Gas Turbine World 2013

September – October 2013

www.gasturbineworld.com

300MW in 10 minutes with under 2ppm NOx page 12

Old Fr 9s given new life and better performance page 18

Marine gas turbine rated 5MW at 34.5% efficiency page 22

September – October 2013

Gas Turbine World • Vol. 43 No. 5

Editor-in-Chief Robert Farmer Managing Editor Bruno deBiasi European Editor Junior Isles Engineering Editor Harry Jaeger Field Editor Michael Asquino News Editor Margaret Cornett

Fast response flexibility Combined cycle plant combines fast startup response for peaking with high efficiency operation for base load generation, page 12

Marketing Director James Janson Publisher Victor deBiasi

On the Cover. Siemens 550MW El Segundo fast start 5000F combined cycle power plant

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

Executive Office Gas Turbine World 654 Hillside Road Fairfield, CT 06824, USA Telephone (203) 259-1812

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Advertising Sales

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2 Project development and company news

$1.6 billion UK order for 8000H plants, $84 million 700MW Woodbridge Energy Center, 1,260MW NGCC Siberia project

12 El Segundo 550MW rapid response plant

From 0 to 300MW in 10 minutes and full 550MW combined cycle power output in less than 1 hour with 2 ppm limit on NOx

18 Technology transplants for old 9F units

Surpassing OEM design ratings to increase output by up to 8% efficiency by up to 2% and TBO intervals by up to 8,000 hours

22 High power density MT7 marine engine

Compact marine gas turbine engine rated at 5MW shaft output and 34.5% efficiency designed to weigh less than 1,000 pounds

26 Dubal upgrading 2,350MW powerplant

Aluminum producer is upgrading output, efficiency and durability of mixed gas turbine fleet to up productivity and cut costs

30 IGCC power and gasification technology © 2013 Pequot Publishing, Inc. All rights reserved. Reproduction without written permission strictly prohibited. Postmaster, please send Form 3579 to PO Box 447, Southport, CT 06890

Technology transplants New technology hardware and controls software can improve original OEM design rated output, efficiency and durability, page 18

China $4.2 billion coal-to-gas project, syngas production in Mongolia, Tepco and Mitsubishi planning to build 4,500MW of coal-based IGCC capacity

More payload and range Smaller turboshaft engines with 25% more power will increase the payload capacity and double the range of new hovercraft in development, page 22

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.

INDUSTRY NEWS merchant power project to be broadly syndicated in the traditional project finance bank market in many years. The debt syndication was oversubscribed, says GE, reflecting the project’s strong fundamentals. “By providing both capital and technology for the Woodbridge Energy Center, we are applying our skills as banker and builder, drawing on our financial strength, risk management and technical know-how,” said Alex Urquhart, president and CEO of GE Energy Financial Services.

England Turnkey order for 8000H 2x1 combined cycle plants InterGen says it has awarded Siemens a turnkey order to supply and build up to 2.1GW of H-technology gas-fired combined cycle generation capacity at two sites in the UK: Spalding Energy in Lincolnshire and Gateway Energy Center in Essex. These will be the first 8000H-technology power plants in the UK and the most advanced, says InterGen, capable of operating at a combined cycle design efficiency of over 60%. Turnkey installed cost of the two plants is estimated at around US$1.63 billion (£1 billion GBP), No further details have been released. Presumably, the two plants will be similar in design and rating. Most likely Siemens’ SCC5-8000H 2x1 combined cycle plants which are nominally rated 1.14GW each and more than 60% efficiency at 59°F (15°C) sea level ISO conditions. At the nominal capacity rating of 2,100MW quoted by InterGen, and estimated $1,603 million equipment and combined construction price, that works out to an installed cost of around $775 per kW for each plant – not counting the cost of financing, project development and related owner’s costs. New Jersey 700MW FlexEfficiency project has an estimated $842 million price tag Competitive Power Ventures (CPV) is building a natural gas-fired 700MW Energy Center in Woodbridge, New Jersey that will be powered by a 2x1 FlexEfficiency 60 combined cycle plant. Project development is being financed through GE Energy Financial Services and ArcLight Capital Partners who arranged to anchor $561 million in senior secured credit against an estimated $842 million total cost for the complete project. Financial details have not been disclosed. Construction is scheduled to begin in the last quarter of 2013 and commercial startup in the first quarter of 2016. The plant expects to sell its capacity through 15-year standard offer capacity agreements with New Jersey utilities. GE Power & Water has a $260 million order to provide a FlexEfficiency 60 com2 GAS TURBINE WORLD September – October 2013

bined-cycle engineered equipment package and engineering services for the 700MW plant. In addition, there is a 16-year contractual services agreement to support long-term plant reliability and availability. The equipment package includes two fast-start fast-ramping 216MW 7F 5-series gas turbine generators, one D-11A steam turbine generator, and two duct-fired triplepressure reheat HRSGs in a 2x1 configuration. Without supplementary duct firing, GE’s 2x1 7F-5 standardized reference plant is design rated at 655MW net plant output and 59.0% combined cycle efficiency, at 59°F and sea level site conditions on natural gas fuel. The addition of duct firing raises output of the Woodbridge CPV plant to its nominal 700MW rating at slightly lower efficiency. Reportedly, the project debt that GE Capital Markets arranged is the first sizeable project financing of a greenfield, partial-

California Over 700MW of combined cycle peaking capacity Calpine reports that its 429MW Russell City Energy Center near Hayward and 309MW Los Esteros Critical Energy Facility near San Jose entered commercial service just ahead of this summer’s peak demand period. The full power output of both plants is going to Pacific Gas and Electric which is supplying natural gas fuel for both plants under 10-year power purchase sales agreements. The California power grid expects about 2,000MW of new gas-fired generation to come online this year, according to the regional power market monitor’s report. As more wind and solar generation comes online to meet the state’s 33% renewable mandate by 2020, the grid agency is looking at the need for backup gas-fired generation to maintain grid reliability. Calpine’s more efficient power plants in the western United States produced 17 percent more electricity in the second quarter this year compared to 2012. This is attributed to the state’s effort to limit carbon emissions from old plants and to a reduction in hydro power. Western Siberia 1260MW combined cycle project nears completion Fortum’s nominally rated 1260MW gas-fired combined cycle power station in Western Siberia is almost two-thirds the way towards completion. The power station that is being built in the town of Nyagan is designed around three 420MW combined cycle units. The first, Nyagan No. 1, was commissioned in April 2013. No. 2 currently undergoing final stages of testing should be commissioned by the end of 2013 and No. 3, the last unit, is scheduled for commercial startup by the end of 2014. When completed, the power production capacity of this state-of-the-art natural gas-fired station will be approximately 1,260MW.

November 2013 Update

J

- Series Gas Turbines

www.mpshq.com

Successful implementation of the M501J continues around the world... n Validated record breaking turbine inlet temperature of 1,600°C (2,912°F) n First commercial J-Series unit, in operation since 2011, with more than 12,400 AOH and 136 starts to date n Eight M501J units now in commercial operation n First unit of the 2,919 MW Himeji No. 2 C/C Plant went commercial early, and the second unit is in advanced stage of commissioning. n New turnkey order (6x501J) – Taiwan Power Company C/C power islands totaling 2,600 MW n Global 60 Hz fleet, now 24 units

Mitsubishi Power Systems Americas, Inc. | 100 Colonial Center Parkway | Lake Mary, FL 32746 USA | 1-407-688-6100

Industry News Iowa Alliant planning $700 million 600MW combined cycle plant In the wake of cancelled plans to build a large coal-fired generating station, Alliant Energy’s Iowa utility company plans to build a nominal 600MW natural gas-fired combined-cycle plant on the site of the Sutherland station in Marshalltown. Alliant expects to receive appropriate regulatory decisions by the end of this year to proceed. If approved, the utility expects to begin construction in 2014 with an anticipated commercial startup date in 2017. The cost of the new 600MW Marshalltown plant is estimated at $700 million. To supplement its power output, Alliant says it will extend for 11 years an expiring agreement to buy power from the state’s only nuclear plant. The agreement to buy 430MW of power from NextEra Energy’s Duane Arnold Energy Center from 2014 through 2025 will lessen capacity needs of the new combined cycle plant and keep nuclear as a significant part of the utility’s energy mix. Saudi Arabia $700 million supply order for 7F-5 combined cycle projects Saudi Electricity Company has awarded General Electric a contract valued at nearly $700 million to supply 7F-5 technology gas turbines and associated equipment and services for two new combined-cycle power projects, PP13 in Dhurma and PP14 in Riyadh. Scope of supply includes 12xGE 295.6MW 7F-5 gas turbines, 4xGE steam turbines and 16xGE generators. Initial shipments are expected to start at the beginning of 2015.The contract also includes two service agreements, one for each site, covering planned maintenance on the units for a fixed period of eight years. Earlier this year, WorleyParsons was awarded a contract valued in excess of $120 million to design and manage construction of the PP13 and 14 greenfield projects. Design specifics and performance have not been disclosed. However, the number of gas and steam turbine units on order suggests that each project is being designed around two 3x1 combined cycle plant configurations (three 7F-5 gas turbines, three unspecified HRSGs and one steam turbine generator). Design ratings for a 3x1 7F-5 combined cycle plant are not readily available. Speculatively, based on the 665MW and 59.0% rating for a 2x1 configuration, the 3x1 design could be close to 990MW and 59.4% efficiency – at 59°F and sea level site conditions.

