Copper mine saving 40 percent on COE Low cost alternative to

Transcription

Copper mine saving
40 percent on COE
page 8
Low cost alternative
to combined cycles
page 14
Steam cooling with
reheat gas turbines
page 28
July – August 2014
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July – August 2014
Gas Turbine World • Vol. 44 No. 4
Editor-in-Chief
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Managing Editor
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European Editor
Junior Isles
Engineering Editor
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Field Editor
Michael Asquino
Piggy bank
Newly completed combined cycle
power station is expected to reduce
mining company’s operating cost of
electricity to 6 cents per kWh from
current 10 cents page 8
News Editor
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Marketing Director
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On the Cover. Copper mine site for two 1x1
Siemens ST6-5000F combined cycle plants
rated 250MW each and 56.9% efficiency
3 Project development and industry news
Alstom KA24-2 combined cycle units,
Tepco 500MW IGCC projects, Mexico CFE
tenders for $2.8 billion, $500M 410MW
combined cycle, China H25 cogen upgrade,
Russia HA.01 plant
8 Mexico CC plant lowering COE by 40%
Second 250MW combined cycle plant was
commissioned recently in a mining company’s long range program dedicated to generating 90-95% of its electricity requirements
GT makeover
Gas turbines can produce up to 70%
more power and burn 40% less fuel
for less than half the cost of converting to combined cycle operation,
page 14
14 Cheng proposal for H and J class turbines
Equipment cost of retrofitting large gas turbines for Cheng operation is estimated at 220
to 250 $/kW vs. reported 350 $/kW cost for
combined cycle conversion of an M701
24 World’s most powerful gas engine intro
New spark-ignited gas recip rated at 18.9MW
and 50% simple cycle efficiency has a routine 480-sec startup with a 75-sec fast start
option for intermittent energy backup
28 Potential 65% combined cycle efficiency
Steam cooled H-system and GT 24/26 reheat
combustion technologies could open the way
to 65% efficiency without exceeding dry low
NOx combustion limitations
Game changer
Steam cooling and reheat combustion could produce a “super turbine”
capable of 64% to 65% combined
cycle efficiency without excessive
NOx, page 28
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INDUSTRY NEWS
Texas
FGE Power building two 747MW
KA24-2 combined cycle facilities
FGE Power has agreed to strategically partner with an affiliate of Starwood Energy
Group Global to finance and build two 747MW Alstom KA24-2 combined cycle gas
turbine plants near the communities of Westbrook and Colorado City, in Mitchell
County, Texas.
The first project is anticipated to break ground for construction in the fall of 2014
and reach commercial operations no later than early 2017. The second plant should
break ground in early 2015 for commercial operations by the summer of 2017.
Alstom’s KA-24-2 combined cycle reference plant is designed around two
230.7MW GT24 gas turbine generator sets, two unfired HRSGs and one nominally
rated 230MW steam turbine generator set. The 2x1 configuration is rated at 664MW
net base load output and 58.4% efficiency.
Presumably the HRSGs for the FGE Power projects are duct fired to increase steam
turbine output by up to 83MW to achieve the quoted 747MW rating for each plant.
This new generating capacity will help enable the Electric Reliability Council of
Texas (ERCOT) meet forecast growth in Texas. In addition to providing low cost and
efficient power to ERCOT customers, the plants will establish new state and national
standards for low emissions.
Indiana
IPL turnkey order for 671MW
7FA-05 combined cycle plant
Indianapolis Power & Light has awarded
CB&I Stone & Webster a turnkey contract
for engineering, procurement and construction of a 671MW combined cycle gas turbine
power station near Martinsville, Indiana.
Station will be powered by a 2x1 General Electric combined cycle plant designed
around two 227MW 7FA-05 gas turbines, an
unfired HRSG and a 244.3MW steam turbine
generator set.
GE’s 7FA-05 combined cycle plant is
rated at 697MW gross and 688MW net plant
output (after deducting 9MW for plant’s parasitic loads) and 59.5% net efficiency.
Timetable calls for start of construction
in 2015 for completion in 2017. Under a certificate of Public Convenience and Necessity,
IPL has been approved to invest approximately $600 million in the the project.
www.gasturbineworld.com Japan
Tepco order for coal based
500MW IGCC design project
Tokyo Electric Power Company has awarded a consortium led by Mitsubishi Hitachi
Power Systems a contract for design of two
500MW coal-based IGCC power plants for
two different utility projects.
Plans call for the construction of one
500MW IGCC plant at Tepco’s Hirono
Power Station (Futaba-gun) and a second
500MW IGCC plant at the Nakoso Power
Plant (Iwaki City) operated by Joban Joint
Power Co. (a company partially owned by
TEPCO).
The MHPS-led consortium is preparing
the equipment specifications, layout design,
major system diagrams, etc. for project
procurement and construction. MHPS is
responsible primarily for designing the gasification and combined-cycle power generation equipment; MHI is in charge of
gas refining equipment; Mitsubishi Electric
will handle power generation and electrical
equipment; and MHI-Mechatronics will design the wastewater treatment facilities.
Compared to conventional coal-fired
power generation systems, Mitsubishi says
that the IGCC configuration not only delivers spectacularly enhanced generation efficiency (over coal fired steam plants) but
also significantly cuts carbon dioxide (CO2 )
emissions, resulting in a thermal power generation system of the next generation.
Among the various fossil fuels available,
coal offers outstanding economy and supply
stability. The introduction of IGCC technology will reduce emissions not only of CO2
emissions but also nitrogen oxides and sulfur
oxides.
Because a high-temperature, high-pressure gasification furnace is used, low-grade
coal, which has a number of disadvantages when employed in conventional thermal
power plants, can be readily used. In these
respects, demand for IGCC systems is expected to grow in many countries like Japan
that have scarce energy resources, in view of
their advantages in the dual terms of effective utilization of resources.
MHPS’s track record in IGCC systems
includes the design and construction of Joban Joint Power Company’s Nakaso Power
Plant Unit 10 (the former Clean Coal Power
R&D Company’s demonstration plant) that
set a world record for continuous operation
of an IGCC system.
Tennessee
TVA has authorized $975 million to
build 1,000MW combined cycle plant
The Tennessee Valley Authority (TVA) has
recommended closing three 55-year old coalfired units at the Allen Fossil Plant and replacing them with a new natural gas-fired
plant on adjacent property in Memphis, Tennessee in an accord to reduce emissions.
In their place, TVA proposes building a
combined cycle plant rated at either 600800MW or 800-1,400MW. Both proposed
configurations would require construction of
new gas pipelines and other infrastructure.
The TVA board of directors recently approved a plan to replace the three coal-fired
units at the Allen Fossil Plant with a combined-cycle natural gas-fired plant.
The board authorized up to $975 million
to build a gas-fired plant with a capacity of
approximately 1,000 MW. This would be the
seventh combined-cycle gas plant TVA has
added to its power portfolio since 2007.
Compared with the existing coal plant,
the new gas-fired combined cycle plant
would reduce carbon emissions by more than
GAS TURBINE WORLD July – August 2014 3
Industry News
60%, nitrogen oxides by 90% and sulfur dioxide by nearly 100%, TVA said.
Dominican Republic
Combined cycle conversion to
cost $228 $/kW for 114 MW
Dominican Power Partners (100% indirectly owned by AES Corp.) has received approval to proceed with conversion of two
gas-fired simple cycle gas turbine units at its
Los Mina Power Plant in Danto Domingo to
combined cycle mode.
The conversion essentially involves the
addition of two heat recovery steam generators and a 114MW steam turbine generator
to an existing 2 x 105 MW simple cycle
natural gas-fired turbine plant. This will increasing the plant’s generation capacity from
210 MW to 324 MW, without using additional gas, while improving heat rate efficiency by 34%.
Cost of the combined cycle conversion is
estimated at around US$ 260 million. On the
basis of new capacity, that investment for an
incremental l 114MW increase in plant output should have a turnkey cost of 228 $/kW
installed.
The project will be designed and constructed through an EPC contract (lump sum
turnkey contract). It will include the modification of the two existing Siemens simple
cycle gas turbine generators (Unit V and
Unit VI with two stacks of 15 m height),
commissioned in 1996, into a combined
cycle plant.
In addition to the two HRSGs and the
STG, the project will include the installation of one condenser, one generator step-up
transformer, one unit auxiliary transformer,
one STG generator circuit breaker, a cooling tower, and the necessary associated
equipment.
The 2x2x1 configuration will require the
installation of bypass stacks, which will only
be operated as an emergency/back up option
in the case the plant is in open cycle mode
operation. The new stacks will be 45 to 54
meters high (to be defined during detailed
engineering).
The existing gas turbines were designed
to operate with fuel oil and in 2003 were
transformed to operate with natural gas.
Since then, the turbines have exclusively
operated on gas. Two fuel oil storage tanks
(1,000,000 gallons each) and related facilities are maintained for potential future use.
Natural gas for the plant comes from
AES Andres LNG terminal and regasification plant. It is transported through an existing 34 km long 12-inch diameter buried gas
line, commissioned in 2003 and operated by
AES Andres. The gas line is equipped with
4 GAS TURBINE WORLD July – August 2014
four remotely operated and secured block
valve stations. Los Mina Units V and VI are connected
to the transmission grid via overhead 138 kV
transmission lines to an electrical substation
and electrical switchyard operated by the local electrical transmission company.
The combined cycle conversion project
will require installation of another generator
step-up transformer that will be connected to
the transmission grid through an expansion
of an existing switchyard within the brownfield site. New Mexico
PNM turnkey contract for
43MW LM6000PC peaker
Public Service Co. of New Mexico (PNM)
has awarded Wellhead Construction a turnkey contract for construction of a gas-fired
LM6000PC simple cycle peaking plant in
Belen, New Mexico, approximately 35 miles
south of Albuquerque.
GE’s LM6000PC gas turbine is ISO rated
at 43.4MW gross base load output with a
heat rate of 8516 Btu/kWh hr (40.1% efficiency) on natural gas fuel.
Under scope of the contract, Wellhead
Construction is responsible for engineering,
procurement of major equipment, construction and providing startup services.
In addition to burning natural gas fuel
to limit combustion emissions, the La Luz
peaking plant will be equipped with selective catalytic reduction and carbon oxidation
reductions system to control emissions.
In addition to an LM6000 gas turbine
package and related auxiliary system skids,
balance of plant equipment includes the
emissions reduction unit with SCR and CO
catalysts, continuous emissions monitoring
system, compressed air system, wter treatment and supply system, high-voltage 115kV
switchyard, generator step-up transformer
and 480-volt step-down transformers.
Project timetable calls for start of construction later this year and completion in
time for commercial service by early 2016.
Saudi Arabia
Six combined cycle power
blocks synchronized to grid
The last of 6 power blocks for the Qurayyah
Combined Cycle Power Plant Project was
synchronized to the grid right in time for the
forthcoming 2014 summer peak demand in
the Kingdom of Saudi Arabia.
With block 6, adding another 635MW
(net), the total output of the Qurayyah mega
project has been increased to its designed
overall electrical capacity of 3,813MW at
reference site conditions (50°C, 70% humid-
ity, 40°C seawater).
At ISO conditions, the power plant output would 4,752 MW, ranking Qurayyah as
one of the biggest power plants worldwide.
Each power block consists of 3 x GE 7FA
gas turbines, 3 corresponding heat recovery
steam generators (triple pressure, reheat),
and one GE D11 steam turbine.
Mexico
CFE to tender $2.8 billion in
power plant, pipeline projects
Mexico’s national power company CFE said
it will offer $2.8 billion in natural gas and
electricity infrastructure project contracts by
the end of this year aimed at boosting economic growth.
Contracts include the construction of two
combined cycle power plants, two natural
gas pipelines and an electricity transmission
system, all located near Mexico’s northern
border with the United States. Their purpose
is to boost natural gas imports from the U.S.
and over time help lower electricity rates
via cheaper inputs and more modern power
infrastructure.
The first power plant project to be built
will be the 928MW combined cycle Norte
III power plant to be located about 19 miles
south of the border city of Ciudad Juarez
which is expected to cost about $1 billion.
Winning bid will be announced in December.
This will be followed by the 714MW
combined cycle Guaymas II power plant
located in northwestern Sonora State which
is expected to cost about $822 million.
That winning bid will also be announced in
December.
The 263 mile Encino-La Laguna natural
gas pipeline will transport gas from southern
Texas to supply northern Chihuahua and Durango states. It will cost about $650 million,
and the winning bid will be announced in
October.
The Huasteca-Monterrey transmission
line will cover 268 miles crossing northern
Tamaulipas and Nuevo Leon states and include two substations. It is set to cost about
$257 million, and the winning bid will be
announced in November.
Finally, the 14 mile San Isidro-Samalayuca natural gas pipeline will transport gas
from southern Texas to the new Norte III
power plant in Chihuahua State. It will cost
about $50 million, and the winning bid will
be announced in December.
Ghana
5-year program to build and
expand 1,000MW power park
General Electric is partnering with the Millennium Challenge Corporation (MCC) to
Industry News
provide $500 million in financing to support
development of a joint venture power project
initiated by GE in partnership with Endeavor
Energy and Finagestion.
Once completed, Ghana will have the
largest power park in sub-Saharan Africa
that will grow in stages to end up providing 1000MW to Ghana’s national grid. The
five-year project will boost Ghana’s power
generation capacity by 50% from the current
2000MW installed capacity.
