about combined gas power plant in dholpur

1. Gas Combined Cycle
Gas Turbine Design
In gas turbine design the firing temperature, compression ratio, mass flow, and
centrifugal stresses are the factors limiting both unit size and efficiency. For
example, each 55°C (100°F) increase in firing temperature gives a 10 - 13
percent output increase and a 2 - 4 percent efficiency increase. The most critical
areas in the gas turbine determining the engine efficiency and life are the hot gas
path, i.e., the combustion chambers and the turbine first stage stationary nozzles
and rotating buckets. The components in these areas represent only 2 percent of
the total cost of the gas turbine, yet they are the controlling factor in limiting gas
turbine output and efficiency. The development process takes time, however,
because each change of material may require years of laboratory and field tests
to ensure its suitability in terms of creep strength, yield limit, fatigue strength,
oxidation resistance, corrosion resistance, thermal cycling effects, etc.
Manufacturers use various combustor arrangements: General Electric has
several combustors mounted in a ring around the turbine; Asea Brown Boveri
sometimes has a single combustor above the turbine; Siemens has two
combustors, one on each side of the turbine. Gas turbines can be fueled with
natural gas, diesel oil (distillate), and even residual or crude oil if appropriate
customized fuel treatment facilities are installed and properly operated.
Turbine nozzles and buckets are cast from nickel super alloys and are coated
under vacuum with special metals (platinum-chromium-aluminide) to resist the
hot corrosion that occurs ! the high temperatures encountered in the first stage of
the turbine, particularly if contaminants such as sodium, vanadium and
potassium are present. Only a few parts per million of these contaminants can
cause hot corrosion of uncoated components at the high firing temperature
encountered. With proper coating of nozzles and buckets and treatment of fuels

2. to minimize the contaminants, manufacturers claim the hot-gas-path components
should last 30,000 to 40,000 hours of operation before replacement, particularly
the hot-gas-path parts, that give rise to the relatively high maintenance cost for
gas turbines (typical O&M annual costs of 4 percent of the capital cost).
The continuing improvements in firing temperatures and compression ratios has
permitted manufacturers to increase the operating performance on the same
basic gas turbine frame or housing. For example, General Electric introduced its
Frame 7 series in 1970 with a rating of 45 MW, a firing temperature of 900°C
(1650 °F) and an air flow of 0.8 million kgs (1.8 million lbs) per hour. Through
many changes and upgrades the latest Model F of the same Frame 7 series has
a rating of 147 MW, a firing temperature of 1260°C (2300°F) and an air flow of
1.5 million kgs (3.3 million lbs) per hour. One of the major advances made was to
air cool nozzles and buckets using bleed air from the compressor to increase the
firing temperature while limiting the metal temperatures of the nozzles and
buckets to withstand hot corrosion and creep. This limiting of the maximum
temperature through air cooling while simultaneously increasing the mass flow
with more air compressor capacity permits higher power output. To increase the
final compressor pressure additional compressor stages are added on the
compressor rotor assembly to give higher compression ratio thus providing
additional turbine power output. Typical industrial gas turbine compression ratios
are 16:1 and aeroderivative ratios are 30:1 with roughly 50 percent of the total
turbine power of either type being required just to drive the compressor.
Compressor blading is special stainless steel, possibly coated by electroplating
with nickel and cadmium to resist pitting in salt and acid environments.
Compressor designs have been quite effective, as evident by the 200,000-hour
life of some early compressors installed in the 1950s.
The gas turbine has the inherent disadvantage that reduced air density with high
ambient temperature or high elevation causes a significant reduction in power
output and efficiency, because the mass flow through the gas turbine is reduced.

