CEPSI 2008/GTj
page 1(15)
Island operation tests in a SCC-800 CHP Plant - an example from an operating plant in Sweden. Presented by GĂśran Tjellander; Product Manager Industrial Plants, Siemens Industrial Turbomachinery AB, Finspong, Sweden.
Abstract
The 261-MWe Rya Combined Heat and Power (CHP) plant supplies power and heat to the city of Gothenburg, Sweden. This combined-cycle CHP comprises three Siemens SGT-800 gas turbines, each connected to a supplementary-fired Heat Recovery Steam Generator (HRSG) supplying steam to a Siemens SST-900 steam turbine. High flexibility with regard to load range, high efficiency, operational reliability and security of power and heat supply were dominant factors in the selection of the Siemens multi-shaft combined-cycle solution. The plant is normally connected to the national grid, but can also operate on the local grid, which is divided into 25 sections. This allows the local grid to be restored after a power cut. Hence reliable house-load operation after loss of grid – or a black start capability to house-load operation using the plant’s own black-start diesel generator were essential requirements. Subsequent energizing of the local grid and loading the sections one-by-one, demands an advanced step-loading capability for the plant from zero to 100% plant power-generation capacity. Extensive testing to verify these properties was carried out during the commissioning period, autumn 2006. Switchover from normal grid operation to house-load operation was tested by opening the plant breakers during normal operation. A black-plant incident followed by a black start-up to house-load operation was tested with minimal disturbance to the grid. The subsequent sequences, i.e. energizing and loading the local grid, were simulated in a computer and fed to the plant controller, enabling verification of the requested plant island-operation behavior whilst being connected to the large national grid. This paper identifies the main advantages of combined-cycle solutions based on multiple medium-sized industrial gas turbines in situations where reliability and secure power and heat generation are important. It gives island-operation test results and findings and compares them with the required plant behavior.
CEPSI 2008/GTj page 2(15) ---------------------------------------------------------------------------------------------------------------Rya Combined Heat and Power (CHP) Plant – a brief overview
Figure 1 - Rya CHP
Rya combined-cycle CHP plant (Figure 1), delivered by Siemens Industrial Turbomachinery AB under EPC contract, supplies power and heat to the city of Gothenburg in Sweden. It has been in commercial operation since mid-December 2006. The plant comprises three SGT-800 gas turbines (GT) , each connected to a supplementary-fired HRSG supplying steam to a SST-900 steam turbine (ST). 261 MWe power and 295 MJ/s district heat (DH) are generated at max. continuous rating (MCR) which is enough to cover the heat and power demand for 30 to 35% of the inhabitants of Gothenburg. An installation overview is shown below (Figure 2). Air Flue gas
Natural gas
Gas turbine HRSG
Power District heat
Steam turbine
Heat condensers Figure 2 - 3D-view of the installation
CEPSI 2008/GTj page 3(15) ---------------------------------------------------------------------------------------------------------------A sea-water-cooled DH auxiliary cooler is installed in parallel with the DH consumers. See the simplified flow diagram in figure 3 below.
Auxiliary cooler
Figure 3 - Plant simplified flow diagram, SCC-800 3x1 DH
Access to the auxiliary cooler, a direct parallel to having access to a steamturbine condensing tail, allows power generation up to 80% of MCR (limited by the auxiliary cooler itself) without any DH connection - or in a combined mode both supplying heat to the DH net and the auxiliary cooler; power generation can be maximized up to 100% MCR. Furthermore, it allows power generation even in an extraordinary situation when the DH-net is not available, for example in a situation where island operation is required due to an external grid cut-off. In this case, heat-condenser cooling is achieved by the sea-water-cooled auxiliary cooler and thus power generation is controlled entirely within the fence of the plant – a situation that is similar to a normal condensing power-generation unit. The DH auxiliary cooler has another advantage. It allows high-load testing during commissioning independently of the prevailing DH conditions. This was especially important during autumn 2006 when the weather was extremely warm in Gothenburg and consequently no full-load demand arose due to low DH-net consumption.
Customer priorities The plant is intended to operate as a base-load unit during wintertime with maximum DH generation and provide the highest possible power generation with regard to the given heat duty, i.e. maximizing the power-to-heat-ratio. During spring and autumn, 1500 h part-load operation and DH-net load following is foreseen. High flexibility with regard to load range, excellent fuel efficiency, operational reliability and secure power and heat distribution were also important factors when Gothenburg Energy AB selected the Siemens multi-shaft combined-cycle solution. The optional sea-water-cooled DH auxiliary cooler was added to the scope as a further measure to secure island operation and power generation independent of the DH-system heat demand.