To rapidly respond to existing power
shortages, the Ghana 1000 project will come
online incrementally, with the first phase to
add 360MW by September 2016, which will
grow to 540MW by 2018 and the full quota
of 1000MW in 2019.
The plant will use LNG-to-power technology that will consist of 6 x GE Frame 9E
gas turbine generators in combined cycle.
The gas turbines will be equipped for tri-fuel
combustion to operate on natural gas, heavy
fuel oil and light crude.
GE’s proposed 9E.03 gas turbine plant is
ISO rated at 130MW gross base load output
and 34.6% efficiency on natural gas fuel for
simple cycle power generation.
In a 1x1 combined cycle configuration, with an unfired HRSG and 69.4MW
steam turbine generator, the plant is rated
at 195MW net base load output and 52.1%
combined cycle efficiency.
In a 2x1 configuration, designed around
two unfired HRSGs and 141.1 steam turbine
generator, the combined cycle is rated at
392.5 net base load output and 52.7% combined cycle efficiency.
Australia
150MW ‘BOO’ combined
cycle station power project
TransAlta Corp. has won its bid to build,
own and operate a 150MW combined cycle
power station in South Hedland, Western
Australia. The project will be built and funded over the next 30 months at an estimated investment cost of approximately AUD
$550M (US $485 million).
Operational plans call for the phased
construction station to be ready for simple
cycle power generation in 2016 (while the
steam bottoming cycle equipment is being
installed) with full combined cycle commissioning of the station in 2017.
Project’s development, fully contracted
under 25-year power purchase agreements
with a state-owned utility, Horizon Power,
and the Fortescue Metals Group may be expanded at some later date to accommodate
additional customers. For now, the station
will supply Horizon Power’s customers in
the Pilbara region as well as Fortescue’s port
operations.
“Our bid on this development project
illustrates the importance and focus that
TransAlta places on customers and business
in Western Australia,” said Dawn Farrell,
President and CEO of TransAlta. “We want
to be the company of choice in providing
reliable and low cost power to customers in
the remote mining regions of the State and
are pleased to be adding another asset at an
important location like Port Hedland.”
Texas
Utility adding two LMS100 plants
for peaking and intermediate duty
The Texas Public Utility Commission approved a September 2013 application
from El Paso Electric (EPE) for two additional 88MW natural gas-fired units at
Available for delivery January 2015
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Call: 203-247-3991
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Industry News
its Montana Power Station in EPE’s service
area in eastern El Paso County.
El Paso Electric has received Texas PUC
authorization to add two gas-fired General
Electric LMS100 gas turbine peakers, Units
3 and 4, at its Montana Power station which
are identical to the first two units currently in
service.
Although the units have a nameplate rating of over 100MW at ISO conditions, each
unit will deliver 88MW (net) to EPE under
summer peak conditions due to the relatively
high elevation and high ambient temperatures in this area of Texas. The high elevation
in the area also means that their heat rate will
be higher than it would be at ISO conditions.
The LMS100PA is rated at 103.5MW
gross base load output and 7815 Btu/kWh
heat rate (43.6% efficiency) at 59F ambient
and sea level ISO conditions. The guaranteed full load heat rate for the Montana units
is 9,074 Btu/kWh which is equivalent to
37.6% thermal efficiency.
In addition to peaking, they will be used
for intermediate service and are expected to
operate at approximately a 40% capacity factor. They are also quick start units that can
be brought on-line within three minutes and
reach full load within 10 minutes of startup.
The cash capital cost of the two new
plants is estimated at $151.2 million total for
engineering, equipment and construction. Allowance for funds used during construction
is estimate at $17.9 million for a total cost of
$169.1 million.
Construction of the first two units at the
plant is expected to be completed by the
summer 2015 peak season.
Montana Units 3 and 4 are expected to
be operational by the summer peaks of 2016
and 2017, respectively.
Uzbekistan
Loan approved for combined
cycle power plant upgrade
The Asian Development Bank announced
that it has approved a $300 million loan to
upgrade Uzbekistan’s Takhiatash Thermal
Power Plant (TPP) in order to meet the country’s growing demand for electricity.
The project will involve the construction of two new combined cycle gas turbine
plants of up to 280MW each and the decommissioning of three existing turbine units.
It will also support staff training and
other assistance for Uzbekenergo, the stateowned power utility, which needs to modernize its management and information technology systems. The project is expected to
take six years, with a projected completion
date of October 2020.
The Takhiatash TPP is the main source
of power supply in the Karakalpakstan and
Khorezm regions. With 730 MW of installed
capacity, the plant now comprises five gasfired steam turbine generation units. Three
units totaling 310MW have passed their designed economic life, and have been operating with de-rated capacity (130MW), low
thermal efficiency (23.7%), and limited plant
availability (25%).
The other two units, totaling 420 MW, are
26 years old or less. However, their capacity
is derated by 15%, the efficiency is low at
31%, and they are over-utilized to meet demand, which prevents regular maintenance.
To ensure reliable power supply, the government and Uzbekenergo, the state-owned
power utility, identified the project as a priority and decided to construct two CCGT units
(230 280 MW each); decommission three existing power units (Nos. 1&3); and maintain
two power units (Nos. 7&8) for backup.
Uzbekistan’s power generation plants are
generally old and inefficient, requiring urgent
modernization. More than 75% of the power
plant units are over 30 years old, reaching
or exceeding their economic life. Their thermal efficiency averages 31%, while that of
energy-efficient CCGTs exceeds 50%.
Replacing existing power generation assets with energy-efficient equipment is a key
strategy for saving energy, securing reliable
power supply, and reducing greenhouse gas
emission.
Philippines
Financing tor 410MW
combined cycle plant
First NatGas Power Corp., a 100% owned
company of the Philippine independent power producer First Gen Corporation, has obtained a $265 million export credit through
a German bank to partly finance its 414MW
San Gabriel natural gas-fired power project
which is valued at about €395M (around US
$502 million).
Proceeds of the loan will be used primarily to finance the eligible German and nonGerman goods and services under the equipment supply contract of the San Gabriel
power plant. Siemens Energy has a turnkey
contract for engineering, procurement and
construction of the San Gabriel combined
cycle power plant in Southeast Asia.
The single-shaft SCC6-8000H 1S combined cycle plant is rated at 410 MW net
plant output and over 60% efficiency. Scope
of equipment supply includes an SGT68000H gas turbine, SST6-5000 steam turbine, hydrogen-cooled SGen6-2000H generator, Benson type heat recovery steam generator, electrical engineering as well as the
SPPA-T3000 control system.
Construction services are being provided
by a Simens subsidiary in the Philippines.
The plant is scheduled to be completed in
the first half of 2016. Meanwhile, demand
for electricity in the Philippines is expected
to almost double from 22 GW of installed
capacity to 42 GW by 2030.
San Gabriel is being built in Batangas
City located in the Calabarzon region, which
is about 110 km south of the Philippine capital of Manila. It is one of three power facilities that First Gen is developing in Batangas
City that will add 1,350 MW of generating
capacity.
United States
Financing secured for three
M501 power plant projects
NTE Energy, a power developer and energy
services provider, has secured an equity investment from Capital Dynamics and Wattage Finance for a trio of natural gas-fired
Mitsubishi power projects.
The investment will allow NTE Energy
to complete development of these projects,
which are valued at more than $1.1 billion,
and begin construction of all three projects
next year.
The development portfolio comprises a
518MW Middletown Energy Center combined cycle project in Ohio; 475MW Kings
Mountain Energy Center combined cycle
project in North Carolina; and site-rated
237MW Pecan Creek Energy Center simple
cycle project in Texas.
Middletown will be powered by a 1x1
Mitsubishi M501JAC (air cooled) combined
cycle rated at 450MW net plant output and
over 61% efficiency, Kings Mountain by a
1x1 M501GAC (air cooled) combined cycle
rated at 412.4MW net and 59.5% efficiency;
and Pecan Creek by a 276MW simple cycle
M501GAC Fast gas turbine.
The combined cycle projects will require
duct firing to increase the plants’ steam turbine power output (over and above non-fired
HRSG steam output). The M501 simple
cycle gas turbine’s 276MW and 39.8% efficiency ISO output will be de-rated by design
conditions to its 237MW site rating.
All three NTE Energy power projects
now in the late stages of development are
expected to close financing and go into construction in the next nine to 12 months. Submit News Articles & Images
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La Caridad 500MW plant reducing
Grupo México’s COE by 40 percent
By Junior Isles
Unit II of La Caridad was declared ready for commercial
operation in June this year, marking completion of the copper
mining company’s two-unit 500MW combined cycle power plant.
I
n a move to cut mining production
costs, Grupo México has embarked
on a plan to ultimately have its own
power plants provide 90-95 percent of
its operating electricity requirements.
One of its subsidiaries, Minera
Mexico, which owns copper mines
in Mexico and the United States, recently commissioned the second of
two Siemens SGT6-5000F combined
cycle turnkey units.
o
Power output. The two 1x1 combined cycle units are site rated at
258.1MW net output at site conditions and 56.9 percent efficiency.
o
Cost savings. New plant is expected to lower the cost of electricity for
mining operations by 40 percent to 6
cents/kWh from 10 cents.
o
Emissions. Gas turbine DLE combustion will limit NOx to less than 25
ppm in compliance with México and
World Banks emissions standards.
Mining and smelting is a highly energy intensive process. Reducing the
cost of electricity can therefore be a
significant contributor to lowering the
cost of production and thereby improving the price competitiveness of
mining companies.
Grupo México began looking sev8 GAS TURBINE WORLD July – August 2014
eral years ago at how it might reduce
the cost of energy. It developed a
business case to show that it would
be more economical to have its own
generating facilities to supply electricity for Minera México’s copper
mining and refining facilities near La
Caridad, in Sonora State, in the western part of the country and for another
mine some 100 km away.
Project scope
The company hired Black and Veatch
as its owner-engineer to perform plant
feasibility and siting location studies
etc. followed by a Request for Pro-
posals (RFP). Initially four companies
submit competitive bids to provide
equipment construction of the two
plants.
However, since building power
plants is not Grupo México’s core
business, it subsequently decided to
instead look for a supplier that could
deliver the plants on a turnkey basis
and would offer a long-term service
agreement.
Eliuth Lopez, Siemens project
manager for La Caridad recalled: “We
initially did submit an offer for equipment only, i.e. a reduced scope power
island and later submitted an offer for
Looking to generate 90-95% of its
power requirements in-house
Grupo México is Mexico’s largest mining company and one of the
world’s biggest copper producers.
The company operates mines in Arizona and in Texas where it
also has mines, smelting facilities and a refinery for copper. It also
specializes in infrastructure projects such as highways, hydroelectric
dams and railways services.
One of its subsidiaries is Minera México, which owns two large
copper mines in Mexico that, until recently, were powered by electricity predominantly supplied by CFE, Mexico’s state utility.
The utility supplied around 90 percent of Minera México’s electricity, with the other 10 percent coming from independent power producers (IPPs). In a move to cut production costs.
Grupo México is now embarked on a plan to have 90-95 percent
of its electricity supplied from its own power plants.
the turnkey bid request.
“Company mining executives visited the Norte combined cyle power
plant that we had just built in the state
of Durango, Mexico, in August 2010
and liked what they saw.
This greatly improved our position
with Grupo Mexico who subsequently
came to Siemens for an EPC solution.”
Under the EPC turnkey scope of
supply Siemens delivered two combined cycle units each equipped with
an SGT6-5000F gas turbine and
SGen6-1000A air-cooled generator,
one SST-700/900 RH steam turbine
and SGen6-100A-2P generator, heat
recovery steam generator, and the
complete electrical and SPPA-T3000
instrumentation & control equipment.
Notably, the gas turbine for the La
Caridad I combined cycle power plant
was shipped in November 2011 at the
opening of Siemens’ new gas turbine
manufacturing facility in Charlotte,
USA. It was the first turbine to be
shipped from the facility.
Plant configuration
The SGT6-5000F gas turbine is the
latest version of Siemens 60Hz Fclass engine providing over 200MW
of power at ISO conditions.
Its design features a 16-stage axialflow compressor, combustion system
comprised of 16 can-annular dry low
NOx combustors, and a 4-stage reaction-type turbine.
The gas turbine’s power output
shaft is coupled directly to the generator at the compressor end of the engine. Natural gas fuel is provided by
three different sources in the US via
a 105 km pipeline that interconnects
with El Paso Natural Gas’s interstate
pipeline system.
Hot exhaust gas leaving the turbine
is fed to a three-pressure heat recovery steam generator for steam turbine
operation. The HRSG for the first
combined cycle unit was supplied by
Nooter Eriksen. The second HRSG
was supplied by Cerrey SA (Mexican
company formerly called Combustion
Engineering Monterrey).
High pressure (HP), intermediate
pressure (IP) and low pressure (LP)
sections of the HRSG contain superheater, evaporator and economizer
tube bundles.
The HRSGs are each connected to
a 2-stage kettle boiler. Steam generated in the HRSG is conveyed through
piping systems to the steam turbine.
The SST-700/900RH steam turbine
is a two-case multi-stage, reheat condensing unit with a high efficiency
blade path. The higher speed HP turbine drives the generator via a gear-
Mining site. Minera México’s copper mining and refining facilities near La Caridad in Sonora State.
www.gasturbineworld.com GAS TURBINE WORLD July – August 2014 9
World Bank emissions standards.
Water for the power station will
come from an underground source
2-3 km away and any effluent discharged will be treated in order to
comply with the Mexican standards
for discharged water.