4 GAS TURBINE WORLD September – October 2013

GE says that its advanced 7F-5 technology will provide significant fuel savings and lower emissions to meet the Kingdom’s growing energy needs with the ability to respond to dramatic daily changes in power demand. US Emerson and Mitsubishi expand scope of turbine control retrofits Emerson Process Management and Mitsubishi Power Systems Americas have expanded their scope of control system retrofits to include steam turbines. Emerson’s expertise in control systems design for the power industry, teamed with Mitsubishi’s experience in gas and steam turbine technology and service, offer owneroperators a competitive alternative to OEMs for control systems maintenance and replacement. Their alliance now supports overhaul and maintenance in the Americas for W501F, 501B, 501D5A and W251 gas turbines as well as all Mitsubishi and Westinghouse technology steam turbines. Recent projects include mechanical upgrades and installation of Ovation control systems at two power plants in Texas. Massachusetts 692MW duct fired 7F-5 NGCC plant Footprint Power Salem Harbor Development LP has been approved to construct and operate a nominal 630MW natural gas-fired quick start combined cycle facility at Salem Harbor Station. With duct firing under summer conditions, the new facility will be capable of generating an additional 62MW for a total output of 692MW. Construction is scheduled to begin in June 2014 and continue for a period of approximately 23 months before the start of commercial operation in June 2016. The existing Salem Harbor Station is comprised of four steam electric generator units. Coal-fired boiler

units 1 and 2, rated at 84MW and 81MW respectively, were removed from service in 2011. Coal-fired boiler unit 3 rated at 150MW and oil-fired unit 4 rated at 440MW are to be permanently shut down by June 2014, Proposed facility is to be powered by two FlexEfficiency 60 combined cycle plants design rated at 315MW each (346MW with duct firing). The gas turbines are to be equipped with dry low NOx combustion to limit emissions and with evaporative cooling to augment hot day power output. The 7F 5-series 1x1 combined cycle reference plant design is nominally rated at 323MW gross and 58.2% efficiency at 59°F sea level site conditions on natural gas fuel. Salem Harbor $200 million contract for 7F-5 FlexEfficiency CC gas turbines Footprint Power has awarded General Electric a contract valued at $200 million to supply FlexEfficiency 60 equipment for redeveloping the existing coal-fired Salem Harbor Station into a new natural gas combined cycle facility. GE says that the new facility will be powered by two 215.8MW 7F-5 series gas

ENEL MACHINERIES AND SPARE PARTS FOR SALE Until February 15 th 2014 it is possible to qualify for the Enel machineries and spare parts sale process. Main equipments on sale are Turbogas, Trafos, Generators, spare parts and components of different types. For more information visit the website http://globalprocurement.enel.com/en-GB/ Reference: Enel Servizi S.r.l. – Italy Procurement – Generation Procurement – Via Arno, 42 – 00198 Roma; e-mail: [email protected]

turbines, making it the first “rapid response” power plant to be deployed in New England with capability to add 300 MW of power to the grid within 10 minutes. Operationally, this will support the continued deployment of wind and other renewable energy sources, while maintaining an efficiency level that rivals any fossil fuel unit in New England. According to GE, the plants will be among the most environmentally advanced in the country, meeting or exceeding the environmental performance of every other fossil fuel power-generating facility in New England. For example, the new facility will reduce regional carbon emissions by an average of approximately 450,000 tons per year. It will also have the ability to turn down during off-peak hours, eliminating the consumption of extra fuel and emissions output associated with a plant startup. With the new plant in service, it is projected that regional NOx emissions will be reduced by 10 percent; SO2 emissions will be reduced by 8 percent; and mercury emissions will be reduced by 6 percent. These reductions result from the efficiency and flexibility of the 7F-5 gas turbine equipment in the new facility, says GE, and HRSG design which will house an oxidation catalyst to limit CO followed by ammonia injection and SCR catalyst to further limit NOx. The plant will also use air-cooled condensers, completely eliminating the use of hundreds of millions of gallons of water per day from Salem Harbor for once-through cooling. According to ISO New England, the new Salem Harbor combined cycle facility is needed to maintain the reliability of electricity supply in the greater Boston area beginning on June 1, 2016. In February 2013, Footprint cleared the ISO-NE “Forward Capacity Auction” to supply electric generating capacity beginning in 2016. The project will receive a five-year capacity payment incentive to construct the facility and fill the power gap in the Northeastern Massachusetts/Boston zone. The existing coal and oil-fired Salem Harbor Station will shut down at the end of May 2014, and GE’s equipment will ship in late 2014/early 2015. Commercial operation of the new facility is planned for June 2016. Poland Turnkey order for 133MW combined cycle CHP plant Polish energy utility PGE has awarded Siemens Energy a turnkey contract to supply and build a nominally rated combined heat

and power plant in Gorzów Wielkopolski. Commissioning is planned for early 2016. The natural gas-fired Gorzów facility will be powered by two Siemens SCC-800 1x1 combined cycle plants ISO rated at 66.6MW and 53.8% combined cycle efficiency each for electric power generation. In combined heat and power mode of operation, with 90MW of thermal output in the form of steam extraction for district heating, the CHP plant is rated at 84% fuel efficiency. Siemens contract scope of supply includes turnkey construction, two 50.5MW SGT-800 gas turbines, one SST-400 steam turbine, three 11 kV generators, two HRSGs and a 12-year maintenance agreement for the gas turbines. Order value for Siemens, including the long-term service agreement, is valued at around Euro 160 million (US $220 million). Compared to the old coal-fired power plant it replaces, the new combined cycle CHP facility will produce 95% less sulfur dioxide, over 30% less NOx and over 95% less particulate emissions. Missouri $170 million to convert V84.3A peaker to combined cycle mode Empire District Electric Company is converting its nominally rated 150MW gas turbine peaking plant (Riverton unit 12) into a combined cycle plant to increase power output and efficiency while reducing emissions. Provisions were made when installed in 2007 to facilitate its eventual conversion to combined cycle operation. The original Siemens Westinghouse V84.3A(2) natural gas-fired plant was nominally rated at 150MW output and 38% simple cycle efficiency. It is expected that the combined cycle conversion will be upgraded to around 250MW output and 56% combined cycle efficiency for base load duty. Empire has awarded Burns & McDonnell the EPC contract to complete the project in the spring of 2016 to replace capacity provided by steam boiler units 7 and 8 which will be retired in conjunction with its commissioning. The total cost of the combined cycle conversion is unofficially estimated at $170 million. This will require the addition of a supplementary fired HRSG, condensing steam turbine generator and cooling tower for the bottoming steam cycle. The original V84.3A gas turbine already incorporates dry low NOx combustion to limit emissions. To reduce emissions even further, the duct-fired HRSG design will include an oxidation catalyst to control CO and volatile organic compound emissions, followed by

selective catalytic reduction to limit NOx emissions. Upon completion of the combined cycle project in 2016, the three most senior generators at Riverton, Units 7, 8 and 9, will be retired. Units 7 and 8 historically operated on coal fuel, but were transitioned to natural gas operation in 2012. After more than 100 years, this transition brought to a close the coal generation era at Riverton. International Wood Group GTS and TurboCare joint venture Wood Group and Siemens have entered into an agreement to form a joint venture that will integrate the maintenance and power solutions businesses of Wood Group GTS with the international aftermarket gas turbine, steam turbine and generator design, repair and manufacturing services currently provided by TurboCare (Siemens business unit). In effect, Siemens is contributing the TurboCare global business and Wood Group contributing a large portion of its Gad Turbine Services (GTS) portfolio. The resulting ownership is to be Wood Group 51% and Siemens 49%. Wood Group’s gas turbine activities are to be limited to joint ventures including Rolls Wood Group, TransCanada Turbines and Sulzer Wood companies which are not part of the planned joint venure, A name for the new company will be announced upon conclusion of negotiations expected in the first quarter of 2014 subject to a range of conditions including merger approvals. Basically, the proposed organization sees itself as a global rotating equipment service provider to the power generation, oil & gas and industrial sectors to build on the complementary strengths of Wood Group and Siemens in these sectors to grow the business. What the Wood Group brings to the party is in-depth experience in asset operations, maintenance, risk management and life-cycle optimization as well as power plant construction services worldwide. Plus, it has a strong presence in the oil & gas and process industries. TurboCare, which primarily operates in the power generation segment, is widely known and respected for its aftermarket gas turbine, steam turbine and generator design, repair and manufacturing services. Together, say company executives, the new company will have greater capability to operate in an expanded global market. The senior leadership team will comprise Mark Dobler from Wood Group GTS

GAS TURBINE WORLD September – October 2013 5

Industry News as CEO, Neil Sigmund from TurboCare as Deputy CEO, and Chris Watson from Wood Group GTS as CFO, supported by management drawn from both parent companies. The still-to-be-named JV company will be the OEM provider of parts, components and associated overhaul and repair services for the generally more mature Fiat and Westinghouse turbines (up to W501D4) and, through Wood Group Pratt & Whitney, Pratt & Whitney FT4 and GG4 gas turbines. It will operate as an authorized service provider of maintenance, supply chain and construction services to OEMs (including Siemens) for gas turbines, steam turbines, generators and other rotating equipment. And operate as an independent aftermarket service provider across a broad range of OEM equipment (including GE and Solar Turbines) including parts, components, overhaul and repair services. It also will provide overhaul & maintenance and engineering, procurement, construction (EPC) services for cogeneration, combined cycle and simple cycle gas turbine configurations. South Carolina Duke seeking approval for a 750MW combined cycle plant Duke Energy has filed an application with South Carolina regulators seeking approval to build a 750MW natural gas-fired combined cycle power plant to be sited at the existing Lee Steam Station in Anderson County, South Carolina. Duke filed the application in partnership with the North Carolina Electric Membership Corp. which will own 100MW of the project if constructed. According to Duke, the company has not made a final decision to build a facility at the Lee Steam Plant, but “it is prudent to continue with the regulatory actions necessary to keep the project moving forward.” If Duke does decide to build the facility, construction could begin after the company receives regulatory approval, with the plant beginning commercial operation as early as June 2017. Australia 242MW SGT-800 combined cycle nearing initial startup Diamantina Power Station Ltd. is developing a site rated 242MW natural gas-fired combined cycle project near Mount Isa in the state of Queensland site rated at 242MW plant output and 51% combined cycle efficiency. The plant is being built around two SGT800 2x1 combined cycle power blocks with bypass capability to operate in simple cycle 6 GAS TURBINE WORLD September – October 2013