CEPSI 2008/GTj page 4(15) ---------------------------------------------------------------------------------------------------------------This is, of course, of importance for the total national grid owner and operator, not only during a longer cut-off situation but also in a potential power imbalance situation. Hence this option was financed by the national Swedish grid owner Svenska Kraftnät.
Siemens Gas Turbine SGT-800 (x3) and Steam Turbine SST-900 DH (x1) SGT-800 is a reliable single-shaft 45 MWe (ISO) industrial gas turbine launched 1997 with high efficiency and high temperature exhaust suitable for combined-cycle application. It was recently upgraded to 47 MWe. Fuelled with natural gas from a 28-bar supply system during normal operation and diesel oil stored at the site as a backup fuel, the possibilities of forced outages due to fuel disturbances are minimized both during normal operation and in island operation. Switchover from natural gas to diesel oil is performed automatically at reduced load if and when the supply-gas pressure has decreased to a defined level. Configuring the plant solution as a 3x1 multishaft solution, i.e. 3 gas turbines and HRSGs supplying steam to one steam turbine, ensures exceptional generation availability. Air intake
Cold end drive
Combustors
Compressor
Turbine
Turbine outlet diffuser
Figure 4 – Siemens gas turbine SGT-800
The installed non-geared single-shaft steam turbine SST-900 (figure 5 below) has steam data 100 bara/540ÂşC upstream of the emergency stop valve. The relatively high steam temperature is attainable and maintainable in the major part of the load range due to supplementary firing (SF). SF increases the steam generation from 46 to 100% in each HRSG. The ST is connected to two heat condensers heating the return DH water in two steps. Downstream of the heat condensers, a dump condenser (DC) with individual dump-steam lines from each HRSG outlet is installed, designed for receiving 70% of the total steam generation. This is enough to maintain heat generation at 100% in case the ST is not available. However - as only the GTs generate power, the total power generation decreases to 50%. The DC allows starting the HRSG individually and synchronizing steam data to the main steam line while minimizing steam loss to the ambient environment. The ST can thus be started and stopped at any combination of GTs in operation provided steam data is sufficient and steam generation is high enough.
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Blading
Exhaust
Turbine Shaft
Generator
Steam Admission
Turbine Casing
Figure 5 – Siemens steam turbine SST-900 DH
Heat Recovery Steam Generators (x 3) The HRSGs are single-pressure water-tube boilers with comprehensive SF (up to 1000ºC), equipped with a Selective Catalytic NOx Reactor (SCR) and a laststage DH water-cooled economizer that minimizes the exhaust losses. The HRSG(s) are delivered by Austrian Energy and Environment CZ. The main internals of the HRSG are shown in figure 6. SF and the low stack temperature (70ºC) allow full-load plant net efficiency close to 94%.
CEPSI 2008/GTj page 6(15) ---------------------------------------------------------------------------------------------------------------Economizer
Drum and evaporator
DH-cooled economizer
SCR
Superheater Membrane walls
Flue gas to stack
Supplementary-firing burners Distribution plate
Cold DH water Hot DH Water Condensate Superheated steam to steam turbine Hot flue gas from GT
Figure 6 - HRSG
The multi-shaft SCC-800 combined-cycle CHP solution The plant concept, using 3 GTs and 1 ST (3x1), implies excellent load range and part-load efficiency as reducing the number of GT´s in operation, when the DH load is reduced, means higher load and efficiencies for the GTs in operation. Compared with a single-GT concept, the continuous load range is expanded from 60% to 90% of MCR approximately, while also maintaining high part-load efficiencies and low NOx-emissions. The minimum continuous plant load is therefore decided by the ST minimum load rather than by the minimum continuous GT load. See figure 7 below showing power-to-heat ratio versus DH load. Here the optimum GT switch on/off DH loads and the effect of SF can be clearly extracted. 120,0
Pwer to Heat ratio (%)
100,0 80,0 3 GT
100% GT load 100% SF
60,0
2 GT 1 GT
40,0
100% GT load No SF Switch-off load (2 to 1 GT)
20,0 0,0 0
50
100
150
200
250
300
DH Heat Duty (MJ/s)
Figure 7 - Power to heat ratio versus DH generation
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Reliability and generation security aspects Loss of generation probability 4 shafts for power generation secures power and heat generation. For reference, see figure 8 below.
Figure 8 - Simplified single line diagram
他 One GT failure from full load causes an output drop of 1/3 MCR. However, if occurring in the part load range, enough and instant capacity may be available by increasing SF of the HRSG in operation or by putting a shut-off gas turbine into operation again. 他 Loss of the total power and heat generation requires that 3 out of 3 GT(s) in operation fail which has a low probability and is realistic only in a commonmode failure incident. 他 If ST is lost, DH generation will continue as steam will bypass the ST directly to the DC.