Gas turbine. This gas turbine for the La Caridad project was the first unit to be
shipped from Siemens’ new gas turbine manufacturing facility in Charlotte, USA.
box, while the IP/LP turbine is directly connected to the other end of
the generator.
A water-cooled condenser is provided to condense the steam turbine
exhaust and miscellaneous drains from
the steam cycle. The condenser includes a vacuum system that utilizes
liquid ring vacuum pumps. The condenser is designed to allow 100 percent steam bypass of the steam turbine.
A forced-draft, counter-flow cooling tower provides the heat sink for
the steam cycle. The cooling tower
transfers heat from the circulating
cooling water by means of circulating
water evaporation and sensible heating of the air.
Circulating water pumps maintain
the water flow between the cooling
tower and the condenser and other
cooling water users.
The choice of technology was determined by the power demands of the
mining operation as well as efficiency.
According to Siemens and the plant
owners, the combined cycle station
has an electrical efficiency of 56.9%.
Grupo México has made a concerted effort to minimize environmental
impacts by optimizing the efficiency
of the entire facility. Heat from the
water used to cool the flash furnace
in the refining process is also recov10 GAS TURBINE WORLD July – August 2014
ered in a waste heat recovery boiler
to generate steam for feeding a small
11.5MW Siemens turbine.
The environmental impact of the
plant was considered in the evaluation process and plant design. The gas
turbine combustion system allows the
plant to achieve NOx levels of ≤25
ppm complying with both Mexico and
Modularization
Lopez also noted that another key consideration for Grupo México was design of a plant that could be constructed in the shortest amount of time.
The construction time for each
plant – with an 8-month stagger between Units I and II – was less
than 30 months from the Notice to
Proceed. This short schedule was
achieved through extensive pre-fabrication and pre-assembly.
Lopez commented: “There are two
options when constructing plants. Either you can ‘stick build it’ – where
you bring all the materials to site and
literally build it like a house – or you
can build as much as possible off the
construction site and bring it in as
pre-assembled modules.”
Systems such as cooling units and
Design features. The SGT6-5000F gas turbine features a 16-stage axial-flow compressor, 16 can-annular dry low NOx combustors and 4-stage reaction-type turbine.
pump and pipe systems were delivered to the construction site prefabricated and integrated into the other
systems on site.
“It’s a case of shifting as much
work as possible to a controlled environment and doing all the pre-assembly, quality control and shipping to
the job site where only minor integration is then needed,” added Lopez.
Pre-fab modules
Around 20 modules were delivered
as prefabricated units, including six
auxiliary systems such as gas conditioning unit, domestic water pump
module, heat exchanger module, air
compressor and the cooler unit.
Pumps and compressors represented the highest percentage of prefabricated components. A level of 47 percent prefabrication was achieved for
instrumentation, followed by steelworks at 46 percent and piping at 40
percent.
Lopez said: “The biggest area of
integration for us was the pipe-rack
i.e. all the steam piping between the
HRSG and steam turbine. So we went
for a pre-assembled, modular pipe
rack. Fabricating it off-site guaranteed
the quality of the material; the chromium alloy is very sensitive material
that must be quality assured.”
According to Siemens, pre-assembled pipe bridge modules, for example, enabled around 31,000 man-hours
to be shifted to prefabrication. This
yielded time and cost savings while
providing low risk and enhanced
quality.
The pipe racks were brought in as
pre-assembled modules, placed on the
foundation and welded together at the
job site. According to Lopez, this approach saves 8-10 weeks on the construction schedule.
He noted: “This is one advantage of
doing a turnkey contract; it provides
risk mitigation, so you don’t lose the
schedule, and improves constructability and safety. We had over 4.5 million
man-hours at the job site without a
loss-of-time accident. The customer
said it was one of the best job sites
they had ever seen in Mexico.”
Total wrap
Both plants will operate in baseload.
All the power from the first plant,
which began operation in September
last year, is being consumed by the
mine operations.
Although the second plant was
completed in June this year it is not
in operation, as the mines do not yet
need the additional power. Lopez
notes: “It will probably be another 8
months or so before they have the load
needed to start up the second plant.”
Siemens’ involvement in the project does not end with hand-over of the
power plants. Its contract with Grupo
México constitutes a total package
– from proving a single customer in-
La Caridad project. Grupo México has built two 1x1 SCC6-5000F combined cycle plants, La Caridad I and II, each rated at
258.1MW net output at site design point conditions.
terface during construction and commissioning, to ongoing service after
start-up.
Lopez commented: “We were able
to give them the whole package. We
call it the total wrap – the performance wrap, complete integration of
all sub-systems into one clean totally
integrated system.
“We take on schedule risk and all
risk management for the owner. This
was very important for the customer –
a single point of contact to ensure they
would get their power plants on time.”
An added level of comfort will
be provided during the plant’s operating life through an 18-year long
term service agreement, covering the
gas turbines and steam turbines and
their respective generators’ scheduled
outages.
An inspection of the combustion
system will be required every 16,600
equivalent base hours (EBH). Hot gas
path inspection will be undertaken at
33,200 EBH, at which time hot gas
path components will be replaced.
Future possibilities
Grupo México has a long term plan
for expanding its mining operations.
Pursuing the self generation path will
help facilitate this expansion.
Speaking at the time of the order
for La Caridad Unit II, Grupo México’s CEO, Xavier Garcia de Quevedo,
said: “The cost of buying power is
very high. As an example, we have
similar mines in Arizona. There we
pay 6 cents/kWh, while in Mexico
we pay just over 10 cents/kWh. With
the new combined cycle plant we will
save 40%.”
Lopez says it looks very likely
that there will be other power plants
similar to those that Siemens built at
La Caridad. “They are already doing
additional feasibility studies to see
where it makes sense to put another
power plant,” he said.
Certainly the success of La Caridad
and the customer’s satisfaction sets
Siemens up for potential future business with Grupo México. n
Steam generator. Pre-assembled HRSG pipe rack modules were placed on the foundation and welded together at the job
site, shaved an estimated 8-10 weeks off the construction schedule.
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Cheng Cycle CHP building on
30 years of industry experience
Advanced gas turbines
21 Unlocking built-in entitlement
By Victor deBiasi
Cheng Cycle technology is being considered for retrofitting both
vintage and advanced H- and J-class simple cycle gas turbine
plants for a 40% fuel saving and 70% increase in power output.
T
hirty years ago the Cheng Cycle
was first commercialized as a
CHP system installed at the San Jose
State University campus to supply
electricity and steam for campus heating and cooling.
Since that day approximately 300
Cheng Cycle plants have been built
around the world, all operating in
combined heat and power (CHP) applications, with a basic design that
has not changed over the last 30
years.
When San Jose made its debut in
1984, it was the first digital computer controlled gas turbine plant of its
kind. It was also the only plant to
offer combined cycle levels of performance without the complexity (equipment and footprint) of a steam turbine
bottoming cycle.
Load matching
Cheng Cycle CHP systems are designed to simultaneously generate
electrical power and process steam in
different quantities independently of
each other to best meet changing load
demand.
This enables operators to overcome a common dilemma posed by
simple cycle gas turbine cogeneration systems in response to changes in
electric power or steam requirements.
Conventional cogeneration systems operate in lock step whereby
electrical power generated by the gas
turbine increases or decreases in the
same proportion as the amount of
steam generated – regardless of how
much electric power or process steam
is needed.
Cheng Cycle CHP installations on
the other hand can increase or reduce
the amount of steam generated for
gas turbine steam injection and/or
process. Depending on requirements,
HRSG steam output can be used for
electrical power, process steam exclusively or as a controllable mix of
power and process.
Cheng Cycle plant. Plant arrangement of the first commercial Cheng Cycle gas turbine plant built in 1984 at San Jose
State University. To date the plant has logged more than 235,000 hours of operation (as of August 2014) and more than
2,700 starts.
Electric
Generator
Allison 501
Gas Turbine
Steam Injection
Piping
HRSG
Commercial startup of historic Cheng CHP installation
The world’s first combined heat and power Cheng Cycle plant was
fired up on December 31, 1984 at the San Jose State University
campus.
Several industry visitors invited to witness that startup included Eva
Skov the A/E project manager from Ebasco, David Porter the support
engineer from Allison Gas Turbines and Russell Stanley the genset
packager rep.
Also present were Richard Zahner the plant operating manager, Bill
Conlon the control engineer, Jim Hamill and Stan Shepard plant support engineers, Sandy Sandoval the plant operator and others.
Every person in that group was surprised to hear that the steam
injection valve would remain fully open throughout the startup procedure. When a boiler is cold, an open valve during startup allows
pressurized air from the gas turbine compressor to flow backwards
through the steam line into the boiler drum.
The flow of high pressure air raises the boiling pressure and temperature of the water stored in the drum. In this case, the gas turbine
was started up and quickly reached its full simple cycle output of
3.25MW and maximum 950°F exhaust temperature in less than 2 minutes. The result was a rapid production of steam without boiler upset.
The minute that steam was produced, its pressure drove all the air
out of the drum back into the gas turbine. At that point, steam being
generated (for the Cheng Cycle) began flowing to the gas turbine.
The engine followed a step-by-step increase in power output as
controlled by the gas turbine firing temperature limits. As soon as it
reached maximum power, the steam valve returned to its computer
controlled position to regulate the steam injection rate in accord to the
Cheng Cycle performance curve.
The operator, Sandy Sandoval, was watching the drum level of the
boiler and saw that the water level moved neither up nor down. Later
he said that he would never have believed it if he hadn’t seen it for
himself. Ever since, according to plant operators, rapid plant startups
have never caused a boiler upset.
Many engineers contributed to pioneering development of the technology, Dr. Dah Yu Cheng notes, including Jim Hamill, Russ Stanley,
Ramji Digumarthi, Ralph Kidder and Del Tischler. An even larger
group, now deceased, also made significant contributions to the evolving technology including J. Lloyd Jones, Harold Hornby, Mark Waters,
Jim Strother and Bob Hillery.
Operating domains
The design of the Cheng Cycle CHP
system has not changed over the last
30 years since first introduced.
Essentially the technology involves
the addition of an HRSG steam cycle
to a simple cycle gas turbine plant installation which injects steam into the
gas turbine to increase power output,
and separately generates steam for
industrial process application.
The Cheng Cycle CHP system
www.gasturbineworld.com HRSG operates with or without duct
firing depending on operating regime
(see diagram on next page):
Regime A with supplemental firing, which is the operating domain for
producing steam for gas turbine injection to boost power output plus steam
for process requirements.
Regime B without duct firing,
where the HRSG output can be toggled between supplying steam on demand for gas turbine injection and
steam for process.
Regime C without duct firing,
where there is no steam injection for
gas turbine power boost and all the
HRSG steam goes to process for heating or air conditioning.
Shown at the lower left of the diagram, the boundary line between B
and C defines the operating trajectory
where steam output is proportional to
the power increase of the gas turbine.
The upper boundary line between
B and A defines the increase in power
output possible with gas turbine steam
injection while reducing the steam
available for process. That line terminates at the vertical axis where all the
steam is being injected into the gas
turbine for maximum plant output and
efficiency.
That point corresponds to what
might be termed a “Cheng Power Factor” where the full-steam injected gas
turbine’s electrical output corresponds
to about a 70% boost in base load output and there is no steam available for
process.
Gas turbine application
These three operating domains are the
same for any Cheng Cycle gas turbine
combined heat and power plant application.
The specific increase in electric
power and steam output will vary for
specific models but, in general, are
substantial as shown by the comparative performance of Rolls-Royce’s
aeroderivative 501KH gas turbine
(see table on next page).
With very few exceptions most gas
turbine designs can be configured into
a Cheng Cycle, even models with apparently inherent design and operating
limitations (both old as well as new
units). Often such limitations can be
circumvented with careful design, Dr.
Dah Yu Cheng maintains.
Existing gas turbine installations
can be retrofitted for Cheng operation
at less than half the cost of conversion
to combined cycle operation, he says.
And within a considerably smaller
land area since there is no need for a
Operating domains. The Cheng CHP system has two HRSG modes of operation: 1) with duct firing to supply steam for gas turbine injection and process,
and 2) without firing where all the HRSG output goes to process.
1.7 –
– Max
Cheng Power Factor
A
Electric Output
GT injection
plus process
B
GT
power
C
Process steam
only
1.0 –
–0
0–
0
|
Process Steam Output (lb/hr)
Max
|
Cheng Cycle vs STIG steam injection
The Cheng Cycle requires a conceptual change in HRSG design and
operation that according to Dr. Dah Yu Cheng is foreign for the most
part to the industry and completely different from constant pressure
HRSGs used for fixed flow pressure STIG applications.
Attempts to improve STIG performance by using once-through boiler
designs fail to understand that his cycle is based on thermodynamic
feedback akin to electronic feedback, he says.
Typical steam injected gas turbine (STIG) operation is based on introducing steam into a gas turbine downstream of the combustion system at a predetermined pressure, temperature and flow rate without
regard to changes in gas turbine operating parameters.
In contrast, Cheng Cycle steam injection is constantly regulated during gas turbine operation to stay in tune with transient changes in gas
turbine performance parameters such as pressure ratio, compressor
flow and firing temperature.
A digital control system programmed to capture peak efficiency
steam injection operation at all times from full to part-load output is
designed to optimize Cheng Cycle performance over the complete
range of gas turbine operating conditions.
