The right technical approach is essential for winning an EPC contract, and sometimes it pays to be innovative.
Figure 1. Enelpower’s experience in the Gulf region includes the Jebel Ali K2 power and desalination plant, photo courtesy of Siemens.
Providing a certain specified target of water and power production from a plant for a client is a complex task. Investigations into the possible configurations that the plant may assume and the number and type of machines that your competitors may adopt start as soon as the tender documents arrive.
It is not easy to find an optimized configuration that allows an EPC contractor on the one hand to fit in with the customer’s requirement and on the other hand to win the contract for developing the plant.
Figure 2. Barka operating plant parameters: net power vs net water production operation diagram
In the last three years Enelpower has been a successful EPC contractor in the Gulf area. Beyond Barka and Ras Laffan, plants like Yanbu 4 (Saudi Arabia) and Jebel Ali K2 (UAE) are also in the company’s backlog.
Tender documents are sometimes full of technical details, so few aspects are left to the contractor’s ingenuity. Documents may also be lighter, describing general operating scenarios and main constraints, and giving targets. The Barka plant in Oman belongs to the latter case, and the technical knowledge and the experience of the EPC contractor could be exploited to the maximum extent.
Barka’s tender documents’ main requirements can be summarized as follows:
•Power island with a guaranteed net power output of 400-440 MW, a minimum of three power units, a design ambient temperature of 50°C, relative humidity 100 per cent, combined or simple cycle GT, dual fuel capability.
•Desalination island capacity of 3800 m3/h guaranteed net water output, with a minimum of three desalination units.
- unconstrained operation over the full range of ambient conditions
- full water production over the range of electrical outputs down to a minimum of 30 per cent of guaranteed net power output
- simple cycle operation of the gas turbine units in the event of HRSG outage, trip or start-up
- each desalination unit fully dispatchable between 60 per cent and 100 per cent of its net design output
- net power output with outage of the largest desalination unit
- full water production with outage of the largest power unit
- full water production and 50 per cent of net power output with outage of one gas turbine.
Enelpower chose the following plant architecture:
- Two gas turbines with dual fuel capacity
- Two HRSGs with supplementary firing, bypass stacks and exhaust stacks
- One condensing-extraction steam turbine
- Desalination island with three Multiple Stage Flash Evaporators
- A feedwater deareator and supply system
- Condensing system for steam flowing in the low pressure (LP) section of steam turbine using seawater from a common intake for phases 1 and 2.
The capacity of each gas turbine is 120 MW. The use of an evaporative cooler at the gas turbine inlet would increase power output and improve the plant heat rate. Each HRSG is a single pressure, natural circulation type. The duct burner is natural gas firing.
Figure 3. Barka exhaust gas cooling diagram
The steam turbine, with a maximum output of 220 MW, is divided into two sections: the high pressure (HP) stage – with an uncontrolled bleeding that feeds the medium pressure (MP) header and a controlled extraction that feeds the LP header – and one single flow LP section with axial exhaust.
In design conditions the steam turbine inlet parameters are 77 bar abs and 541°C. The steam turbine is operated in sliding pressure mode between the nominal admission pressure (80 bar abs) and a minimum pressure of 50 bar abs. The controlled bleeding has a constant pressure due to the minimum pressure required from the MSFEs and it supplies steam slightly superheated.
The HP section is sized for the full steam capacity of the two HRSGs with supplementary firing operated at full load. The LP section can accept the difference between the HP outlet and the controlled blending in design conditions, resulting in an LP design flow of approximately 40 per cent of the HP one. In case of an MSFE trip the LP section is able to accept five per cent of additional flow at the same inlet pressure, the remaining LP steam flow is discharged through an LP bypass to the condenser. With this approach the full power capacity is achieved when one desalination unit is out of service.
In Barka, the real winning point was the skill used to limit the number of the gas turbines in compliance with the client’s requirements. The goal was to try to choose a configuration having one gas turbine less than those in competitors’ proposals, using a higher size of gas turbine set.
This choice resulted in the installation of a water/steam cycle with a gross power output almost equal to that produced by the gas turbines altogether.
As a consequence this brought us to an ‘obliged choice’, a sensible power plant cost reduction. If the power is only produced by the gas turbine sets, the cost of a plant is directly proportional to the installed power. On the other hand, where the power is produced through a steam/water cycle the cost is influenced by the scale effect. In other words, the steam turbine set and the associated plant, 150 MW in size, does not cost 50 per cent more than a 100 MW size unit, but 20-30 per cent more.
The possibility to install two gas turbines instead of three had several economic advantages.
A steam/water cycle with a larger size does not introduce further technical complications but those connected to its own size. The installation of the supplementary firing system in this kind of plant is practically a must and its sizing slightly affects its costs. Attention has to be paid to the exhaust gas temperature downstream the burner grid that, in order to avoid HRSG design complications, should be limited to 800-820°C.
Likewise, the reduction of gas turbine numbers may increase the constraints due to off-design case operation. In the case of Barka the installation of a fresh air firing system was necessary to guarantee a total net power output not less than 50 per cent, with simultaneous 100 per cent water production in case of one gas turbine being off-line.
