|The cogeneration plant at the Porto refinery in Portugal|
CHP installations are often associated with industrial process and so any failure at the plant can be a commercial disaster for the owners if they have to cease production as a result. However, with a more sophisticated set up it is possible to continue to operate seamlessly, even in the event of an unexpected gas turbine trip, explains Stef Verhagen of NEM Energy bv.
Cogeneration of electrical power and steam saves energy and can be optimized for availability and reliability. It is probably the most suitable solution for refineries and chemical plants, where typical needs for this kind of plant are electrical power together with intermediate pressure (IP) steam (15″20 barg) and optional high pressure (HP) steam (>60 barg). This must be delivered with both high availability and reliability, too.
A typical cogeneration plant consists of a gas turbine (GT) with an electric generator and a heat recovery steam generator (HRSG) that runs on the heat from the turbine exhaust gas (TEG).
Even if a plant only requires intermediate-pressure steam, it is generally more efficient to produce high-pressure steam with the exhaust gas from the gas turbine. This high-pressure steam is then used to drive a back-pressure steam turbine (ST) which reduces the HP to IP. This is typically used for producing electricity, in addition to that of the gas turbine-generator combination, or providing mechanical energy, for example for compressors. In a typical case, the back pressure steam turbine is non-condensing and the IP steam downstream is used as process steam.
Since an uninterrupted heat and power supply is vital for most chemical plants and refineries, back-up capacity is required in case of an unexpected shut-down or maintenance outages. Ultimately, a shortage of steam in particular could shut down processes, resulting in substantial financial losses and it is obvious that back-up facilities for power and steam are installed in most cases.
Back-up capacity for power and steam may be provided by extra units, but less costly alternatives are possible through the optimization of the existing cogeneration installation.
|Figure 1. Cogeneration installation with a steam turbine, bypass stack, FA fan, post firing burners and a flying take-over assembly|
The most extensive type of cogeneration plant configuration is shown in Figure 1, in which a number of additional components have been added to the basic configuration of a GT plus HRSG only.
|Figure 2. Detail of the steam turbine model|
In this more sophisticated set up there is a bypass stack with diverter or louvre dampers. The diverter damper is a typically a blade arrangement below the bypass stack, which allows the inlet to the HRSG to be closed.
This enables standalone operation of the GT, also called single or simple cycle mode. The louvre dampers are large multi blade valves at the inlet of the HRSG and inlet to the bypass stack. The functionality of diverters and louvered dampers is the same, but some characteristics, such as opening and closing speed, are different.
In addition, there are facilities for post-combustion firing. By post-firing, the temperature of the exhaust gas leaving the gas turbine can be increased before entering the HRSG. In this way steam production can be increased independently of turbine output. Post-combustion firing is also known as supplementary firing, in the case where the HRSG is operating in gas turbine mode, or auxiliary firing in cases where the HRSG is operating with fresh air. By allowing steam production to be increased while electricity production is decreased, post-firing gives for more operational flexibility.
|Figure 3. Gas turbine start-up curve for exhaust gas flow and temperature|
Similarly, a fresh air (FA) fan, together with the burner of the post-firing facility, also called fresh-air firing, allows the HRSG to be operated even when the GT is not. In general, operating in FA mode results in higher NOx emissions as its production depends largely on the oxygen concentration of the combustion air. Fresh air contains approximately 20.95% oxygen, while GT exhaust gas has 12″15%. However, depending on the time of operation, temporarily increasing NOx emissions may be acceptable and where they are not, they can be reduced with additional equipment.
|Figure 4. HRSG start-up curve for steam flow, pressure and temperature|
Another more advanced capability is a rapid speed of reaction. Fast moving dampers on the bypass and boiler inlet, together with a fresh-air fan which can quickly come on-line, allows the HRSG to switch over to fresh-air firing without any interruption of the steam supply, even in the event of gas turbine trip.
The configuration of the unit shown in Figure 1 is one in which the reliability and availability are optimized. In case of a gas turbine shut down, steam production by the HRSG can be continued using the FA fan and post-firing. In the case of an HRSG shutdown, the fall in steam production can be partly or fully compensated for by other units, with post-firing on a high output. Using this set up means full backup capacity can be reached, but sometimes a lower back-up capacity is sufficient to continue the main plant processes in the event of a failure.
Changing modes of HRSG operation
With a suitable configuration the HRSG can be changed from GT operation (also called turbine exhaust gas (TEG) mode) to fresh air operation (FA mode) and vice versa without interrupting steam supply. This means that the steam conditions (pressure, temperature, flow) will remain within the given boundary values during the change-over, as well as return to initial conditions within a given time frame. Various change-over modes exist: manually initiated change-over from TEG mode to FA mode and back or automatic change-over from TEG mode to FA mode in the case of an emergency GT shutdown, either because of GT or generator failure or external causes, such as a failure of the electricity grid.
Automatic change-over from TEG mode to FA mode in the event of an unexpected shut down of the GT is the most challenging. This change-over mode is also called a flying take-over, or FTO. In this case the GT flow and exhaust temperature decrease very rapidly, almost step wise.