3. A 28°C (50°F) results in about a 25 percent output reduction and a 10 percent
higher heat rate. Similarly, at 1000 meter (3300 ft) elevation the gas turbine
output would be 15 percent lower than at sea level. Steam plants and diesels are
not affected to the same degree by ambient air temperature and elevation
changes.
Aeroderivitive Versus Industrial Gas Turbines
The advanced gas turbine designs available today are largely due to the huge
sums that have been spent over the last 50 years to develop effective jet engines
for military applications, including their adaptation as gas turbine propulsion
systems for naval vessels. The commercial aviation, electric power and to a
lesser extent, the sea and land transportation industries, have benefited
accordingly. Given the aircraft designer's need for engine minimum weight,
maximum thrust, high reliability, long life and compactness, it follows that the
cutting-edge gas turbine developments in materials, metallurgy and
thermodynamic designs have occurred in the aircraft engine designs, with
subsequent transfer to land and sea gas turbine applications. However, there are
weight and size limitations to aircraft engine designs, whereas the stationary
power gas turbine designers are seeking ever larger unit sizes and higher
efficiency.
To emphasize this difference in approach, today the largest aeroderivative power
gas turbine is probably General Electric's 40 MW LM6000 engine with a 40
percent simple-cycle efficiency and a weight of only 6 tons. This engine is
adapted from the CF6-80C2 engine that is used on the CF6 military transport
aircraft. By comparison, General Electric's largest industrial gas turbine, the
Frame 9 Model F has an output of about 200 MW, an open-cycle efficiency of 34
percent, but is huge compared to the LM6000 and weights 400 tons. The
aeroderivative is a light weight, close clearance, high efficiency power gas
turbine suited to smaller systems. The industrial or frame type gas turbine tends

4. to be a larger, more rugged, slightly less efficient power source, better suited to
base-load operation, particularly if arranged in a combined-cycle block on large
systems. There is no significant difference in availability of two types of gas
turbines for power use, based on the August 1990 Generation Availability Report
of the North American Electric Reliability Council. For the period 1985-1989 the
average availability of 347 jet engines (1587 unit years) was 92 percent and that
for 575 industrial gas turbines (2658 unit years) was 91 percent.
Combined Cycle Sizes/Costs
Gas turbines of about 150 MW size are already in operation manufactured by at
least four separate groups-General Electric and its licensees, Asea Brown
Boveri, Siemens, and Westinghouse/Mitsubishi. These groups are also
developing, testing and/or marketing gas turbine sizes of about 200 MW.
Combined-cycle units are made up of one or more such gas turbines, each with a
waste heat steam generator arranged to supply steam to a single steam turbine,
thus formatting a combined-cycle unit or block. Typical combined-cycle block
sizes offered by three major manufacturers (Asea Brown Boveri, General Electric
and Siemens) are roughly in the range of 50 MW to 500 MW and costs are about
$600/kW.
Combined Cycle Efficiencies
Combined-cycle efficiencies are already over 50 percent and research aimed at
1370°C (2500°F) turbine inlet temperature may make 60 percent efficiency
possible by the turn of the century, according to some gas turbine manufacturers.
Low-Grade Fuel for Turbines
Gas turbines burn mainly natural gas and light oil. Crude oil, residual, and some
distillates contain corrosive components and as such require fuel treatment
equipment. In addition, ash deposits from these fuels result in gas turbine

5. deratings of up to 15 percent They may still be economically attractive fuels
however, particularly in combined-cycle plants.
Sodium and potassium are removed from residual, crude and heavy distillates by
a water washing procedure. A simpler and less expensive purification system will
do the same job for light crude and light distillates. A magnesium additive system
may also be needed to reduce the corrosive effects if vanadium is present.
Fuels requiring such treatment must have a separate fuel-treatment plant and a
system of accurate fuel monitoring to assure reliable, low-maintenance operation
of gas turbines.
Alternative Combined Cycle Designs
Gas dampers are often provided so the gas turbine exhaust can bypass the heat
recovery boiler allowing the gas turbine to operate if the steam unit is down for
maintenance. In earlier designs supplementary oil or gas firing was also included
to permit steam unit operation with the gas turbine down. This is not normally
provided on recent combined-cycle designs, because it adds to the capital cost,
complicates the control system, and reduced efficiency.
Sometimes as many as four gas turbines with individual boilers may be
associated with a single steam turbine. The gas turbine, steam turbine, and
generator may be arranged as a single-shaft design, or a multishaft arrangement
may be used with each gas turbine driving a generator and exhausting into its
heat recovery boiler with all boilers supplying a separate steam turbine and
generator.
Combined-Cycle Shaft Arrangements

