholly owned GE subsid-iary with a strong presence in the re-gion. Safety on such a project is a very important issue. One of the first things to focus on is getting the cranes in place and ensuring scaf-folding and tools etc., are certified by safety engineers. Staff is also as-signed responsibility for quality is-sues. All of the teams come together several times during the planning phase to anticipate scenarios and plan reactions to potential problems dur-ing upgrade work. Although much of the work is carried out in parallel, the first job is to remove the combustion system before removing the compres-sors.

Service contractEMAL has awarded General Electric

a 12-year contractual service agree-ment that replaces the existing con-tract for phase 1 plant gas turbines. The new contract scope includes long-term maintenance support for seven of the Fr 9 gas turbines at both the phase 1 and phase 2 plants. It cov-ers all aspects of gas turbine mainte-nance such as scheduled hot gas path and major inspections, as well as un-planned events “If there’s a forced outage for ex-ample, we mobilize people, obtain the parts and get started immediately,” says Azeez. “We also provide site support and all the engineering sup-port that goes with this kind of main-tenance.” He points out that while a service agreement allows customers to pre-dict maintenance costs and cash flows etc., it also benefits GE. “It allows us to have a steady forecast of main-tenance activities in the region and therefore plan investment.” Azeez sees EMAL as a “very smart customer” looking at how it can grow and regards this project as a “great example” for the region. “They show how to be flexible in changing times and with changing technologies, to come up with a winning solution for all stakeholders.” n

9F 3-series Net Plant Net Heat Net Plant Condenser Gross GT CC plants Output Rate/kWh Efficiency Pressure GT Power ST Output ST Power

one-on-one 397,104 kW 6295 kJ 57.2% 1.2 inch Hg 259,800 kW 142,419 kW 402.2 MW 5966 Btu

two-on-one 798,702 kW 6260 kJ 57.5% 1.2 inch Hg 519,539 kW 288,805 kW 808.4 MW 6295 Btu

9FA CC plants

S109FA 390,800 kW 6350 kJ 56.7% 1.2 inch Hg 254,100 kW 141,800 kW 395.9 MW one-on-one 6020 Btu

S209FA 786,900 kW 6308 kJ 57.1% 1.2 inch Hg 508,200 kW 289,200 kW 797.4 MW two-on-one 5980 Btu

Comparative Fr 9F combined cycle design ratings. Net plant performance with all losses, including auxiliary parasitic power consumption, on natural gas fuel at 15°C sea level site conditions. Based on reference plant designs with unfired HRSGs and without SCR to limit emissions.

Source: GTW Handbooks, 2007 and 2013 Editions

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Knowledge = Power


Cheng Power Systems is telling utilities that simple cycle gas

turbine plants equipped for Cheng Cycle operation are able to produce more electricity at lower cost than any combined cycle plant designed around the same model gas turbine(s). Both cycles are based on recover-ing and utilizing waste energy in the gas turbine exhaust to improve per-formance. The Cheng Cycle differs in that the energy is recycled directly and more effectively through the gas turbine instead of through a separate steam turbine generator. In effect, the steam turbine and associated equipment are eliminated. Comparable plant site requirements, conversion costs and performance:

o Plant site. Combined cycles re-quire three times the land and twice the water of Cheng Cycle plants which typically operate on less than half the water combined cycles lose to air cooling tower evaporation.

o Conversion. Cost of retrofitting a simple cycle LM6000PC gas turbine plant for Cheng Cycle is estimated at around $15 million, less than half the $33 million estimate for combined cycle conversion.

o Output. Cheng Cycle has the po-tential to increase simple cycle gas turbine output by up to 70% and low-er the heat rate by 40%, depending on gas turbine’s OEM design parameters.

Major project cost factors for the util-ity industry are centered on capital

costs, fuel prices, emissions, operat-ing and maintenance costs. To mini-mize those costs, the gas turbine in-dustry has regularly invested large sums on improving efficiency and unit power output to reduce fuel con-sumption and lower $/kW. Currently, with the discovery of shale gas, the $8/MMBtu (LHV) price of long-term natural gas fuel supply contracts in the US has dropped to somewhere below $3.5/MMBtu, with spot market prices dip-ping to below $2.50, so that the price of fuel has diminished in importance. Top priority for both utilities and gas turbine OEMs has switched to faster response times, to support vari-ability in intermittent wind and solar power generation, and higher part-load efficiencies.

Flexible GT designs This has given rise to a new breed of

“flexible” gas turbines such as Gener-al Electric OpFlex and Siemens Flex Plant series which are designed for rapid start grid back-up, low turn-down idling capability, cyclic opera-tion, high ramp rates (up and down), and good part-load efficiencies. General Electric’s new flexible Fr 7FA-05 will introduce a new family of compressor designs with dramati-cally improved surge margin and op-erating stability, capable of higher 17.8 to 1 pressure ratios and 1145 lb/sec mass flow. Earlier E-class gas turbines like the 7111EA needed 17 stages of compres-sion to achieve a 13 to 1 pressure ra-tio. By contrast, the new FA-05 class could operate at a 20 to 1 pressure ratio. In simple cycle mode, the 7FA-05 is ISO rated at 215.8MW base load and 8830 Btu/kWh LHV heat rate (38.6% efficiency). If modified for

Combined cycle heat rates at simple cycle $/kW plant costs By Victor deBiasi

Fast full-load startup features make Cheng Cycle plants ideally suited for renewable energy backup to support solar and wind plants.

Plant efficiency. Cheng Cycle operation is optimized to operate at peak plant efficiencies as determined by gas turbine compressor pressure ratio (CPR) and turbine inlet firing temperature parameters.

Efficiency CPR 40

CPR 30 CPR 20

CPR 10

Turbine Inlet Temperature

60%

55

50

45

40

35

1500°F 2000°F 2500°F 3000°F 3500°F

Source: Cheng Power Systems, March 2013


Single 3-on-1 Single 2-on-1 Cheng CyclePlant configuration 7111EA CC plant 7FA-05 CC plant Fr 7FA-05 plantNumber of gas turbines 3 GTs 2 GTs 2 GTsNumber of boilers 3 HRSGs 2 HRSGs 2 HRSGsNumber of steam turbines 1 ST 1 ST 0 Plant design rating Nominal net plant output 363 MW 645 MW 720 MW Net plant heat rate (HHV) 8,230 Btu/kWh 6,414 Btu/kWh 7,353 Btu/kWh Net plant efficiency (HHV) 41.5% 53.2% 46.4% Capital cost estimate Installed cost ($/kW) $950 per kW $1,000 per kW $700 per kWTotal plant cost $344,850,000 $645,000,000 $504,000,000 O&M cost estimate ($/yr) 40% capacity factor (2,468 hrs) $20,882,000 $25,845,000 $21,267,00060% utilization (3,702 hrs) $22,413,000 $28,469,000 $24,736,00080% utilization (4,936 hrs) $25,142,000 $33,220,000 $28,760,000 Operating heat rate (HHV) 40% capacity factor 9461 Btu/kWh 6895 Btu/kWh 7835 Btu/kWh 60% capacity factor 9737 6991 789280% capacity factor 9461 6895 7835 Fuel consumption (Btu/yr) 40% capacity factor (2,468 hrs) 8,475,959 MM Btu 10,975,875 MM Btu 13,922,482 MM Btu60% utilization (3,702 hrs) 13,084,834 16,693,040 21,035,65280% utilization (4,936 hrs) 16,951,917 21,951,749 27,844,963 Power production (MWh/yr) 40% capacity factor (2,468 hrs) 895,884 MWh 1,591,860 MWh 1,776,960 MWh60% utilization (3,702 hrs) 1,343,826 2,387,790 2,665,44080% utilization (4,936 hrs) 1,791,768 3,183,720 3,553,920 Cost of electricity * 40% capacity factor (2,468 hrs) 9.6 cents/kWh 7.2 cents/kWh 6.3 cents/kWh60% utilization (3,702 hrs) 7.9 5.9 5.480% utilization (4,936 hrs) 6.9 5.2 4.9* Estimate, COE will vary for specific projects depending on actual plant, utilization, fuel and financing costs. Source: Cheng Power Systems, March 2013.

Cheng comparative combined cycle owning and operating cost studyStudy is based on conceptual 3-on-1 Fr 7111EA and 2-on-1 Fr 7FA-05 combined cycle plant designs vs. two simple cycle Fr 7FA-05 gas turbines equipped for Cheng Cycle operation (without steam turbine cycle) operating a 5-day week, daily cycling and weekend shutdowns. Levelized cost of electricity is based on $4 per MMBtu fuel and 25-year utility financing format.


Cheng Cycle operation, basically the same engine could be upgraded to 360.7MW base load (65% boost in power) and 6685 Btu/kWh heat rate LHV which is equivalent to 51.1% ef-ficiency.

Comparative cost study Cheng Power Systems recently com-pleted a study on annual owning and operating costs of contemporary 7E and more advanced FA-05 gas turbine combined cycle plants vs. two simple cycle FA-05 gas turbines equipped for Cheng Cycle operation. Fuel consumption and mainte-nance costs are calculated for base load output at 40%, 60% and 80% ca-pacity factors which take into account the impact of start-stop cycles on heat rate (fuel consumption) and mainte-nance costs. In this context, the term “capac-ity factor” is intended to represent the percentage of time a plant is utilized during the year at full load output. Duty cycle is based on 5 days per week of operation with daily start-stop cycling between weekend shut-downs. The Cheng study parameters are modeled on those for an EPRI-funded Sargent & Lundy study in 1989 on annual owning and operating costs for a contemporary 3-on-1 Fr 7EA combined cycle, new (at that time) advanced 2-on-1 Fr 7FA combined cycle plant and a steam injected LM5000 simple cycle gas turbine. The new study is based on year 2012 design ratings for a 3-on-1 Fr 7111EA and advanced 2-on-1 Fr 7FA-05 combined cycle plants vs. poten-tial plant powered by two simple cy-cle Fr 7FA-05 gas turbines modified and equipped for Cheng Cycle.

Cost factors Manpower costs to operate and main-tain each of the plants are calculated on the basis of current average sal-ary levels. The percentage of the total ownership cost set aside for main-tenance follows the same format as

used for the earlier EPRI Report. Fuel cost is based on a project-ed $4/MM Btu price of natural gas (HHV) delivered under a long term supply contract. Base load heat rates used for calculating fuel consump-tion are adjusted for the differences in duty cycle at 40, 60 and 80% capacity factors. Frequent start-stop cycling will increase fuel consumption because of inefficiency during plant start-up

before reaching full load output and during the time required to gradually reduce load during shut-down. Plants operating at 40% capacity factor operating less than 9-10 hours a day will have fewer start-stop cycles than plants at 60% in service 14-15 hours of the day. Similarly, plants at 80% factor operating up to 19 hours a day will have fewer start-stop cycles (similar to 40% operation). Multiplier factors based on in-

CHP steam and power tradeoff. This is a performance map for 501KH San Jose State’s Cheng plant. Trajectory line defines all the peak efficiency condi-tions of gas turbine compressor pressure and firing temperature operation.

Efficiency

1700°F 1800°F

1600°F

1500°F

w/o steam

0.45 kg/s steam

0.9 kg/s

1.4 kg/s

1.8 kg/s

2.3 kg/sTrajectory of peak efficiency

Simple Cycle GT

40%

38

36

34

32

30

28

26


Horsepower

4000hp 5000hp 6000hp 7000hp

Fr 7FA-05 Fishnet. Cheng Cycle operating map for advanced 7FA-05 gas tur-bine shows power increase to 360.7MW from 215.8MW (for a 12% steam-to-air ratio) and efficiency going to 51.1% from 38.5%.