mode. Each block consists of two SGT-800 gas turbines, one inlet chiller (for summer operation) two NEM twin pressure HRSGs and one SST-400 steam turbines with associated balance of plant equipment for the steam bottoming cycle. Siemens is responsible for the overall plant design and is providing technical advisory services during the construction and commissioning phases of project development. Siemens scope of equipment supply includes 4 x gas turbines, 2 x steam turbines and the 4 x HRSGs. Diamantina is on schedule to be fully operational next year, with the first block available in late 2013 and the second block available in the first half of 2014. Total cost of the project is estimated at around AU $500 million (US $455 million). Texas Developer proposing 470MW multi-unit simple cycle plant The Texas Commission on Environmental Quality has issued an air permit to Guadalupe Power Partners for a proposed 470MW peaking plant to be built outside San Antonio that will be powered by multiple simple cycle units. On a fast-track schedule, with financing and permitting in place, the peaking plant could be installed and commissioned for commercial service by mid-2015. The project developers are also working to obtain a greenhouse gas permit from the Environmental Protection Agency. Today’s aeroderivative and small industrial gas turbines are designed to reach full output within less than 10 minutes of a cold start which is fast enough to qualify for nonspinning reserve capacity. They are also fast ramping up and down for intermittent renewable power backup. The Guadalupe project is reported to be one of about 10 similar generation projects totaling 4,200 MW under development in Texas’ primary grid that is overseen by the Electric Reliability Council of Texas (ERCOT). Other developers have obtained or are seeking permits to build another 8,200MW of combined cycle generation in ERCOT, according to Reuters data, which are capable of peaking as well as intermediate power generation due to their fast startup, high ramp rate, cycling and very low part-load operation. Currently, Panda Power Funds, Calpine Corp. and the Lower Colorado River Authority are constructing 2,800 MW of additional gas-fired generation in ERCOT. Many developers, however, are said to be waiting for the Public Utility Commission to show support before committing to build new projects.

Guadalupe Power Partners is owned by Minnesota-based Wayzata Investment Partners and managed by Navasota Energy which in the past built and operated two 550MW gas turbine plants in Texas. According to the state permit, Guadalupe will pick either a GE or Siemens high efficiency gas turbine model for its proposed peaking plant. England RWE contract award for GT26 performance and life upgrade Alstom has agreed plans for a major upgrade with RWE Generation to implement its high performance MXL2 upgrade package on all nine gas turbines at the 2,200MW Pembroke and 1,650MW Staythorpe facilities – Britain’s two biggest gas-fired combined cycle power plants. The five GT26 gas turbines at Pembroke and four at Staythorpe will each be retrofitted with the multi-mode MXL2 upgrade, which offers increased performance, substantial improvements to operational efficiency and enhances availability through increased maintenance intervals. This agreement also includes a comprehensive maintenance program for the RWE Generation GT26 fleet across Europe (including Staythorpe and Pembroke in the UK, and Claus-Maasbracht in the Netherlands). The MXL2 upgrade offers GT26 owneroperators two key benefits, says Alstom, depending on choice of operation. In the M mode, gains of 13-23MW in power output are possible for combined cycle, along with a possible 0.7 to 0.8% point increase in efficiency. In the XL mode, component lifetime is extended to allow up to an additional 8,000 operating hours before the next Type C hot gas path inspection which increases availability and reduces maintenance costs. In addition, overall plant output is expected to increase by 4-12MW and 0.4 to 0.5% point increase in efficiency. Canada 7F-3 efficiency upgrade worth $900,000 a year in fuel savings GE and TransCanada are working together to help recast the energy generation landscape to the benefit of both the power provider and its customers. Driven by GE’s 7F-class gas turbine upgrade portfolio, TransCanada’s Ravenswood power plant in New York and 167MW Mackay River cogeneration facility in Alberta, Canada, are delivering more power while reducing operational costs and emissions. FlexEfficiency upgrade options, which

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Industry News couple advanced gas path hardware with performance-enhancing software, were installed on one natural gas-fired 7F 3-series gas turbine at each plant. The Ravenswood combined-cycle unit has experienced an output increase of nearly 5% from the upgrade, says GE, while Mackay River plant output saw a 10% increase in output. Additionally, Ravenswood and Mackay River have experienced fuel efficiency increases of more than 1% and 2% respectively. TransCanada says it expects these efficiencies to result in a total of approximately $900,000 in annual fuel cost savings for the company, as well as new revenue opportunities for Ravenswood in bidding into the area’s power market. The Mackay site has also experienced a reduction in emissions of approximately 160 tonnes of NOx per year. Kentucky 640MW NGCC planned to replace retired 800MW of coal-fired units Louisville Gas and Electric and Kentucky Utilities have announced plans to apply for permission to construct a second natural gas combined-cycle generating station (in

Muhlenberg County) and a solar generating facility. The two companies had previously announced retiring 800MW of old coal-fired generation (at Cane Run, Green River and Tyrone stations) and building a 640MW NGCC unit at Cane Run. A request for proposals was issued in September 2012 to address the amount of lost generating capacity in light of long-term load growth. Competitive bids that were submitted included renewable energy, existing energy within Kentucky and building new generation. Building a second NGCC at the existing Green River site proved to be the best long-term solution for base load generation. Details are being finalized, but the plant is expected to have about 700MW of capacity and cost approximately $700 million to construct. Additionally, they want to construct a nominal 10MW solar facility costing approximately $25 million at one of its existing generating stations. Several sites are under consideration. The companies plan to file a certificate of public convenience and necessity for the new NGCC plant and solar facility before

the end of this year. The utilities intend to have the NGCC plant online in 2018 and the solar facility online in 2016. If approved, LG&E and KU’s generation capacity will be 59% coal-fired, 40% natural gas-fired and 1% renewable. Maryland Control system upgrade to improve starting reliability Emerson Process Management has replaced aging turbine and balance-of-plant controls with its Ovation expert control system at Exelon Generation’s Westport unit 5 station in Baltimore, Maryland. This 116MW simple cycle peaking unit has a unique configuration consisting of eight Pratt & Whitney aeroderivative GG47 gas generators that are coupled with four Worthington Model ER-224 double-flow expander turbines. If any pair of turbines is taken offline, the unit still generates power, as the remaining turbines blend operation to maintain load on the generator. As part of this turnkey project Emerson also installed eight natural gas-fuel modulation valves, 16 gas-fuel stop valves and eight gas-fuel vent valves.

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Building Confidence Bechtel is among the most respected engineering, project management, and construction companies in the world. Bechtel operates through five global business units that specialize in power generation; civil infrastructure; mining and metals; oil, gas and chemicals; and government services. Since its founding in 1898, Bechtel has worked on more than 22,000 projects in 140 countries on all seven continents. Today, our 53,000 employees team with customers, partners and suppliers on diverse projects in nearly 50 countries. We stand apart for our ability to get the job done right—no matter how big, how complex, or how remote.

Industry News Emerson says that they managed to complete the project within a compressed schedule of roughly six months. This timeframe was necessary in order for the unit to be available to meet peak summer demand. Kazakhstan-China RB211 compressor units to power Asia-China pipeline Rolls-Royce announced a $175 million contract to supply Asia Gas Pipeline with twelve RB211 gas turbine powered pipeline compressor units. They will be installed to power four compressor stations along the 1,115km Line C gas pipeline section of the vast 1,833km long Central Asia-China gas pipeline network. When it reaches full operating capacity in 2016, the Central Asia-China network will transport up to 55 billion cubic meters of gas each year from Turkmenistan and Uzbekistan to China through Uzbekistan and Kazakhstan. The Line C pipeline in Kazakhstan will contribute up to 25 bcm per year of the total capacity, including potential to supply gas domestically to the Republic of Kazakhstan. Rolls-Royce will manufacture and package the equipment at its energy facilities in Montreal, Quebec and Mount Vernon, Ohio. Russia LMS100s to provide peaking power for the Olympic games GE announced that two of its LMS100-PB gas turbines that will supply power for the Krasnodar region and peaking backup during the 2014 Winter Olympic Games are close to being commissioned. The units, which are sited at Inter RAO’s Dzhubginskaya thermal power plant, can start up to reach full power output in less than 10 minutes. They also feature DLE 2.0 dry low emissions technology, which eliminates the need for water injection to reduce NOx emissions. The 50Hz LMS100-PBA is ISO rated at 99MW and 44.3% simple cycle efficiency at 15°C sea level on natural gas fuel. Norway First offshore application for LM6000 gas turbine power Norway Statoil Petroleum has entered into two 5-year agreements for GE Oil & Gas to supply equipment as well as services to support Statoil’s installed fleet of GE turbomachinery. GE Oil & Gas Global Services will support the new equipment sold to Statoil and also provide aftermarket components and equipment for Statoil’s installed fleet of GE