6. Combined Cycle Modular Installations
One significant advantage of combined-cycle units is that the capacity can be
installed in stages with short lead time gas turbines being installed initially (1 to 2
years) followed later by heat recovery boilers with the steam turbines (3 years
total). In this way each combined-cycle unit (i.e. block) can be installed in three
(or more) roughly equal capacity segments.
The modular arrangement of combined-cycle units also facilitates generation
dispatching because each gas turbine can be operated independently (with or
without the steam turbine) if part of the combined-cycle unit is down for
maintenance or if less than the combined-cycle unit total capacity is required.
This may give a higher efficiency for small loading than if the total capacity was
operated.
Furthermore, since combined-cycle units are available in sizes of roughly 50 MW
to almost 500 MW (and 600 MW are expected to be available soon with 200 MW
gas turbines), there are many selection possibilities for most sizes of power
system.

7. Another point favoring staging a combined-cycle unit is that the gas turbine (or
combined-cycle) per kilowatt cost does not seem to increase significantly for
smaller units, as is the case for steam units due partly to the high cost of the
substantial civil works necessary for steam plants regardless of steam unit size.
Finally, combined-cycle units can be installed in 3 years while a steam unit
typically requires 5 years, and once committed there is no power output from a
steam unit until the complete unit is available.
Fuels for Combined Cycles
Using present technology the combined-cycle unit can be fueled with natural gas,
distillate, and even crude or residual oil with appropriate fuel treatment. Fueling
with crude or residual oil, however, definitely results in extra capital costs for fuel
treatment equipment. Operations suffer due to additional operating costs for
additives to counteract contaminants such as vanadium, lower availability due to
additional maintenance and water cleaning shutdowns to remove blade deposits,
and reduced life because there is a greater tendency for hot gas path corrosion
due to blade deposits and corrosion.
The daily (or even more frequent) testing of the residual or crude oil for
contaminants with appropriate adjustments of fuel treatment is critical to prevent
damage to the gas turbine. Even with good operation there will be a reduction in
efficiency with crude or residual oil fueling to reduce firing temperatures, as
recommended by most manufacturers for this mode of operation, and due to the
blade deposits which build up between water-washing intervals. The gas turbine
has to be shut down periodically for cleaning and allowed to cool before washing
can be done by injecting water while rotating the unit using the starting motor.
Operational Considerations of Combined Cycles
This gas turbine is the main component that requires maintenance on combined-
cycle units. All manufacturers recommend specific intervals for hot-gas-path

8. inspections and for major overhauls, which usually involve hot-gas-path part
changes. During overhauls the condition of aeroderivatives may require that the
complete engine or at least major components be sent to overhaul centers, while
the industrial gas turbines usually will require only part changes on site.
The type of fuel and mode of operation are critical in determining both the
maintenance intervals and the amount of maintenance work required. It is
estimated by one manufacturer that burning residual or crude oil will increase
maintenance costs by a factor of 3, assuming a base of 1 for natural gas, and by
a factor of 1.5 for distillate fueling. Similarly, maintenance costs will be three
times higher for the same number of fired hours if the unit is started, i.e. cycled,
once every fired hour, instead of starting once very 1000 .fired hours. Peaking at
110 percent of rating will increase maintenance costs by a factor of 3 relative to
base-load operation at rated capacity, for the same number of fired hours.
The control system on combined-cycle units is largely automatic so, after a start
is initiated by an operator, the unit accelerates, synchronizes and loads with
automatic monitoring and adjustment of unit conditions in accordance with
present programs. The number of operators required in a combined-cycle plant
therefore is lower than in a steam plant.
Developed Country Combined Cycle Installations
The following key topics provide examples of developed country combined-cycle
installations.
Electricity Supply Board of Ireland Oil-to-Gas Conversion
The electricity Supply Board of Ireland converted two old oil-fired
steam plants to gas-fired combined cycle units in the late 1970s.
Originally, there units were used for baseloaded operation, but
recently change to intermediate load.