Btu/kWh

3% steam

1700°F 1900°F

2100°F 2300°F

6% steam

9% steam

12% steam

Power output (MW)

9500

9000

8500

8000

7500

7000


110MW 160 210 260 310 360

Trajectory of peak efficiency

Simple Cycle GT


dustry experience in the operation of combined cycle plants in intermittent and base load services are used to ad-just full output heat rates to reflect the impact of cycling on fuel consump-tion. For the 3-on-1 Fr7EA plant, the multiplier is 1.15 times the OEM plant design heat rate for 40% ca-pacity factor (fewer startups); 1.18 multiplier for 60% capacity factor op-eration (more frequent starts and shut-downs); and 1.15 multiplier for 80% capacity factor levels (fewer startups). Adjusted heat rates for the single 2-on-1 7FA-05 CC plant is based on half the regular combined cycle mul-tipliers. For the Cheng Cycle plant, the multiplier is 1.0395 for the 40% and 80% capacity factors – and 1.073 for 60% capacity operation. Based on a projected long term natural gas fuel price of $4 per MM Btu, and estimated 30 percent low-er $/kW plant cost, the Cheng Cycle plant shows the lowest cost of elec-tricity and, therefore, a better return on investment than building a com-bined cycle plant.

Cheng Cycle features The Cheng Cycle is basically a “feed-back” heat recovery cycle, with ef-ficiency maximized by ever changing steam-to-air ratios highly tuned to gas turbine operating parameters. On average, two-thirds of the pow-er generated by the turbine compo-nent of a simple cycle gas turbine feeds back to the compressor to sup-ply its power needs; only about one-third of the turbine power is available for generating electricity. Similarly, with a steam Rankine cycle, approximately two-thirds of the heat input into the boiler is used to evaporate water into vapor. Overall, only about 40 percent of the fuel en-ergy ends up as electrical power, with the balance going up the stack and lost to evaporation of cooling water used to condense the steam. In the Cheng Cycle, steam gener-ated by waste heat recovery of en-

ergy in the hot gas turbine exhaust is injected into the combustion cham-ber of the gas turbine. The injected steam is heated by additional fuel, reaches the working temperature of the gas turbine and mixes with the air as additional working fluid expanded through the turbine section. Since the steam does not flow through the compressor, it will pro-duce 3 times more power for genera-tion, In addition, each pound of steam expanded through the turbine section produces net work equivalent to two pounds of air. Therefore, each pound of steam will produce 6 times the mass flow of the air in power output. Moreover, there is an additional operational dividend in that the add-ed mass flow through the turbine in-creases the amount of exhaust flow from which heat can be recovered to produce steam. There are two choices open to Cheng Cycle plants for maximizing heat recovery effectiveness: 1) in-crease steam production, which re-quires more fuel and produces more power, or 2) increase steam tempera-ture, closely as possible to the ex-haust temperature, which minimizes the fuel required to heat the steam to working fluid temperature. This tradeoff creates the peak ef-ficiency trajectory of plant operation

as a function of a steam-to-air ratio based on cycle parameters (see chart). Since heat recovery depends on gas turbine pressure ratio and firing tem-perature, the steam-to-air ratio is highly tuned in sync with operational changes in pressure ratio and firing temperature. This constantly changing steam ratio is what distinguishes the Cheng Cycle from other arbitrary steam in-jected systems known as STIG.

Control logicThe Cheng Cycle achieves high part-load efficiency throughout its operat-ing domain by following an opera-tional trajectory based on transient peak efficiency conditions of pressure ratio and firing temperature to opti-mize performance. In part-load condition, for exam-ple, the logic control system picks up the peak efficiency point based on the engine’s characteristics of pressure ratio, firing temperature, and onset of power demand for fuel and steam-to-air ratio control. Each firing temperature has a unique efficiency vs. steam-to-air ra-tio plot which peaks at a certain value of steam injection. Those peak effi-ciency points are then linked to set up an operating trajectory throughout the full range of engine operation.

Tuned steam injection. Steam-to-air ratio is always changing during operation to maintain peak efficiency in tune with gas turbine firing temperature (TIT) and compressor pressure.

Efficiency

1500°F TIT

2000°F TIT

2500°F TIT

3000°F TIT

Steam-to-air ratio

Compressor pressure ratio = 20

55%

50

45

40

35

10% 15 10 25 30



The steam injection performance map for a 501KH gas turbine Cheng Cycle plant built in 1984 at the San Jose State University shows a plot of that peak efficiency operating line (see CHP tradeoff chart).

CHP tradeoffs The intersection of gas turbine firing temperature curves with steam injec-tion rate curves defines plant power output and efficiency under different operating conditions. At 1800°F base load firing temper-ature, the Rolls-Royce simple 501 gas turbine without Cheng steam injec-tion is nominally rated at around 4500 hp and 29% efficiency.

At max 2.3 kg/s (5 lb/s) steam injection, output is boosted to over 7,000 hp and around 40% plant ef-ficiency. The “peak efficiency trajec-tory” curve at the top of the map links all the peak efficiency conditions of pressure and firing temperature in the plant operating domain. The mesh of curves, trapped be-tween the simple cycle gas turbine operating line at the bottom (without steam injection) and peak efficiency trajectory line of Cheng operation at the top (with max steam injection) map out the tradeoffs between power and heat for CHP plant operation.

Fast response to load change

Heat recovery steam generators for Cheng Cycle plants have larger than usual steam drums designed to op-erate under variable pressure condi-tions. The heat recovery boiler for the San Jose plant, for example, has a 40% enlarged drum volume. Whenever the gas turbine engine is throttled back, the thermal inertia and excess surface area of the heat recov-ery boiler makes the drum pressure go up. This raises the boiling tem-perature which sets the limit of steam production. In effect, this represents an energy storage feature unique to Cheng Cycle boilers. During routine power generation at less than maximum steam injection,

Simple Cycle GT LHV Heat SC Plant Cheng LHV Heat ChengOEM Model Power Rate/kWh Efficiency Power Rate/kWh Efficiency

R-R 501-KB5 3.9 MW 11,747 Btu 29.0% 6.4 MW 8509 Btu 40.1%

LM2500PH 19.1 MW 9667 Btu 35.3% 27.5 MW 7613 Btu 44.8%

LM6000PC 43.4 MW 8516 Btu 40.1% 62.4 MW 6916 Btu 49.3%

W501D5 120.5 MW 9840 Btu 34.7% 188.6 MW 7310 Btu 46.7%

GE 7FA-05 215.8 MW 8830 Btu 38.6% 360.0 MW 6684 Btu 51.1%

Some gas turbines respond better than othersSimple cycle gas turbines from 4MW to over 200MW unit output can be equipped for Cheng Cycle operation with var-ing degrees of economic success determined in large part by original gas turbine pressure ratio, firing temperature and compressor design parameters.

Comparatively simple. Cheng Cycle eliminates the steam turbine and all associated equipment (except for HRSG and auxiliaries) including generator, condenser and cooling tower which makes it simpler, more compact and less expensive than a combined cycle plant.

Combined cycle

Cheng cycle

Generator Generator

Gas Turbine Gas Turbine

SCR SCR

CC Controls 2nd Generator

Deaerator

Deaerator

Water Tank

Water Tank

Condenser

Cooling Tower

Steam Turbine

BoilerBoiler



the plant may be called upon at any time to immediately ramp up to full output. When that happens, the extra steam injection needed is available in the drum to rapidly increase gas tur-bine output and deliver more power. That is taken care of by the unique Cheng HRSG and drum design. Stored higher pressure steam will pro-vide the additional supply of steam required without having to wait for the boiler to respond. This makes Cheng Cycle response time as rapid as that of the simple cycle gas turbine on its own to reach higher output.

Fast start-up Unlike combined cycle requirements for gradual steam turbine warm-up, which limit the gas turbine in order to avoid boiler upsets, the Cheng Cycle can start and ramp up to full load as quickly as a simple cycle gas turbines on cold startup. A steam injection valve is actuated to open on startup so that gas turbine compressor air flow is directed to flow backwards through the gas tur-bine steam injection port in order to pressurize the drum, thus preventing boiler upset. At the same time, the maximum turbine exhaust gas flow ducted into the HRSG at maximum temperature heats the boiler water which rapidly evaporates into steam without restric-tion. Once the water reaches boiling temperature, any air in the boiler drum (and rest of the piping system) is purged by the steam being injected into the gas turbine. This unique startup process has been used for the past 28 years on the Cheng Cycle without incident. It has never caused a boiler upset or drum corrosion problem, say plant engi-neers, because oxygen is driven off water at 250°F operating temperature. For cycling and faster start-up to full plant output, the HRSG boiler can be kept bottled up under pressure and

Dr. Dah Yu Cheng comments on steam injection

Typical steam injected gas turbine (STIG) designs are based on introducing steam into a gas turbine downstream of the combustion system at a prede-termined pressure, temperature and flow rate without regard to changes in gas turbine operating parameters.

In contrast, Cheng Cycle steam injection is constantly regulated during gas turbine operation to stay in tune with transient changes in gas turbine performance parameters such as pressure ratio, compressor flow and fir-ing temperature.

A digital control system is programmed to capture peak efficiency steam in-jection operation at all times from full to part-load output, to optimize Cheng Cycle performance under a full range of gas turbine operating conditions.

The Cheng Cycle requires a conceptual change in HRSG design and op-eration that according to Dr. Dah Yu Cheng is foreign for the most part to the industry and completely different from constant pressure HRSGs used for STIG applications.

Attempts to improve STIG performance by using once-through boiler de-signs fail to understand that his cycle is based on thermodynamic feedback akin to electronic feedback, he says.

Fast response to load change requires a drum type HRSG design to pro-vide an energy storage system. Otherwise, he explains, the system will experience a delayed response in heating and cooling due to the thermal inertia of the HRSG mass.

Cheng Cycle is truly a cycle in the classical thermodynamic sense, Dr. Cheng stresses, whereas the STIG design application of mass steam in-jection is not a cycle. Many engineers do not really understand the thermo-dynamic differences between the two.

As a result, he says, STIG plants with comparable levels of steam injection cannot rival Cheng plant output or efficiency. “They simply cost more and perform less”.

Simple layout. First commercial Cheng Cycle plant built in 1984 at San Jose State has typical in-line layout of gas turbine and HRSG, without the clutter of steam turbine bottoming cycle plant equipment otherwise needed for combined cycle operation.

Generator

Stack

HRSGGas

Turbine Steam Injection

Piping


temperature to remain warm during shutdown. Basically this requires a flapper plate in the exhaust stack to prevent cold air convection through the boiler.

Rapid shutdown Without a steam turbine, the engine can be shut down as quickly as a simple cycle. Immediately after shut-down is a good time to purge the sys-tem instead of waiting for the next startup, says Dr. Cheng, especially for fast response to renewable energy deficit loads. Cold intake air used for purging will be warmed in passing through the still hot gas turbine with mini-mal cooling impact when exhausted through the HRSG boiler. This will shave at least 2 minutes off the usual purge time needed on startup. When the Cheng Cycle was pat-ented in 1984, its efficiency reached a 39.3% level which was better than any small or medium gas turbine combined cycles at that time. Today, Cheng Cycle can be ret-rofitted to many gas turbine engine designs, ranging from 3MW to over 200MW in unit output, with various degrees of economic success. An LM2500 Cheng Cycle plant built on Kauai Island in 2002 is still in commercial service operat-ing at 44.3% efficiency. And the first LM2500 STIG plant made its market-ing debut in 1987 rated at only 37.4% steam injected efficiency. Today’s LM6000PC Sprint gas tur-bine design with compressor water spray inter-cooling is ISO rated at 48MW base load output and 40.7% efficiency. Retrofitted for Cheng op-eration, output can be increased to 57.8MW and 50% thermal efficiency – while maintaining high part-load efficiencies over a range of 40% to 100% full load operation.