Fast response to load change requires a drum type HRSG design to
provide energy storage. Otherwise, he explains, the system will experience a delayed response in heating and cooling due to the thermal
inertia of the HRSG mass.
Cheng Cycle is truly a cycle in the classical thermodynamic sense,
Dr. Cheng states, whereas the STIG design application of mass steam
injection is not a cycle. There is a fundamental thermodynamic difference between the two.
steam turbine plant and all of its associated systems.
The cost of engineering, equipment and installation for converting
an LM6000PC gas turbine plant to
Cheng Cycle operation is an example.
He estimates the total retrofit cost at
around $15 million versus more than
$30 million for a typical combined
cycle conversion.
[Editor’s note: For more information, we refer you to a rather extensive article on engineering aspects,
application, performance, operation
and economics of Cheng Cycle technology that was published last year
in the March-April 2013 issue of Gas
Turbine World. Today’s article picks
up from there to report on the application of that technology to specific
models.]
San Jose case study
Over the last 30 years of operation,
the 501KH5 Cheng CHP installation
at San Jose has built up an extensive
range of engineering, performance
and maintenance experience on a
Cheng Cycle plant in commercial operation.
Twelve unusually large injection
ports on the order of 2.5 to 3-inches diameter are used to inject steam
into the 501 gas turbine downstream
of the compressor for rapid mixing
with compressor discharge air into the
combustor.
Some of that steam premixed with
air entering the swirling vanes around
the fuel nozzles suppresses the production of NOx emissions during
combustion. As a result, the 501 unit
at San Jose operates at very low levels
of NOx on the order of 22 ppm at full
load which, in 1985, was unprecedented for any gas turbine to achieve.
The Allison 501 gas turbine also
incorporates internal air cooling passages that now have an additional
steam/air mixture which keeps the hot
gas path parts cooler.
A study sponsored by PG&E to
evaluate the steam/air cooling on the
San Jose turbine was the subject of
an ASME IGTI paper, No. GT-200230514, which was written in 2002.
TBO 42,500 hours
Among other results, the paper reports that the time between hot parts
overhaul has been increased to 42,500
hours from 12,500 hours.
This is due to the fact that steam is
mixed with the air entering the cooling passages of the first stage nozzles
and blades.
The steam increases the heat removal capacity and reduces thermal
stresses and other damaging effects
of high temperature in the hot metal
parts. The steam also helps increase
heat content of the working fluid.
Typically, turbine inlet temperature
must be raised in order to increase the
heat energy content per unit mass of
working fluid. But since the specific
heat of steam is about twice that of
air, the steam air mixture increases
heat content without raising the working fluid temperature.
Operating profile
The San Jose CHP plant is programmed and fully automated to control electrical power and steam output
in response to seasonal variations in
demand for power and process steam.
For example, electrical power during the summer days is produced at
maximum capacity which is enough
to supply power to the State University campus with a surplus for sale to
the grid. The process steam produced
goes to drive an absorption chiller
which provides 4°C water in the piping system to all of the buildings and
dormitories.
During summer nights the electric
power is cut back and process steam
reduced to the minimum needed for
supplying only the dorms with chilled
water cooling.
During winter days, electric power
is also produced at maximum capacity for campus use with surplus sold
to PG&E for the grid. The HRSG
duct burner also operates to maximize
steam output to heat all the buildings.
Retrofit potential for existing gas turbines
There is potential to retrofit existing designs such as GE 7EA and 9E
gas turbine series for upgraded Cheng Cycle performance without extensive modification.
Typically the original designs for older gas turbines provide only
a limited surge margin for steam injection. This design limit can be
bypassed by opening up the flow area of the first stage nozzle, usually
around 5 percent.
In recent years General Electric introduced an upgraded PHmodel of its LM2500PE gas turbine by opening up the first stage PEnozzle to allow a larger surge margin. Generally the surge margin of
old machines can be increased simply by rotating the nozzle vanes
about 3-5 degrees.
The 9E for instance can be retrofitted for Cheng Cycle steam injection to operate safely with a surge margin of 8 percent, and significantly increase its power capacity and efficiency (even at high ambient temperatures) with about a 10% increase in pressure ratio.
Frame 9E Gas
Turbine Unit Power Pressure Output Ratio Heat Rate (per kWh) GT Plant
Efficiency
Simple cycle 128.0 MW
12.6 to 1 9980 Btu
34.2 %
Cheng Cycle 217.8 MW 13.5 to 1 7306 Btu 46.7 %
On top of producing almost 70 percent more power and reducing fuel consumption by 40% per kWh, the 9E Cheng Cycle retrofit
provides 233,603 lb/hr of process steam (at 120 psig saturated) which
lowers the 7306 Btu/kWh plant heat rate for electrical production to
6,025 Btu/kWh, equivalent to 56.6% plant efficiency.
This steam can be used to provide the energy source for absorption chillers for large complex air conditioning systems or serve as a
heat source drive for multistage desalination systems and other industrial uses.
Dr. Cheng notes that in 2006 China
installed two FT8 TwinPac CHP systems in downtown Beijing for similar
duty. They operated to provide electric power all year round and steam
in the winter for municipal heating.
In the summer the steam output was
used to drive absorption chillers for
air conditioning.
Air conditioning in the city of Beijing was previously provided by win-
dow units running on electrical power.
It was very expensive. Operating the
CHP system (for city block air conditioning) took the electrical load away
from the utility and helped make the
project economically viable.
Large scale CHP systems
The CHP market is growing rapidly
around the world for base load electric power generation and process
501KH gas turbine plant. Cheng Cycle CHP can increase gas turbine power
output by up to 3,000 kW plus supply up to 25,000 lb/hr of process steam.
501KH
Gas Turbine
Base Load
Output
Heat Rate
per kWh
Electric
Efficiency
Process
Steam
Simple cycle cogen
3,800 kW
11,747 Btu
29.1%
45,000 lb/hr
Cheng Cycle CHP
6,800 kW
8,221 Btu
41.5%
25,000 lb/hr
Source: Cheng Power Systems, August 2014
steam -- typically for refineries, small
industrial food processing plants and
paper mills – and to replace coal-fired
electric utility power and district heating cooling systems.
More recently in China, a large
Mitsubishi M701 combined cycle
plant for CHP operation was built in
the Bejing area to cut down on heavy
pollution from coal-fired power
plants. Government officials say they
will be shutting down and replacing
an unspecified amount of coal-fired
power plants with gas-fired CHP systems on a national scale.
In Europe the widespread and
growing installation of alternative energy, solar and wind power generating
capacity has made thermal-fired IPP
and utility power generation uneconomical and unsustainable.
Utilities have been forced to cut
back and shut down both simple cycle
gas turbine peaking plants and combined cycle plants that are no longer
required.
The exceptions are gas turbine
heat and power systems that have survived, doing well economically, and
able to generate additional income by
selling process steam.
China for many years produced
process steam for big cities using
coal-fired boilers. In several regions,
due to heavy pollution, those coalfired boilers are now required to be
modified or shut down for replcement
by CHP systems.
The typical configuration for large
projects heat and power is a combined
cycle such as the Mitsubishi M701
gas turbine and steam turbine on the
same shaft driving a large 350MW
generator. Gas turbine power is typically 270MW.
While the HRSG produces enough
steam to generate about 130MW of
power, steam turbine produces only
80MW electrical while an additional
50MW (equivalent) of process steam
is supplied as heat for large city
blocks during the winter.
This kind of system worked well
during the 2008 Olympics where it
helped reduce the air pollution around
Beijing. The configuration has similar
characteristics to a simple cycle CHP
Retrofit system modules. Cheng CHP retrofit modular package design features a duct-fired heat recovery steam generator (HRSG) with a low-pressure boiler and highly superheated steam generator. More compact and simpler than a combined cycle plant which requires the installation of steam turbine power plant and associated equipment.
Deaerator
Module
Lube Oil
Cooler Module
Air Inlet
Filter
Evaporative
Cooler
Economizer
Plant Air
Module
Fuel
Module
Electrical
Module
HRSG
Module
Injection
Steam Piping
Water Treatment
Module
Exhaust
Transition
Genset
Superheater
Firing
Duct
Burner Transition
Evaporator
plant in that the electrical power generated and the amount of steam available for municipality heating are in
direct proportion to each other.
The operational advantage that
Cheng Cycle CHP plants offer over
combined cycles, says Dr, Cheng, is
the ability and flexibility to operate
between the needs of electricity vs
process steam in phase with changing
requirements or to maintain steam and
lower electrical output during weekends and holidays.
Cheng CHP performance
GE’s Fr 9FB5 gas turbine is rated at
298MW and 38.7% efficiency for
simple cycle and cogeneration operation (same ballpark as the M701).
That same gas turbine retrofitted
for Cheng CHP operation would be
able to produce 530MW of electrical power at 52.5% efficiency plus
320,061 lb/hr 120 psig saturated
steam for process heating.
Cost is another advantage. Typically, because of its relative simplicity
compared to a combined cycle plant,
the cost of a Cheng Cycle CHP plant
is on the order of 220 to 250 $/kW
(equipment only). By way of comparison, the equipment cost of an M701
combined cycle is said to have been
quoted recently at around 350 $/kW.
Operationally, gas turbine steam
injection for Cheng operation is limited by its compressor surge margin.
The 501KH5 turbine happens to have
a large surge margin that can accommodate a steam injection rate of 18%
by weight of air flow.
Aerodynamically the acceptable
amount of steam that can be safely
injected varies with turbine pressure
ratio and firing temperature. Mechanically it has to do with the reserve
surge margin of the compressor design and capability of the shaft design
to handle the increased power.
Steam injection flow
As a general rule today’s average
large industrial turbines with a higher
pressure ratio and firing temperature
M701 combined cycle CHP. Plant arrangement in which electrical output
(GT and ST) and process steam are in direct proportion to each other. Typical
cost of M701 combined cycle conversion equipment is estimated at around
350 $/kW.
Injection line
Combustor
Generator
Steam
Turbine
Compressor
Turbine
HRSG
Steam to process
can accommodate a steam injection
rate of about 15% by weight of air
flow.
The amount of steam injection rate
is inversely proportional to pressure
ratio. Fortuitously, the new crop of
gas turbine designs entering the marketplace do lend themselves to Cheng
Cycle operation.
The GE 7F5 gas turbine for instance has replaced the traditional
17-stage industrial compressor with
a 14-stage advanced aeroderivative
type of compressor to achieve higher
pressure ratio and mass flow – with
a larger surge margin well suited to
steam injection.
As a Cheng Cycle plant the 7F5
gas turbine produces 166.3MW more
power and 13.8 percentage points
higher efficiency (see 7F5 table at
bottom of the page).
It is projected that the 7F5 engine will have an equipment cost of
less than 250 $/kW and operate at a
combined heat and power heat rate
(Cheng plant) on the order of 5815
Btu/kWh (58.9% efficiency).
Another interesting medium sized
modern engine is the GE 6F3. As a
Cheng Cycle plant, the 6F3 will produce 64.6MW more power (if not limited by its gearbox) and 155,844 lb/hr
process steam at 100% quality and 120
psi pressure (see table on next page).
The Cheng 6F3 CHP plant also
is equipped with Cheng CLN lower emissions control (inherent to the
technology) which will limit NOx to
single digit levels and CO to less than
2 ppm – with electrical efficiencies
much higher than advanced aeroderivative gas turbines like the LM6000
series, Trent and FT4000 engines.
The cost of heavy frame gas
turbines units is also lower than
aeroderivatives. For example the
cost of the 24MW LM2500PE and
the 27.5MW RB211 are estimated to
be in the range of $400-$450/kW –
versus 220-250 $/kW cost of heavy
frame units.
7F5 performance entitlement. Cheng Cycle CHP can increase gas turbine’s
power output by up to 156.5MW plus supply up to 395,421 lb/hr steam for heating and cooling.
Base Load
Heat Rate
Electric
7F5 Gas Turbine
Output
per kWh
Efficiency
Simple cycle rating
215.5 MW 8,829 Btu
38.7%
Cheng entitlement
381.8 MW
6,505 Btu
52.5%
395,421 lb/hr N/A
N/A
CHP entitlement
Cheng 9F5 CHP plant. Gas turbine and HRSG independently produce electrical output and process steam to meet changing load requirements. Typical cost
of Cheng 9F5 CHP retrofit equipment is estimated at around 220-250 $/kW.
CHP steam
Injection line
Combustor
Generator
Turbine
Compressor
Potential for CHP market
Much of this article has been devoted to the application of Cheng Cycle
technology for GE machines. But as
Dr, Cheng points out, the cycle is just
as applicable to Siemens, Alstom, Ansaldo and Mitsubishi gas turbines.
In the same way that combined
cycle technology has broadened the
market for an improved form of gas
turbine power, so can Cheng Cycle
technology.
Owner-operators are attracted by
the economics and performance of
retrofitting existing (and often times
technologically outmoded) simple cycle gas turbine installations for Cheng
Cycle operation -- with the added bonus of generating process steam as a
byproduct for industrial cogeneration
and district heating and cooling.
Given today’s constraining market
HRSG
conditions, gas turbine OEMs have
also become more interested in the
the performance of relatively low-cost
Cheng technology.
It has the potential to 1) create a
new market for upgrading old gas turbine life and performance, and 2) significantly leveraging the power output and efficiency of new gas turbine
models with add-on capability for industrial and municipal CHP operation.
Environmental regulations, energy
conservation, renewables and a depressed world economy are holding
back the gas turbine demand for new
power generation capacity – except
for replacing old coal-fired plants.