CEPSI 2008/GTj page 8(15) ---------------------------------------------------------------------------------------------------------------¾ Loss of power generation due to faults in the internal HV power transmission is not very likely since there are two redundant three-winding step-up transformers 1 supplied from the gas turbines GT1/GT2 and GT3 respectively. ¾ Loss of power generation due to failures in the MV and LV distribution systems are also unlikely since there are two redundant internal auxiliary power distribution systems 6/0.4 kV. There is also a 10.5 kV external spare supply connection to the MV/LV systems.
One of these common-mode failures could be an externally caused complete loss of power incident, i.e. losing the 142 kV grid. If the plant is in operation at the instant of the power cut, it should be automatically switched over to “House load operation” and continue to operate - now isolated from the external power grid and operating with a load corresponding to its own auxiliary power consumption. If the plant is not in operation when the external power cut occurs or if houseload operation fails for some reason, a black start is foreseen by using the black-start diesel generator sized for 2.8 MVA or 2.5 MW active power. This power is primarily required for motoring one of the 3 GT´s during HRSG purging and until flame is established and rotor accelerates. The starting motor requires peak 1.5 MWe and remains high during a 6-minute period. Black start-up to house-load operation can be carried out by any of the three GT(s) on natural gas or diesel oil, whichever is available. However, start of GT1 or GT3 is prioritized as each of them serves one independent auxiliary grid (see Figure 8). Having GT1 and GT3 in operation, these power redundant auxiliary objects, such as pumps, from two independent power sources.
House-load operation capability By “House- load operation” we understand the situation where the 142 kV plant breaker is opened due to external grid faults or failures such as unacceptable voltage or frequency deviations. The turbine load is suddenly lost and it turns from load to frequency control with the plant’s own internal auxiliary power as the only load. The auxiliary power at MCR is around 3% but decreases to around 1% of MCR during House-load operation as the main auxiliary objects like large speed-controlled pumps gradually decrease their speed. House-load operation as such is a requirement in Sweden for powergenerating plants larger than 50 MWe. The old regulation required 1 h continuous house-load operation, while the new one stipulates 12 h house-load operation time after an external grid disturbance (frequency or voltage disturbance that allows the plant to be isolated from the external grid) or a total external power cut. The new requirements reflect the consequences of deregulations of the electricity market in 1996. Since then, an intensified focus has been aimed at securing island operation areas around the larger cities in Sweden in case of national power cuts.
1
The three-winding transformer connected to GT3 is prepared for a fourth GT/HRSG (option)
CEPSI 2008/GTj page 9(15) ---------------------------------------------------------------------------------------------------------------There are two auxiliary power sections within the plant, supplying power to redundant objects like feed-water pumps etc. One is fed by GT1 and GT2 and the other by GT3 (please refer to figure 8 – cross-feeding is also possible). Thus if all three GTs are in operation, two of them, GT1 and GT3, will remain in house-load operation supplying power to one section each, while GT2 and the ST will trip.. Consequently, if two or more gas turbines are in operation (which is the case during the load-intensive part of the year) on the occasion of the disturbance, the high availability continues to be maintained during house-load operation and subsequent resynchronization to the external grid.
From house-load operation to island operation In case a longer power cut occurs – for example longer than the earlier required 1h but much shorter than the currently required 12 h house-load operation - a decision may be taken to energize and load the local grid within the operability of Gothenburg Energy. Energizing and loading the sections one by one demands both careful preparation and an advanced plant step-loading capability. As starting and loading the plant in steps are defined by the grid section to be loaded and not by the plant operator or the plant load control, the sequence of preparations has the character of preparing the operational ground that will not jeopardize the subsequent loading and collapsing the island operation. Hence there has to be an intensive communication between the plant operators and the island-grid operators. The preparation involves the following main steps seen from the view of the plant operators. ¾ The gas turbine(s) are initially in house-load operation. This initial condition may be obtained either from a successful switchover to house-load operation directly after the initiating external grid disturbance or by a black-start sequence using the black-start diesel generator as a means to bring GT(s) to house-load operation. ¾ Selection of island operation on the operator display which switches the GTs to frequency control. Steam turbine frequency control is not affected. This means that the gas turbines and steam turbine will share load; however the gas turbines only will control frequency. ¾ Switch-over to sea-water-cooled auxiliary cooler operation instead of DH generation in case the DH system is not available. This will take up to half an hour, as the auxiliary cooler has to be evacuated from air before starting the cooling pumps. ¾ Planned or automatic switch-over from natural gas fuel to reserve fuel in case the gas supply pressure tends to decrease. Fuel change during ongoing island operation is not suitable as the change may cause an intolerable frequency disturbance during island operation. ¾ After energizing the first and nearest island section and before loading, the steam pressure is put to fixed full steam pressure. This measure has two
CEPSI 2008/GTj page 10(15) ---------------------------------------------------------------------------------------------------------------purposes. Fixed steam pressure will reduce the boiler temperature transients during subsequent step-loading and will also shorten the response time for the ST. ¾ Loading the individual sections step by step where each step has to have a known or predefined load level. This is so because the plant has a limited ability to handle step loads that depends on its operational status, such as how many of the GTs are in operation and if SF or ST is in operation or not.