9. Refer To: World Bank IEN Working Paper #35: "Prospects for Gas-
Fueled Combined-Cycle Power Generation in the Developing
Countries", May 1991.
Midland Nuclear Plant Conversion, U.S.A.
Twelve Asea Brown Boveri 85 MW gas turbines and heat recovery
boilers were installed to supply two 350 MW steam units originally
installed for the Midland nuclear plant. This combined-cycle
cogeneration plant will supply 1380 MW to Consumer Power Co.
and process steam plus 60 MW of power to Dow Chemical Co.
Refer To: World Bank IEN Working Paper #35: "Prospects for Gas-
Fueled Combined-Cycle Power Generation in the Developing
Countries", May 1991.
LNG-Fired Combined-Cycle by Tokyo Electric
The world's largest regasified LNG-fueled combined-cycle plant is
in operation near Tokyo in Japan. Fourteen 165 MW single-shaft
combined-cycle units serve as mixed base-load and mid-range
generation on the 41,000 MW Tokyo Electric Power Co. system.
The plant capacity is 2,310 MW at 15°C ambient decreasing to
2,000 MW at 32°C. A unique feature is the low NOx emission level
of 10 ppm due to the use of selective catalytic reduction equipment.
Refer To: World Bank, IEN Working Paper #35: "Prospects for Gas-
Fueled Combined-Cycle Power Generation in the Developing
Countries", May 1991.
Developing Country Combined Cycle Installations

10. The following list provides examples of Combined Cycle projects in developing
countries. These examples are discussed in greater detail in the associated Key
Topics.
5 x 300 MW in India
3 x 300 MW Gas Turbines in Malaysia
2 x 300 MW in Pakistan
5 Combined-Cycle plants in Mexico
300 MW in Egypt
772 MW in Thailand
Combined-Cycle in Bangladesh
The dollar per kilowatt capacity costs vary from $592/kW for a new 1,080 MW
combined-cycle plant in Egypt to $875/kW for a steam addition to convert four
gas turbines at Multan in Pakistan to a combined-cycle plant. Although the
operating performance of combined-cycle units in North America is reported to
be satisfactory with availability factors of about 85 percent, the developing
country experience is less favorable, and in some countries the performance has
been poor.
Developing Country Combined Cycle
Installatons
5 x 300 MW Installation in India
As of 1991, only limited operational performance data are available on the 5 x
300 MW combined-cycle units in India which were commissioned in 1990. During
the commissioning runs some blades failed on one gas turbine reportedly due to
poor alignment; the manufacturer (Mitsubishi) made repairs and no further
trouble has been reported.