After a GT trip signal, the FA fan is started. After approximately ten seconds its discharge pressure then high enough to open the fan discharge valve, also called the fan discharge damper. Immediately after this, the HRSG inlet damper is closed and the bypass stack damper is opened. The combustion air supply to the HRSG will change from Turbine Exhaust Gas (TEG) with a temperature of 500″600à‚°C to ambient fresh air. This rapid reduction is compensated for by supplementary firing. Such a change-over process requires a rapidly responding, stable and very reliable control system, in particular to manage the steam temperature which is determined by the temperature of the gases entering the HRSG and the flow rate of attemperation water. Normally, the steam temperature shall be within à‚±20à‚°C of the required steam temperature. In stable operation this is not a problem, but during change-overs it is clearly a challenge.
To compensate for the immediate heat reduction a rapid increase in the burner thermal output is required.
During the transition, until the HRSG inlet damper is fully closed and the FA fan is at full load, not all the required combustion air is necessarily available, leading to a fuel rich inlet mixture.
Without sufficient measures, this may result in excessively high flue gas temperature.
A further complicating factor is the location of the post-firing arrangement, which is installed within the inlet duct of the HRSG. Without a properly designed flow distribution grid, the flow distribution within the inlet duct is not uniform. In such a case, a local deficiency of combustion air may result in localized peak temperatures.
To ensure a stable combustion process, sufficient combustion air flow should be supplied at all times. The Burner Management System monitors the duct pressure continuously, as well as other parameters, such as the position of the HRSG inlet damper, the bypass stack damper and the running speed of the FA fan. These parameters are used to decide whether a change-over can be initiated safely and to confirm that a change-over has been successful.
As change-overs involve dynamic processes, it is very helpful that dynamic simulations are done which take the effects of the rapid transition into consideration.
Using dynamic simulation
To secure rapid change-over processes and flexibility and reliability, advanced engineering tools have been developed. Their main purpose is to verify and optimize operating scenarios and equipment designs. For example, NEM’s Dynamic Simulation (NDS) software can model the complete HRSG with auxiliaries and control characteristics. With dynamic simulation it is possible, for instance, to check that steam properties stay within allowable limits (Figure 2).
|Figure 5. Results of the functional test of the Flying Take-Over ” gas turbine trip at 4:16:30 pm|
Figure 4 shows one example of the various simulations and calculations of the HRSG start that can be done by the dynamic simulation model.
The input data for the cold HRSG start is the gas turbine curve, Figure 3, which shows the full turbine exhaust gas mass flow is reached after 17 minutes and max outlet temperature after 27 minutes.
In Figure 4, it can be seen that stable steam conditions are reached after 30 minutes. It is obvious that the shape of the curves depends on the type of HRSG and the actual control system. Figure 4 shows a Benson-type HRSG.
For FTO modelling, equipment in the exhaust gas system has been extensively modelled in the NDS, including multi-louvre dampers and FA fan discharge dampers with pressure-flow characteristics.
Other elements featured in the model are the pressure-flow characteristics and acceleration behaviour of the FA fan and the start-up sequence and time delays for igniters, pilot burners and groups of burner rods, load ramps for the supplementary firing system.
For the calculation of heat transfer and water/steam side pressure drop, the HRSG model includes all essential pressure parts and equipment such as heat transfer surfaces, circulation systems, drums, headers and steam piping as well as pump pressure-flow characteristics and efficiency and control valve pressure-flow characteristics as a function of opening and travelling time.
Dynamic simulations have proven to be useful to model, design and optimize change-over processes, resulting in rapid, reliable procedures and the avoidance of problem solving and tuning of controls during commissioning.
The flying take-over process has been optimized by such a dynamic simulation and offers high reliability and availability for critical processes, while significantly reducing the requirements for backup capacity.
Dynamic simulation at the Porto refinery
One of NEM’s projects encompasses two HRSGs, each downstream of a GE frame 6B gas turbine.
The arrangement is equipped with an FA fan, supplementary firing and bypass stack. The installation was supplied to the EPC contractor Efacec and is located on the Porto refinery in Portugal.
The CHP plant’s key data are:
- Supplier: NEM Energy bv
- Number of HRSGs: 2
- Gas turbine: GE type frame 6B
- Steam conditions: 66 barg, 450à‚°C
- Max. continuous rating steam load: 130 t/h, both in TEG and FA mode
- Peak load: 143 t/h, both in TEG and FA mode
The main purpose of the simulation was to prove the capability of the designed control system to keep the steam conditions during the change-over modes within a bandwidth of +2 to -5 bar and +5 to -15à‚°C of the normal operational values. Another purpose was to optimize the HRSG and its components for the various change-over modes. During the engineering of the project the NDS software was applied to reach the targets. The simulations proved that the final design was able to meet the requirements.
After commissioning was finalized the change-over modes were tested in order to determine whether the requirements for the steam conditions were indeed met. The results of the flying take-over test are shown in Figure 5. At 4:16:30 h the gas turbine is shut down, as shown by the blue load curve dropping to 0 MW. One minute after the gas turbine shut down, steam production reaches the lowest point (69 t/h) but recovers in the following one and a half minutes.
The steam temperature drops 2à‚°C and the steam pressure drops about 1.5 bar. The process supported by the cogen installation will not be disturbed at all though, since the steam-supply system always has some natural storage capacity.
Performing the tests confirmed that the change-over modes were performing well and that both during and after, all steam parameters met requirements.
The author would like to acknowledge both GALP and EFACEC.
Stef Verhagen, Project Lead Engineer, NEM Energy bv, The Netherlands. www.nem-group.com