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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
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654 Hillside Road
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Telephone (203) 259-1812
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Europe – Peter Gilmore
Telephone +44 (0)207 834 5559
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Japan – Masahiko Yoshikawa
Telephone 3 32 35 5961
Facsimile 3 32 35 5852
[email protected]
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
26Dubal upgrading 2,350MW powerplant
Aluminum producer is upgrading output,
efficiency and durability of mixed gas turbine fleet to up productivity and cut costs
30IGCC power and gasification technology
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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
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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
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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
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
1853-2013
Branded energy
for 160 years
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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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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.
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
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.
G
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
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
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.
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
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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while reducing fuel consumption and carbon
emissions. It’s simple and fast to implement, and
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months. Cheng Power Systems’ technologies
(including CLN and ACS) are proven, with a track
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NOx Emissions
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These days, turbine operators are under more
pressure than ever to reduce emissions and
make their operations more “green”, all while
keeping costs down. Easier said than done –
nearly all emissions control systems are
expensive, slow to implement, and degrade
performance, which increases operating costs.
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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
*InstalledUpgraded
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-
Stay Ahead of the Curve
2013 Performance Specs
29th Edition
Saturn 110 MW upgrade
may use nanotechnology
January - February 2013
Volume 43 No. 1
May – June 2012 • Volume 42 No. 3
Wind energy being
stored as hydrogen
Can CLN really
reach zero CO?
page 14
page 12
page 10
200MW with 15-minute
start and 38% efficiency
For Project Planning,
Proposals, Engineering,
Evaluation and Procurement
IGCC cutting COE
price levels by 20%
30MW at 41%
with low NOx
page 19
page 14
page 20
Shale gas boom fueling
electrical load demand
ISI adds 6MW
to Trent rating
SGT-300 mech drive
ready to make debut
page 24
July - August 2012 • Volume 42 No. 4
page 24
November – December 2012 • Volume 42 No. 6
page 25
Your Guidebooks to the Changing World of Industrial GT Projects,
Application, Operation and Maintenance
GAS TURBINE WORLD MAGAZINE
The industry’s most in-depth periodical devoted to Gas Turbine news, emerging technologies and the defining
issues that impact utility, oil & gas, industrial and marine turbine operators around the globe.
(Bi-monthly)
GTW HANDBOOK
The “go-to” reference for Gas Turbine buyers, owners, operators, project planners and EPCs. Includes design
ratings for all GT makes and models, power plant budget prices, engineering trends, index to GT product and
service suppliers, worldwide orders and installations.
(Annual)
GTW PERFORMANCE SPECS
Comprehensive, buyer’s-eye-view of the new model year’s field of gas turbines for utility, oil & gas, industrial and
marine operation. The industry’s premier resource for performance comparison, technology assessment
and product specification.
(Annual)
2013 GTW Handbook is available at
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
Software companies come and go, sometimes in
the middle of a project. They change ownership,
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no matter if your application is district heating,
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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
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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Through a continued focus on combustion R&D,
Siemens has achieved best-in-class levels of NOx
emissions. In addition to achieving 9 ppm on
natural gas, our F-class gas turbines can now meet
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What’s more...this achievement has been proven
in operating plants, not just in the lab or on the
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With this advanced combustion technology, you
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Answers for energy.
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