turbomachinery equipment. The service agreement includes spare parts, upgrades and repair service as well as field service engineers and training. GE’s first equipment order (under the agreement) is to supply LM6000 mechanical drive gas turbines for operation in the Aasta Hansteen field and LM2500 gensets for SeaSmart offshore packaging. Oman 1.5GW combined cycle capacity on schedule Siemens Energy and its consortium partner GS E&C have commissioned Sohar 2 and Barka 3 combined cycle plants in the Sultanate of Oman on schedule. Generating 750MW each, the plants will add 1.5GW of electrical generating capacity, raising the Sultanate’s current existing capacity to approximately 6GW. Siemens scope of supply included two 292MW SGT5-4000F gas turbines, one SST5-5000 steam turbine, three SGen52000H generators, electrical equipment and the SPPA-T3000 instrumentation and controls system. GS E&C supplied the HRSGs and was responsible for the civil construction work, electrical transformers and ancillary systems as well as equipment installation. Russia Huge gas turbine compressor order for LNG megaproject GE has received an order to provide key turbomachinery equipment for the Yamal liquefied natural gas (LNG) megaproject being developed on the Yamal Peninsula in Russia’s northern Siberia region. Consortium made up of Technip in France and JGC in Japan have been awarded the EPC contract for three production trains, each with the capacity to produce about 5.5 million tons of LNG a year. Each train to consist of two main refrigeration units for converting natural gas into LNG for transportation. In all, GE will supply six Frame 7E gas turbines (86MW each), 18 centrifugal compressors, six variable speed drive (24MW each) and six waste heat recovery units. The gas turbines are to be manufactured in Greenville, South Carolina, and the compressors in Florence, Italy. The two complete turbo compressor systems also will be string tested in Italy. Meanwhile, GE Power Conversion facilities in France will test the variable speed drives prior to shipment. In addition to equipment supplies, the order also covers installation supervision

and technical support at the commissioning stage. GE is scheduled to deliver the equipment to Russia in the second half of 2015. According to project plans, the first gas liquefaction train is to reach its full capacity in 2017 followed by the second and third trains in 2018 and 2019, respectively. UAE Offshore oil platform order for five Trent 60 generators Rolls-Royce has a contract to supply Abu Dhabi Marine Operating Company with power generation equipment and related services to help boost oil and gas processing at an offshore project in the United Arab Emirates. The contract for the Satah Al-Razboot (SARB) offshore project was awarded to R-R by the Korean engineering, procurement and construction firm, Hyundai Engineering and Construction. Rolls-Royce will supply five Trent 60 gas turbine generator sets to power offshore production platforms and oil and gas processing facilities on Zirku Island. Each Trent 60 gas turbine is capable of producing up to 66MW of power and will feature low emissions technology to minimize environmental impact. Scope of the SARB project includes the construction of facilities to transfer oil that will be produced by eighty-six wells tapping the offshore field located about 120 km northwest of Abu Dhabi. Equipment related to collection and transport of that oil will be constructed on two artificial islands. In addition, Hyundai will build a facility in Zirku Island to separate gas from crude oil collected in the SARB and Umm Al Lulu oil fields. That oil and gas processing facility will have a daily capacity of 200,000 barrels of oil and 35 million cubic feet of gas. Abu Dhabi Marine is 60% owned by the Abu Dhabi National Oil Company, with the remaining 40% shareholding divided between BP, Total and JODCO.

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El Segundo combined cycle offers 300 MW of peaking in 10 minutes

By Junior Isles

550MW Flex-Plant 10 combined cycle project represents a growing trend in the use of combined cycle technology that has the ability to provide peaking and base load power to complement intermittent renewables.

O

n September 12th, NRG Energy Inc. inaugurated what is only the second combined cycle plant in the US to use Siemens “Flex-Plant” technology. The new facility, in El Segundo, California, represents what is a growing trend among US operators to install plants that have the operating flexibility to back up the growing amount of renewable generation on the grid in markets like California. The El Segundo Energy Center features two Siemens Flex-Plant 10 fast-start SCC6-5000F 1x1 combined cycle power blocks. Performance highlights include the ability to deliver 300MW in 10 minutes and limit transient NOx emissions during operation to 2 ppm. More specifically: o Rating. Each power block is rated at 275MW net output (at 85°F design point) for a total plant output of 550MW at 48.9% combined cycle efficiency. o Fast start. Each SGT6-5000F gas turbine can deliver 150MW of nonspinning reserve peaking power within 10 minutes of startup, for a total of 300MW. o Emissions. Entire combined cycle block can ramp up and down at 3035MW per minute while maintaining 2 ppm NOx stack emissions and virtually no CO.


The El Segundo Energy Center is the latest move in NRG’s ongoing drive to lower emissions from its thermal generating fleet while at the same time allowing greater use of renewables and the gradual replacement of aging steam units at the site. The original plant at the El Segundo facility comprised four natural gas fired steam units – Units 1 and 2 which began operating in the 1950s and Units 3 and 4, which had been running since the 1960s. Units 1 and 2 were retired in 2002 and demolished in 2010 to make way for the two new units. Unit 3 has also since been retired as part of the permitting of El Segundo Energy Center, while the 335MW Unit 4 is still operating. In addition to helping the integration of renewables, the new plant will enable the site to reduce the consumption of potable water by nearly 90%; allow NRG to meet or exceed the State and South Coast’s strict air quality standards; and require 30% less natural gas per MW produced than the original steam boilers. Also, the removal of two large oil tanks at the south end of the property will lower the site’s profile and reduce the overall visual impact. Meeting demand The repowering project has long been in the making. NRG first proposed the project in response to identified

demand by California’s Independent System Operator (ISO). Population continues to expand to the eastern parts of the Los Angeles basin, where summer hot spells make air conditioning a necessity. Regional resources have not kept pace with this growth and the recent closure of the SONGS nuclear plant has resulted in the need to produce even more electricity than was previously thought. The California Public Utilities Commission has determined that about 2000MW of locally produced power will be required to meet the region’s energy demand by 2016. The repowering project is therefore essential for local energy reliability. In terms of operation, each of the 1x1 combined cycle units is permitted to start 200 times per year to meet both California’s base load and peak load demand. Although NRG has committed to a capacity factor of about 60%, which equates to a little over 5400 hours a year, the plant must be available 24/7. Commenting on the new plant, Richard Loose, Siemens’ Director of Marketing Energy Solutions, Americas, says: “When you look at the plant, you might think it looks like any other 1x1 combined cycle, but the unique thing is that it’s actually a peaker. When you hit “start” each block delivers 150MW in 10 minutes; for a combined cycle that’s gamechanging technology.”

Change of plan Originally, the proposed plant was to be a 2x1 combined cycle plant designed to use ocean water for cooling. Accordingly, NRG was issued a licence in 2005 by the California Energy Commission for a 630MW ocean-cooled base load plant. In 2007, however, the company moved to an air-cooled configuration as explained by George Piantka, Director of Environmental Business for NRG West Region, who has been part of the permitting effort since 2000, first as a consultant and then as an employee of NRG. He recalls that the decision to switch to a configuration that used air cooling allowed the retirement of around 400 million gallons per day of ocean water cooling. This was in compliance with the objectives of the State Water Resources Control Board, ultimately approved in 2010. Cooling is provided by low profile, air-cooled heat exchangers (ACHEs), which remove the energy and condense the steam, feeding condensate down a condensate receiver back into the cycle. Adopting this air cooling design allowed water usage to be reduced by about 90 percent. Also, the old plant did not have its own sanitary discharge system. So, as part of the infrastructure improvements, the new plant is connected to the city’s sanitary discharge. The facility is also designed for zero liquid discharge. Fast start technology The new plant features two power islands delivered by Siemens. Each unit comprises an SGT6-5000F gas turbine, an SST-800 steam turbine, an SGen6-100A-2P generator, a heat recovery steam generator and an air-cooled heat exchanger. Siemens also supplied the complete electrical equipment and the SPPA-T3000 power plant instrumentation and control system. The SGT6-5000F at the heart of the plant is capable of reaching

150MW in 10 minutes, full gas turbine output in less than 15 minutes and full plant output (GT at base load, ST valves wide open) in less than 60 minutes. The plant is also designed to ramp up or down at 30MW per minute between 100% and 55% gas turbine load, while maintaining emissions at the stack to less than air permit levels. According to Siemens, the plant’s fast start capability to deliver 200MW in 30 minutes or less can result in a 30% reduction in greenhouse gas emissions when compared to traditional F-class combined cycle plants. Since first introduced in 1993, the 5000F engine has evolved over time, with improvements made to increase efficiency and power output, extend maintenance intervals and enhance operating flexibility.

Design features According to Siemens, the engine is now designed for high reliability and frequent ramping without any service or increased maintenance penalty for fast startup and fast ramping. It features a 13-stage compressor with four rows of variable compressor guide vanes enabling high efficiency at part load as well as at base load. The compressor is connected to the 4-stage turbine by a single tie-bolt. There are no nickel-based alloys used in the rotor construction. Instead, the rotor uses upgraded steel discs in the turbine section with a rotor air cooler to allow for greater flexibility in turbine blade cooling air temperature. The engine is offered with an option of two combustion systems. The latest version of the turbine uses an

Renewables driving combined cycle flexibility California is among the strictest states in the US with regards to power plant emissions. In 2006, lawmakers passed the California Global Warming Solutions Act – a bill that requires the Air Resources Board to adopt a state-wide greenhouse gas emissions limit equivalent to the state-wide greenhouse gas emissions levels in 1990 to be achieved by 2020. At the same time, it adopted a Renewable Portfolio Standard, increasing the amount of electricity generated by renewables from 17 percent to 20 percent by 2010. This was expanded in 2011, requiring that the amount of electricity supplied by renewables reaches 33 percent of total generation by 2020. The burgeoning amount of renewables on the grid requires additional peaking capacity to compensate for the variability of renewable generation such as wind and solar. In the US, gas-fired simple cycle peaking power plants have become the preferred technology for providing this renewable support. Manufacturers, however, are also working to improve the flexibility of combined cycle gas turbine (CCGT) plants that are also capable of backing up intermittent renewables, but with much higher electrical efficiency than peaking plants. In August last year, the Northern California Power Agency inaugurated the Lodi Energy Center – the first operating Siemens FlexPlant 30 combined cycle gas turbine power plant in the USA. Now, one year later, a second Flex-Plant owned by NRG Energy has started up in California, this time in El Segundo. In addition to featuring Siemens Flex Plant technology, the site-rated 550MW facility is notably the first to incorporate NEM’s new DrumPlus heat recovery steam generator design.