EmissionsAs mentioned above, the first com-mercial Cheng Cycle plant was built in 1984 at San Jose State Universi-

ty packaged as a 501KH gas turbine CHP facility to supply heat and power to the university. One of the more notable environ-mental features of the plant was that combustor steam injection enabled the plant to operate at record low NOx emission levels of around 22 ppm. Today, say Cheng engineers, they can go to 5ppm NOx without SCR. Dr. Dah Yu Cheng notes that the 25 ppm NOx regulatory limit in the US is based on that early Cheng Cycle performance. However, with envi-ronmental limitations on NOx and

CO emissions increasingly stringent and demanding, steam injection on its own is no longer sufficient. Dr. Cheng and his research team have been working for several years on engineering development of ultra-low emission control system designs which premix fuel and high tempera-ture steam in a homogenous fashion prior to combustion in order to con-trol flame formation and emissions. Recently, they demonstrated a breakthrough with a system that si-multaneously limits the combustion production of CO as well as NOx emissions. This important develop-

Startup response. Gas turbine heat recovery steam injection during start-up enables Cheng Cycle plants to ramp up more quickly than simple cycle gas tur-bines from a cold start -- and even faster with the HRSG design option of a warm storage steam drum.

Cheng Output

Starting Time (Minutes)

100%

80

60

40

20

0

0 5 10 15 20 25


Start of Cheng steam injection

Simple Cycle gas turbine start

Cheng warm start

purge

Cheng cold start

Backup for renewable energy. A fleet of 10 relatively low-cost 60MW LM6000 Cheng plants can be individually dispatched to more efficiently match unpredict-able deficits in wind/solar energy than a single higher priced 600MW combined cycle plant in part-load operation.

Btu/kWh

Backup power (MW)

LM6000 Cheng plants (10)

9000

8000

7000

0 100 200 300 400 500 600



ment is contrary to the typical obser-vation where reducing NOx usually triggers an increase in CO emissions.

CLN combustion system Last year, Detroit Edison replaced DLE-combustion systems on a fleet of five 501-KB7s in cogeneration ser-vice with Cheng Low NOx combus-tion systems. Test results show that the con-version increased unit power output almost 20% to 6MW from 5.2MW and lowered the firing temperature to 1870°F from 1935°F. Company proj-ect engineers say that the 65°F lower firing temperature will significantly extend hot parts life. The main capability currently be-ing achieved is the unexpected effec-tiveness of the CLN control system to virtually eliminate CO emissions. With NOx emissions limited to 18 ppm, CO levels were reduced to an unprecedented level of zero at 1.65 to 1 steam-to-fuel injection ratio.

Hot section lifeThere is a totally unfounded but widely held belief that Cheng steam injection shortens the life of hot sec-tion parts by causing them to over-heat. It may be surprising, says Dr. Cheng, but steam injection actually contributes to more effective cooling of first-stage nozzles and blades by mixing with the compressor bleed air used for cooling. The higher heat transfer rate of the steam (relative to the air) enhances heat exchange of the mixed steam and air flow to do an even better job of internal cooling, as confirmed by Cheng plants in service. For instance, hot section overhaul intervals for the Rolls-Royce 501 KH installation have increased to 42,000 hours from 12,000 hours initially rec-ommended. TBO intervals for an LM2500 PH burning liquid fuel have been in-creased to 40,000 hours from 12,500 hours.

Similarly, a retrofitted Fr 6B Cheng plant burning natural gas has more than tripled its originally sched-uled hot section TBO maintenance intervals.

Cost of water Availability and cost of water depends on site location. The most expensive water in the U.S. is on Southern Cali-fornia, near the Pacific coast. In Torrance or Santa Monica, for instance, the local water district sup-plies industrial water to replace well water usage to avoid lowering the aquifer water level. This is done to guard against sea water intruding and contaminating the aquifer supply. The price of industrial water varies with location. Priced at $748 per acre-ft., for example, the cost of water for a Cheng plant would be around 0.219 cents per kWh or $2.19 per MWh. This is based on a steam rate of 8 lb/hr per kWh, which is negligible com-pared to the cost of fuel. Water and land usageTypically, Cheng heat recovery boiler pressure is much lower than required for combined cycle steam turbine op-eration requires. Plant water usage is also less than half the evaporation rate of a compa-rably sized rated combined cycle’s wet cooling tower for the condenser. In addition to river water, Cheng plants can use treated gray water, well water or sea water for HRSG conver-sion to steam. The water requires conventional treatment and reverse osmosis steps (depending on incoming water qual-ity) that meet boiler feed water and gas turbine injection purity stan-dards. In general, combined cycle plants require at least three times more land area for bottoming cycle equipment, including the cooling tower, as well as the steam turbine generator build-ing and condenser. The Cheng HRSG does not have a superheater or reheat-er, which also saves space.

Plant operationThe Cheng Cycle digital program-mable logical control system typically requires only one operator to start and shut down the plant. Combined cycles typically require two and sometimes three operators. The controls can be set to automat-ically operate at different load condi-tions, depending on the prevailing market price of electricity or on the variability of intermittent solar and wind power generation for renewable energy back-up. Over the last 10 years of operation, the Cheng plant on Kauai has aver-aged only one unplanned outage per year. This is attributed, in large part, to its relative simplicity compared to combined cycle installations.

Retrofit costsConverting an LM6000PC gas tur-bine installation to combined cycle can cost anywhere from $33 million to $40 million, depending on options such as SCR or supplementary HRSG burner. Project engineers estimate that ret-rofitting the same LM6000PC simple cycle installation for Cheng Cycle, with a comparable increase in plant output, should not cost more than $15 million. They say that the same relative cost of “less than 50%” holds for retrofitting most other simple cycle gas turbines such as GE Fr 7EA and Westinghouse 501D5 models. “It makes Cheng Cycle the least costly method for increasing the ca-pacity of gas turbine peaking units and lowering CO2 footprints below the California target goal of an 80% reduction in power plant emissions,” says Dr. Cheng. n

Contact the EditorsE-mail [email protected] to comment on this article, ask Cheng Pow-er Systems to address your questions, elaborate on any statements or provide more information. We will do our best to reply promptly.

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Filling in the gas turbine product lineup in the 45 to 65MW class,

Ukraine’s Zorya-Mashproekt is intro-ducing two new single-shaft variants for 50Hz electric power generation. Intended for simple cycle, com-bined heat and power and combined cycle electric plants, application rat-ings include:

o GTE-45 genset. Rated 45MW and 34.4% simple cycle efficiency with 137 kg/sec and 550°C exhaust flow at base load ISO conditions.

o GTE-60 genset. Rated 60MW and 37.0% simple cycle efficiency with 173 kg/sec and 520°C exhaust flow at base load ISO conditions.

o GTCC plants. Nominally rated 66.1MW and 50.8% net efficiency for a GTE-45 1x1 plant and 132.2MW and 50.8% for the 2x1 design.

The UGT 45000/60000 gas turbines are based on scaled-down versions of the large GTD-110 (UGT 110,000 gas turbine) designed by Z-M that is currently being built, marketed and installed by NPO Saturn in Russia. The new gas turbine driven gen-erator sets, known as GTE-45 and GTE-60 respectively, are packaged for simple cycle power generation with reduction gearing and 50Hz gen-erator. Both plants are being bid for po-tential power generation and indus-

trial users in People’s Republic of China, Republic of Korea, Russian Federation, Western Europe and the Middle East among others, according to Z-M marketing executives. In particular, they note, “several potential customers from France and Poland have expressed their interest in this new (engine) development of Zorya-Mashproekt.”

ArchitectureBoth machines share a nearly identi-cal design, operating with different pressure ratios and mass flows to ac-count for their different power output

and efficiency ratings. The single-shaft engine uses a15-stage axial compressor with variable inlet guide vanes (IGVs), followed by three rows of variable vanes. Blow-off valves located at stages 6, 9 and 15 (last stage at the compres-sor outlet) are used to control surge. Large diameter piping carries the compressor blow-off into the exhaust plenum. The lower-rated UGT 45000 com-pressor operates at 14.1 to 1 pres-sure ratio with the rotor shaft speed at 3960 rpm at full load, while the higher output model 60000 has an

Zorya launching 45 and 60 MWgensets for world 50Hz markets By Robert Farmer

New single-shaft UGT 45000 and 60000 frame machines feature high performance for grassroots and repowering projects – set for series production in year 2015.

Test engine. Skid-mounted 60MW gas turbine is being tested at Kaborga facility to confirm predicted design performance and operating characteristics under startup, part-load, max load, shutdown and cycling conditions on natural gas and distillate fuels, with generator output going to the national grid.

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18.0:1 pressure ratio and runs at 4320 rpm. Both compressors are similar in design. Power takeoff is out the front (compressor) end into a reduction gearbox which reduces gas turbine shaft speeds down to 3000 rpm for driving 50Hz generators.

Gearbox features Zorya-Mashproekt is a major design-er and builder of both conventional and epicycle gearboxes, supplying many units to the Russian Navy for surface ship and hovercraft propul-sion services. For these new GTE units, Z-M designs, builds and supplies its own gearbox assembly. The parallel shaft design for the genset packages is a simple, rugged gearbox designed to accommodate over 70MW of load. While these gearboxes are intend-ed for 50Hz applications (3000 rpm output shaft speed), it would be easy to offer the units for 60Hz service ar-eas with only a minor change in gear ratios providing 3600rpm output. Exhaust is axial out the rear, which allows close coupling to heat recov-ery boilers for good efficiency with low thermodynamic duct and heat losses. Twenty can-type reverse-flow combustion chambers are fitted around the turbine centerline. Multi fuel capability includes a variety of gaseous and liquid fuels. The turbine is a four-stage axial unit with air cooling on the forward stages. First three stages of stationary vanes (nozzles) and three stages of rotating blades are air-cooled. The rotor shaft is supported by tilt-ing-shoe bearings. A combined jour-nal and thrust bearing is located at the inlet side of the compressor and the second journal bearing is housed at the exhaust end.

Engine performanceBased on shaft power output, the UGT 45000 gas turbine engine is gross rated at 47.7MW and 36.1%

thermal efficiency and the UGT 60000 at 63.5MW gross and 38.8% efficiency, with no losses when burn-ing natural gas. As simple cycle generator sets, burning natural gas, the GTE-45 plant has generator terminal power output of 45MW, and 34.4% efficiency. The

GTE-60 power output is 60MW and 37.0 % efficiency. Exhaust temperature at the exit of the exhaust diffuser is 550°C (1022°F) for the UGT 45000 and 520°C (968°F) for the UGT 60000. Respectively, the exhaust flow is 137 kg/sec (302 lb/sec) and 173 kg/sec

Design Parameter GTE-45 Power Plant GTE-60 Power Plant

Gross base load 45,000 kW 60,000 kW

Gross heat rate LHV 10,465 kJ/kWh 9730 kJ/kWh

9920 Btu/kWh 9220 Btu/kWh

Gross efficiency 34.4% 37.0%

Pressure ratio 14 to 1 18 to 1

Turbine speed 3960 rpm 4320 rpm

Exhaust flow 137 kg/sec 173 kg/sec (302 lb/sec) (381 lb/sec)

Exhaust temperature 550°C (1022°F) 520°C (968°F)

Nominal GTE-45 and GTE-60 simple cycle ratings. At 15°C sea level site conditions, the GTE-45 plant is rated at 45MW and 34.4% efficiency (at the generator terminals) and the GTE-60 at 60MW and 37.0% efficiency, on natu-ral gas fuel. ZM expects to begin manufacturing production in 2015.

