Hazira brings clean power to Gujarat16 November 2001
Hazira has proved to be one of the shortest lead-time combined cycle power projects in India. Both gas turbines have synchronised in a record time of 16 months from the notice to proceed. The advanced GT8C2 gas turbines are the first units of this type to be equipped with dual burners to fire gas as prime fuel and high speed diesel (HSD) as backup fuel. Hazira is also the first use of GT8C2 machines in combined cycle mode. Gilbert Roy and Paul Baerfuss, Alstom, Baden, Switzerland
Gujarat State Petroleum Corporation Ltd (GSPC) was originally set up as the state government arm for launching petrochemical complexes in Gujarat. In 1991 it seized the opportunity presented by the upstream hydrocarbon sector when the Indian government liberalised its oil exploration policy. GSPC was awarded five small oil and gas fields and in association with the Canadian operator, Niko Resources Ltd, by the end of 1994 it started production of oil and gas.
Judicious drilling of new wells in its Hazira gas field led to the discovery of new and extensive gas horizons which were not exposed by earlier drilling. Reinterpretation of data and results from the new wells pointed to large gas reserves, in the region of 1012 cubic feet which would yield over 3 million cubic metres of natural gas per day. This could bring tremendous benefits to the energy starved state of Gujarat as well as the hinterland. To achieve high safety levels and deploy advanced technology, GSPC has collaborated with companies such as AMEC Heritage of the UK and HOEC of India, as well as Niko Resources, and is already providing natural gas to serve the needs of industry around Surat city.
Additional new oil and gas fields like North Balol, Unawa, Dholasan, North Kathana, Kanawara and Allora, as well as two exploration blocks, Tarapur and Palej, have since been awarded to GSPC which will greatly help expand its base and substantially augment the production of oil and gas in the state of Gujarat.
Diversifying into power
GSPC decided to move into power generation as part of its corporate diversification plan and embarked on a short gestation power project based on the use of natural gas from its gas fields. The Hazira area of Gujarat was chosen as the site for a combined cycle plant.
The plant, with a capacity of 156.1 MWe gross, has a "two-on-one" multi-shaft configuration (designated KA8C2-2), with two gas turbines and one steam turbine, plus a forced draught wet cooling tower. The facility operates with natural gas or with No 2 distillate oil as back-up fuel, if the gas supply is interrupted.
The gas turbines are housed in outdoor enclosures, while a building is provided for the steam turbine, allowing maintenance to be carried out regardless of weather condition. An electrical building contains the medium and low voltage switchgear equipment as well as the main control room for the plant. The plant is also provided with overhead cranes for the main machinery.
To implement the project, GSPC set up a separate subsidiary company named Gujarat State Energy Generation Ltd (GSEG).
GSEG, in turn, selected Alstom as contractor for the project through international competitive bidding. Alstom is supplying the complete plant on a turnkey basis. Its scope includes two GT8C2 gas turbines with generators, a steam turbine with generator and heat recovery steam generators as well as the overall power plant control system. The contract also includes civil works, balance-of-plant and buildings. GSEG has employed Desein Consulting Engineers of Delhi as advisors and to supervise the turnkey contractor's compliance with the plant specification.
GSEG has also selected Steag as O&M contractor for the project.
The power purchase agreement for the project has been approved by GEB.
It is expected that the plant will mainly be run in continuous baseload operation with occasional start-up and shut-down. However, the plant will be capable of daily start-up and shut-down, if required.
The plant is designed to operate in an ambient temperature range of 15 °C to 45.6 °C with the design fuel. The net output is 152.2 MW at design conditions (Tamb = 28 °C, Pamb = 1.012 bar, relative humidity = 60 per cent).
The power supplied by the plant is in the form of three-phase 50 Hz AC, at a nominal voltage of 220 kV.