ultra low NOx (ULN) combustion system that employs 16 can-annular combustors to reduce NOx levels to less than 9 ppm. The ULN system uses five fuel stages to mix the natural gas with combustion air. The pilot and the main pre-mixers (on the combustor support housing) employ swirler fuel injection, where the fuel is injected off the swirler vanes. This provides more injection points and better mixing than the previous dry low NOx combustor. In addition to reducing NOx, the ULN combustion system controls CO, volatile organic compounds (VOC) and particulate emissions. Reduced low load CO emissions are achieved by operational modifications and bypassing supplemental cooling air around the combustor. Bypassing air around the combus-

tor increases combustor flame temperature, which leads to reduced CO production. In this version, CO emissions are kept below 10 ppm down to at least 40% load, without alteration to the internal architecture of the combustion system. This allows greater flexibility during cyclic operation. First-of-a-kind Exhaust gas leaving the gas turbines at a temperature of about 582°C (1079°F) is fed into an HRSG used to generate steam to drive the steam turbine. Interestingly, these combined cycle units feature first-of-akind HRSG technology developed by NEM. Unlike Lodi, which is a Flex-Plant 30 design that incorporates a triple pressure boiler, the Flex-Plant 10 at El Segundo has a single pressure boiler, producing 78.3 kg/s of steam at a tem-

perature of 502°C and a pressure of 99.6 bar. Although double and triple pressure versions of the boiler are available, the single pressure version was used at El Segundo due to space constraints at the site. Steam from the HRSG is fed to the backpressure non-reheat steam turbine for an additional 70MW per train and resulting in an overall plant electrical efficiency of about 49 per cent. This is around 9-10 percentage points higher than a traditional simple cycle gas turbine peaking plant. The innovative heat recovery steam generator design allows the Flex-Plant 10 to not only meet the challenging emission regulations in California but also, according to NEM, is the most economically competitive solution for peak-to-intermediate duty cycles.

550MW El Segundo plant. Rated at 550MW and 48.9% efficiency powered by two gas-fired SCC6-5000F Flex-Plant 10 combined cycle blocks. Each plant is designed around a 5000F gas turbine-generator (which can generate 150MW in less than 10 minutes and reach full load in 12 minutes), HRSG with standard SCR/CO catalytic reactor, single-pressure non-reheat bottoming cycle with an air-cooled heat exchanger for backpressure steam condensing. 14 GAS TURBINE WORLD September – October 2013

HRSG design NEM worked with Siemens on the boiler design for the El Segundo units. According to project engineers, the key consideration in its design was that it should not restrict any operation of the gas turbine. The design of the DrumPlus boilers ensures that no hold points are imposed on the gas turbine during startup. Instead of having a large high-pressure steam drum, the water/steam separators have been located outside of the drum. The drum also uses a thinwalled design to minimize stresses across the drums. Whereas conventional drum-type HRSGs run a high risk of severely reduced lifetime due to cycling stresses, the significantly lower peak stress means the boiler can handle 10-minute start-ups while maintaining the same design life span of conventional drum-type HRSGs. The boiler design also allows the use of a conventional selective catalytic reduction (SCR) and CO catalyst. The result is a plant that can operate like a peaker, with unrestricted startup, but with a conventional SCR at the back end. Essentially, El Segundo has the operating profile of a peaker but the emission footprint of a combined cycle. According to Siemens, start-up CO emissions are reduced by 90% compared to conventional combined cycle gas turbine plants as a result of the shorter startup time. Ramping operation Another unique aspect of El Segundo is the use of what Siemens calls ‘Clean Ramp’ technology. It has been tested at several locations but this is the first time it is being fully implemented. The technology allows the entire plant to ramp up and down at 30 to 35MW per minute while maintaining 2 ppm NOx out of the stack. There will be virtually no CO emissions from the new units. Transient NOx emissions are seen 16 GAS TURBINE WORLD September – October 2013

El Segundo performance. Each 5000F 1x1 Flex-Plant 10 is design rated (at 85°F) to deliver 150MW of gas turbine power in 10 minutes (non-spinning reserve) for peak backup of intermittent renewable generation and full 275MW plant output at 48.8% efficiency in less than 60 minutes. Full GT power in under 15 minutes

Load

– 100% Less than 1 hour to fully open steam valves

– – 80 – – 60

Flex-Plant combined cycle

– – 40

Conventional combined cycle

– – 20 – –0

Time (minutes)

0

30

60

during ramping. Normally, sensors in the stack detect a NOx excursion and send a signal to input more ammonia to reduce NOx. Basically, it is a reactive process. Clean Ramp technology essentially links into the controls of the gas turbine and SCR. As soon as the gas turbine gets a signal to ramp up, the gas turbine and ammonia injection system operate in a proactive process to avoid NOx excursion at the stack. The technology is hugely important in a state that has one of the strictest legislations in the country for NOx emissions. Piantka noted: “In this district, for Best Available Technology, there is a NOx limit of 2 ppm over an hour. So, when ramping up or down, we have to meet our limit over that hour period.” The plant has successfully demonstrated this during commissioning and operation. Ready to meet demand Despite having to be built on an existing site subject to space constraints, the new plant was completed in time

90

120

150

to meet the growing demand in the region. This can partly be attributed to a logistics plan developed by Siemens for special rail car usage and transit clearance to ensure that gas turbine and generator delivery to site went smoothly. Effective implementation of the plan resulted in all equipment delivered ahead of schedule: steam turbines were delivered 63 days early; gas turbines three days early; HRSGs 42 days early, and air cooled heat exchangers (condensers) 21 days early. With its second Flex Plant now in operation, Siemens believes this will be a growing trend in the US, where natural gas fuel is cheap, and especially in regions where there is an increasing amount of renewables. A third Flex-Plant is scheduled to begin operation in Sherman, Texas by the end of 2014. This project, being built for Panda Power Funds, will be followed by another project in Temple, Texas, also for Panda Power, that is scheduled for completion a year later. n

Expanding performance while resetting the clock on old assets

By Victor de Biasi

Advanced gas path upgrades coupled with model-based controls software can improve performance and value of old 9F and 9B/E gas turbine units.

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E has introduced separate technology upgrade programs for its large 50 Hz fleets of Fr 9B/E and Fr 9F-class gas turbine installations in service around the world. Both programs combine hardware and software technologies to enhance power plant performance, operation and durability. And both incorporate advanced gas path upgrades (similar to the 7F upgrade GE introduced 2-3 years ago) designed to increase power output, efficiency and operational profitability of old units: o Frame 9F-3. Up to 6 percent more power, 2 percent higher fuel efficiency and 33 percent greater outage intervals (32,000 hours) for maintenance. o Frame 9B/E. Up to 3.8 percent more power, 0.9 percent higher fuel efficiency and 33 percent greater outage intervals (32,000 hours/1,300 starts). o Investment. Fully upgrading a 500MW plant could be worth over $500,000 annually in extra revenue and up to $1.25 million a year in fuel savings. New controls software that go with gas path upgrading have been developed to help satisfy a growing variety of operational needs. “We are seeing huge value in combining hardware with software,” says Fintan Tuffy, General Manager, responsible for gas


turbine fleet analysis and performance management services. “Ten years ago, customers were just interested in output and efficiency. Now, depending on where you are in the world and what type of customer you are – whether a merchant, state-owned utility or cogen operator – you may be looking for slightly different results.” Primary interest one day might be peak firing; another time it may be to bring down operating costs and extend maintenance intervals. Ultimately, the shared goal is to deliver technologies blended through a collaborative process between GE and owner-operators to identify customized solutions that best achieve desired outcomes. Fr 9B/E program GE refers to the improvement program for 9B/E-class gas turbines as a “LifeMax Advantage” platform (LMA) configured to reset the clock and significantly extend the life cycle of aging assets which typically average over 17 years in service. “These units are coming to the end of their original design life, so we are really looking at life extension strategies,” notes Tuffy. “Owner-operators have access to a suite of upgrade solutions that will enable 9B/E-class gas turbines recapture lost performance and lower operating costs.” LifeMax blends advancements in hot gas path components with OpFlex model-based controls software to in-

crease power output, fuel efficiency and maintenance intervals. The portfolio of options includes: ● Dry Low NOx1+ combustion which allows operators to run their gas turbines up to 32,000 hours between scheduled overhaul maintenance intervals, ● broader suite of OpFlex controls which help expand operating profiles across all modes of power plant operation, and ● flange-to-flange replacement components for core engine upgrades including compressor and combustion systems. Dubai Aluminium (Dubal) is the first GE customer for an LMA upgrade. In April 2013, Dubal installed an advanced gas path upgrade plus DLN1+ and OpFlex advance controls systems on one of three 9E gas turbine units. This was carried out as part of a scheduled engine maintenance overhaul. Since its return to service, gas turbine output has increased by 3.4 percent (generating an additional 5,880kW) while fuel efficiency has increased by approximately 1.5 percent. The other two 9Es are scheduled for this same upgrade when overhauled. Across all three units, the site expects to increase its output capacity by 17.64MW, reduce its fuel use by 1.5 percent, and extend major overhaul intervals to 32,000 hours (equivalent to almost an additional year of operation).

The extra power will be used to increase smelter production while also reducing operating costs. “Incorporating these new technologies into our power station is central to our longterm strategy of producing aluminum products as efficiently and cost-effectively as possible for our customers,” says Tayeb Al Awadi, Dubal’s vice president, power & desalination. Dubal is also installing new OpFlex AutoRecover and Peak Fire software plus a Mark VIe controls upgrade to drive further output and efficiency site improvements while holding down overall maintenance costs. AutoRecover, based on GE’s highload pre-mix transfer technology, enables gas turbines to recover from lean-lean operation to pre-mixed operation without any change in load, typically in as little as 10-15 seconds. Project engineers explain that this capability can help avoid load interruption, emissions spikes and longer term maintenance costs. OpFlex Peak Power technology enables operation at higher firing temperatures. without increases in emissions or combustion instability. It is expected that up to 8 percent additional output can be achieved on 9E-class gas turbines by installing the Peak Power option. All five LMA options are scheduled for installation on Dubal’s second 9E gas turbine in November 2013, with installations on the remaining unit to follow in 2014. Fr 9F-3 program GE refers to the improvement program for 9F-class gas turbines as a “FlexEfficiency Advantage” platform (FEA) configured to expand gas turbine output, efficiency and operating windows. Owner-operators can benefit from an extension of maintenance intervals and parts life through more durable hardware components and software technology that automate operational adjustments to reduce stresses on parts.