Source: Zorya Mashproekt, February 2013

UGT 45000 UGT 60000 Design Parameter Gas Turbine Gas Turbine

Continuous power 47,700 skW 63,500 skW 63,960 shp 85,150 shp

Heat rate LHV 9975 kJ/kWh 9280 kJ/kWh 7050 Btu/hp-hr 6560 Btu/hp-hr

Efficiency 36.1% 38.8%

Pressure ratio 14 to 1 18 to 1

Turbine speed 3960 rpm 4320 rpm

Exhaust flow 137 kg/sec 173 kg/sec (302 lb/sec) (381 lb/sec)

Exhaust temperature 550°C (1022°F) 520°C (968°F)

Nominal weight 31 tons 31 tons

Nominal size LxWxH 5.65 x 3.35 x 3.52 m 5.65 x 3.35 x 3.52 m 18.5 x 11.0 x 11.5 ft 18.5 x 11.0 x 11.5 ft

UGT 45000 and 60000 gas turbine engine shaft ratings. High performance gas turbines will be packaged as 50Hz GTE-45 and GTE-60 gensets for sim-ple cycle, cogeneration and combined cycle projects calling for a relatively small gas turbine footprint and high efficiency.

Source: Zorya Mashproekt, February 2013


(381 lb/sec). The ‘tubular-sectionalized’ dry low emission combustor design is capa-ble of 25ppm NOx production when burning natural gas, without water or steam injection. Each combustor can has an indi-vidual fuel nozzle to handle a range of fuels including natural gas, associ-ated gas oil, distillate, diesel or kero-sene. The cans are interconnected via flame tubes. Natural gas is intended as the main fuel with distillate and diesel serving as backup. Switchover under load is designed into the fuel system and en-gine/genset controls.

Development and testFirst experimental prototype gas tur-bine engine UGT 60000 was manu-factured in 2011 and test procedures started in 2012.

One of the main design development goals was precise tuning of the IGV row geometry and variable guide vanes to maximize cycling capabili-ties and part-load efficiency, note Zo-rya engineers. Work centered on controlling load by varying air flow rates through the compressor (variable guide vanes, bleed valves) and matching these with delivery of fuel to the combustors to optimize part-load operation. Correctly matching air flow and fuel flow rates “can maintain fairly constant exhaust temperature (and combustion temperature) at part load,” note development engineers, “which serves to provide steady pro-duction of heat energy to power ex-haust heat recovery boilers.” The digital control system was mapped to optimize air and fuel flow

rates for best part-load efficiency. It provides complete automatic process control of the plant (simple cycle, cogeneration or combined cycle) in-cluding startup, shutdown, and load following with minimum operator in-terface.

60MW test programA prototype of the UGT 60000 was installed for testing at the company’s Trial Operation Facility at Kaborga, only about 60 km from the main of-fice in Nikolaev, making it easy for constant attention by the development engineering staff. Previously, this was the same site used for development of the 110MW units that are now in series production as the GTD-110. In 2010 this site was converted for the 60MW test program. Over the test period of 2011–2012, a number of research and develop-ment activities were carried out to evaluate thermal parameters and reli-ability of the new GTE design. The electricity produced during the test process is supplied to the national power grid of Ukraine. Final testing and company startup of its manufacturing line should be completed by the end of 2014 in prep-aration for serial production of both the GTE-45 and 60 gensets starting in 2015.

Combined cycles While Zorya is not planning to design and market combined cycle plants,

Power versus Temperature. GTE-60 and GTE-45 power limiting at generator terminals vs. compressor inlet air temperature.

80MW

60

40

20

-20-40°C 0 20 40

Inlet Ambient Temperature (°C)

GTE-60

GTE-45

Power

Net Plant Heat Rate Net Plant Heat Rate No. & Type GTCC Plant Output Btu/kWh Efficiency kJ/kWh GT Output ST Output GT Gensets

GTE-45CC1 66,100 kW 6720 Btu 50.8% 7090 kJ 44,100 kW 22,000 kW 1xGTE-45




Nominal GTE-45 and GTE-60 combined cycle ratings. Estimated design performance of conceptual combined cycle plants based on DLE gas turbines exhausting into unfired dual pressure heat recovery steam generators, operating on natural gas fuel. Ratings will vary according to OEM steam turbine bottoming cycle engineering specifications.

Source: Gas Turbine World, February 2013


the new machines will certainly be available for complete turnkey supply and construction projects undertaken by industry power plant EPCs, build-ers and developers. Reference plant engineering stud-ies have been developed for multi-shaft combined cycle configurations where the GTE is connected to its own generator and the steam turbine drives a separate generator. These combined cycles powered by GTE-45 and GTE-60 gas turbines are built around unfired heat recovery steam generators. Typically, based on conceptual plant studies, a conservatively de-signed 1-on-1 GTE-45 combined cycle plant would be nominally rat-ed at 66.1MW net output and 50.8% net plant efficiency. A 2-on-1 design would be rated at 132.2MW and 50.8% efficiency. Similarly, the design of a 1-on-1 GTE-60 combined cycle plant would be rated at 83.8MW net output and 52.1% net efficiency. And the 2-on-1 design would be rated at 167.6MW and 52.1% efficiency. Dual-pressure level HRSGs are normally specified, with the plant EPC’s choice of either natural or forced circulation. Boiler OEM sup-pliers for combined cycle projects within Europe could include Energo-mash and EM-Alliance in Russia and Aalborg Engineering in Slovakia.

Repowering projectsZorya-Mashproekt executives are par-ticularly interested in applying the new machines for repowering proj-ects to upgrade and modernize exist-ing steam plants. According to Alexander Golovash-chenko, Z-M’s Deputy Manager of the Marketing Division, “the com-pany expects that UGT 45000 and UGT 60000 machines will be used for simple cycle, cogeneration and in combined cycle power plants.” They also can be used for conver-sion of existing conventional steam-

turbine modules into combined cycle power plants. “Due to the relatively small dimen-sions and low weight they can be eas-ily built into the existing steam power generating sites for achieving better efficiency. Such modernization shall require significantly lower investment compared with newly built combined cycle units.” Overall size of the GTE-60 gas tur-bine mounted on its skid is approxi-mately 5.65 by 3.35 by 3.52 meters (LWH). Weight of GTE-60 on skid is

31 metric tons. For repowering applications, the GTE-60 gas turbine exhaust flow and temperature are well suited for up-grading steam plant installations with existing boilers operating at 500-600 t/h steam capacity. Adding a GTE-60 generator set and new HRSG could convert an ex-isting condensing extraction steam turbine plant into a “low-cost” PGU-220 combined cycle power plant rated at around 220MW gross base load output and 53% efficiency. n

Efficiency versus Output. GTE-60 and GTE-45 efficiency vs. power at genera-tor terminals.

40%

30

20

10

0Power at generator terminals (MW)

GTE-60

GTE-45

Efficiency

100 MW 20 30 40 50 60

UGT45000/60000 architecture. Single-shaft engine design has a 15-stage axial compressor with IGVs and three stages of variable vanes; reverse-flow can-annular combustor design with 20 individual cans; air-cooled four-stage turbine section with cooled first three stages; rotor support by combined tilting-pad journal/thrust bearing at front and journal bearing at rear.


AbstractMany superchargeable heat-to-power cycles with turbo-machines have been proposed but only a few have been built and operated. This paper tracks the sequence of ideas up to the latest and most promising one. The history of super chargeable turbomachinery started with closed cycles receiving heat via heat exchangers. Later many variants of semi-closed cycles receiving the heat by internal combustion were proposed. The most recent proposal suggests an air breathing “semi-closed recuperated cycle” (SCRC) for electric power genera-tion. Such plants have the potential to exceed the widely used gas turbine combined cycle (GTCC) technology with respect to operation flexibility, power density and simplicity. They have an efficiency potential similar to GTCC. A first simula-tion indicating the potential of such cycles is shown in the second part of this paper.

IntroductionSupercharging of Diesel and Otto motors is a widespread technology. Current thermal power generating cycles with gas turbines do not use supercharging at all. This is astonish-ing because among the first gas turbines the closed cycles played an important role. Such cycles can be operated at an elevated compressor in-let pressure with the advantage of a higher power density. A machine of a given size can therefore generate more power. This is also a motivation for supercharging Diesel or Otto motors. But this paper is limited to turbo machinery based super charged cycles. The history of supercharged cycles started with the class of closed cycle gas turbines. These had a time window of commercialization starting in 1939, but still have a poten-tial for heat sources with limited temperature like solar or nuclear. In these cases the temperature limitation of the heat exchanger technology does not matter. Overcoming this temperature limitation requires internal combustion like in the Brayton cycle. The answer was the idea of semi-closed cycles. The first corresponding patents appeared in the forties. Since then various arrangements have

been proposed. Such cycles use a fluid circulation in a closed loop, which allows super charging. Their heat input is generated by inter-nal combustion fed with injected fuel and oxidizer. If nearly pure oxygen is used as oxidizer, we talk about an “oxyfuel cycle”. Such ideas came up since the eighties. They were driven by the need for limiting CO2 emissions. The internal com-bustion generates heat and excess fluid mainly consisting of steam and CO2. This allows (in case of CO2 storage at least theoretically) emission free operation. It is also attractive to use ambient air as oxidizer in a semi-closed cycle. The advantages are the high power densi-ty and the possibility of power control by changing the pres-sure instead of changing the temperature. This allows high part-load efficiency and, for the hot parts, reduced thermal transients that are critical for limiting maintenance cost.

Air Breathing Semi-Closed Recuperated Cycle and its Super Chargeable Predecessors

Exclusive Guest Feature

By Dr. Hans E. Wettstein Swiss Federal Institute of Technology Zurich

SCRC based on proven technologies offers CO2 capture readiness, 55% to 60% efficiency at high load, over 50% at low load, ability to reach full power from idling in seconds, lower specific cost than GTCC plants.

Nomenclature and Acronyms

CCS “Carbon Capture and Storage”. (with carbon as CO2 )

EGR Exhaust gas recirculation (into the GT compressor)

GT Gas turbine (for open air-breathing cycle or Brayton cycle)

GTCC Gas turbine combined cycleHRSG Heat recovery steam generatorHPRTE high pressure regenerative turbine engineLHV Lower heating value (also used as

approximation for the fuel exergy)NOx Mix of NO and NO2 in GT exhaust gasORC Organic Rankine cycle PoWER Power, water extraction, and refrigerationSCRC Semi-closed recuperated cycle (in this context

always air breathing)TBC Thermal barrier coating (often a plasma

sprayed porous ceramic layer)


Such cycles have been proposed since the 1980s for dis-tributed power generation, refrigeration and air conditioning and for propulsion. Details of this latest proposal for a semi-closed recuperated cycle (SCRC) for electric power genera-tion are worked out below to demonstrate its extraordinary potential.