An expanding CHP market served
by bargain-priced gas turbine power
could jump start new growth for intermediate and base load power generation projects.
6F3 performance entitlement. Cheng Cycle CHP can increase gas turbine’s
power output by up to 64.6MW plus supply about 155,854 lb/hr process steam at
100% quality at 70 bar pressure.
Base Load
Output
Heat Rate
per kWh
Electric
Efficiency
Simple cycle rating
77.5 MW
9,571 Btu
35.7%
Cheng entitlement
142.2 MW
6,740 Btu
50.6%
155,854 lb/hr N/A
N/A
6F3 Gas Turbine
CHP entitlement
Showcase CHP sites
Gas turbine OEM builders and owneroperators interested in learning more
about how Cheng technology has been
performing in commercial service can
arrange visits to two sites that have
logged several years of operation.
One is on the island of Kauai in
Hawaii where a Utility Co-operative
has been operating an LM2500 Cheng
Cycle generating plant in year-round
service with nightly shutdowns since
October 2002.
GE’s LM2500 is normally rated at
19.5MW and 9799 Btu/kWh heat rate
(34.8% efficiency) for simple cycle
power generation. The Cheng Cycle
generating plant is rated at 27.5MW
(without any derating for high ambient temperature) and 7652 Btu/kWh
(44.6% electrical efficiency) on naphtha fuel.
Since startup, the plant has been
carrying around 50 percent of the island’s load operating with mostly daily shutdowns and startup. To date the
plant has averaged less than 1 forced
shutdown per year.
The LM2500 turbine design, which
has single crystal nozzles blades, has
extended its time between overhaul
intervals to more than 40,000 hours.
The plant operators welcomes visitors and are happy to provide a tour
and share performance and maintenance experience.
San Jose State University campus
is also worth a visit. They also welcome industry visitors who are seriously interested in finding out more
about the plant’s operation, performance and maintenance. n
Go to www.gasturbineworld.com
and click on “Editorial Hot Stuff”
to view the March-April 2013
article on how Cheng Technology works.
Cheng Cycle (CHP) Entitlement Performance
Advanced GE Gas Turbine Series
9FB7 CHP________________
Gas Turbine
GT mass flow
Steam injection Steam/mass flow 1640 lb/sec
867,600 lb/hr
241 lb/sec
14.7 %
Retrofit Notes
OEM simple cycle gas turbine power
output* is for ISO gross base load operation at 59°F ambient and sea level
site conditions without losses.
Cheng Cycle plant output is for
steam injected gas turbine net power
operation including losses for inlet, outlet and shaft-driven auxiliary systems.
Overall heat rate** for the Cheng
Cycle plant is based on a combination
of electrical and steam output at 0-ft
elevation and 59°F ambient temperature
site conditions.
Cheng single-shaft Fr 9FB7. Conversion to Cheng Cycle increases simple
cycle 9FB7 plant output to 558.2MW from 339.4MW, raises efficiency to
52.1% from 39.9% and produces up to 321,251 lb/hr of process steam for
combined heat and power (CHP) applications.
Gen Elec 9FB7 Calculated
Design Parameter
OEM Ratings Design Ratings
Power output*
339.4 MW
339.0 MW
Heat rate (per kWh)
8526 Btu
8526 Btu
Electric efficiency
40.0%
40.0%
Pressure ratio
19.7
19.7
Turbine rotor inlet temp
unspecified
2445°F
GT inlet flow
1640 lb/sec
1670 lb/sec
Exhaust temperature 1161°F
1063°F
GT steam injection rate
none
none
867,600 lb/hr
Steam temperature
none
none
1025°F
Steam pressure
none
none
474 psi
Process steam rate
none
none
321,251 lb/hr
Steam temperatrue
none
none
341°F
Steam pressure
none
none
120 psi
Steam quality (dry saturated)
none
none
1
Overall plant heat rate** 8526 Btu/kWh
CHP plant efficiency
40.0%
9FB5 CHP________________
Gas Turbine
GT mass flow
913,899 lb/hr
253.9 lb/sec
17.3 %
Retrofit Notes
Cycle plant is based on a combination
of electrical and steam output at 0-ft
elevation and 59°F ambient temperature
site conditions.
CHP system’s design incorporates
provision for gas turbine CLN emissions
that will produce single-digit NOx level
operation at any load.
www.gasturbineworld.com Cheng Cycle
Plant Ratings
558.2 MW
6556 Btu
52.1%
22.1
2445°F
1670 lb/sec
1078°F
8526 Btu/kWh
40.0%
5770 Btu/kWh
59.1%
Cheng single-shaft Fr 9FB5. Conversion to Cheng Cycle increases 9FB5
simple cycle plant output to 530.1MW from 298.2MW, raises efficiency to
52.2% from 38.5% and additionally produces up to 320,061 lb/hr of process
steam for combined heat and power (CHP) applications.
Gen Elec 9FB5 Calculated
Design Parameter
Power output*
298.2 MW
298 MW
Heat rate (per kWh)
8855 Btu
8823 Btu
Electric efficiency
38.5%
38.7%
Pressure ratio
18.4
18.4
unspecified
2445°F
GT inlet flow
1470 lb/sec
1570 lb/sec
1088°F
Steam temperature
Steam pressure
none
none
none
none
none
none
Cheng Cycle
Plant Ratings
530.1 MW
6500 Btu
52.5%
20.8
2445°F
1570 lb/sec
1097°F
913,899 lb/hr
1000°F
356 psi
Process steam rate
none
none
320,061 lb/hr
Steam temperatrue
none
none
341°F
Steam pressure
none
none
120 psi
none
none
1
8823 Btu/kWh 5768 Btu/kWh
38.5%
38.7%
59.8%
7FA-05 CHP______________
Gas Turbine
GT mass flow
671,540 lb/hr
186.5 lb/sec
16.3 %
Project Notes
Simple cycle plant is ISO rated* at base
load output without losses. Cheng plant
output is rated at net power operation including losses for inlet, outlet and shaftdriven auxiliary.
Cycle plant is based on a combination of
electrical and steam output at 0-ft elevation and 59°F ambient site conditions.
The 7FA-05 is GE’s newest singleshaft engine with a brand new 14-stage
compressor and 3D geometry blades.
The 3-stage turbine is based on a proven -04 design with a change from Inconel 73 to Inconel 78 turbine disc material
to operate at a higher firing temperature.
Cost of converting a simple cycle
7FA-05 gas turbine plant to combined
cycle is estimated at around $600 per
incremental kW added, say project engineers, compared to $220 per kW for
Cheng retrofit.
6F3 DHC_______________________
Gas Turbine
GT mass flow Steam injection Steam/mass flow 469 lb/sec
185,834 lb/hr 51.6 lb/sec
11.0%
Retrofit Notes
Cycle plant includes energy of additional steam for heating and cooling.
A gearbox allows the 6F3 gas turbine to generate 50-Hz or 60-Hz electricity. The gearbox limits power output
at 100MW so the plant has more waste
heat to produce more steam for heating
and air conditioning.
Cheng single-shaft Fr 7FA-05. This is GE’s biggest 60-Hz single-shaft
engine. Conversion to Cheng Cycle increases simple cycle plant output to
381.8MW from 215.8MW, raises efficiency to 52.5% from 38.7% and additionally produces up to 396,421 lb/hr of process steam for combined heat and
power (CHP) applications.
Gen Elec 7FA-05 Calculated
Design Parameter
Power output*
215.8 MW
215.5 MW
Heat rate (per kWh)
8830 Btu
8829 Btu
Electric efficiency
38.7%
38.7%
Pressure ratio
17.8
17.8
unspecified
2450°F
GT inlet flow
1145 lb/sec
1117 lb/sec
1088°F
Steam temperature
Steam pressure
none
none
none
none
none
none
671,540 lb/hr
1075°F
393 psi
Process steam rate
Steam temperatrue
Steam pressure
none
none
none
none
none
none
none
none 395,421 lb/hr
341°F
120 psi
1
38.5%
8829 Btu/kWh
38.7%
5815 Btu/kWh
58.9%
Cheng 6F3 for DHC Application. The 6F3 is a new engine to replace the
GE 7EA. Conversion to Cheng Cycle increases simple cycle 6F3 power output to 100MW from 77.6MW, raises electrical efficiency to 45.5% from 35.6%
and additionally produces up 128,742 lb/hr of steam for district heating and
cooling.
Gen Elec 6F3 Calculated
Cheng Cycle
Design Parameter
DHC ratings
Power output*
77.6 MW
77.5 MW
100.0 MW
Heat rate (per kWh)
9574 Btu
9571 Btu
7496 Btu
Electric efficiency 35.6%
35.7%
45.5%
Pressure ratio
15.7
15.7
17.3
unspecified
2367°F
2100°F
GT inlet flow
469 lb/sec
445 lb/sec
445 lb/sec
Exhaust temperature1107°F1104°F947°F
none
none
185,834 lb/hr
Steam temperature
none
none
875°F
Steam pressure
none
none
354 psi
District heating steam none
none
128,742 lb/hr
Steam temperature
none
none
341°F
Steam pressure
none
none
120 psi
none
none
1
Plant efficiency
35.6%
Cheng Cycle
Plant Ratings
381.8 MW
6505 Btu
52.5%
19.9
2450°F
1117 lb/sec
1134°F
9571 Btu/kWh
35.7%
6643 Btu/kWh
51.4%
VSSG 6F3 DHC____________
Gas Turbine
GT mass flow Steam injection Steam/air flow 469 lb/sec
257,976 lb/hr 71.7 lb/sec
15.3 %
Retrofit Notes
Variable synchronous speed generator
(VSSG) allows an increase in Cheng
Cycle plant output to 142.2MW and process steam output to 155,854 lb/hr.
Simple cycle plant is ISO rated* at
base load output without losses. Cheng
plant is rated at net power including
losses for inlet, outlet and shaft-driven
auxiliaries. Overall heat rate** includes
energy of additional steam.
The VSSG converts electric power
into 50Hz or 60Hz regardless of turbine
shaft speed. Operation involves AC field
and DC armature with the commutating
switch done by solid state electronics.
Cheng was awarded a Japanese
patent in 2013 for the VSSG principle.
It is applicable to any size turbine (such
as the 6F3 and bigger), say project engineers, unlimited by capacity. That is
still pending.
9E DHC__________________
Gas Turbine
GT mass flow
465,070 lb/hr
129.2 lb/sec
14.3 %
Project Notes
Simple cycle gas turbine is ISO rated at
gross base load output without losses.
Cheng plant output is rated at net power including losses for inlet, outlet and
shaft-driven auxiliaries.
Overall plant heat rate** for the
Cheng Cycle plant includes energy of
additional steam for distric heating and
cooling.
The 1st-stage turbine inlet area
has been increased 5% to preserve the
surge margin built into the original 9E
gas turbine design.
Quoted equipment and construction costs show that Cheng retrofit is
less than half the cost of a combined
cycle conversion ($/kW).
Low cost of NG fuel and low purchase price for electrical output (Europe
and Middle East) favors low capital cost
($/kW) over high fuel efficiency.
Cheng VSSG single-shaft 6F3. Performance potential of 6F3 plant modified
to eliminate the 100MW gearbox limt on output. Cheng Cycle increases GT
simple cycle output to 142.2MW from 77.6MW, raises electrical efficiency to
50.6% from 35.6% and additionally produces up to 155,854 lb/hr of steam.
Gen Elec 6F3 Calculated
Design Parameter
Power output*
77.6 MW
77.5 MW
Heat rate (per kWh)
9574 Btu
9571 Btu
Electric efficiency 35.6%
35.7%
Pressure ratio
15.7
15.7
unspecified
2367°F
GT inlet flow
469 lb/sec
445 lb/sec
Exhaust temperature
1107°F
1104°F
Cheng Cycle
DHC Ratings
142.2 MW
6740 Btu
50.6%
17.9
2367°F
445 lb/sec
1111°F
none
none
257,976 lb/hr
Steam temperature
none
none
1065°F
Steam pressure
none
none
363.1 psi
District heating steam none
none
155,854 lb/hr
Steam temperature
none
none
341.3°F
Steam pressure
none
none
120 psi
none
none
1.00
9571 Btu/kWh 5785 Btu/kWh
Plant efficiency
35.6%
35.7%
59.0%
Cheng retrofitted 9E for DHC application. Conversion to Cheng Cycle Increases 9E simple cycle power output to 217.8MW from 128MW, raises electrical efficiency to 46.7% from 34.2% and in addition produces up to 233,603
lb/hr of steam for district heating and cooling.
Design Parameter
Power output*
Heat rate (per kWh)
Electric efficiency Pressure ratio
GT inlet flow
Exhaust temperature
Gen Elec 9E
Calculated OEM Ratings Design Ratings
128.0 MW
129.6 MW
9980Btu
10,036 Btu
34.2%
34.0%
12.6
11.7
unspecified
2055°F
896 lb/sec
899 lb/sec
1012°F
1035°F
Cheng Cycle
Plant Ratings
217.8 MW
7306 Btu
46.7%
13.5
2055°F
899 lb/sec
1025°F
Steam temperature
Steam pressure
none
none
none
none
none
none
465,070 lb/hr
975°F
286.7 psi
District heating steam Steam temperature
Steam pressure
none
none
none
none
none
none
none
none
233,603 lb/hr
341°F
120 psi
1
Plant efficiency
34.2%
10,036 Btu/kWh
34.0%
6025 Btu/kWh
56.6%
World’s most powerful gas
engine ready for market
By Junior Isles
MAN Diesel & Turbo has unveiled the world’s most powerful
spark-ignited gas engine. With an output approaching 20 MW,
the new engine is set to capitalize on the growing use of gas
engines to compensate for intermittent wind and solar generation.