Turbines and generators
Hazira is the first combined cycle power plant ordered which uses Alstom's GT8C2 gas turbine (see MPS, April 2001). The GT8C2 provides a high degree of operational flexibility with its excellent mass flow turn down capability. Two such gas turbines are used in the Hazira plant. There have been earlier applications of this machine - two at Baku, Azerbaijan, and one at the Birr test facility in Switzerland - but these are all simple cycle and/or cogeneration facilities.
The dual fuel GT8C2 is a high efficiency 3 stage gas turbine with 12 stage transonic compressor and an annular combustor. The combustor contains 18 single EV burners, working according to the principle of lean premix vortex breakdown, thus achieving very low NOx values with dry combustion during gas operation. In oil operation, water is injected to control the NOx emissions.
The compressor is equipped with a single row of variable inlet guide vanes, positioned on the compressor inlet. The combustion airflow rate can be adjusted by changing the angular position of the vanes. Load control of the gas turbine is therefore managed by varying the amount of fuel and combustion air.
Among other main design features of the GT8C2 gas turbine are the following:
• The compressor and turbine blades are mounted on a single rotor shaft, which is supported by journal and thrust bearing
assemblies mounted externally within the compressor intake housing and exhaust diffuser for ease of maintenance.
• The compressor intake, compressor, turbine housings and exhaust diffuser are bolted together to form one rigid unit and access to the compressor and turbine components is gained after removal of the top half-housings.
• All turbine stages, except the last, are air-cooled.
• Correct ignition in the EV combustors is monitored by temperature sensors and flame monitors.
• Boroscope inspection ports are located at strategic positions for inspection of the turbine and combustor.
• The following inspection/maintenance tasks can be carried out without opening the compressor/turbine housings: inspection, repair and renewal of the bearings; inspection of the first stage of the compressor and the first and last stage of the turbine; boroscope inspection of all turbine stages and combustors; and balancing of the rotor in three balancing planes.
A fuel gas pressure control station controls the supply of gas to both gas turbines. The internal gas supply system consists mainly of fuel gas filters, a moisture separator skid, gas preheaters and the distribution pipe work. In order to increase cycle efficiency, a fuel gas preheater, a shell and tube type heat exchanger with the fuel gas inside the tubes, is provided for each gas turbine. The heat input is provided by extraction water from the heat recovery steam generator downstream of the low pressure economiser.
The lubrication system of the gas turbine provides also for the lubrication of the generator. Two 100 per cent lube oil pumps (plus one 100 per cent DC emergency pump) supply oil through the lube oil cooler to the bearings of the power train. During rotor barring, the gas-turbine/generator shaft is lifted by a hydraulic jacking oil pump.
Each gas turbine drives a generator through a reduction gear from the compressor end. The axial exhaust makes for easy connection of the heat recovery steam generator. The straight flow reduces pressure losses and eliminates the need for turning vanes.
The steam turbine is of the Alstom DKZ2-1N33 type and operates at 3000 rpm. The single casing machine is equipped with two admissions to take HP (high pressure) and LP (low pressure) steam from the heat recovery steam generators. The axial exhaust is directly connected to the horizontally arranged condenser.
The steam turbine is designed for sliding pressure operation.
HRSG and water-steam cycle
The water-steam cycle consists of non-reheat heat recovery steam generators and the single casing steam turbine, with HP live steam provided at 484°C and a pressure of 71 bar.
The unfired natural circulation heat recovery steam generators produce superheated steam at two pressure levels. The boiler comprises an economiser, an evaporator with drum and a superheater section for both high pressure and low pressure systems. The heat discharged from the gas turbine as hot exhaust gas serves as the heat source and generates steam by heat transfer.
The LP system is fed directly with condensate from the condenser hotwell. The condensate is preheated in the LP economiser before entering the LP drum. The LP feedwater control valve is located downstream of the LP economiser. The LP drum serves as feedwater tank for the HP circuit. Water for fuel gas preheating is taken from the outlet of the LP economiser and returned to the flash box of the condenser.