Closed cycle gas turbinesLet us look back to the first closed cycle gas turbines pio-neered by Escher Wyss. Their first application was launched in 1939 with the designation AK36. The thermal efficiency was measured later with 31.6% and the nominal power 2000kW. The book of Frutschi [1] describes this and 22 other com-mercial plants sold and operated in these times. The advan-tage was the capability to use dirty fuels because the heat is transferred via heat exchanger to the circulating cycle fluid, which therefore remains clean. Frutschi explains the disappearance of closed cycle gas turbines with the growing availability of clean fuels, first distillates and then natural gas. This favored the simpler and cheaper open cycle gas turbines for power generation. This technology was developed until now to a dominating market share.

First semi-closed cycles The first semi-closed cycles with internal combustion were patented in the 1940s. One of the first patents of the French company Rateau [2] has the priority date 1947.07.21. It de-scribes in the pressurized part of the cycle an arrangement with two turbines and combustors upstream of each. Frutschi [1] describes a complex semi-closed plant with three expanders that was built by Sulzer in the 1950s. This plant named “Weinfelden” suffered strongly from the use of a dirty fuel and was soon replaced with open cycle GTs. At that time the technical significance of semi-closed cycles remained limited.

Semi-closed oxyfuel cyclesIn the 1980s, the need for limiting CO2 emissions came into the focus and ideas allowing capturing and storing CO2 from fossil fuel burning plants were desired. One concept was to use a semi-closed cycle with internal combustion of a carbon containing fuel with injected nearly pure oxygen. Such “oxyfuel cycles” generate an excess gas whose main constituents are water and CO2. After condensing the water, the remaining CO2 can be processed to the condition needed for any application like enhanced oil recovery or simply stor-age. The acronym “CCS” standing for “Carbon Capture and Storage” has been created to describe this motivation. Two families of oxyfuel cycles are mentioned here: The first with mainly steam in the circulating loop is well-known as the “Graz” cycle [3]. The second family with mainly CO2 circu-lating is known as the “Matiant cycle” [4]. These cycles are complex as can easily be seen from the indicated publications. Also less complex oxyfuel cycles like a proposal of the au-

thor [5] with recuperation were suggested. Nevertheless there is no commercialization visible so far, probably because the production of technically pure oxygen for the combustion in an air separation unit (ASU) is both expensive, space and energy consuming. It is therefore indicated to minimize the need of oxygen. Burning hydrocarbons consumes more oxygen than needed to form CO2 because the combustion product water also needs oxygen. When burning methane fuel, exactly 50 per-cent of the oxygen goes into forming water as the product of combustion. This means that about half of the oxygen is consumed and lost for the purpose of protecting the environment. Oxyfuel cycles therefore are only economic when burning high car-bon containing fuel. Such plants have reached the test opera-tion like “Schwarze Pumpe” [6].

Open cycle GTs with exhaust gas recirculation An alternative option to capture is absorption of CO2 from the exhaust gas of existing GTCC plants. For an open cycle gas turbine, this is not very economic because the CO2 con-centration is lower compared to many plant concepts with near stoichiometric combustion. Therefore, recirculation of cooled exhaust gas into the compressor (EGR) has been suggested [7]. Recent papers on this technology indicate that this works fine for existing gas turbine combined cycle plants (GTCC). Up to a recirculation rate of 35 to 40% the current blading designs can cope well with the changed fluid composition. There is even a most welcome side effect: The changed gas composition reduces NOx formation rate in the combustor at a given flame temperature. A large gas turbine frame sup-plier has announced plans to use this effect for allowing a higher turbine inlet temperature [8]. Others are working on this concept too [9], [10].

HPRTE and PoWER technologiesSince the late 1990s, a group of engineers from the Uni-versity of Florida have been working on an air breathing supercharged semi-closed cycle. There are two variations; the basic cycle is named HPRTE (high pressure regenerative turbine engine) and the other, with an integrated refrigeration loop, referred to as PoWER (power, water extraction, and refrigeration). This group recognized the high potential of this cycle and declared its aimed use for distributed power generation, refrigeration, air-conditioning and propulsion in several vari-ants. We do not go into details here, because the very similar cycle for electric power generation on a small to very large scale is discussed below. We have referenced only two im-portant publications: the most comprehensive one is a NASA report from 2001 [11] and a later one dated 2010 [12].

Air breathing SCRC for electric power generationBased on difficulties with semi-closed oxyfuel cycles, H.U. Frutschi, author of the closed cycle book [1], suggested an


air breathing semi-closed recuperated cycle (SCRC) using turbocharger or micro turbine components. This idea is the subject of a US patent [13]. It is remark-able that he did not know about the University of Florida de-velopments in spite of their obvious similarity. Even the later patent examination never brought this information to light. Frutschi’s idea illustrated in Fig.1 schematic shows that the charger group ATL2 sucks up fresh atmospheric air into the cycle and expands the excess combustion gas to ambient pressure. The main engine group ATL1 with compressor 1, turbine 2, recuperator 5, combustor 6 and after-cooler 7 operate at a higher pressure level than ambient and drives the main generator 4. By using the bypass valve 11 fast transients can better be controlled. A large part of the turbine exhaust gas is recirculated allowing a low-oxygen and high-CO2 concentration in the stack. But this point is not mentioned in the patent description. Later on, the author was looking for cycle options with exhaust gas recirculation allowing the required low temperature heat extraction suitable for driving CO2 absorp-tion. And here Frutschi’s patent was pulled out again. Derived from this an initially unexpected bunch of op-portunities popped up. These were published in a com-prehensive patent application in 2008 [14], still without knowledge of the University of Florida’s pub-lications. After his employment ter-minated, the author arrived at his

decision to describe these and additional opportunities of this technology in this paper. All of the following presentation is based on the cited publications and on completion of the author’s proposal prepared in 2012. During preparation of this paper the afore- mentioned publications from the University of Florida were detected.

Description of the SCRCFig. 2 shows the basic cycle scheme as published in a patent application[14]. External air is compressed in the charger compressor 23 and mixed into the supercharged loop. The mixture is cooled down in the after-cooler 17. Excess water 34 is condensed out. The main flow 43 is then compressed in the main compres-sor 11, heated up first in the recuperator 15 and then in the combustor 16. The hot gas is expanded in the main turbine 12. Lower temperature air 33 is extracted from the high pres-sure path of the recuperator supplying cooling systems of combustor 16 and main turbine 12. The details of this cool-ing fluid (33) distribution are not shown in this figure. The indicated mixing point corresponds to the calculation of the “mixed turbine inlet temperature”. The (low pressure) exit fluid from the main turbine 12 flows through the recuperator 15 transferring heat to the high pressure fluid. Excess fluid is discharged from the low pres-sure path of the recuperator into the discharge turbine 24 and after-cooler 21 into the CO2 absorption column 26. The main turbine 12 drives the main compressor 11 and the main generator 14. The discharge turbine 24 drives the charger compressor 23 and the charger motor/generator 25 via the shaft 22. It is possible to arrange all turbo-machinery on the same shaft with one generator, but the arrangement shown provides more flexibility for load ramps. The CO2-rich sorbent fluid is regenerated in the column

Fig 1. Basic cycle scheme of the Frutschi patent [13]. Key features: (1) compressor, (2) turbine, (3) drive shaft, (4) main generator, (5) recuperator, (6) combustor, (7) after-cooler, and (11) bypass valve.

Fig 2. Basic cycle of Wettstein patent [14]. This is a variant with CO2 absorption.

1 23

4

5

6

78

910

11

15ATL 2

ATL 1

1535

11

14

13

43

34

36 20 23 22 24 25

1918 16 12

10

29

28

21

17 32 27 30 31 26

33


27 which is supplied with heat from the after-cooler via the loop 32. For the case of an electric load rejection, a fast valve 35 (with discharge to ambient) may be necessary for depres-surizing the main loop. Different variants are shown in [14]. Among them is a version without CO2 separation allowing the use of the heat from the after-cooler and/or from the discharge flow for co-generation or for a bottoming cycle. The latter may be a Ran-kine steam cycle or an Organic Rankine Cycle.

Optimization of the SCRC cycle dataBased on Fig.3 the author has continued thinking on the cycle optimization and its opportunities. This has been done without knowing what the owner of the patent [14] is going to do with it. The results are so attractive that it is worth publishing it. Key cycle data of major significance are: • charging pressure ratio (compressor 6 in Fig. 3) • main cycle pressure ratio (compressor 1 in Fig. 3) • firing temperature (mixed average hot gas temperature 3 in Fig. 3 upstream of the main turbine)

The recuperator imposes restrictions because temperature can only be transferred from higher to lower temperature. The arrangement has the effect that two (temperature) pinch points occur at the hot and at the cold end while the tem-perature difference within the recuperator remains higher (example in Fig. 6). A reference case of the cycle has been calculated following the state changes along the fluid path with the assumptions given in annex A. Data selected for the reference case correspond to a large GTCC (gas turbine combined cycle) with 400MW output and 1500°C hot gas temperature. This allows comparison to the status of current GTCC technology [15]. Table 1 gives

the calculated data used for a comparison with a state-of-the-art GTCC plant in table 2. Hot gas temperature for the reference case has been chosen to match the current state of gas turbine design. The maxi-mum pressure in the reference cycle is 53 bar. The pressure ratio of the main turbine is 9 and therefore considerably lower than current gas turbine ratios of up to 35 (single shaft) and up to 50 (aero-engines). Cooling and leakage air requirement of the main turbine has been assumed at 12% compared to typically 20% in single-shaft gas turbines, considering that fewer stages will be needed and leakage losses will be lower. The reference cycle has two heat sources for a bottom-ing cycle: the after-cooler with a level of up to 277°C (305.7MW) and the charger turbine outlet with a temperature of 268°C (64.1MW). Using these heat sources for an Organic Rankine Cycle (ORC) a “combined cycle” efficiency of 62% is achievable. In this case the assumption of 69% exploitation of the ex-tracted exergy has been made. In comparable GTCC’s the bottoming steam cycles have up to 74% exploitation of the exergy extracted in the heat recovery steam generator [18]. Many publications available on ORC applications indicate its suitability for applications over a 150 to 300°C window of heat source temperatures. We do not go into this subject but reference a recent publication [17].

Comparative SCRC efficiency Looking at a thermodynamic comparison with the GTCC technology (see table 2) it becomes clear that the SCRC can benefit from improvements at the “bottoming end” of the cycle. There are several options: 1) As already mentioned an Organic Rankine Cycle is the best option with respect to the overall efficiency. But its dis-advantage is a certain complexity. 2) For lower complexity a combination of different cycle fluids should be avoided. With one intercooling stage in each compressor, 59% gross thermal efficiency can be reached while extracting 150°C heat for cogeneration without caus-ing a power loss.

Fig. 3 SCRC scheme for the calculations. Follow the flow: 1) thru main compressor, (2) thru combustor flame, (3) thru main turbine, (4) excess fluid thru charger turbine, (5) LP recuperator cold end, (6) air thru charger compressor, (7) into after -cooler, (8) condensed water, (9) into cooling system, (10) via stack to ambient, and (11) cooling water.

Fig. 4 SCRC scheme with a closed cooling system. It pro-vides an optional loop for cooling hot turbine parts: (1) main compressor discharge air, (12) closed loop cooling fluid with booster, (2) combustor, (3) main turbine and (9) heat exchanger.

