The Power Plant planning capacity of XXXXX CPDO is 3x750 MW class, which comprising three phases: one set of nominal 750 MW class output natural gas/light diesel oil fired Combined Cycle units will be built in phase 1, and another two sets of nominal 750 MW class output natural gas fired Combined Cycle units will be built in phase 2 and phase 3. And the additional expansion is possible.

The whole site is separated into four parts, they are main power block building area, switch gear equipment area, auxiliary production area and plant front area.

Main power block building area is arranged in the central area, it consists of steam turbine house, gas turbine generation unit, heat recovery steam generator and electrical building. The north area of the plant is reserved for the extension purposes. Switch gear equipment area consists of transformer yard and 220kV GIS. The switch gear equipment area, rain water drainage pump house and starting boiler house are arranged east to the main building area. Plant front area is arranged south of main building area, this area consists of the following items: production overall building, mess hall, bathroom, rest room for night shift, warehouse and maintenance building. And gas regulator station is arranged east of the plant front area. Auxiliary production area is arranged in the west, this area consists of the following items: combined water treatment station, chemical water treatment station, sewage water treatment house, industrial waste water treatment station and hydrogen generation plant.

To the first phase, the plant is about 280m across from north to south and about 360m from east to west, the area of power plant is 8.30 hm2.

Due to the capacity of the phase 1 and phase 2 and phase 3 are the same, the same main equipment are selected for the phase 1 and phase 2 and phase 3 for the convenience of the design, installation, operation, maintenance, BOP and spare parts.

One set of S209FA gas-fired combined cycle unit is installed in each phase, the estimated plant performance for XXXXX CPDP Project is seen in the table 5- 4.

The following assumptions, guidelines, and criteria govern this analysis.

- Performance will be based on a 2x1 General Electric PG9351(FA) combined cycle operating on natural gas from the “City Gas�?

- Performance is based on new and clean equipment operating at ISO conditions; 15�?(59°F), 60 percent relative humidity, mean sea level.

- GT performance is based on estimated performance of the 9FA operating on natural gas with a dry low nitrogen oxides combustion system.

- The design characteristics of the Natural gas are given in table 1.3-2.

- The gas line pressure is 7 bar which is not sufficient for the GE 9FA. The 9FA requires a minimum gas pressure of 3.25 MPa, so, gas Compressors are necessary to rise the gas line pressure.

- The cooling water temperature is provisional 15°C.

        

Natural gas will be used for the project. The composition analysis of natural gas is listed in Table 1.3-2.

Characteristics of the Fuel Gas to be Used by the Power Plant :                                                 

                     Table 1.3-2. natural gas Composition

Percent by Weight	Percent by Volume	Composition
0.62	0.385	Nitrogen
1.72	0.688	Carbon Dioxide
84.49	92.766	Methane
7.03	4.117	Ethane
3.03	1.211	Propane
1.74	0.529	Butane
0.68	0.165	Pentanes
0.67	0.138	Hexanes
0.02	0.001	Heptanes Plus

 

Value	Parameter
17.57	Molecular weight
0.742 (0.0046)	Density gm/liter (lb/ft3) @ 60 F and 14.696 psia
	Higher heating value:
12,809 (23,056)	kcal/kg (Btu/lb)
9545 (1072.6)	Kcal/kg (Btu/ft3) @ 60 F and 14.696 psia
10,060 (18,103)	Sulfur content, ppm (max)

According to the above fuel gas, the Natural gas consumption is given in the following Table.

 

The proposed gas-fired combined cycle plant consists of two gas turbines, two heat recovery steam generators and one steam turbine. The combustion turbines exhaust into separate heat recovery steam generators (HRSGs), which produce steam to drive the single condensing steam turbine (ST).  Steam exhausted from the steam turbine is condensed in a deaerating condenser.  The condenser rejects its heat through a circulating once-through seawater system.

The GT used for the performance runs is the General Electric (GE) PG9351(FA) (9FA), equipped with a hydrogen cooled generator.  The 9FA is derived from the GE 9F CTG of 50 Hz, heavy-duty type GTs.  The 9FA GT consists of a 15.8-stage axial flow compressor and a 3-stage reaction type turbine.  In addition, the 9FA uses horizontally split casings and a cold end drive generator.

The HRSGs are designed to recover heat from the exhaust gas of the gas turbines and produce steam for use in the steam turbine. Each HRSG is an unfired, three-pressure, reheat, natural circulation type with horizontal gas flow and vertical fin tubes in all sections.

Each HRSG is arranged with a high-pressure (HP) superheater, reheater sections, HP drum, HP evaporator, high temperature and low temperature HP economizers, intermediate-pressure (IP) superheater, IP drum, IP evaporator, IP economizer, low-pressure (LP) superheater, LP drum, LP evaporator, LP economizer, and an exhaust stack. Three 50 percent capacity boiler feed pumps with interstage bleeds are included to take suction from the LP drum and pump through the HP and IP HRSG sections. Each exhaust gas stream passes through a stack to the atmosphere.