I
ncreasingly strict emissions legislation combined with the need to
support renewables is seeing an increasing role for gas fired generation.
In June this year, MAN Diesel &
Turbo announced what will be the
largest reciprocating gas engine when
it becomes available later this year.
Intro ratings:
o Simple cycle. The 18V51/60G design is ISO rated at 18.9 MW full
load output (1050 kW/cyl) and 50%
simple cycle efficiency.
o Start-up. Normally 480 secs to
reach full output with an “instant
loading” option of 75 secs for renewable backup operation.
o Combined cycle. Plant output
with heat recovery can be increased
by more than 10% at over 52% combined cycle efficiency.
Growing availability of clean natural
gas fuel along with heightened environmental concerns continue to drive
new gas fired power generation. According to MAN, the global market
for gas and dual-fuel engines in 2012
for the first time exceeded that for
diesel/heavy fuel oil (HFO) engines.
At the same time, utilities and
power generating companies are
looking to build larger gas engine
plants. In line with this trend MAN is
introducing a new spark-ignited gas
engine that will help meet the need
for such plants.
Michael Grün, Product Manager
for the new engine, known as the
51/60G, says: “We are no longer talking about plants of 10, 20 or 30 MW.
People are looking for plants of 100
or more MW. Projects based on bigger engines offer higher efficiency,
lower specific investment and are easier to service.”
There are several spark-ignited reciprocating gas engines in the market with power output in the 10 MW
range, he notes. Prior to the launch
of MAN’s new engine, however, only
Wärtsilä offered an engine with an
output in the 18-20 MW range.
The 18V51/60G is an 18-cylinder
V-type engine with a bore of 510 mm
and stroke of 600 mm. Power output
is 1050 kW/cyl. The 50 Hz version
has a brake mean effective pressure
(bmep) of 20.6 bar at 100% load and
operates at a speed of 500 rpm, while
the 60 Hz version has a bmep of 20.0
bar and speed of 514 rpm.
Both versions have a maximum
power output of 18.9 MW. With its
modular design, using different numbers of cylinders, MAN says it can
cover a power range from about 15
MW to possibly 21 MW in the future.
This massive power output comes
from a genset package that measures
18.558 mm long (including the generator), 4700 mm wide and 6530 mm
high. It has a dry mass of 373 tons.
Engine operation can be optimized
for simple cycle or combined cycle
operations.
Designed for high efficiency
In simple cycle operation the engine
has an efficiency of 50%. In combined cycle, the engine itself has an
efficiency of 49.2% but the slightly
lower efficiency is more than compensated for by the higher overall efficiency of a combined plant.
A typical combined cycle application uses four engines with a single
steam turbine to achieve an overall
plant electrical efficiency of more
than 52%.
MAN achieves these levels of efficiency by adjusting the engine controls for each application as well as
through the use of two different piston designs: one for simple cycle installations and the other for combined
cycle and combined heat and power
(CHP) operation.
Stefan Terbeck, Head of Technical
Development for the engine, explains
how the change in piston design
and engine control setting impacts
efficiency. “We slightly reduce efficiency but have more exhaust gas energy; essentially we move a portion of
energy from mechanical to thermal.”
These efficiency levels are valid at
an altitude of 500 m above sea level,
ambient temperature of 25°C and a
pressure of 1 bar.
The ability to operate in hot, humid conditions without derating is
one advantage of a reciprocating engine compared to a gas turbine, which
typically will start derating above ISO
conditions. Studies have shown that
gas turbine efficiency deteriorates by
one per cent for every 10-degree rise
in temperature above ISO conditions.
MAN says its air/fuel ratio control
can compensate for ambient temperature rises between -10°C and +30°C.
This means the engine can operate in
95% of all ambient conditions worldwide without, for example, pre-heating of intake air for the turbocharger.
Modular platform
The engine is based on a modular
platform using technology from its
existing family of engines. It will use
the same frame, crankshaft, camshaft,
valves and connecting rods, etc., as
the well-proven 48/60 heavy fuel oil
(HFO) engine, which has accumulated around 7 million operating hours.
The bore and stroke will be the same
as the 51/60 DF (dual fuel engine),
as well as the main gas system. The
ignition components are taken from
MAN’s smaller 35/44G gas engine.
The platform approach allows customers to convert existing 48/60 HFO
engines to gas or dual fuel technology
in markets where gas supply is either
unreliable or not yet available.
“It’s a family concept where we
either use the same or scale-up some
parts,” says Terbeck. “The spark plugs
and check-valves in the 51/60G and
35/44G are exactly the same. The prechamber is scaled up but the material
and technology are the same. Picking
components from our platforms helps
speed up development.”
The turbocharger assembly has a
www.gasturbineworld.com Figure 1. The 18V51/60G engine is rated at 20 MW full power output. Genset package measures 18.558 mm long (including the generator), 4700 mm wide and 6530
mm high.
modular design consisting of the turbocharger and two charge-air coolers
with associated cabling and sensors
etc., mounted on a base frame. This
turbocharger assembly is then mounted on the engine. The power unit,
comprising the cylinder head, liner,
piston and connecting rod, is also preassembled before being inserted into
the engine frame.
Most of all the platform approach
is beneficial to customers, as it allows
them to convert existing 48/60 HFO
engines to gas or to dual fuel technology in markets where gas supply is
either unreliable or not yet available.
Operation
In a typical installation, pre-heating is
provided for engine cylinder cooling
water and lube oil.
Under normal loading, when the
generator is synchronized to the grid
the engine typically reaches full load
in 480 secs. An “instant loading” option is also possible whereby full output can be achieved in 75 secs.
The ability to start-up quickly
makes reciprocating engines particularly well suited to balancing intermittent renewables such as wind and
solar. Providing highly flexible electricity is one of the key benefits the
MAN engine was designed for.
“With more and more renewable
energy generation there is an increasing need for balancing power. Those
markets for balancing energy are usually regulated and require prequalification,” Terbeck explains.
“In Germany, for instance, energy
providers are required to deliver power to the grid within five minutes to
compensate for wind and solar power.
With our engine, customers can qualify for this market and earn money just
by having this type of fast-start capacity available.”
During normal operation, exhaust
gas leaves the turbocharger at a temperature of 320°C. For combined cycle operation this is increased by about
80°C to provide the necessary steam
conditions to drive the steam turbine.
In simple cycle operation sufficient
heat can be recovered from the engine
cooling water circuit and lube oil to
generate lower grade heat for CHP
applications.
The engine operates according to
the lean burn Otto cycle. This combined with Miller timing, which produces low combustion temperature,
results in high efficiency and low
NOx. The engine is therefore able to
meet TA-Luft and World Bank limits
for NOx emissions as well as the EU
Directive IED/IPPC (i.e 200 mg/Nm3
at 5% O2) without the need for any
exhaust gas treatment.
A safety engine control system provides active monitoring of knocking.
Individual gas valves can be adjusted
so that the combustion, and therefore
the emissions, in each cylinder can be
controlled.
Notably, the 18V51/60G can run
on a wide range of gas types and qualities. “Natural gas qualities vary all
over the world. As the engine is sold
globally, we have to be able to handle
different gas qualities,” Terbeck says.
“Also the use of different piston designs extends the window of operation to handling gases with methane
number 60.”
Another advantage, he says, is that
engines use low-pressure gas injection. This means the engine can use
gas at more or less the pressure at
which it is supplied from the gas grid
to the power plant.
Development and commercial intro
Development of the combustion system was essentially divided into three
steps.
It began with thermodynamic
calculations followed by extensive
testing on a single cylinder engine.
These tests allow engineers to determine items such as piston design and
hardware for the full-scale engine. All
the pre-validation is performed on a
single cylinder engine. This shortened
the time for the third and final step
of full-scale engine validation, which
started in autumn of 2013.
The key areas during validation are
on meeting performance specifications such as power output, efficiency
and emissions. Terbeck said: “We can
see that the basic design is fine and
there are no problems with output or
efficiency.
We therefore focus on widening
the operating window for using gas of
various qualities and on how to maintain engine performance at different
ambient conditions.”
MAN says it will also concentrate
on the engine’s dynamic load capability to allow it to respond quickly to
sudden drop-offs in wind and solar
power.
Work on the 35 bore gas engine was
started first so that developments could
be incorporated into the larger 51 bore
engine. According to Terbeck, its platform approach cut engine development
and validation time by 35%.
“We decided to start development
of the 35 bore engine and let it run
some 6-8 months. It gives you time to
iron-out any problems and also puts
less of a strain on budgets and engineering resources,” said Terbeck.
Focusing on the smaller engine
first is also a case of following market
demand. “The market for big engines
is at its beginning and growing,” added Grün. “We are seeing this very
clearly in our core markets.”
On the current program, production
of the first serial engines will start in
September this year and the first fullscale 18V engine will be on the test
bed by mid-November this year.
For now, however, the engine is
officially commercially available and
will be installed at a launch customers’ project site soon enough. But “it
is too early in the project to give away
any details”, says Grün.
He concludes: “The 51/60G is an
innovation in the market and it will
set a new benchmark. We are looking
forward to this engine being very successful as it completely matches the
market demands.” n
Figure 2. The 18-cylinder V-type engine has a bore of 510 mm and stroke of 600
mm, utilizes the same frame, crankshaft, camshaft, valves and connecting rods, etc.,
as the 48/60 heavy fuel oil engine.
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Guest Feature
General Electric – Alstom merger
brings visions of the Überturbine
Also in this story
31 Building on the past
33 Looking to the future
By S.C. Gülen, PhD, PE
Principal Engineer, Bechtel Corporation
Integration of the two OEMs’ advanced gas turbine designs could deliver
combined cycle efficiencies that leapfrog the best available today.
Envisioned is the potential for the integration of GE’s steamcooled turbine technology and Alstom’s reheat combustion
design to come up with a practical steam-cooled reheat design. The concept of a steam-cooled reheat combustion gas
turbine is more than three decades old, e.g. see [1].
Individually the two pillars of the concept, namely steam
cooling of hot gas path (HGP) components and reheat (sequential) combustion, have already been deployed in successful commercial units: GE’s H-System™ and Alstom’s
GT24/26 gas turbines, respectively.
The combination of the two technologies has been proposed and analyzed in the past -- always turning out as
offering the most efficient combined cycle system [2] possible. This article takes another look at the thermodynamics
behind the analysis to quantify the inherent advantage of the
concept.
Up to now neither company has given any public indication of actively pursuing the idea as far as the author knows.
(In all likelihood they must have looked at it internally as
evidenced, for instance, by old ABB patents.) The reason
for that is easy to surmise: size, complexity and cost of the
overall system. Now that the two companies are merging into
one, this Überturbine might finally emerge as a viable commercial product.
In addition to the announced merger, there are two external drivers at play here: 1) ever higher firing temperatures
are pushing the limits of dry low NOx (DLN) combustor
design to achieve low emissions and 2) increasing need for
gas-fired clean base load power generation (relatively speaking) to replace old pre “Clean Air Act” coal-fired clunkers
and feared nuclear plants.
There are three mechanisms for NOx production in the combustor of a gas turbine: thermal, nitrous oxide and prompt
NOx – each of which is described by different chemical reaction paths.
Of these three, when flame temperatures are above
2,780°F the dominant mechanism is thermal NOx or the
extended Zeldovich mechanism. Below this temperature,
thermal reactions are relatively slow. Beyond about 3,100°F
(1,700°C), thermal NOx production grows exponentially (see
Figure 1). This can be considered as an upper limit for DLN
combustion.
Current advanced H and J class machines with 2,900+°F
(1,600°C) turbine inlet temperatures (TIT) operate at the
edge of this limit. (Note: combustion flame zone temperatures are higher than TIT.)
Dry low NOx technology can be tweaked to go up in TIT
maybe by another 100°F or so. One gas turbine OEM employs axial fuel staging (also known as “late lean” injection)
to alleviate increased NOx production at high firing temperatures but even that is expected to hit a limit quite soon. Fig 1. NOx emissions as a function of flame temperature for
a typical dry low NOx combustor.
40
30
20
10
°F
in
T
TI
0
20
+
0
4x NOx
Based on old concept
At the edge of the NOx barrier
Normalized NOx
The recent decision by the French government favoring
General Electric’s acquisition of Alstom’s thermal business
and subsequent approval of the $17 billion deal by Alstom’s
Board (a mere formality in light of the board’s well publicized endorsement of the deal) opens up the prospect of a
new super gas turbine.
Flame Temperature / 2600
1.00
1.05
1.10
1.15
1.20
In passing, a commonly encountered mistake is to confuse ideal
cycle efficiency with the “ultimate”
Carnot efficiency, 1 – T1/T3 , which
represents the theoretical maximum.
The key message here is that in
order to have the same mean-effective heat addition temperature (that
is, the same cycle efficiency) as
the reheat cycle in Figure 2, a non3r
Cycle Max Temp
2c
reheat cycle must increase its cycle
(TIT) Proxy
3,3c,5
Increase in TIT
maximum temperature (a proxy for
for same METH
4r
TIT) and/or cycle pressure ratio.
as Reheat
Reheat
As illustrated by Figure 2, the
increase would be much higher at
the non-reheat cycle’s pressure raIncrease in METH
tio (P2/P1). On an ideal cycle basis,
for same TIT
4,6
2r
3,3r
the
advantage of reheat cycle over
2,2r
5
the
non-reheat
cycle is illustrated in
2
4r
METL
Figure 3.