123

4

9

RecuperatorOpen loop cooling fluid supply

Combustor receiving fuel

Main Turbine

5

7

1

1

23

3

4

9

RecuperatorOpen loop cooling

fluid supply

Combustor receiving fuel

Main Turbine

Electric Generator

Turbine for excess fluidCharger

CompressorAmbient air

intake

Condensed water drain

After-cooler

Mixing point

Main Compressor

Main Generator

Excess fluid discharge

(low oxygen)

5

7

6

6

1011

8

12


3) Further improvements at the bottoming end may include more than one intercooling stage and/or the use of a refrig-eration cycle for the after-cooler. The limit approach of this is using a fully isothermal compressor technology. Such technology has been built and operated according to the report of Woodbridge [19]. He claims a measured ef-ficiency of 82% for his more than 100-year old “hydraulic (air) compressor”. This curiosity appears to have no succes-sors so far. (But it could again be installed in combination with high pressure hydraulic power stations. This is just a side note exceeding the scope of this paper.) 4) Another efficiency improvement is fuel preheating with the available extracted heat. In the reference case preheating to 250°C is assumed. 5) If a higher charging pressure ratio is used the charger compressor discharge into the recuperator (as shown in Fig. 1) can be beneficial with respect to efficiency. This has not yet been investigated in detail. Other options include increasing the hot gas temperature at the high temperature end of the SCRC to achieve efficien-cy levels of current advanced technology high-temperature combined cycles [18]. One GTCC supplier has announced a hot gas temperature of 1700°C and already operates units at 1600°C [8]. For the SCRC higher hot gas temperatures will require a higher pressure ratio in the main turbine in order to keep the exit temperature on a level within recuperator capability. An additional efficiency improvement can be achieved by using at least partially a closed cooling system 12 (see Fig. 4) with a small booster compressor. This can be applied for the main turbine and/or for the combustor. The benefit would be a reduction in cooling fluid flow (9), which will improve the function of the recuperator and reduce fluid flow bypassing the combustor. The net effect is to increase the mixed inlet temperature of the main turbine while maintaining the hot gas temperature. The limits of partially closed cooling systems will be reached if the hot side surface temperature of the hot parts cannot be kept below the material capabilities. Even thermal barrier coated parts do not allow a surface temperature ex-ceeding 1150 to 1200°C. An improvement to 1300°C may be expected in the next 10 years, according to industry experts. The hottest vanes and blades will still require additional film cooling. For the combustor liner, a closed cooling system will be sufficient because of the lower (hot side) heat transfer coefficients associated with the lower hot gas velocity.

Opportunities for improving SCRC operation Power augmentation may be possible by arranging fine water spray injection upstream of the main compressor like “high fogging” in gas turbines. And if a supply of cold water is available for cooling the after-cooler, then SCRC power and efficiency can both be increased considerably. If using CO2 separation by absorption methods, the needed heat extraction for regeneration of the absorption agent can be taken from the after-cooler and/or from the excess gas dis-

Table 1: SCRC cycle data for reference case. At base load conditions; numerals in brackets refer to Fig. 3. schematic.


charge without any loss of power. The exhaust gas corresponds to a near stoichiometric composition because exhaust gas recirculation is an inherent feature of this cycle so that the SCRC is inherently “CCS-ready”. The relevant fluid compositions of the reference case are indicated in table 3. As shown, the CO2 fraction of gases out the stack represents 15.17% by mass of the exhaust flow. The SCRC can be designed for extremely low-load parking with high efficiency and low emissions. The reason is that the pressure can be reduced allowing the main turbo machin-ery to operate in its design condition and the combustor at or nearly at its design temperature. In a first step, the load can be reduced by a factor cor-responding to the pressure ratio of the charger compressor. That means that charger compressor and turbine are simply bypassed. A second step to operate at even lower power is possible if the charger compressor acts as an expander and the charger

turbine as a compressor with correspondingly low mass flow rate. That means that the main compressor has an inlet pres-sure below ambient while the firing temperature in the main turbine is still maintained. The corresponding transient pres-sure changes may need additional measures discussed with the control concepts below. Another advantage of the SCRC is significant in arid en-vironments. Open cycle gas turbines lose all the water pro-duced by combustion through the stack. In contrast, as shown in table 1, the reference SCRC plant produces 24.3 kg/s con-densed water under ISO standard conditions. It will be less in hot and dry ambient conditions. If a dry cooling technology is applied the plant can still export water.

Design considerations for SCRC turbo machineryThe high pressure level in the main turbine increases the heat transfer coefficients. This represents a challenge because of correspondingly higher thermal stress in the hot parts.

Mitigation for these effects is improved by film cooling systems in connection with thermal barrier coatings. Another challenge is the high pressure for the casings. But the simple mitigation is to arrange the high pressure parts in a common pressure vessel (see Fig. 5). This ves-sel operates at the discharge pressure of the charger com-pressor and it sees internally only the low temperature of the after-cooler discharge. This vessel does not need heat resistant steel. An addi-tional advantage of the com-mon pressure vessel is the fact that the recuperator cas-ing has only to be mechani-cally designed for its own pressure drop. The main generator can be arranged in the vessel as shown, but this increases the windage losses. The genera-tor casing surrounding the generator rotor may therefore be kept at a lower pressure. Another option is to use shaft sealing and arrange the gen-erator outside the vessel. Ei-ther hydrogen or air cooled generators may be used. The pressure level of the SCRC main turbo machinery is higher than in a conven-

Table 2. Thermodynamic comparison of SCRC and GTCC losses. Percentage losses shown below are related to 100% of the lower heating value unless otherwise indicated.

Operating conditions 1500°C SCRC w/o intercooling 1500°C GTCC Design

Hot gas temperature equal equal

Exergy loss because of combustion related to LHV

typical 22% exergy loss because of higher combustor inlet temp

typical 25% exergy loss

Exergy loss by heat transfer from fluid with higher temp to fluid with lower temp

recuperator with well-matched heat exchanger 1.8% exergy loss; plus after-cooler 9.5% exergy loss (available for heat extraction)

HRSG losses from constant temperature evaporationCondenser approx 0.8% exergy loss (because of low temp)

Heat exchange need relative to net power

207% (sum of 131% for recuperator and 76% for after-cooler)

163% (sum of 100% for HRSG and 63% condensation)

Pressure losses comparable comparable

Dissipation in turbo machinery

lower, thanks to lower pressure ratio in the main loop (8.…12)

higher, because of higher ratio in the gas turbine (19….35)

Losses in inlet/outlet ducts (incl. filters, silencers)

lower; the specfic power is related to 1462 kJ/kg air inlet flow rate

higher; specific power related to 700 kJ/kg air inlet flow rate

Low temp heat extraction no power loss up to 270°C only with power loss

Stack temperature 2.6% exergy loss 250 to 300°C (less if compressors are intercooled)

approx. 0.8% exergy loss, 70 to 100°C

Net thermal efficiency 54.5% (with bottoming ORC to 62%)

60% at full plant output

Part-load operation or low load parking efficiency

nearly constant (pressure ratio and temp maintained) limit < 20% relative power

loss, due to reduced pressureratio and/or firing temp; typical limit around 50% relative power

Fuel compressor may be needed for natural gas fuel (not needed for liquid fuel)

needed for high load, eats up 0.5% of the efficiency at base load, but not at part load below 50% power

normally not needed for NG fuel (depends on the supply pressure)


tional gas turbine, causing higher bending stress in blades and vanes. This requires a sturdier cascade design with re-duced airfoil numbers per row and correspondingly larger airfoil chords. This applies especially to the first compressor stages and to the rear turbine stages. The combustor must operate with an oxidizer inlet tem-perature of around 850°C in the above mentioned reference case. Conventional gas turbine premix burner technology may not be usable for this condition. But the industry has already found a proven solution for this operating condition: the second combustor in sequential combustion gas turbines. These combustors operate already in many commercial machines at an even higher oxidizer inlet temperature level [10]. According to cited publication, it has been tested for operation with low oxygen content. This corresponds to the operating condition in the SCRC. The self-ignition principle of operation for such combus-tors in normal operation is very similar to their application

in the SCRC at nominal temperature. But for start-up, an ad-ditional igniter torch or a similar device will also be needed because of the lower combustor inlet temperature. The effect of the higher operating pressure will be marginal for fuels like methane, for which the combustion reaction implies no volume change. This is a consequence of the well-known Principle of Le Chatelier. The recuperator is a key component that bridges the high temperature range with a limited exergy loss. For the reference case, the calculated heat exchange is shown in Fig. 6 as a function of the Carnot factor of the heat exchange temperature. This representation shows the exergy loss caused by the temperature drop as area between the LP and HP curves. The exchange temperature is indicated ad-ditionally as dashed line (refer to the right scale). In this case the exergy loss by heat transfer is calculated with 1.76% of the fuel heat flow. Considering size, the recuperator will be the dominating component within the pressure vessel suggested in Fig. 5. The thermodynamic comparison in table 2 shows that the recuperator heat exchange requirement is 131% of the net power output. Because this heat transfer occurs at elevated pressure (6 bar in the reference case) the heat transfer coefficients will be considerably higher. The recuperator size of a SCRC will therefore be smaller than the HRSG in a GTCC of compa-rable power output. Of course the recuperator operates at a higher temperature, but this can be covered by heat resistant materials. A similar size consideration can be applied to the after cooler. An important design parameter is the oxygen excess fac-tor in the combustion, often referred as λ“lambda”. In a gas

Pressure Vessel open loop cooling fluid

to turbine and combustor cooled flue gas recirculating flowCombustor

Recuperator

Charger Group

After-cooler Condenser

condensed water

cooling water

cooling water

Intercooler

Generator

LP and HPcompressors

air intake

excess gas to ambient or to CO2 absorption

Diffuser

Turbine

fuel supply

Table 3. Mass fractions in the SCRC reference case. Carbon dioxide fraction makes up 15.17% by mass of the exhaust flow.

Fluid Ambient Air Into Main Out of Composition ISO Conditions Compressor MainTurbine

Argon (Ar) 1.28% 1.34% 1.32%

Nitrogen (N2) 75.15% 78.90% 77.29%

Oxygen (O2) 22.90% 9.90% 1.56%

Carbon dioxide (CO2) 0.04% 9.77% 15.17%

Water (H2O) 0.63% 0.09% 4.67%

Figure 5: Proposal for a SCRC arrangement in a common pressure vessel


turbine environment, the typical alloys used for the hottest parts survive only because of dense oxide layers. Reducing zones in the combustion gas can destroy these oxide layers. Therefore, a safety margin for the lowest oxygen content in the combustion gas needs to be maintained. Because of this the combustor λ lambda in the reference case has been selected with 1.12. The lowest average oxygen mass fraction in the main turbine exhaust gas amounts to 1.56% according to table 3. The SCRC technology has another benefit with respect to power limitation. Gas turbines with direct coupling to a two-pole generator are limited to a mass flow rate of around 900kg/s. This is caused by the centrifugal load reaching the strength limit of existing materials for blades and rotor disks. The limit corresponds to a GTCC power block size of 470MW in a 60Hz grid. In a 50Hz grid, the limit is 1.44 times higher. For a SCRC power block, this limit is extended either by a factor corresponding to the pressure ratio of the charger com-pressor or by the mass flow limitation of the charger group. The lower value applies. But even the latter case extends the limit by a factor of three. Currently, the GTCC technology is already reaching the power block size limits. The conventional size-increasing approach for GTCC tech-nology would be to jump to a size upscale by a linear factor of two by using a direct coupled four-pole generator. But this is a huge step in the manufacture of large high temperature parts. With SCRC technology, existing manufacturing methods can be used for all power sizes from a few MW up to around 1200MW (with the data of the reference cycle) with the full

benefit of geometric scaling the same design. Up to this power level, the hot parts of a SCRC do not need a bigger size than currently used today for large gas turbines. It is an attractive alternative to four-pole generators which were used for large steam turbines a few decades ago.