In addition to gas path upgrades, the FEA portfolio includes Dry Low NOx combustion technologies and a broad suite of controls software options that can expand the operational flexibility of F-class machines. New features will be added in the future as a result of ongoing collaboration between GE and customers. For example, many 9F-3 gas turbine power plants today are running in cyclic operation. As a result, says GE, they are investigating how to start up faster and turn down to minimum loads at night. Turkish power producer, Enka, recently placed the first order for GE’s 9F-class advanced gas path upgrades on 10 gas turbine installations (at Gebze, Adapazar and İzmir power stations) which, when completed, will

deliver close to 150MW of additional capacity. Enka will also lower its emissions footprint by retrofitting the gas turbine units with a Dry Low NOx (DLN)2.6+ combustion system upgrade. Installation of the technologies is scheduled to begin in late 2015, during the second major inspection of all ten units, with a targeted completion date of 2018 for the last one. “The performance improvements this solution delivers to our plants will allow us to maximize the value of the energy we provide through power purchase agreements,” said Enka O&M Chairman Mr. Tahsin Kösem. “This collaborative effort with GE will also put our sites in a better position with more available power and flexibility for electricity markets with

Advanced Gas Path upgrades An AGP upgrade essentially involves applying the latest hot gas path technology to the three rotating and stationary sets of components in the hot gas path section – buckets, shrouds and nozzles – to improve gas turbine efficiency and output. It includes the use of new materials that allow higher firing temperatures; as well as better cooling and sealing processes to minimize the energy wasted as a result of cooling. Explaining the expansion to cover the 9F and 9E, Fintan Tuffy, General Manager, Fleet Analytics & Performance Management Power Generation Services GE Power & Water said: “We wanted to initially focus on our F technology, so we started with the 7F. “With 900 units around the world, it is probably our single biggest fleet in our 60 Hz market. Now we are taking some of the lessons learned and some of the technologies from our 7F introductions and applying them to our 50 Hz equipment.” Depending on gas turbine frame type and configuration, the AGP upgrade increases output of the 9F-3 by up to 6 per cent and fuel efficiency by up to 2 per cent. At the same time, maintenance intervals can be extended by up to 33 per cent or as long as 32,000 hours. On the 9E, output increases up to 3.8 per cent and fuel efficiency by up to 0.9 per cent. Maintenance intervals can be as long as 32,000 hours with 1300 starts (extending outage intervals up to 33 per cent). The upgrade is typically carried out during a major inspection or when the hot section of the machine is open. Here, the three rows of components would be removed and replaced with newer technologies. The case for AGP upgrades in Europe and the Middle East is being driven by the changing market conditions. With older fleets struggling to compete in a market where performance is key, the AGP upgrades will help the installed base compete in the market.


demand increases being forecasted across Turkey.” Large data pool As of September 2013, GE says it has achieved 100 million hours of operational data documented on its globally monitored gas turbine fleet of more than 1600 units. The insights derived from analysis of this operational “big data” can be applied to help customers expand their earning power while reducing operational costs and risk. As these “intelligent” machines communicate their operating statistics through an average of 100 physical sensors and 300 virtual sensors on each gas turbine, the GE team can help operators translate that information into actionable decisions. Armed with these data-driven insights, says GE, operators can more effectively identify potential barriers before they occur, treat minor issues before they lead to catastrophic events, and dynamically adjust performance to improve efficiency and reduce parts wear and tear. GE says it is tapping into knowledge gained from this data analysis to develop new technology breakthroughs, both hardware- and softwarebased, that enable customers to unleash more potential from their existing gas turbine and balance of plant assets. Program engineers estimate that unlocking the full capacity of a 500MW power plant could be worth more than $500,000 annually in increased revenue, while a public utility could reduce its heat rate efficiency curve by 1 percent and save up to $1.25 million dollars annually in fuel costs. Performance advancements based in part on extensive data analytics of its global installed gas turbine fleet are being integrated into 9F-3 and 9E new gas turbines units, says GE. These platforms feature technology innovations, both hardware and software, derived from extensive data analytics of the GE fleet’s real-world operating data. n 20 GAS TURBINE WORLD September – October 2013

9F gas path upgrade. Power output of the 9F-3 can be increased by up to 6% and fuel efficiency by up to 2%.

9E gas path upgrade. Power output of the 9E can be increased by up to 3.8% and fuel efficiency by up to 0.9%.

Tracking center. GE’s Monitoring & Diagnostics Center in Atlanta, Georgia collects around 30,000 hours of operating data daily for storage and evaluation that is generated by more than 1600 gas turbines across the globe.

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MT7 marine gas turbine to power new hovercraft fleet

By Robert Farmer

New turboshaft engine will power next-gen amphibious hovercraft being developed to rapidly transport personnel, materiel, and vehicles from ship to shore.

R

olls-Royce Marine is supplying the main propulsion systems for the new ship-to-shore connector (SSC) hovercraft vehicles being developed as next generation replacements for the U.S. Navy’s current air cushion landing craft. The SSC will be powered by four MT7 gas turbines, each nominally rated at 6000 to 7000 shp, driving lift and propulsion systems through gearboxes. In addition to hovercraft, the new engine is being proposed for other potential marine and industrial roles, specifically: o Patrol boats. Boost power for stealthy high-speed displacement hull designs running on combined diesel and gas turbine powered waterjet propulsion. o Gensets. Compact generator set could produce 4 to 5MW of base load power at over 33% net simple cycle efficiency for surface ship combatants. o Offshore. Light weight and small size engine is well-suited for power generation, gas compression or pump drive on platforms and FPSO vessels. For the U.S. Navy SSC project, RollsRoyce Marine is working with hovercraft builder Textron Marine & Land Systems, which has contracted for MT7 gas turbines for the initial development craft. This first round of engines will be delivered to Textron in 2015. First 22 GAS TURBINE WORLD September – October 2013

test hovercraft should begin sea trials in 2017 and become operational in 2020. Fully funded, the program could extend to 73 craft, meaning more than 300 engines over the next 20 years, including operational units and spares. According to R-R engineers, the MT7 will deliver a 25% increase in power compared to the current air cushion landing craft engines, enabling each SSC to transport up to 74 metric tons of cargo at speeds over 35 knots. At the same time, they note, the engine will improve fuel efficiency by 11 percent over its predecessors. And offshore mission range has been extended to 25 miles from 15 miles for the air cushion hovercraft now in service. Power density As an aero-derivative engine, the marine MT7 is rather compact; about 5 x 2.4 x 2.9 ft in size (LxWxH) including all engine-driven auxiliaries, but not its cold-drive torque tube, with a dry weight of less than 1,000 lbs. The engine is fully marinized for offshore and coastal service, with extensive use of corrosion and erosionresistant materials and coatings. Critical parts are protectively coated to withstand sand erosion and salt and water ingestion corrosion attack during hovercraft operation, which surely is the most challenging of marine environments. Power output is quoted in a nomi-

nal range of 4,000 to 5,000 kW continuous (about 6,000 to 7,000 shaft hp) at 15,000 rpm output shaft speed on marine diesel fuel with a specific fuel consumption of 0.4 lb/hp-hr (34.5% efficiency). Engine design The MT7 is a two-shaft gas turbine, with an axial compressor and twostage axial gas generator turbine on one shaft and an aerodynamically coupled two-stage free power turbine forming the second shaft. A 14-stage axial high-pressure (HP) compressor is followed by an effusion-cooled combustor. This single annular combustor has multiple fuel nozzles at the head end, using a piloted air-blast type nozzle. The combustor liner and transition are air-cooled. This low emissions, low smoke combustor is designed to handle a variety of liquid fuels including distillate, marine diesel, kerosene and F76 military diesel. As opposed to conventional combustor cooling designs, which use large cooling holes, slots or channels, with effusion film cooling, hundreds of very small diameter holes are machined into the liner wall at an angle to the incoming airflow. The pressurized compressor discharge air flows through this array of multiple holes, cooling the surface with an insulating layer (or film) of air to protect the metal. This allows engine operation at high combustion and high turbine inlet temperatures for

maximum power and performance. With an overall pressure ratio of 16.7:1, the compressor features six stages of variable geometry guide vanes at the forward end. These are used to modulate air flow and improve engine performance across a range of different operating conditions, providing precise engine control. The guide vanes also provide more efficient variable speed operation, with higher efficiency at part-loads and surge-free compressor operation with rapid acceleration and deceleration capabilities. The compressor is directly coupled to and driven by an axial twostage HP turbine featuring internal air-cooled nozzles and blades on both stages. The separate low pressure LP shaft, driven by a two-stage axial free power turbine, drives concentrically out the front end of the engine. The free power turbine airfoils are not cooled. Accessories Nominal power shaft speed is 15,000 rpm at full load, with shaft rotation counterclockwise when viewed from exhaust end. A torque tube at the compressor front end drives into lift fan and propulsion fan gearbox systems on the SSC. 28.9”

Marine MT7 gas turbine. Aeroderivative MT7 engine is rated at 5,230 shp and 0.4 lb/hp-hr SFC (34.5% efficiency) for continuous duty output on a 100°F day, operating on marine diesel and allowing for 12-inch inlet and 20-inch exhaust losses.