1
Also shown in Figure 3 is an esti4
6
mate of the realistically achievable
1
4c
performance advantage, which is
Entropy (S)
much more modest than predicted by the ideal cycle comparison.
The primary drivers for this are in Another builder looking into ~3,100°F (1,700°C) class
creased hot gas path component cooling load and combustor
gas turbines had to consider exhaust gas recirculation (EGR)
design requirements.
for NOx control, which adds significant cost and complexity
In fact, for turbine inlet temperature values of approxito the design.
mately 1,450°C (2642°F) or above, the reheat cycle effi Thus, the only surefire way to keep NOx emission in
ciency advantage disappears due to significant increase in
check is to rein in the urge to go full blast with turbine inlet
cooling losses [3]. This is where closed-loop steam cooling
temperature and not sacrifice efficiency. This is where the
concept enters the picture.
reheat combustion concept enters the picture.
Temperature (T)
Fig 2. Heat addition and heat rejection irreversibility (losses) of the ideal Brayton
cycle (1-2-3-4-1) are represented by the triangular areas (2-2c-3c-2) and (1-4-4c-1),
respectively. Reheat cycle (1-2r-3r-4r-5-6-1) reduces the heat addition irreversibility
as quantified by the area (2-2r-3r-4r-2). The net effect is an increase in cycle meaneffective heat addition temperature (METH) and cycle efficiency without an accompanying increase in cycle maximum temperature (T3,3r ).
It is a well-known axiom of thermodynamics that does not
hurt repeating: “Any heat engine cycle is a valiant albeit vain
attempt to replicate the Carnot cycle”.
The biggest hurdle in this somewhat quixotic engineering
quest is achievement of isothermal heat transfer. Reheat or
sequential combustion is a modest approximation of isothermal heat addition, which can be found in any undergraduate
textbook.
The goal is to realize an increase in the cycle effective
heat addition temperature (see Figure 2) without increasing
the turbine inlet temperature which is the maximum cycle
temperature. For a fundamental discussion of reheat, ideal
cycle efficiency can be written as
Steam cooled gas turbine
For all practical purposes, there is only one closed-loop
steam cooled gas turbine: General Electric’s H-System.
Fig 3. The shaded box designates the most likely near-tomidterm impact of closed-loop steam cooled reheat gas
turbine.
50%
Ideal Cycle Benefit
40
Efficiency
Reheat Gas Turbine
Real Cycle Benefit
with Steam Cooling
Reheat
Non-Reheat
Same efficiency
and lower TIT
Real Cycle Benefit
where METL and METH are the cycle’s mean-effective heat
rejection and heat addition temperatures. (They are logarithmic averages of heat transfer beginning and ending temperatures; i.e., T2 and T3 for METH and T4 and T1 for METL.)
www.gasturbineworld.com 30
Turbine Inlet Temperature (°F)
2,400°F
2,600
2,800
3,000
3,200
Fig 4. Internal air cooling reduces firing temperature into
stage 1 turbine blades by about 200°F versus 80°F with
steam cooling.
Air-cooled
∆200°F
Steam-cooled
∆80°F
Hot
Gas
Hot
Gas
TIT
TFire
TIT
Air In
Air cooling also needed
TFire
Steam In Out
Admittedly, it is true that Mitsubishi G and J class gas turbines also employ steam cooling for combustor liner, transition piece and stage 1 and 2 turbine rotor rings (J class).
In terms of hot gas path “chargeable” and “non-chargeable” cooling air reduction, however, Mitsubishi’s G and J
class gas turbines are essentially air-cooled machines.
(It should be noted that Mitsubishi did design and test a
fully steam cooled “H” machine almost 15 years ago, back
around 2000-01, which had a cycle pressure ratio of 25 to 1.
It was never offered commercially but its compressor design
lives on in current G and J class gas turbines.)
In H-System gas turbines, on the other hand, closed-loop
steam cooling reduces hot gas temperature drop across the
stage 1 nozzle to less than 80°F.
For the same combustor temperature and turbine inlet
temperature, this results in an increase of 100 to 150°F in
firing temperature vis-à-vis advanced F class machines with
air cooling (Siemens H class gas turbines also belong in this
category).
An additional benefit of steam cooling is less parasitic
extraction of compressor discharge air and higher flow to the
head-end of the dry low NOx combustor for fuel premixing.
If the firing temperature is kept at the F class level, the benefit of steam cooling presents itself as reduced turbine inlet
and combustor temperatures, i.e., reduced NOx production.
In the H-System, the first two turbine stages are fully
steam cooled including nozzles and buckets. This reduces the
amount of chargeable cooling air and increases gas turbine
output via higher gas flow through the hot gas path.
Heat rejected to the coolant steam is converted into additional steam turbine power output. The net benefit of full
steam cooling is a two percentage points increase in combined cycle efficiency [2,3].
Closed-loop steam cooling does not eliminate air cooling
altogether. Air purging is still needed to prevent ingestion of
hot gas into the wheel spaces.
In addition, air is used for cooling the trailing edges of
stage 1 and 2 nozzle vanes via internal coolant flow (presents
a challenge). Supplementary cooling of inner and outer side
walls (platforms) and trailing edge of the nozzle vanes with
wheel space purge air is also a requisite to ensure adequate
parts life.
Steam cooled gas turbines, of necessity, are only available
in combined cycle configuration. In fact, they are more aptly
described as “integrated steam/gas” cycles [1].
The connection between the topping and bottoming cycles
goes way beyond the exhaust gas duct between the gas turbine and heat recovery boiler (HRB). The network of alloy
pipes and valves required to interconnect them, in addition to
a cooling air cooler (kettle reboiler type heat exchanger) for
IP steam generation (not to mention the performance enhancing fuel heating), results in a veritable (and expensive) maze.
The cooling air cooler is a consequence of the high Brayton cycle pressure ratio (23 for the H-System) requisite for
an optimal design necessitated by high firing temperature
(2,600+°F) and reduced hot gas dilution by coolant in the
hot gas path (leading to high compressor discharge temperatures).
A significant hurdle in H-System bottoming cycle design
is excessive reheater pressure drop (approximately 25%
vis-à-vis typical 10-12% for modern reheat steam bottoming
cycles) caused by the HGP cooling steam circuit embedded
within the reheat steam piping. n
Part 2
Engineering building blocks
for a Überturbine prototype
The modern steam-cooled H-System and the GT 24/26 reheat
combustion design represent the two unique gas turbine
architectures needed for the Überturbine.
Despite undeniable performance benefits, neither steam
cooling nor reheat managed to vanquish their conventional
air-cooled rivals, whose basic design has not changed much
from the pioneering jet engines of 1940s and 1950s.
As of today there are only six H-System units in commercial operation. Moreover, for quite some time, the H-System
has not been offered by GE commercially – even though
listed in GE’s product portfolio.
Most recently, GE announced the air-cooled HA class
machines, which draw heavily upon the technologies proven
in their steam cooled predecessors (e.g., single crystal materials, advanced thermal barrier coatings and 4-stage turbine
section).
As far as reheat combustion is concerned, there are many
more GT24/26 units in commercial operation. Nevertheless
today’s owner of the technology, Alstom, fell way behind the
leading OEMs in terms of worldwide gas turbine sales. Why
is that? A short review of the history behind the current design provides an answer.
Reheat gas turbine background
The idea of reheat or sequential combustion has been around
for quite a long time. Stodola explicitly referred to it as “a
means to increase efficiency” in an article he wrote right
after he oversaw performance testing in 1939 of the world’s
first industrial gas turbine [4].
Brown Boveri Corp (BBC) developed the concept into
working hardware and, in 1948, built and tested two such gas
turbines in Beznau, Switzerland. These machines were quite
different from the compact “jet engines on steroids” that one
tends to associate with the term ‘industrial gas turbine” these
days.
They were rather complex power plants in their own right
with an intercooled two-shaft configuration comprising separate low pressure (LP) and high pressure (HP) compressorturbine trains and large external single-can combustors.
In the 1950s, BBC supplied such “tailor made” units all
over the world, including 4 x 25 MW for the Port Mann station in Vancouver, BC and a single-unit plant in Lima, Peru.
Another more recent and well known site is the Huntorf
www.gasturbineworld.com compressed air energy storage plant in Germany with its
single-shaft HP-IP turbine and two silo combustors.
Asea Brown Boveri, descendant of the venerable BBC
company, took an evolutionary design path in 1993 with the
introduction of a compact GT24/26 (60/50Hz) reheat gas
turbine with two annular combustors comprising proprietary
EV and SEV burners. (Initial designs included an intercooler
which significantly added to engine length and was dropped
from the final production design.)
At the time ABB, like other gas turbine OEM suppliers
in the industry, did not have an in-house test facility large
enough to put the entire machine through its paces prior to
customer shipment. With so many innovations involved in
the design, this put the first units placed in service at considerably higher risk than usual for the introduction of any new
engine.
The first commercial GT24 unit, installed by Jersey
Central Power & Light at the Gilbert Station in New Jersey,
underwent extensive field trials and prototype testing prior to
its operation. In spite of this, the initial series of production
units were beset with serious technical problems – largely
due to the new 30:1 compressor (with about twice the pressure ratio of existing heavy frame industrial gas turbine
compressors) as well as the sequential combustion system.
At first, ABB managed to keep a lid on the field problems
and continued to have success in selling new orders well into
the pre-2000 boom years. As a result, the promising new
technology suffered severe damage to its reputation that
would remain for years to come.
Ultimately, ABB terminated further deliveries, allowed
orders to be cancelled, compensated clients for damages and
devoted large resources to fixing the problems.
In 1999-2000, Alstom formed a joint venture with ABB
and subsequently acquired a 50% share of their gas turbine
business. Since then Alstom has been the OEM supplier for
reheat combustion GT24/26 technologies.
In a 2000 press release Alstom acknowledged the severity of the design issues and field problems associated with
GT24/26 and said it was setting aside close to 1 billion Euros to address those issues. Since then, it is fair to say that
GT24/26 reheat gas turbines have established themselves as
reliable and efficient power generation systems.
Steam cooling trial and error
The history of component cooling using water or steam goes
even further back than the reheat concept.
In 1903, Aegidius Elling patented a gas turbine that included water cooling to lower the hot combustion gas temperature to about 750°F (400°C) at the turbine inlet. The
steam generated during the process was mixed with the gas
and expanded in the turbine. In essence, it demonstrated a
“poor man’s H-System” with open-loop steam cooling configuration a century before first fire of GE’s 9H at Baglan
Bay.
In 1930 Brown Boveri introduced a prototype of Holzwarth’s “explosion” turbine (constant volume combustion)
which had an inlet gas temperature of about 1300°F (700°C)
and water-cooled first stage [4]. And in the 1950s, Siemens
invested considerably in the design of a turbine rotor with
water-cooled blades for 1800°F (~1,000°C) inlet temperature
[5].
The steam generated inside the water-cooled blades was
routed out through the hollow rotor and piping. A myriad
problems surfaced but were resolved (vibration, water filter
clogging and parts overheating) to achieve a turbine inlet
temperature of 1930°F (1,055°C) in the tests. But the program eventually folded due to cost issues.
Reheat gas turbine hall. Brown Boveri’s two-shaft intercooled, reheat gas turbine power plant in Port Mann, Vancouver, BC, Canada. Note the four 25MW units lined up in
a row along the turbine hall. The first unit is shown in the
foreground with the generator connected to the low pressure
train on the right and high pressure train on the left. The two
vertical cylinders on the left are the LP and HP combustors.
Starting in the mid-1970s, GE investigated water-cooled
stage one nozzles as part of U.S. DOE’s High Temperature
Turbine Technology (HTTT) program. Parts were designed
and cascade tested in gas temperatures at temperatures of
up to approximately 3000°F (1,650°C), the DOE program
goal, at 145 psia [6]. Rig tests in an actual turbine similar to a
Frame 6 were planned but never carried out.
Difficulties with controlling water-steam phase changes
and instabilities associated with nucleate boiling as well as
limited coolant temperatures eliminated water as a turbine
coolant once and for all. By the time GE joined DOE’s Advanced Turbine Systems (ATS) program, closed-loop steam
cooling was the chosen path and led to the commercialization
of the H-System.
H-System success
The H-System did not run into the same problems and none
of the six units in field operation revealed any design flaws.
This fact can be attributed to the cautious path that GE took
in developing the highly complex design over a period of 10
years, albeit at an exorbitant cost partially offset by DOE’s
ATS program funding.
Comprehensive testing of the first 109H single-shaft combined cycle power plant in 2003-2004 fully demonstrated the
capability of the machine to start in air-cooled mode, transition into steam cooling to reach base load, run as predicted
over its entire operating envelope for an extended period, and
shut down. (Full disclosure: the author was a GE engineer at
the time and participated in the test program.)
The same was true of the other five H-System units (three
50Hz 109H units in Japan and two 60 Hz units in California). Today, the six H-System units have accumulated more
than 175,000 fired hours at firing temperatures well above
2,600°F (1,430°C), a level only recently achieved by Mitsubishi’s J class gas turbines with 2,912°F (1,600°C) turbine
inlet temperature.