The HP system is fed with feedwater from the LP drum by the HP feedwater pumps. To avoid chemical problems in the HP system due to a high concentration of salts in the LP feedwater drum, an "all volatile treatment" with dosing of amine, is used for the LP system, while the HP system is treated in the conventional way with dosing of trisodium phosphate. The feedwater is preheated in the HP economiser before entering the HP drum. The HP section of the heat recovery steam generator includes an attemperator for the HP live steam, which takes water from an extraction downstream of the feedwater pumps.
The two 100 per cent HP feedwater pumps are of the horizontal ring sectional type with strainer and minimum flow check valve. They run with constant speed and are throttle controlled. The pump motors are connected to the medium voltage switchgear. One pump per HRSG is in operation at full load.
To increase the operational and start-up flexibility of the plant, a steam bypass system is provided. It is automatically activated in the event of steam turbine start-up, shutdown, or turbine trip.
The steam bypass system is designed to handle the whole steam production at full pressure under all ambient conditions. It consists of an isolating and a steam pressure reducing valve with integrated water injection and the associated measurement, control and protective devices. Injection water for desuperheating of the steam is taken from the main condensate line.
The condenser is a horizontally arranged water-cooled surface type with two passes. The water boxes are divided, so that maintenance on the water side is possible during operation of the steam turbine. A flash box is connected to the side of the condenser shell. The hotwell is sized to provide sufficient storage capacity to the water-steam cycle.
The two 100 per cent main condensate pumps are of vertical can type design with venting on the suction side. One pump is in operation at full load. The second pump serves as standby and is switched on automatically in case of failure of the operating pump or to support steam bypass system operation.
The evacuation systems consists of one 100 per cent single stage steam jet start-up ejector without condenser and one 100 per cent two stage steam jet service ejector with inter and after condenser. The motive steam for the ejectors is taken from the HP steam line. A constant pressure, upstream ejector, is controlled by pressure control valve. The condensed steam is returned to the main condenser. The extracted air is discharged to atmosphere. The start-up ejector also serves as a back-up in case of failure of the service ejector.
A forced-draught wet cooling tower system transposes the waste heat of the water-steam cycle to the atmosphere. Two 100 per cent main cooling water pumps supply the cold water from the cold water basin to the main condensers and the intercoolers of the closed cooling water system. The condenser is equipped with a continuous operating sponge ball cleaning system to keep the condenser tubes in clean condition.
Losses in the system are made-up by clarified raw water. The cooling water quality is controlled by the cooling water sampling and chemicals dosing station. This controls scaling and corrosiveness of the cooling water. A chlorination system is provided to prevent bio fouling in the cooling water systems.
A separate closed cooling water (CCW) system ensures the cooling of the lube oil system, the steam turbine generator air coolers, the HP feedwater pumps, and the sampling system coolers, the sampling system, etc. Two 100 per cent capacity circulating pumps are provided for this CCW system. The heat is dissipated to the main cooling water system via two 100 per cent capacity water to water heat exchangers.
Losses in the system are made-up by demineralised water from the demineralised water system. To achieve a defined quality of water, an inhibitor dosing station is connected to the CCW system.
The raw water is clarified in the pretreatment plant to be mainly used as makeup to the cooling water system. Some of the clarified water produced is stored in a clarified water tank for use as feed to the pressure filters upstream of the demineralising plant.
Part of the filtered water from the pressure filters is stored in the overhead filtered water tank for use as potable water for HVAC make-up and service water.
The other part of the filtered water from the pressure filters is fed to the activated carbon filters and the subsequent ion exchange vessels. The demineralising plant, with two streams of 30 m3/h capacity each, produces demineralised water for the facility, as makeup to the steam-water cycle and for injection into the gas turbine for NOx control. Limited periods with higher demand for demineralised water (eg, fuel oil operation or higher losses of process steam condensate) can be covered by water stored in two demineralised water tanks of 500 m3 capacity each.