11. These five combined-cycle blocks are operating on gas and the National Thermal
Power Corporation (NTPC) reportedly is satis&ied with their performance and
plans installing additional combined-cycle units. However, full operation of the
combined-cycle plants has not been possible due to power contract disputes.
The gas price has not been finalized, so the NTPC selling price to the State
Electricity Boards has not been resolved, giving some uncertainty concerning the
load dispatching of the combined-cycle units.
3 x 300 MW Gas Turbine Installation in Malaysia
The Paka 900 MW (3 x 300 MW Alsthom-Hitachi blocks) gas-fueled combined-
cycle plant in Malaysia has had serious problems due to gas bypass damper
jamming and gas turbine start-up train torque converter bearing faults. Availability
reportedly has been only 55 to 60 percent in the past, but corrections have been
made and higher availability is expected.
Some of the problems have been attributed to split contracts for the gas turbine,
boiler and steam unit components with interface difficulties, particularly on control
systems. The country is still planning to install a large amount of combined-cycle
capacity in the 1990s (3,840 MW by 1999) expecting that "teething troubles" with
the technology will be overcome. However, some gas-fueled steam capacity will
also be installed, so that future power supply is not dependent on only one
technology.
2 x 300 MW Installation in Pakistan
2 x 300 MW blocks of gas-fired combined cycle gas turbines were installed at
Guddu, Pakistan.
According to USAID's consultant, RCG/Hagler Bailley, Inc. the availability of the
plant has been good in the 80-85 percent range but efficiency has been lower
then expected. No clear explanation of the reasons for the shortfall is provided.

12. Refer To: Annex 8 of the World Bank, IEN Working Paper #35: "Prospects for
Gas-Fueled Combined-Cycle Power Generation in the Developing Countries",
May 1991

13. Five Combined Cycle Plants in Mexico
Mexico has the largest amount of combined-cycle capacity in any developing
country totaling almost 1,900 MW at five plants. The units were installed in
1975-1986 and are typically dual-fueled, natural gas and distillate. The operating
performance has not been good; unit availability factors range from 38 percent to
83 percent; efficiencies vary from 20 percent for units installed in 1975 to 39
percent for later units. Comision Federal de Electricidad does not plan to install
any additional combined-cycle units, partly because of their poor operating
record and also because there is surplus residual oil which can be used in steam
plants.
300 MW Installation in Egypt
A 100 MW steam addition to 8 x 25 MW General Electric gas turbines. This plant
is a 300 MW Talkha gas/distillate-fueled combined-cycle in Egypt. USAID's
consultant, RCG/Hagler, Bailley, Inc. has reviewed the operational performance
of this plant and concluded that the availability of the plants has been quite
reasonable -- in the 80-85 percent range -- but efficiency has been lower than
expected without a clear explanation of the reasons for the shortfall. Gas turbine
component failures are the cause of most of the forced outages on these two
combined-cycle plants.
Refer To: Annex 8 of the World Bank, IEN Working Paper #35: "Prospects for
Gas-Fueled Combined-Cycle Power Generation in the Developing Countries",
May 1991
772 MW Installation in Thailand
The early operation of the gas-fueled, Bang Pakong 772 MW combined-cycle
addition reportedly was troubled by low gas turbine start-up reliability, difficulties

14. in fuel changeover, vibration, gas damper distortion, gas supply problems, and
the lower system inertia of the combined-cycle units. The plant availability is
understood to be only about 70 percent at present. Nevertheless, the Electricity
Generating Authority of Thailand is planning to install more gas-fueled combined-
cycled units to almost triple this type of capacity on its system by the end of the
1990s.
Combined Cycle Installation in Bangladesh
There are substantial gas reserved in the eastern half of Bangladesh, so
combined-cycle technology should be a logical generation candidate for this
country. Unfortunately, the operating experience has been poor on a small, UK-
fi.anced GEC combined-cycle unit installed at Ashuganj in the early 1980s.
Based on this experience, the Bangladesh Power Development Board (BPDB)
prefers to install gas-fired steam units. This situation is reflected in a recent
article by a consultant on system planning activities in Bangladesh:
"The BPDB have rather limited and somewhat unsatisfactory experience of their
one CC unit, and their FORs for the smaller gas turbines which they have
operated for a much longer period of time seem to be higher than average by a
factor of at least two, and possibly more than three.
Faced with these facts a cautious approach to planning was adopted using base-
load regime but with high FORs for CC plant. With this approach, selection of CC
plant by the program is limited and gas-fired steam plant claims most of the gas
allocation available."