The two 107H units at the Inland Empire Energy Center
in California, which entered service in 2008, made the top 20
list in heat rate in Electric Light & Power magazine’s annual
“Operating Performance Ratings for Top 20 Power Plants”
articles.
Even though the capacity factor was only about 60%, this
is not a bad feat. Furthermore, the Inland plant ranked number one in 2011 and 2012 in terms of NOx emissions rate
(0.00385 lbs/MMBtu in 2012).
The two units were successfully tested in the summer of
2008 (the author was there as well) operating with a unique
fuel moisturization system for improved efficiency and NOx
control. Unfortunately, near the end of the testing in 2008,
Unit 2 suffered a compressor failure.
Although never publicly disclosed, the rumored cause of
the failure was a manufacturing defect in the compressor’s
last stages, and the restart was delayed until 2010 due to difficulties encountered in procuring replacement parts. n
Part 3
Looking beyond air cooling
for 64 or 65% net efficiency
Gas turbine OEMs are claiming over 61% net efficiency for advanced
combined cycle plants. How much higher can steam cooling and
reheat realistically achieve?
The previous discussion of engineering building blocks
makes the point that, separately, both steam cooling and
reheat have been proven reliable in commercial service and
capable of delivering superior performance. Their possible
use for combined cycle design remains to be seen.
Today, four major OEMs (soon to be only three) make
claim to over 60% net combined cycle efficiency for production plants using advanced air-cooling designs; actually
GE and Mitsubishi claim better than 61% net efficiency for
their HA and J class gas turbine combined cycle plants.
Put aside for a moment the fact that only Siemens has
actually “walked the walk” albeit while employing an advanced steam bottoming cycle and taking advantage of ideal
site conditions. And let us examine the underlying fundamentals behind combined cycle efficiency and the potential
for going beyond advanced air cooling techniques with a
“super turbine” employing both steam cooling and reheat
combustion.
The combined cycle efficiency can be estimated reasonably accurately as follows:
where
is the GT efficiency, ε is the GT exhaust exergy as
is gross bottoming cycle
a fraction of exhaust energy,
exergetic efficiency which is the ratio of steam turbine generator output to gas turbine exhaust exergy, and α is the plant
auxiliary load as a fraction of gross combined cycle output
(see Gülen and Smith [7]).
Exergy is the maximum work potential of the working
fluid (in this case, gas turbine exhaust gas) of given pressure,
temperature and composition. It can only be achieved in a
hypothetical Carnot cycle.
With a known equation of state (e.g., JANAF tables for
gases) the exergy of a given fluid can be exactly calculated. For a gas turbine exhaust temperature range of 1,1001,200°F, ε is 0.46-0.48. In other words, maximum work
potential of a gas turbine bottoming cycle is roughly 50% of
the exhaust gas energy.
A real cycle can feasibly achieve only a fraction of the
maximum work potential (the Carnot factor). For the Rankine steam bottoming cycle of a gas turbine combined cycle
in the formula) is typically
plant design, this value (
around 0.74-0.75 for a 3-pressure reheat steam cycle with
steam temperatures 1,050-1,100°F, condenser pressure of 1.2
inches of mercury and an advanced steam turbine with suitably large exhaust annulus.
The value of α, the percent of auxiliary load losses, is
1.6% for typical combined cycle performance ratings listed
in the Gas Turbine World Handbook. This is commensurate
with once-through open-loop water cooled condenser operation at 1.2 inches of mercury and no fuel gas compression.
and α
With appropriate values for the variables of ε,
thereby established, the simple CC efficiency equation lays
out the combined cycle vs. gas turbine efficiency landscape
concisely, as shown in Figure 6. The takeaways from the figure can be summarized as follows.
For 60% combined cycle efficiency, minimum 39%
gas turbine efficiency, high exhaust temperature (implying
system level optimization to determine gas turbine firing
temperature and cycle pressure ratio) and a state-of-the-art
bottoming cycle are requisite. 1
For 40%-plus efficiency gas turbines, over 60% combined cycle efficiency should be eminently achievable. (Caveat: This statement is true only with favorable site conditions suitable to low steam turbine back pressures with
minimal parasitic power consumptions.) All bets are off with
extremes such as air-cooled condensers in desert climates
and/or high site elevations. (The reader is referred to the article by Maher Elmasri in GTW July-August 2013 issue for
more on this.)
Between 40% and 41% gas turbine efficiency, over 61%
combined cycle efficiency is a stretch, but possible, given a
truly advanced steam cycle and steam turbine. The ability to
1
Note that the reheat gas turbine with open-loop steam cooling proposed by Rice in his 1982 paper [1] had an efficiency of 42.5% and 1,299°F
exhaust temperature. It was a bona fide 61+% net GTCC enabler. Unfortunately, Rice was not as visionary with his choice of bottoming cycle (he
had a two-pressure cycle with 300°F HRSG stack and feedwater heating) and ended up projecting well below 60% efficiency.
draw cooling water year round from the cold Danube would
not hurt either (as is Siemens’ good fortune at the Irsching
8000H plant).
With more than 41% simple cycle efficiency gas turbines,
over 61% combined cycle efficiency becomes a realistic
prospect.
Current-production F, G, H and J class gas turbines are
primarily air-cooled machines, whose performance (over
40% simple cycle efficiency) is driven by high firing temperatures and commensurate cycle pressure ratios (20 to 23)
complemented by advanced steam Rankine bottoming cycles
to achieve over 60% combined cycle efficiency.
Even more advanced air-cooled designs on the horizon
can establish the basis for the best-case scenario air-cooled
machines (see Table 1). Their embedded technologies such as
advanced aero design, new hot gas path materials and coatings, advanced film cooling techniques and higher component efficiencies can all be retained in a steam-cooled reheat
combustion architecture.
Game changing technology
Table 1. Composite rating for “best” air-cooled F, G, H
and J-class gas turbine design performance.
Gas Turbine Design Parameter
Best Case
Gas turbine output (60/50 Hz)
300-500 MW
Approximate gas turbine efficiency 41+ %
Compressor pressure ratio
22 to 23
Turbine inlet temperature
1,600°C
Turbine inlet temperature
2,912°F
Approximate GT exhaust temp
1145°F
Net combined cycle efficiency
61+ %
only; the second is for “full steam cooling” of the HP nozzle
vanes plus LP stage 1 and 2 vanes and buckets.
For the latter, performance is estimated at two compressor pressure ratios – with the higher value expected to be
representative of a final optimized design. Cooling steam is
supplied from the cold reheat and returned to the hot reheat
line. Cooling air cooler heat rejection is used for IP steam
generation in a kettle reboiler.
Bottoming cycle calculations assume state-of-art, threepressure reheat steam cycle and advanced steam turbine with
water-cooled (open loop once-through) condenser. Firing
temperature is defined as the rotor/bucket inlet stagnation
temperature, and the HGP total cooling airflow rate is expressed as a percentage of compressor inlet airflow.
Combined Cycle Efficiency
How would steam cooling and reheat change this picture?
The improvement obtainable from a closed loop steam
cooled reheat configuration is summarized by Table 2.
For full steam cooling, à la General Electric’s H-System,
from 2 to 2.5 percentage points can be added to combined
cycle efficiency when operating at the same TIT conditions
and reach 63% to 64% CC efficiency [2,3].
With only stage 1 nozzle steam cooling the adder is about
Can they get there?
halved to 1 to 1.25 percentage points to operate at 62% to
GE and Alstom have significant gas turbine architecture dif63% combined cycle efficiency [3] as defined by the green
ferences: i.e., can-annular versus annular combustors and
shaded rectangle in Figure 6.
Fig 6. Combined cycle efficiency as a function of gas turbine efficiency (ISO base
Unless materials significantly rewith optimal bottoming cycle heat rejection). The two levels of exhaust temperducing the need for HGP compoature represent low and high ends of F, G, H and J class heavy frame turbines.
nent cooling such as ceramic matrix
Base ”BC is 74% for Texh = 1,125°F and 74.7% for Texh = 1,175°F at ISO conditions.
composites come onto the scene in a
timely manner, steam cooled reheat
technology is the most likely canClosed-Loop Steam Cooled
64%
didate to reach the 65% barrier (or
Reheat Gas Turbine
come closest) without running into
63%
combustion and emissions problems.
Best CC Performance
The estimated stage-by-stage rat62%
(Air Cooled Only)
ings for steam cooling with reheat
were calculated using Thermoflex
61%
Average F, G, H, J Class
software (developed by Thermo(Air Cooled Only)
60%
flow) based on best “state-of-theart” air-cooled gas turbine perfor59%
mance. The deltas shown should be
considered as purely thermodynamic
58%
Base BC Ex. Eff.
entitlement values.
Texh = 1,175°F
Base + 1%
Single-stage HP turbine (pres57%
Texh = 1,115°F
Base + 2%
sure ratio of 2) and four-stage LP
56%
turbine are assumed. The two cases
Gas Turbine Efficiency
assume two different levels of steam
cooling. The first is for steam cool30%
32%
34%
36%
38%
40%
42%
ing HP and LP stage 1 nozzle vanes
Table 2. Estimated benefit of reheat with steam cooling (two cases) as referred to “best case” air cooling technology, with hot
gas path (HGP) total cooling air flow expressed as a percentage of compressor inlet airflow.
Design parameter
Air Cooled
Reheat combustion
No
Gas turbine output
Base
GT efficiency (points)
Base
Compressor pressure ratio
22.5
*Only S1N Steam Cooling
Yes
+ 15%
+ 0.25
35.6
**Full Steam
Intro Design
Yes
+ 35%
+ 1.30
35.6
**Full Steam
Optimized
Yes
+ 35%
+ 2.00
39.3
HP firing temperature
2,715°F
2,545°F
2,545°F
2,545°F
LP firing temperature
N/A
2,725°F
2,725°F
2,725°F
HGP cooling air flow
28.8%
26.5%
16.4%
16.2%
Exhaust temperature
Base
+ 90°F
+ 180°F
+ 145°F
Cooling air-cooler duty
N/A
5,500 Btu/sec
6,200 Btu/sec
7,250 Btu/sec
Steam cooling duty
N/A
13,590 Btu/sec
23,500 Btu/sec
23,500 Btu/sec
Steam turbine output
Base
+ 22%
+ 40%
+ 35%
Combined cycle net output
Base
+ 19%
+ 38%
+ 35%
CC net efficiency (points)
Base
+ 1.25
+ 2.5
+ 2.75
*Limited steam cooled HP an LP Stage 1 nozzle vanes only
**Fully steam cooled HP nozzle vanes and LP stages 1 and 2 (vanes and buckets)
bolted versus welded disk rotor construction, respectively.
The exact nature of technology “osmosis” or “integration”
between the two merged organizations remains to be seen.
As far as a potential steam-cooled reheat machine is
concerned, the most likely approach is to keep the current
GT24/GT26 architecture and integrate the proven cooling
steam delivery system into the welded rotor design. Even
though the performance entitlement offered by a “fully steam
cooled” turbine is highly tempting, the expectation is that
cost and complexity issues will preclude it – at least for the
next 5 to 10 years. However, steam cooled HP and LP turbine
inlet nozzle vanes provide most of the proverbial “bang for
the buck” and should be eminently do-able with reasonable
investment cost and engineering effort.
Conceivably, the first Alstom (EV) annular combustor can
be replaced by a can-annular GE design with axial fuel staging to get the highest possible HP turbine inlet temperature.
In all likelihood, however, the second (SEV) annular combustor would be retained for the most compact final configuration.
There is no doubt that a steam-cooled reheat combustion
integrated cycle power plant will be quite expensive. But
the plant would be more flexible than existing public opinion
suggests; it would retain the low-load capability of existing
reheat machines and would not be too sluggish in terms of
warm/cold starts and load ramping. True, it would not be as
nimble as an air cooled “fast start” unit, readily amenable to
daily two-cycled load following and/or stand-by. Then again,
this is not the intended application for a highly efficient and
pricey system most suitable to base load duty.
In conclusion, do not hold your breath but do not totally
dismiss a near future announcement of this highly integrated
system either. n
www.gasturbineworld.com Cited References
[1] Rice, I.G., 1982, “The Reheat Gas Turbine with SteamBlade Cooling—A Means of Increasing Reheat Pressure,
Output, and Combined Cycle Efficiency,” J. Eng. Gas Turbines Power 104(1), pp. 9-22.
[2] Chiesa, P., and Macchi, E., 2004, “A Thermodynamic
Analysis of Different Options to Break 60% Electric Efficiency in CC Power Plants,” J. Eng. Gas Turbines Power,
126, pp. 770–785.
[3] Gülen, S.C., 2011, “A Simple Parametric Model for the
Analysis of Cooled Gas Turbines,” J. Eng. Gas Turbines
Power, 133, #011801.
[4] Eckardt, D., 2014, “Gas Turbine Powerhouse – The Development of the Power Generation Gas Turbine at BBC –
ABB – Alstom,” Oldenburg Verlag, München.
[5] Leiste, V., 2006, “Development of Siemens Gas Turbine
and Technology Highlights,” Siemens, Erlangen.
[6] Collins, M.F. et al., 1983, “Development, Fabrication
and Testing of a Prototype Water-Cooled Gas Turbine Nozzle,” Transactions of the ASME, Vol. 105, pp. 114-119.
[7] Gülen, S.C., Smith, R.W., 2010, “Second Law Efficiency of the Rankine Bottoming Cycle of a Combined Cycle
Power Plant,” J. Eng. Gas Turbines Power, 132, #011801.
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