Demineralised water is pumped by two 100 per cent pumps (one in operation and one in standby), providing water-steam cycle makeup and occasional supply to dosing and sampling stations, closed cooling water systems and GT compressor washing skids.
Two NOx water pumps (2 x 100 per cent) supply demin water for gas turbine NOx reduction when HSD is fired.
Chemical and emissions monitoring
The plant has a sampling monitoring system equipped with all required instruments for on-line monitoring and analysing of steam and water quality of the process. There is one sampling rack for controlling the quality of heat recovery steam generator blowdown, water-steam circuit (steam and condensate), makeup water and closed cooling water circuit.
The water-steam cycles of the units are provided with a combined amine and hydrazine dosing plant for the condensate system and LP boiler drum, and a trisodium phosphate dosing plant for the HP boiler drum.
The main cooling water system is equipped with a sulphuric acid dosing plant.
For emissions monitoring, each gas turbine exhaust gas diffuser has a connection to an emission sampling cabinet for on-line analysis and monitoring of the exhaust gas composition (O2, NOx, SO2, CO and CO2).
The heat recovery steam generator stacks are provided with additional test ports to allow for installation of temporary equipment for periodic tests by the authorities.
The facility is equipped with an overall plant process control system based on ADVANT technology. This system enables safe and reliable operation, control and supervision of the process with a high degree of automation.
The ADVANT DCS provides functions such as signal conditioning, annunciation, recording, operation, monitoring and supervision, open and closed loop control, sequence logic, protection, data communication, and plant management applications.
Operation and supervision of the plant is generally performed from the main control room using the operator station.
Control system engineering and diagnostics are handled from the engineering station.
The gas turbine control module (EGATROL) includes the start-up and shutdown sequencing, open and closed loop control and the
gas turbine protection system.
The steam turbine control module (TURBOTROL) includes open loop control and the interfaces to the steam turbine governor and the steam turbine protection system.
The water-steam cycle, HRSG and BOP control module includes open loop control, closed loop control, protection and interfaces to the autonomous systems.
The power generated at 11.5 kV is stepped up to 220 kV through three step up transformers (70 MVA) and connected to the 220 kV switchyard located inside the plant boundary. Two outgoing lines connecting to the Kim substation are used for power take off as well as for providing start up power.
Two station service transformers (6 MVA, 11.5/6.9kV) and four LV auxiliary transformers (2 MVA, 6.6/0.433kV) are provided to meet the auxiliary power requirements of the power station.
To cover critical functions, 220V DC , 48V DC and 24V DC systems are provided, backed up by Ni-Cd batteries.
For DCS and other plant requirements, a 230V UPS (40 kVA) with Ni-Cd battery back up is provided.
Operation of essential auxiliaries and safe shut down of the plant in the event of blackout are guaranteed by two emergency diesel generator sets ( 625 kVA, 415 V).
The plant has a compressed air system, which is divided into the instrument air distribution network and the service air distribution network. Instrument air consumers are served with oil free and dry compressed air. The service air system will distribute normal quality compressed air for purging, cleaning, pneumatic tools etc.
The power plant is also equipped with a fire fighting system meeting all local and contractual international authorities' requirements. The main components are fire detection and alarm systems, gas detection system, water fog fire extinguishing system, HVW spray system for transformers, and fire hydrant system. The water supply for this system is provided directly from the raw water reservoir.
To ensure good communication throughout the plant, it is equipped with a central public address system, a telephone system and a central time system.
The first generating unit (simple cycle mode) was synchronised to the grid on 30 September 2001 and the second just over two weeks later, on 16 October. The provisional acceptance certificates for these units were scheduled for 1 November and 1 December respectively.
First steam to the steam turbine is scheduled for 16 January 2001, with synchronisation of the steam turbine slated for 28 January. The plant is due to be in full commercial combined cycle operation by the end of February 2002.
TablesMain data for Hazira Hazira project: key dates