Control concepts for the SCRC For start-up the main shaft may be driven by the generator acting as a motor while the charger group is wind milling or slowly turning. After ignition, acceleration to nominal speed and synchronizing of the main generator with the electric grid, the hot gas temperature is increased to nearly nominal value. Still having close to atmospheric pressure in the vessel, the power of the reference concept (table 1) may be around 17% of nominal. This allows sustained combustion at nearly nominal temperature with correspondingly low emissions. This operation point is also suitable for low-load parking with readiness for immediate power pick up. For further loading the charger group increases pressure in the vessel until base load or according to the need. This may need a good mass flow control by variable guide vanes and/or variable speed of the charger compressor. For fast load changes, the charger turbine may also need variable guide vanes. This allows fast pressure build-up by reducing the discharge fluid flow. For the case of a load re-jection. a fast fuel shutoff may still be necessary. It could be supported by an additional fast valve (35 in Fig. 2) from the main compressor discharge to ambient. With a clever com-bination of these measures, the hot part life can be consider-ably extended. If the after-cooler is supplied with variable temperature cooling water, the excess gas discharge from the recuperator should be shifted to either a higher or to a lower temperature in order to achieve optimal performance. This could be ar-ranged with two different discharge nozzles and a mixing valve. If an extremely fast power pick up is required, pressur-ized fluid can be kept ready in a high pressure reservoir for injection into the combustor inlet area. Another low pressure reservoir could be used for simultaneously injecting fluid upstream of the main compressor. Such injection rates must initially remain below the nominal mass flow rates and they can be maintained until the main compressor inlet side has reached its base load pressure. With this method, the vessel can be charged along the surge limit of the main compressor. During the filling process, the ratio of main turbine power to main compressor power may exceed the steady state value. Therefore, more electric power is available than the value corresponding to the actual inlet pressure of the main compressor. With this method, power ramps similar to a high pressure hydro generator may be nearly achieved. The operation phases during high load or during slow power changes can be used to charge the above mentioned two-pressure reservoirs out of the main cycle taking a small-er fluid flow from upstream and downstream of the main

Fig 6. Heat exchange within recuperator. Follow the flow: 1) LP gas from main turbine exit to mixing pointe, 2) HP gas from main compressor to combustor, 3) link from local heat exchange temp to the Carnot Factor, 4) area between curves indicates directly the exergy loss by heat exchange, and 5) this corner is caused by the excess gas discharge at this point.

500MW

400

300

200

100

0

800°C

700

600

500

400

300

200

Hea

t ex

chan

ge

(MW

)

Carnot Factor of the heat exchange temp

Lo

cal h

eat

exch

ang

e te

mp

(°C

)

0.5 0.6 0.7

1

2

3

4 5

Hot end

Cold end


compressor. Only associated piping and valves are needed for that and no extra compressors. The case of very low load parking characterized by an inlet pressure of the main compressor below ambient pressure exceeds the capability of a normal charger compressor and turbine. Preparing the SCRC for such operation cases may require one or more extra charger engine groups with the corresponding ducting and switchover procedures. A low load parking of the above mentioned reference case at around 2% of nominal power corresponds to turbofan en-gine operation at cruising altitude with around 0.1 bar com-pressor inlet pressure. Developing such concepts will become attractive because of the current trend of replacing base load supply from nu-clear and coal plants by renewable energy like wind or solar. This trend creates more fluctuation in the power supply that will have to be smoothed by short-term callable power supply with the possibility of very fast power ramps. And this is exactly what the SCRC technology can provide, even at a reasonably low price.

Conclusions In spite of a long history, SCRC technology has not yet made the step to commercially available products. This may change because of its simplicity and unprecedented op-erational flexibility including part-load efficiency close to the base load value.

In a future with a high share of renewable power sources the following features will be important: • low load parking with readiness to immediate (within a few seconds) power pick up, • thermal efficiency above 50% at low load • thermal efficiency in the 55 to 60% range at high load

Although mature GTCC technology has made considerable progress in operational flexibility, suppliers are working hard on further small step improvements. Nevertheless, we can expect that the first well developed and tested SCRC will outperform even the best GTCC with respect to operational flexibility and cost. Another advantage of SCRC technology is that its technical block power size limitation is much higher than in the GTCC technology. The step to four-pole generators from two-pole generators could be omitted for the foreseeable future. The author is eager to see which engine manufacturer will first seize this opportunity for a fast growing business.

AcknowledgementsThe author thanks his former employers Brown Boveri, ABB and ALSTOM. For 34 years they provided him with the enriching engineering environment of both experience and motivation to develop this paper. And the author appreciates the ETHZ where he enjoys now the freedom of acting fully independent and free of commercialism.

[1] Hans Ulrich Frutschi, 2005: “Closed–Cycle Gas Tur-bines, Operating Experience and Future Potential”, ASME Press, © 2005 by ASME, Three Park Avenue, New York, NY 10016, ISBN 0-7918-0226-4.

[2] Anxionnaz, R. 1945, (Societe Rautear, SA): “Installation a “Rateau”, turbines a gaz a circuit semi-ouvert”, French pat-ent 999-133, 14.11.1945. Mark.

[3] Jericha, H., 1985, “Efficient Steam Cycles with Internal Combustion of Hydrogen and Stoichiometric Oxygen for Turbines and Piston Engines”, CIMAC Conference Paper, Oslo, Norway.

[4] Mathieu, P., Niehard, 1999: “Zero Emission MATIANT cycle”, Journal of Engineering for Gas Turbines and Power, January 1999, Vol. 121 / 117.

[5] Frutschi, H. U., Wettstein H. 1998: „Kraftwerksanlage mit einem CO2 Prozess“ Patent EP 0 953 748 B1. Mark.

[6] Vattenfall/ Gaz de France: 2008: “Schwarze Pumpe, Car-bon Dioxide Capture and Storage Project”.

[7] Bolland, O., Saether, S, 1992: “New Concepts For Natu-ral Gas Fired Power Plants, which Simplify the Recovery of Carbon Dioxide”, Energy Convers. Mgmt. Vol. 33, No. 5-8, pp. 467-475.

[8] Eisaku, Ito et al., 2011 “Development of key technologies for the next generation high temperature gas turbine,” ASME Paper GT2011-45172MHI 1700°C.

[9] A. M. Elkady, A. R. Brand and C. L. Vandervort 2011: “Exhaust Gas Recirculation Performance in Dry Low Emis-sions Combustors”, GT2011-46482.

[10] Guethe, F, et al. 2011: “Flue Gas Recirculation of the Alstom Sequential Gas Turbine”, GT2011-45379.

[11] Lear, W. E., Laganelli, A. L., 2001, “High Pressure Re-generative Turbine Engine: 21st Century Propulsion”, NASA / CRm2001-210675 (“HPRTE cycle”).

[12] Choon Jae Ryu, William E. Lear, S.A. Sherif, 2010, “Second law analysis of a refrigeration system for a nov-el semi-closed gas turbine-absorption combined cycle” GT2010-23729.

Patent and Referenced Citations


Detailed design and performance calculations of the SCRC reference case at base load conditions were carried out for this paper, but only the main assumptions, principles and for-mulas are summarized below. It is important to point out that all performance related assumptions made for the calculations were based on experi-ence numbers taken from commercially available gas turbine combined cycle plants. For straightforward calculation, fluid compositions were determined in a first step assuming the air inlet mass flow rate, the recirculation factor and the oxygen excess factor in the combustor. This task is done by calculating the mass flow rates of each fluid at each composition change event in the scheme of Fig. 3. In the reference case, we use pure methane as fuel. And for the composition vectors (table 3) we considered the following five gases: argon, nitrogen, oxygen, steam and carbon-dioxide. The second step of the calculation was aimed at fluid state changes along the flow shown in Fig. 3. This was done by assuming ideal gas mixture data with the composition vectors as calculated before. The gas data are taken from the libraries issued by Kretzschmar [16]. These data consider the effect of dissociation. The latter causes an increase of the specific heat of air above around 1200K. Compression or expansion is modeled as a polytropic state change in the blading according to the formulas, which are valid for an ideal gas mixture with the specific heat cp(T). These formulas are solved numerically for the un-known exit temperature T2:

Here T1 is the temperature before the state change, λ the polytropic efficiency, cp(T) the specific heat for constant pressure as a function of the temperature T, R the gas con-stant and π the pressure ratio. For low temperature and very high pressure the ideal gas assumption becomes inaccurate although it is mostly used for gas turbine performance calculations. If the design pressure of the SCRC is selected above 40 to 60 bar, the polytropic state changes should be expressed with different formulas, which allow considering the real gas effects. Such formulas are indicated, for example, in well-known text books from Traupel [20] or Baehr [21]. But the formulas from the two sources are not identical and their use is beyond the scope of this study. The polytropic efficiencies used in formulas (1) and (2) were selected as follows:

Main Compressor ηmc = 92%Charger Compressor ηcc = 91%Main Turbine ηmt = 87%Charger Turbine ηct = 91%

[13] Hans Ulrich Frutschi, 2004, “Method for operating a partially closed turbocharged gas turbine cycle and gas tur-bine system carrying out the method”, Patent US6901759B2 (19. Feb. 2004). Mark.

[14] Wettstein H., Wirsum M. Schulz S., 2008, „Gas turbine system with exhaust recycling and method for operating of such system“, Patent WO2010/049277 A1 and CH01700/08 (29.10.2008) Mark.

[15] Wettstein, H. E. 2011: “Natural Gas Fired Gas Turbine Combined Cycles for the Energy Supply in an Economy with Growing Renewable Energy Sources”, 2011 World Engi-neer’s Convention Geneva, 4-9 September.

[16] Kretzschmar, H. J., Stoecker, I., and Jaehne, I., 2011 “FluidMAT for Mathcad - Property libraries for calculat-ing thermodynamic and transport properties of steam, gas mixtures, combustion gases and humid air”. Zittau/Goerlitz

University of Applied Sciences, Department of Technical Thermodynamics.

[17] Bhargava R. K. et al: “Gas Turbine Bottoming Cycles for Cogenerative Applications: Comparison of Different Heat Recovery Cycle Solutions”, GT2011-46236.

[18] Wettstein, H. E., 2012: “The Potential of GT Combined Cycles for Ultra High Efficiency”, GT2012-68586.

[19] Woodbridge, D.E. 1907: “The Hydraulic Compressed-Air Power Plant at the Victoria Mine”, The Engineering and Mining Journal Volume LXXXIII, page 125-130, January 19 1907.

[20] Traupel, Walter,1977: “Thermische Turbomaschinen”, Volume 1, Springer, 3rd Edition 1977.

[21] Baehr, Hans Dieter, 2005: “Thermodynamik”, Springer, 10th Edition.