Step-load capability and frequency disturbance requirements during island operation When powering the island grid sections, the following main requirements with reference to the plant’s step load capability were set up with reference to figure 9 below: ¾ Step-load capability at load increase: 10% of nominal load 2 from zero to 80% of nominal (available maximum load) ¾ Step-load capability at load decrease: 10% of nominal load from 100% to 20% of nominal (available maximum load) ¾ Momentary overspeed/frequency variation: < 4% / 2 Hz ¾ Frequency recovery time constant: < 30 sec ¾ Speed/frequency band ± 0.2% / 0.1 Hz
Mått på reglerprestanda Mått på reglerprestanda - lastfrånslag 1.08 1.07
Relative speed or frequency
Varvtal [pu] rad storhet
1.06 1.05
Momentary overspeed, So 1.04 1 03
Recovery time, Tr
Speedband, Ss
Time (sec)
Figure 9 - Definition of momentary overspeed, recovery time and speed band (illustrated during a step load decrease transient)
2
Nominal load is equal to available maximum load that is dependent on ambient conditions
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Verification tests during commissioning
Extensive testing to verify the plant’s characteristics with regard to stationary and dynamic properties in general and in particular its capabilities with respect to island operation was carried out during the plant commissioning period, autumn 2006.
House-load operation tests Switch-over from normal grid operation to house-load operation was tested by opening the 142 kV plant breaker with all GTs in operation at 90% load (40 MWe), SF not in operation and ST in operation at 56 MWe. The test was successful as ST was disconnected while GT1 and GT3 stayed in house-load operation for 1.5 hours, after which the test was interrupted. The overspeed of each of the gas turbines was below 5.3% (compare overspeed trip levels: 10%). This was expected as the SGT-800 has full load-rejection capability. Figure 10 below shows speed and power generation for the three GT´s in operation for 30 minutes after test initiation. The power generation for the two GT´s that remain in house-load operation stabilized at 1.5 and 0.9 MWe respectively after 50 minutes of house-load operation, mainly achieved by the DH pumps and feed water pumps reaching their minimum speed.
GT1/2/3 load
GT1/3 speed in house load operation
GT1/3 load in house load operation
Parameter data at time 15.07 immediately before initiation of house load test
GT2 speed
Figure 10 – GT data before and after switch-over to house load operation
CEPSI 2008/GTj page 12(15) ---------------------------------------------------------------------------------------------------------------Island operation tests A black plant incident followed by a black start-up to house-load operation could also be tested without disturbing the grid as carried out by disconnecting the plant from the external grid immediately after having stopped GT1 and ST.in operation and then starting GT1 to house load operation by using the black-start diesel generator. The intended subsequent sequences, i.e. energizing and loading the local grid, could for natural reasons not be carried out. However, simulating the response from that grid in a computer and feeding it to the plant controller, gives an opportunity to verify the requested plant island operation behavior while simultaneously being connected to a large national grid. Solvina AB and the Swedish national-grid operator Svenska Kraftnät have together designed a hardware-in-the-loop simulator called SolvSim Power Station SSPS. SSPS is a combined real-time simulator, data acquisition system and controller used for island-operation testing in Rya CHP. The test principles are shown in figure 11 below. The load transient and the islandfrequency response from the island grid are generated and calculated by the computer replacing the real power and frequency as input to the plant load/frequency controller. Hence the plant reacts as if being exposed to the load transient and island frequency although the real grid frequency is stable and the power transient does not affect the real large grid to any noticeable extent.
Figure 11 - Principle of SSPS
Testing was carried out with combinations of 1, 2 and 3 GT´s in operation, with or without ST and SF in operation, intended to mirror a real situation when the plant is in island operation from zero to full load. The island load was dependent on the number of shafts in operation but typically exposed to 1,2,3,4,5,6,7,8,10,12,14, 15, 20 and 25 MWe unit loads from 10 MWe (1 GT only in operation) up to 150 MWe (2 GT and ST in operation).