To eliminate the concern of exhaust gas condensation on the LP economizer tubes the condensate inlet temperature is controlled using an LP economizer recirculation loop. A recirculation pump is provided to pump a fraction of water from the LP economizer outlet to the LP economizer inlet for temperature control.

The ductwork and casings are designed to achieve the required outer face temperatures. Platforms, stairways, and ladders provide access to the drums, instrumentation, and valves. Access doors facilitate inspection and maintenance of the ductwork and/or heat exchanger modules.

The steam turbine is a horizontally split, multi-stage, condensing, reheat, dual flow, down exhaust steam turbine, which is directly coupled to a 3, 000 rpm generator. The steam before the main steam entrance valve of the steam turbine is designed to operate at throttle conditions of 12.4 MPa/566°C and in a sliding-pressure mode. The steam turbine also has a low-pressure admission. The steam turbine has standard accessories including a lube oil system, digital electro hydraulic control (DEHC) system, turning gear, and a gland steam condenser. The steam turbine, steam turbine generator, and condenser will be housed in a steam turbine building.

Heat rejection for a set of S-209FA combined cycle in this project is accomplished by circulating cooling water through the deaerating condenser. The cooling water is obtained from the Nile River. The cooling water flow rate is 12, 480 kg/s with a 10°C temperature rise. The cooling water flow rate includes auxiliary cooling water, which is approximately 5 percent of the total cooling water flow.

The condenser air removal system creates and maintains vacuum in the shell side of the main condenser by removing air and noncondensable gases. Noncondensables will be removed and condenser vacuum will be maintained using liquid ring vacuum pump.

Steam entering the condenser is deaerated as it condenses to the hot well which supplies deaerated condensate to the suction of the condensate pumps. For low load operation, sparging steam is supplied to the condenser if necessary to maintain proper oxygen levels.

The main equipment performance of S-209FA is based on 15 °C, 60 percent relative humidity, mean sea level with cooling water temperature of 15 °C, new and clean equipment, and operating on natural gas from the “City Gas�?with a dry low nitrogen oxides combustion system for NOx control.

 

The thermal system is based on multi-axis S-209FA combined cycle for each phase, including: two sets of gas turbines, two sets of HRSGs and one steam turbine.

Air is compressed by the compressor which is on the same shaft with the gas turbine, then it enters the combustion chamber and mixes with the natural gas, the high temperature flue gas produced from combustion of the mixture gas drives the gas turbine. The flue gas from the gas turbine goes to the HRSG for the heat exchange, then passes through the stack to atmosphere. The high temperature flue gas also can pass through a bypass stack to atmosphere to meet the rapid startup requirement.

The steam and water processes are as follows: The feed water from the HRSG LP economizer is split into the two parts. One part is pumped to the fuel heater through the recirculating pump, another part is fed to the LP steam drum and forms the natural circulation in the LP evaporator section by gravitation. Water from the LP evaporator section is supplied through an interstage bleed feed water pump into two parts. The IP part is first fed to the IP economizer, then to the IP steam drum and form the natural circulation in the IP evaporator section by gravitation. The HP part is first fed to the HP economizer, then to the HP steam drum and form the natural circulation in the HP evaporator section by gravitation. HP steam produced from the HP steam drum is heated in superheater, then supplied to the HP steam turbine. The exhaust steam from the HP steam turbine is mixed with the IP steam produced from the IP steam drum, then enters the IP reheater before it goes to IP steam turbine. The exhaust steam from the IP steam turbine is mixed with the LP steam produced from the LP steam drum and heated in LP superheater, then enters the LP steam turbine. The steam turbine exhausts steam downward to a deaerating condenser. The condensed water from the condenser is supplied to the condenser pump and mixed with the condensate from the fuel heater, then goes to the LP economizer, a steam water cycle is thus completed.

The main steam system will convey HP steam from the two sets of HRSGs to the HP steam turbine. The main steam system will be provided with bypass of main steam flow to the cold reheat system during startup, shutdown, and sudden load changes. The pressure and temperature of the main steam will be reduced with a combination pressure reducing and desuperheating valve before the steam enters the cold reheat piping. The boiler feed system will provide desuperheating water.

The reheat system consists of hot reheat and cold reheat steam piping. The cold reheat piping transports steam from the exhaust of the HP steam turbine to the reheater sections of the HRSGs. Cold reheat also receives steam from the intermediate pressure superheater on each HRSG. The hot reheat steam piping conveys the reheated steam from the HRSGs to the intermediate pressure steam turbine.

The reheat steam system will be provided with bypass of reheat steam flow to the condenser during startup, shutdown, and sudden load changes. The pressure and temperature of the reheat steam will be reduced with a combination pressure reducing and desuperheating valve before the steam enters the condenser. The boiler feed system will provide desuperheating water.