Appendix 1. Explanation of the SCRC Reference calculation


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These values correspond to the blading only (inlet and outlet losses are considered extra with the pressure drops). These values were selected according to the current status of large commercial gas turbines. The lower value for the main turbine is caused by additional losses due to the intense cool-ing. Details to these assumptions with further references can be found in [18]. For any fluid which changes its state from T1 to T2 the specific heat input (at constant pressure) “q” or the specific power “p” of polytropic state changes follows the following formula:

Any specific exergy transfer Δe in kJ/kg associated with heat transfer is calculated as below (with a sign + or -accord-ing to the context):

The last formula is memorable because the factor in the brackets is the Carnot efficiency (with Ta being the ambient temperature). The use of enthalpy or entropy is avoided in order to keep the formulas easily remembered and to allow

easy exchange of the gas data. Pressure drops in the cycle are considered as relative to the particular input pressure as percentages for: (1) after-cooler 3%, (2) recuperator high pressure side including pipes, com-pressor diffuser and header to the combustor 5%, (3) recupera-tor low pressure plenum 3%, (4) combustor including main compressor diffuser pressure loss and main turbine inlet pres-sure loss 4%, (5) charger turbine exhaust duct until ambient 4%, and (6) if applicable the compressor intercoolers 2.5%. The bottoming cycle (if applicable) is only addressed briefly and modeled with its external energy and exergy balance. Both the bottoming cycle and the fuel preheating receive the energy and exergy from the after-cooler and from the excess gas discharge. Our model of the SCRC includes assumptions on mechan-ical friction losses in the turbo machinery, generator losses between the mechanical coupling and electrical terminals (to-gether 1.7% of the thermodynamic power output). Auxiliary system power consumption is not considered because it is typically in the range of below 0.25%. As a consequence of the chosen sequence of calculation, the hot gas temperature at the main turbine inlet is a result. It can be increased by reducing the recirculation factor or vice-versa. In the reference case, the recirculation factor is 70.6% as shown in table 1.


IGCC and Gasification

US580MW Kemper projectpulls DOE loan requestMississippi Power Company withdrew its request for a $1.5 billion loan guaran-tee from the U.S. Department of Energy for the 582MW Kemper County IGCC project just days after state regulators approved an agreement giving the util-ity a new avenue to cover rising costs for the project. A Southern Co. spokesman said Mis-sissippi Power dropped a plan to seek a loan guarantee in late January after determining it could find lower-cost financing than it expected the government to offer. The withdrawal was prompted by a settlement ap-proved by the Mississippi Public Service Commission (PSC) that allows the company to pursue legislation to issue up to $1 billion in securitized bonds to recover Kemper costs over and above a $2.8 billion limit set by the state. The price tag for the IGCC plant along with the lignite mine and carbon dioxide pipe-line has risen from about $2.4 billion when proposed to more than $3.2 billion, according to recent utility filings. Mississippi Power began building the Kemper plant in 2010 de-spite an ongoing legal challenge to the plant’s need certificate issued by the PSC. It faces a May 2014 deadline to begin service to keep certain tax incentives. The recent regulatory settlement also allows the utility to seek a rate increase previ-ously rejected by the commission. Mississippi Power said the PSC’s denial of recovery of early Kemper costs hurt its credit rating. Mississippi Power said it has so far spent more than $2.6 billion on the Kemper project, one of only two IGCC projects being built in the United States after rising costs, lack of carbon legislation and competition from cheaper gas-fired generation led to cancellation of dozens of clean-coal projects.

Saudi ArabiaPrequalification process begins for IGCC project Saudi Aramco has started the prequalifica-tion process for a proposed 2,400MW IGCC power plant to be built next to the $7 billion Jizan refinery in the southwest. The project will be larger than most con-ventional power projects and will use tech-nology provided by the UK/Dutch Shell Group. KBB has been awarded responsibility for a front-end engineering design (FEED) study as well as for project management and con-sulting services for the refinery and power plant. Aramco has invited international engineer-ing, procurement and construction (EPC) contractors to submit prequalification docu-ments for various phases of the development project. The contracts will be split into five pack-ages: air separation unit (oxygen supply); combined cycle power island; gasification system; supporting offsite and utility sys-tems; and sulfur recovery system. Once the prequalification process is com-pleted, Aramco will then issue tenders for the packages to successful EPC contractors.

A lump-sum turnkey contract model is be-ing used to execute the project. The Jizan Refinery Project will need only about 500MW of power from the proposed IGCC plant with the remainder being used to power potential large-scale industrial projects at Jizan Economic City. Aramco is taking over development of the power plant project from the Saudi Elec-tricity Company, which was previously in charge of its development.

Saudi Arabia Jizan gasification plant to integrate sulfur packages Saudi Aramco says it selected Shell IGCC technology in order to optimize energy ef-ficiency. In addition to electricity, the Shell IGCC process will supply the refinery with hydrogen and Jizan Industrial City with water. Operationally, the gasification plant will use 90,000 barrels per day of vacuum resi-due from the refinery as feedstock which will be combined with oxygen to produce syngas that will fuel the combined cycle plant gas turbines. Saudi Aramco is preparing a tender for the oxygen package but at this point, say

project engineers, it is unclear if the tender should be for an integrated refinery plant package or an oxygen supply contract. Since fuel gas desulfurization perfor-mance is directly related to the IGCC pro-cess, this package as well as the sulfur re-covery unit have been transferred from the refinery scope and been made part of the power plant project packages. As a consequence of the increase in con-tent, they figure the Jizan power plant pack-age may end up costing somewhere be-tween $3 and $5 billion capital expenditure. Despite this expanded scope of work, Saudi Aramco, Shell and KBR expect the Jizan gasification plant to come on stream at the end of 2016.

USAdvances in clean coal CO2 capture technologyResearchers at The Ohio State University (OSU) report that have successfully com-pleted more than 200 hours of continu-ous operation of their patented Coal-Direct Chemical Looping (CDCL) technology. This technology provides a one-step pro-cess for the production of electric power and high-purity carbon dioxide (CO2). It is believed that this test represents the longest integrated operation of chemical looping technology anywhere in the world to date. The test was conducted at Ohio State’s 25 kWt combustion sub-pilot unit under the auspices of DOE’s carbon capture program. The successful test moves chemical-looping a step closer to full scale. The program’s specific goal is to develop carbon capture and compression technolo-gies that can reduce the capital cost and energy penalty of capture by more than half—equivalent to CO2 capture at less than $40 per metric ton—when integrated into a new or existing coal fired power plant. Ohio State reports that the 200+ hours of testing on metallurgical coke and sub-bituminous and lignite coals resulted in nearly 100% solid fuel conversion and a CO2 stream more than 99% pure, making it applicable for enhanced oil recovery injec-tion. The project is expected to benefit the DOE Carbon Capture Program by identify-ing oxygen carriers and a chemical looping process with the potential to control mul-tiple pollutants. Those pollutants include sulfur dioxide and nitrogen oxides, along with the carbon dioxide. The university research program aims to identify potential barriers and optimize the CDCL technology and provide realistic data


for future technological and economic anal-ysis. In a related project, DOE’s National Carbon Capture Center in Wilsonville, Ala-bama, will serve as the host site for con-struction and operation of a fully integrated 250 kWt pressurized syngas chemical loop-ing pilot unit starting this year. The facility will be used to further prove the operability and economic feasibility of advanced chemical looping technologies.

IndiaChar filtration contract forJamnagar gasification plantReliance Industries has selected Porvair to design and build char filtration systems for its planned gasification plant at Jamnagar. Char is a solid material that results from the conversion process. The gasification plants at Jamnagar will gasify petroleum coke using E-Gas technol-ogy licensed from Phillips 66 to produce fuel and hydrogen for the expanded refinery, petrochemical complexes and captive power plant. The syngas will also be used as feed-stock for future chemicals production. In total, Reliance expects to invest around $11 billion for this refinery exten-sion program which is to be completed in 2016. Reportedly the largest oil refining complex in the world, with an aggregate re-fining capacity of 1.3 million barrels of oil per day.

India Linde awarded contract to build four large ASUsReliance Industries Ltd has also awarded the Linde Group a major contract to build several plants to generate and purify gases for the Jamnagar complex. Linde’s Engineering Division will supply four large air separation units (ASUs) for the production of gaseous oxygen. Massive streams of oxygen will be needed for its proposed petroleum coke and coal gasifica-tion facilities. To treat the synthesis gas generated dur-ing this gasification process, Linde will also deliver two Rectisol acid gas removal units. In addition, they will supply the license, process design, detail engineering and pro-curement services for this project. Linde will also build two additional ASUs to supply high-purity oxygen for ethylene glycol facilities in Jamnagar.

China$1.6 billion coal mining waste-to-syngas projectHainan Dongfang Henghe Energy Develop-

ment Company Ltd. has selected Synthe-sis Energy Systems for a $1.6 billion coal waste to synthetic natural gas (SNG) proj-ect in Jiangxi Province, China. The Jiangxi Province project will be de-signed to convert coal mining wastes into two billion normal cubic meters of syngas per year, and is expected to be built in mul-tiple phases. Both companies have agreed to work to-gether exclusively for this project over the next 12 months to complete commercial agreements for licensing SES technology, equipment supply and service agreements. During this period, Henghe will man-age development of the project including obtaining necessary government approvals. Construction is set to begin some time in 2014.

USRockport IGCC survives legislative challengeThe Indiana House of Representatives delivered developers of the proposed 2,600MW Rockport IGCC plant a ma-jor victory, watering down a measure that could have led to the project’s demise. As a result, the $2.6 billion plant, and the Indiana state government’s contract to buy and then resell its product, is much more likely to survive legislative and legal chal-lenges from opponents who argue that it could saddle ratepayers with higher bills. Lawmakers are debating the wisdom of the 30-year contract negotiated in 2011 by the Indiana Finance Authority to buy the Rockport plant’s synthetic natural gas at a pre-negotiated rate and then resell it to Indi-ana ratepayers at open-market prices. If the Rockport plant syngas prices beat the market rate, those Indiana gas custom-ers would save money. If natural gas prices remain suppressed, ratepayers would pay higher bills. Either way, if the plant is built, all Indiana ratepayers would see 17 percent of their gas bills tied to the Rockport plant’s prices over the next three decades.

USMore hearings set on FutureGen program Illinois State regulators expect to hold an-other round of hearings regarding electricity sales that would be generated by the pro-posed 275MW FutureGen 2.0 coal-gasifica-tion project. The project would repower Ameren’s 200MW Unit 4 coal plant in Meredosia, Il-linois with advanced oxy-combustion tech-

nology to capture approximately 1.3 million tons of CO2 each year - more than 90 per-cent of the plant’s carbon emissions. The Illinois Power Agency will negotiate a purchase contract with FutureGen on be-half of Ameren and Commonwealth Edison customers. Ameren and ComEd have filed notice of plans to intervene in the case. The FutureGen Alliance also is awaiting a decision from the U.S. Dept. of Energy on the start of design work for the $1.65 billion project. The federal agency has committed $1 billion to the project, if it proceeds.

UkrainePre-design and feasibility study for three projectsGaz Ukrainy is reported to be funding a feasibility study and pre-design work for the proposed construction of three coal gas-ification plants: to be located in Severodo-netsk, Horlivka, and Odesa. Study scope includes gasification require-ments for various grades of coal and analy-sis of the physical and chemical charac-teristics of the syngas produced as well as caloric content. Schedule calls for completion of the pre-design and feasibility work to be completed by June 2013.

China New IGCC plant for energy diversificationChina’s regulatory authority has given the green light on preparatory work for a huge coal gasification project in Xinjiang Uygur autonomous region. This is one of four coal gasification proj-ects for which preparatory work has recent-ly been approved and will have the capacity to produce 6 billion cubic meters of syngas annually. The other three, located in Shanxi Prov-ince and Inner Mongolia Autonomous Re-gion, have a combined capacity of 12 bil-lion cubic meters of syngas annually.

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IGCC and Gasification

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