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Figure 12 below shows a typical response when two gas turbines (GT2 and GT3) only are in operation and exposed to a +10 MWe island operation step-load change (green curve). The gas turbines share load quite nicely (red and black curve) and the frequency dip is around 1.25 Hz (blue curve).
GT2 and GT3 power generation Power
Frequency
Frequency
Time (sec)
Figure 12 â&#x20AC;&#x201C; Power and frequency response in island operation mode for a +10 MW step load when two gas turbines only are in operation
Figure 13 shows results of a 20 MWe step-load reduction at the 100 MWe load level when two gas turbines and the steam turbine are in operation. Here the frequency control of the gas turbine is assisted by the steam turbine loss-of-load controller that quickly reduces the steam turbine load.
GT1 and GT3 power generation
Frequency
Power
Frequency
Steam turbine power generation Time (sec)
Figure 13 - Power and frequency response in island operation mode for a - 20 MW step-load when two gas turbines and steam turbines are in operation
CEPSI 2008/GTj page 14(15) ---------------------------------------------------------------------------------------------------------------Testing was carried out for three days; however some problems with one of the gas turbines made it appropriate for the tests to be split into two occasions. The problems encountered concerned GT1. At step-loads above 5 MWe, undamped oscillations occurred and revealed too large clearances in the main gas valve with motor control. The valve and servo were immediately replaced by Siemens and tests were repeated a few days later with consistent results comparable with GT2 and GT3. Test results are summarized in the table below. As seen, a sufficient frequency margin is received for step loads of 7 MWe for each gas turbine in operation. Operation cases with two gas turbines in operation thus can take a 14step MWe load and so forth. If the steam turbine is in operation a further step-load capability is possible. Based on the test results it was estimated that a step-load capability around 40 MWe is obtainable within the frequency requirements when all shafts are in operation. These results were well above the initial step-load capability requirements. Shafts in operation GT1
Max 3 Load 43 MWe
Step load ± 7 MWe
Frequency transient 1,8 Hz
Remark Estimated
GT2
43 MWe
± 7 MWe
1,8 Hz
Measured
GT3
43 MWe
± 7 MWe
1,7 Hz
Measured
2xGT
86 MWe
± 14 MWe
1,7 Hz
Measured
3xGT
129 MWe
± 20 MWe
1,8 Hz
Measured
2xGT+ST
130 MWe
± 20 MWe
1,3 Hz
Measured
3xGT+ST
170 MWe
±40 MWe
<2,0 Hz
Estimated
3xGT+ST+SF
265 MWe
Limited by GT max load / SF max/min load
Figure 14 - Results in summary
SF complicates the picture somewhat because attention has to be given to the maximum power generation limits of the gas turbine during load increase and the (automatic) shut-off limit of the burners during load decrease. Hence, before a planned load increase, the degree of SF has to be adjusted so that GT-load is around 70% (80% during load decrease) to allow for the subsequent highest possible gas-turbine step-load capability (based on automatic shutdown of SF at 65% GTload). Reducing the gas turbine load to 70% from a higher load in a preceding step means increasing the SF and thus increasing the steam turbine load (decreasing the SF in case of load decrease).
3
Max load refers to max gross power generation load at the current ambient conditions
CEPSI 2008/GTj page 15(15) ---------------------------------------------------------------------------------------------------------------Concluding remarks Combined-cycle solutions based on multiple gas turbines, like the Rya CHP, possess the built-in flexibility that support high part-load efficiency, extended load range and secure heat and power generation during normal operation. The high operational reliability has been verified during commercial operation up to now. Certainly, when discussing the security of heat and power supply in the event of external grid disturbances, the same arguments apply. Multiple gas turbines increase the possibility of keeping the plant in operation after an external power cut. In the same way, multiple shafts may increase the probability of successfully building up an island grid if the plant is rightly prepared for it and the operational limits are well controlled, especially if supplementary firing is in operation. Tests performed during commissioning confirmed both the expected house-load operation capability and the step-load capability in island operation. The latter was verified as being higher than 16% of the current load with GTs only in operation and being estimated up to 23% with all shafts in operation, which fulfilled the requirements by a comfortable margin. This capability was practically independent of GT load level as long as it did not approach the output limits of the gas turbines or the load limits of SF. The test method used proved also to be an effective way to discover any malfunctions in the affected equipment, in this case unacceptable clearances in the main gas valve actuator.