The compressor rotor drives the bottom-mounted accessory gearbox through a jackshaft and bevel gear arrangement. Drives include the dual pressure fuel pumps, lube oil pressure and scavenge pumps, and an AC alternator. A primary lubrication system provides regulated oil pressure, filtering and cooling, dry sump scavenge, and low pressure sump venting. The lube oil sumps are sealed so that the engine can operate through a wide range of angles. Starting is through a pneumatic air

turbine starter motor that drives into a pad on the accessory gearbox. An engine-mounted full authority digital electronic control system (FADEC) for fuel control includes advanced health monitoring and prognostics functions. The control system has dual-redundant architecture, with one controller metering the fuel while the redundant controller is in hot standby. The active duty controller also positions compressor variable vane geometry, controls the combustor igniters and regulates engine bleed valves. MT7’s modular design and con59.1”

34.5”

Two-spool marine design. MT7 turboshaft engine features a 14-stage compressor (with variable geometry vanes on six stages) and 2-stage high pressure turbine on the first spool; fully annular combustor; and an air cooled 2-stage free power turbine as the second spool, with a concentric output torque tube out the front compressor end. Bare engine is about 5 feet long (not including torque tube) and less than 2.5 feet in diameter, weighs just 972 lbs dry. GAS TURBINE WORLD September – October 2013 23

struction, and easily accessible components, are said to allow reduced maintenance time and costs, with “oncondition” maintenance capability as standard. To ensure high reliability, all the engine-mounted actuators and sensing devices that interface with the FADEC are also duplex designs. Common core Common core technology, says R-R Marine, is one of the keys to the MT7’s initial cost, performance upgrades, high reliability and maintainability characteristics. MT7 is a direct derivative of the AE 1107C-Liberty turboshaft gas turbine design (aka T406) that ended up retaining over 90% component commonality with the aero parent. Basically all of the internal engine design and components are identical. Only minor variations from the aircraft engine design are required for the SSC application, note company design engineers: mainly a new engine controller, compressor bleed air system and power take-off shaft to suit the hovercraft role. Marine MT7 operators also stand to benefit from an over 80% parts commonality with the company’s other AE family of engines currently in volume production which include the popular AE 2100 turboprop and the AE 3007 turbofan. All told, the AE engine family’s total cumulative operating time now exceeds 52 million hours. This provides a wealth of support capabilities including spares, modules, training, operating and maintenance expertise. R-R executives point out that “field-proven AE aero engine upgrades exist today that could increase the MT7 available power by up to 20 percent and extend engine life.” For the hovercraft application, this potential power growth capability could allow larger payloads or provide life cycle cost savings if the extra power is not needed.” MT7 engines and components are built at Rolls-Royce manufacturing 24 GAS TURBINE WORLD September – October 2013

facilities in Indianapolis, Indiana (former Allison Engine works), in the same facilities that produce the other AE engine family members. SSC craft ratings Ratings are at Navy standard day 100°F ambient temperature, sea level, 40% relative humidity and include 12inch inlet and 20-inch exhaust losses (water gauge) for the SSC installation. Currently, specific ratings at those standard Navy conditions are assigned to the MT7 gas turbine engine for its power role in the ship-to-shore connector craft program. There are two power output requirements that are critical: one is for maximum continuous power of 5,230 shp (on a 100°F day) and the other is for maximum intermittent power of 5,700 shp for max speed. Both outputs are to be available at power turbine output shaft speeds of 95 to 100% (14,250 to 15,000 rpm) on demand. Other applications R-R designers note that the MT7 is “suited to a variety of system configurations” in that it offers ship designers and builders increased flexibility in terms of propulsion system layout for both mechanical and electrical drives. One potential naval ship role en-

visions high-speed attack craft built around a combined propulsion system using Kamewa waterjet propulsors powered by twin MTU high-speed diesels for routine cruising and the MT7 gas turbine for high-speed boost. The compact CODOG propulsion package allows for a small superstructure (very low radar profile) combined with a high-speed displacement hull. Such a vessel would excel in fast attack and high-speed patrol and interdiction roles with stealthy radar signature and low waterborne noise. As ship’s service generator set, the already marinized and shock-resistant MT7 would provide 4000 to 5000kW of shipboard electric power at an estimated generator set efficiency of over 33% burning marine diesel oil. The small MT7 gas turbine driving a 50- or 60-Hz air-cooled generator through epicyclic reduction gearbox could be packaged as a compact module that would also be suitable for industrial power on offshore platforms and FPSO vessels. Project engineers point out that the gas turbine engine could also be configured into a very lightweight singlelift mechanical drive package to power high-speed centrifugal or axial gas compressors for gas lift and reinjection or for oil and water pump drive operation on offshore installations. n

Ship-to-shore transport. Next generation amphibious hovercraft will be powered by four MT7 gas turbines driving lift and propulsion fans through gearboxes at over 35 knot speeds carrying a payload of 74 tons for rapid deployment of vehicles, men and equipment from ships onto land.

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Dubal upgrading combined cycle plants to lower cost of electricity

By Junior Isles

Dubai Aluminium is upgrading its 2,350MW power station to boost power output and reduce cost of electricity for smelter operations.

W

hen Dubai Aluminium (Dubal) began commercial operation in January 1980, its entire planned production volume was 135,000 tons per year. Today, smelter capacity is up over one million tons per year with an onsite generating capacity exceeding 2,350MW to supply all of the smelter’s electric power needs. Dubal is currently upgrading five General Electric Fr 9B combined cycle plants commissioned in 1980 by retrofitting new engineering design technology (including DLN combustion) to the gas turbines and replacing the old HRSGs with newly designed units that will improve overall power output and efficiency. Highlights: o Firing temp. Gas turbine upgrade includes raising firing temperature to 1,124°C (2,055°F). o Power output. Unit power output is expected to increase by 10% to 88MW (at 35°C) from 80MW. o Steam output. Unit HRSG output is expected to increase by 24% to 228 ton/hr from 180 ton/hr. o Timetable. Gas turbine upgrade and HRSG projects should be completed by the end of April 2015. Dubal awarded General Electric a contract in July 2012 to upgrade all five Fr 9B gas turbines. This was followed in May 2013 by a contract with


Comparative 9B power output. Site rated output of Dubal’s upgraded 9B gas turbine units is being increased from 80MW (when first installed) to 88MW on a 35°C hot day. PG9111B *Installed Upgraded Performance specs 15°C ISO Rating 35°C Rating Base load output Heat rate (per kWh)

82.6 MW

88.0 MW

11,210 Btu

N/A

30.4%

N/A

Gross efficiency Firing temperature

1950°F

2055°F

Pressure ratio

9.8 to 1

9.8 to 1

753 lb/sec

775 lb/sec

1020°F

est 1040°F

Air flow Exhaust temperature

*Source: 1980 Gas Turbine World Handbook

Bilfinger Babcock CZ to remove and replace the old HRSGs with newly designed units. Main goal of the combined upgrade projects is to increase power output and efficiency of the overall plant to cut costs and be more competitive. Electricity needed for smelter operations is said to account for fully one-third the cost of aluminum production. Power generation The power generation capacity of the Dubal combined cycle power station has grown substantially since the smelter’s commissioning in 1979. An initial installed capacity of 483MW, which more than met the load demand of 302MW at startup, has increased five-fold in the intervening years.

From an initial 13 gas turbines, today’s 2,350MW power station comprises 23 gas turbine generators (eight Fr 5s, five Fr 9Bs, one 13DM, six Fr 9Es and three 13E2s) operating in combination with 7 steam turbine generators (two backpressure and five condensing types). Each gas turbine is ducted to its own HRSG (thirteen single-pressure and ten dual-pressure types) that produce waste heat recovery steam for the seven steam turbine generators and a seawater desalination plant that produces up to 30 million gallons of drinking water per day. Station project engineers report that, thanks to the cogeneration and combined cycle design of the Dubal power station, approximately 36.8% of the total power generated is fuelfree. Over the years, gradual improve-

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ments in efficiency enabled the station to operate at 44.2% thermal efficiency in 2012 producing more power while burning less fuel per MW generated. HRSG replacement Deutsche Babcock, an EPC provider for power, desalination, oil and gas, petrochemical and chemical industries, has partnered with associate company Bilfinger Babcock CZ on the HRSG project. The turnkey contract covers design, manufacture, supply, installation, testing and commissioning works for the upgraded Fr 9B gas turbine HRSGs, including all associated civil and control systems modifications on the existing footprint after decommissioning and disposal of the existing units. The existing single-pressure boilers, that have been in operation for more than 30 years, operate at a maximum continuous rating of 136 t/h ambient temperature 28°C, steam pressure 20 bar(a). According to the contract, three of the boilers will be replaced by singlepressure HRSGs, with an option on the two remaining boilers. Depending on the turbine upgrade, the boilers for Units 4 and 5 could potentially be designed as dual-pressure HRSGs or single-pressure HRSGs. Design features David Ilik, Bilfinger Babcock CZ’s Project Manager of the Dubal project said: “The decision on the option will be taken six months from the contract date of signing. The decision on whether these last two units will be single- or dual-pressure will be taken at the end of this year.” The steam turbines and desalination equipment are at the moment designed to operate at 1.5 bar, as are the single-pressure boilers. If the dualpressure boiler option is used for units 4 and 5, then outlet steam parameters will be in the range of 90 to 100 bar. This will see the operating pressure rise to about 5 bar for the low pres28 GAS TURBINE WORLD September – October 2013

sure part of the steam turbine. This change may also require investment in a new, higher parameter steam turbine. The temperature of the exhaust gas from the upgraded Fr 9B gas turbines is expected to fluctuate between 520°C and 580°C, depending on the ambient temperature, which can vary from 5°C to 45°C. Improved performance After conversion, the plant steam capacity of each HRSG is projected to increase by 24 percent, from 180 t/h to 228 t/h (at 45°C ambient) and noise levels will be effectively reduced to 85 dBA. The new boilers receiving this hot exhaust gas will play a key role in increasing the overall efficiency of the combined cycle units. Jan Dvorak, head of Engineering at Bilfinger Babcock CZ, explained how the higher efficiency is achieved. “We increase the heating surface and reduce the pinch point and approach point. The smaller the pinch and approach temperature, the more efficient is the HRSG.” Pinch point is the difference between exhaust gas temperature and temperature at the evaporator; ap-