The LP steam system will convey LP steam from the HP steam turbine and the HRSGs to the LP steam turbine.

The LP steam system will be provided with bypass of LP steam flow to the condenser during startup, shutdown, and sudden load changes. The pressure and temperature of the LP steam will be reduced with a combination pressure reducing and desuperheating valve (if required) before the steam enters the condenser. The boiler feed system will provide desuperheating water (if required).

Condensate pumps will take suction from the condenser hot well through suction strainers. Condensate will be pumped from the hot well by the condensate pumps, through the gland steam condenser and the HRSG LP economizers before reaching the LP drum. Condensate regulator control valves will control the water level in the LP drum.

The boiler feedwater system will take water from the LP drum of the HRSGs and supply the HP and IP economizer sections of the HRSG. The water from the feedwater pump outlet is fed to the HP economizer. The IP feedwater using an interstage bleed from the pump at the required pressure is fed to the LP economizer. The boiler feedwater system will also supply desuperheating water to all the desuperheaters within the plant.

The steam turbine exhausts steam downward to a condenser. The condensing system will receive steam from the steam turbine and condense it using sea water from the circulating water system as the cooling medium. The condenser air removal system creates and maintains vacuum in the shell side of the main condenser by removing air and noncondensable gases.

The circulating water is pumped from the intake structure pond through the condenser and closed cycle cooling heat exchangers and discharged to the Nile River.

The Auxiliary Cooling Water System removes heat from the Closed Cycle Cooling Water System via the closed cycle cooling water heat exchangers.

During normal operation the Circulating Water System will supply cooling water to the closed cycle cooling water heat exchangers. After passing through the heat exchangers, the auxiliary cooling water will be discharged into the Circulating Water System downstream of the condenser discharge iso­la­tion valves

The Closed Cycle Cooling Water System provides a clean source of cooling water to the mechanical and fluid systems requiring cooling. This cooling water is provided by circulating water through the closed cooling water heat exchangers which are cooled by the Circulating Water System.

The Demineralized Water Makeup and Storage System will supply demineralized water for the condenser, and the combustion turbine wash and closed cooling water system.

Makeup water can enter the condenser by either pump or gravity.

Air compressors will provide control and service compressed air for the power island and chemical water treatment portion of the plant.

The boiler vents and drains system will take all operating and maintenance vents and drains from the HRSG and convey them to the appropriate location. High pressure HRSG operating drains will be taken to the flash expander before entering the plant drains system. Low temperature HRSG drains will be taken directly to the plant drains system.

The emergency diesel generator is used to bring the plant in an orderly manner in the event of a plant trip. Black start capability has not been included. Electrical power requirements for starting the plant up will be taken from the grid.

The fuel of the project is natural gas. Natural gas will be transported to the site via a gas pipeline operated by "City Gas". At the outlet of the reducing gas station, the gas pressure is 7 bar. The gas line pressure is not sufficient for the GE 9FA which requires a minimum gas pressure of 2.79 MPa (405 psia), so, gas Compressors are needed to rise the gas line pressure.

As the fuel supply system is relatively reliable, no gas tank is provided inside the plant. A totaling flow meter will be supplied to measure gas consumption of each gas turbine.

A gas-operated (spring closing) valve will automatically isolate the fuel gas lines coming into the turbine generator building when a fire is detected on the gas turbines or in the building. A solenoid valve will then vent the gas in the line outside the generation building.

 

 

1  Investment Estimation

1.1  Scope of drawing up

The investment estimation consists of the equipment, civil engineering, installation work within the wall of the power plant,  excluding Land reclamation and Land costs�?/DIV>

Table 1A :		Designed Capacity: 750MW		Date: December.2009
/DIV>	Description and Specification	engineering expenses of construction	purchase expense of equipments	installation engineering expense	other expenses	Total in 10000 USD
A	Thermal system　/DIV>	2,583.37	55,759.54	1,896.45	/DIV>	60,239.36
B	Fuel supply system　/DIV>	227.81	3,211.68	73.96	/DIV>	3,513.45
C	Chemical water treatment system	220.83	452.48	261.65	/DIV>	934.97
D	Water supply system　/DIV>	266.19	813.21	431.55	/DIV>	1,510.95
E	Electric system　/DIV>	208.97	4,991.60	2,142.05	/DIV>	7,342.62
F	I&C system　/DIV>	/DIV>	1,660.96	582.61	/DIV>	2,243.57
G	Accessory production engineering	1,273.37	581.21	102.92	/DIV>	1,957.50
/DIV>	Sub total　/DIV>	4,780.54	67,470.69	5,491.18	/DIV>	77,742.40
H	Other expenses　/DIV>	/DIV>	/DIV>	/DIV>	21,620.39	21,620.39
/DIV>	Total　/DIV>	4,780.54	67,470.69	5,491.18	21,620.39	99,362.79