HRSG option. Engineers are mulling a mix of single- and dual-pressure designs.

proach point is the difference between the saturation temperature and economizer outlet temperature. The project is split into six separate Provisional Acceptance Certificates (for the five HRSGs plus the feedwater station) with roughly four months between deliveries. Handover of the last unit, together with the final acceptance certificate, is scheduled for April 23, 2015. n

Dubal capacity and load growth. Dubal’s initial installed capacity of 483MW, which more than met 302MW demand, has grown five-fold in the intervening years. 2,127

Capacity (MW)

1,656

1,656

2,350

1,656

1,329 483

553

675

883

1979-82 1982-89 1989-95 1995-98 1998-02 2002-04 2004-05 2005-06 2006-08 2008-12

Load (MW) 302

346

481

674

915

1,096

1,295

1,407

1,623

1,900

1979-82 1982-89 1989-95 1995-98 1998-02 2002-04 2004-05 2005-06 2006-08 2008-12

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IGCC and Gasification The total production capacity of “underconstruction” coal gasification projects in Inner Mongolia has reached 17.6 billion cubic meters. Another five gasification projects in the region, for which preparatory work has been approved, have a combined capacity of 20 billion cubic meters. Other major coal gasification projects are also reported underway in northwest China’s Xinjiang Uygur Autonomous Region, Shanxi Province and northeastern Liaoning Province.

US Kemper County 582MW IGCC plant start-up delay Southern Company recently announced a delay in the schedule to begin operation of its 582MW Kemper County coal project that is currently under construction by its subsidiary, Mississippi Power. Southern now expects the project to be completed in the last quarter of 2014 and the costs to exceed $4 billion. Company earnings for the three months and nine months ended September 30, 2013, include after-tax charges of $93 million and $704 million respectively, related to increased cost estimates for the construction of the Kemper County project. When Mississippi Power held a ground-breaking ceremony in December 2010 for start of construction, the projected cost of the IGCC plant was estimated at $2.4 billion. Operations were targeted to commence in 2014. In April 2013, the project cost was estimated to be over $3.2 billion, with a May 2014 deadline to start service to retain certain tax incentives. By the third quarter of 2013, the Kemper County project achieved several major construction milestones, including first fire of the facility’s two gas turbines, which were completed August 28 and September 4. Steam turbine testing was completed in late September.

China Coal-to-gas project ready to supply gas Now that the initial phase of the Hexigten coal gasification project in north China has been completed and fully tested, commercial operation to supply gas to Beijing is scheduled to start at the end of this year. This stage of project development is capable of producing 1.3 billion cubic meters of syngas each year. When completed, in three phases, the gasification plant will have a total capacity of 4 billion cubic meters annually, or nearly half of the capital’s current annual gas demand. The Hexigten coal gasification plant, the first such project to be approved in the coun30 GAS TURBINE WORLD September – October 2013

try, began construction in August 2009 with an estimated investment of $4.2 billion and will operate on domestic coal feedstock. Mongolia Three projects in build and another five approved Inner Mongolia, with estimated reserves of more than 800 billion tons of coal, is being developed as a clean energy resource base for Beijing and north China. Coal gasification projects are a key part of the region’s economic development. In the second half of this year, three coal-based gas projects began construction in the region, each with a design capacity to produce 4 billion cubic meters of syngas per year when fully operational.

Japan Two coal-based IGCC power plants planned for Fukushima Tokyo Electric Power Co (Tepco) and Mitsubishi Heavy Industries have announced plans to build two integrated gasification combined cycle (IGCC) stations at Fukushima. The two facilities, which will be built in the city of Iwaki and town of Hirono, will have a combined capacity of about 4500MW. Both are projected to start operations around 2020. Mitsubishi group companies will have a majority stake in the new plants while cashstrapped Tepco will be in charge of running the facilities as soon as they are operational for commercial service. Industry project engineers point out that higher efficiency of IGCC technology can be expected to generate 20 percent more power than conventional coal power plants, using the same amount of feedstock. Ukraine China to build four IGCC plants under advance credit agreement Ukrainian President Viktor Yanukovych has reached an agreement with China for the construction of 4 coal-based IGCC power plant in Ukraine. Yanukovych said that the plants will be built as a part of the policy of reducing Ukraine’s dependence on imported natural gas fuel. Last year, the country managed to cut gas imports from 44.8 billion cubic meters in 2011 to 27.3 billion cubic meters in 2012. Naftogaz Ukrainy, Ukraine’s national oil and gas stock company has signed a credit agreement with China Development Bank Corporation for $3.7 billion under state guarantee for projects involving the replacement of gas with coal. Coal-water slurry fuel technology and the construction of plants for the gasification of coal will make it possible for

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IGCC and Gasification Ukraine to replace around 4 billion cubic meters of imported natural gas with its own coal-derived syngas. This is expected to provide a stable market for the sale of around 10 million tons of coal per year, create new jobs, and save up to $1.5 billion a year in avoided gas imports. The credit line is open for 19 years (2012-2031) allowing 4 years for the preparation and coordination of confirmed projects and the signing of individual credit agreements. Plants for the gasification of brown and bituminous coal will be built in Luhansk, Donetsk, and Odessa Regions using Shell technology approved by China. China Coal to methanol expansion project Jiutai Group has selected GE’s 8.7 MPa high-pressure gasification technology for a coal-to-methanol factory expansion project in Inner Mongolia. The expansion will enable the factory to boost methanol production to 1.5 million metric tons of “coal-to-methanol” annually, a 100 percent increase in capacity. Adopting GE gasification technology is expected to reduce methanol production costs by as much as 11 percent compared to the original facility. It also will exceed China’s national energy rules that require industries to utilize more efficient, environmentally friendly technologies. For this project, GE Shenhua Gasification Technology Company, a joint venture with the Shenhua Group, will supply the license for GE’s gasification technology, gasification process design package, technical services and key equipment. GE Oil & Gas will also supply three model DH7JM compressors to be used for polyethylene and polypropylene production. The compressors will be manufactured at GE’s service center in Houston, Texas, tested at its facility in Connersville, Indiana and shipped to China during 2014. The expanded methanol production facility is scheduled to begin commercial production in 2016. China Gasification technology demonstration phase Wison Engineering Services Co. reports that its Shell-Wison hybrid gasification technology demonstration plant has successfully started up in Nanjing. Purpose of the plant is to demonstrate the 32 GAS TURBINE WORLD September – October 2013

reliability of the technology and evaluate its operating economics, efficiency and emissions while processing a wide range of coal feedstocks. The new hybrid gasification technology was developed using extensive experience from Shell’s coal and residue gasification technologies, and offers a more compact design based on water quench technology. The successful operation of the demonstration plant will help to propel development of China’s burgeoning coal-to-chemical industry. North Dakota Dakota Gas studying urea facility at Synfuels Plant Dakota Gasification Company, a subsidiary of Basin Electric, has submitted an application for an environmental permit for a urea production plant at its Great Plains Synfuels Plant near Beulah, ND. Urea production requires anhydrous ammonia (made from natural gas) and carbon dioxide, both of which are manufactured in the Great Plains Synfuels Plant’s process. Company says this application is a key preliminary step as part of the investigation of the project. Urea is a granular fertilizer commonly used in agricultural applications. Dakota Gas executives say they are in the final stages of a Front-End Engineering and Design study for the production facility. Subject to a successful FEED study and final board approval, the urea plant would be scheduled for completion in early 2017 with a capacity to produce 1,100 tons of urea daily. “We’re excited about the potential to build onto the fertilizer products we already produce,” said Andrew Serri, Dakota Gasification Company president and chief executive officer. Urea has the highest nitrogen content of all solid nitrogen fertilizers, but costs less to handle, store and transport than other nitrogen-based fertilizers. Two other agricultural fertilizers currently produced at the Synfuels Plant include anhydrous ammonia and ammonium sulfate. China Focused on coal to chemicals and IGCC power generation Given the vast coal reserves in China and the importance of the country’s coal-tochemical industry, GE sees huge potential for its technologies and experience, according to Yang Dan, business leader Power Generation China at GE Power & Water. In 2012, GE announced the creation of

its GE Shenhua Gasification Technology Company joint venture with the Shenhua Group to develop and deploy energy projects in China, with a focus on using coal in a much cleaner way. The company combines GE’s expertise in coal gasification technology with Shenhua’s expertise in applying a broad range of technologies for coal gasification and coalfired power generation. Future coal-to-chemical projects in particular stand to benefit from GE’s integrated Radiant Syngas Cooler (RSC), extended slurry, and advanced refractory technologies, says Dan. GE’s gasification technology utilizes the company’s latest-generation RSC heat recovery system to capture heat in the form of steam during the gasification process, which converts coal to syngas. This enhanced steam production greatly reduces the need for additional steam or power produced from stand-alone boilers, boosting the efficiency and reducing the emissions of coal-to-chemical facilities. GE is also introducing a proprietary technology to increase slurry concentration above traditional methods, enabling economic gasification of a wider envelope of coals. This extended slurry technology can be used to improve efficiency and reduce capital expenditure, particularly for less expensive, lower rank coal feedstock. The company also has introduced a proprietary refractory lining system for gasifier vessels that extends the operating life cycle and overall availability of the gasifier, while reducing maintenance costs compared to standard commercially available refractory technology. For instance, the advanced refractory lining system used for IGCC plants is expected to perform 50 percent longer than GE’s standard refractory technology, delivering one percentage point improvement to the overall plant availability.

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