Beyond a first appearance, the presence of a broad thermal input in the supplementary firing system, necessary where the water/steam cycle provides 50 per cent of the total power output does not worsen the combined cycle efficiency. This occurs mainly in cogeneration plants where more than 50 per cent of the produced steam is extracted for desalination.
Theoretically, the energy supplied in an intermediate point of the thermodynamic cycle drives to a poor overall combined cycle efficiency but several factors have to be considered, including the condensate return temperature. The temperature of the condensate return, in the case of cogeneration for desalination, is usually rather high. In any case, considering the environmental conditions, the condensation pressure is usually rather high too, and so, also after the mixing of different streams, the condensate temperature remains high, making heat recovery difficult in the lower part of the gas turbine exhaust gas path.
Further, the application of a supplementary firing system makes the installation of a second pressure level in the HRSG economically inconvenient. So the exhaust gases to the stacks are high in mass flow and have a temperature of 140-150°C.
With this arrangement, the combined cycles have a rather poor efficiency compared with a non-cogen combined cycle plant. Consequently, any worsening introduced by the heat supplied in the bottoming cycle has a lower impact.
The possibility of steam condensation gives great flexibility to this kind of plant where combined power and water production occurs because it allows separation of the two products’ generation.
Theoretically, the energy discharge to the condenser represents an energy loss. It has to be avoided where possible.
A larger size water/steam cycle means a larger HP steam production and it also means also a larger steam flow rate to the condenser. So condensation occurs not only for flexibility improvement, but for power production too.
The low pressure (LP) steam turbine has been sized for the steam flow rate foreseen at 100 per cent MCR, practically without margins (LP control valve fully opened) exploiting maximum efficiency at that load. The utilization index of the Barka complex foresees that water production is always higher than power output. No scenario is foreseen in which continuous full power production occurs with desalination at part load. Thus, any distiller trip is managed via the opening of an LP bypass from the LP steam header directly to the steam turbine condenser.
Main steam parameters
Where the conventional power plant sees the HP steam turbine inlet parameters as a sizing point, the cogen plant, associated with desalination facility, has its key point in the parameters of the steam sent to the distillers.
The steam turbine extraction should be around 2.7 bar abs and 133-134°C. This is the HP turbine expansion line end point (ELEP). The HP inlet parameters (P and T) are the direct consequence of the expansion curve of the steam turbine itself. The designer of the plant starts from the HP ELEP and comes back up to the right point.
But what is the right point? It depends on the steam turbine power output target, on the steam turbine typology that can be applied, on how much steam may be sent to condensation without large adverse effect on the cost. The two parameters (P and T), married by the steam expansion line, may have different and sometimes contradictory, effects on the associated items.
At Barka, steam parameters have been chosen as 77 bar abs and 541°C, because they allow:
- The choice of a certain type of axial exhaust LP steam turbine
- The choice of an HP steam turbine with stop and control inlet valve directly installed on the machine
- A sufficiently low exhaust gas temperature
- A steam flow rate to the condenser coherent with the incremental cost of the cooling water system.
A closer look should be given to the steam parameters whenever operating load and environmental conditions may lead these parameters falling not on the curve and especially on the left side of the steam turbine design expansion line. For instance, when a plant is operating at maximum load but at different ambient conditions the exhaust gas flow rate from the gas turbines is higher than the plant design point, but it is colder. In this condition the required steam production is easily fulfilled with supplementary firing thermal input smaller than the designed one; this way the steam pressure linked to the steam flow rate is fine, while the steam temperature may not be. The consequence is a different starting point of the expansion line that may drive to 2.7 bar steam without a proper superheated condition.
In a cogen steam/water cycle used for desalination, with post firing installation, the superheater steam temperature is fundamental. It is related to the expansion requirement of the HP turbine. The supplementary firing system is usually located in the divergent duct in front of the HRSG.
This arrangement has a very easy layout, it is cheap, but has the drawback that the superheater steam temperature is strongly correlated with the supplementary firing thermal input. When the supplementary firing load decreases without being necessarily followed by HRSG steam production, the superheater steam temperature goes down. Where a supplementary firing system out service is used, the superheater temperature drop may be so high that it could at one side induce a dangerous quick cooling effect on piping or at the other side create dangerous distortion in the main piping connection to the HP steam header when other HRSGs are feeding steam at the rated value.
Other critical situations may happen when the electrical load is low but with full water production; consequently the HRSG steam production is high and achieved with high supplementary firing thermal input. The superheater surface excess may bring to the superheater spray water attemporation higher than ten per cent, giving perturbation in the steam circulation in the superheater tube bundles.
Bearing this in mind, and considering that the use of supplementary firing allows the choice of the final superheater steam temperature to be made independent of the gas turbine exhaust gas temperature, a profound study of superheater tube bundle arrangement seems justified.
To get rid of such problems, the following tube arrangement was made at Barka: a small superheater upstream of the burner grid. This may help to maintain constant the superheater temperature when the HRSG steaming load is very high, but the supplementary firing thermal input is far from 100 per cent. In the case of a lower exhaust gas flow rate, and possibly even cold, with very high thermal input in the burners, this small superheater is unaffecting the heat exchange and has the effect of improving the superheater temperature control of the attemporating spray water system.
The HRSG tail
Also the last part of the HRSH, exhaust gas wise, has its own importance. Cooling down the exhaust gas at its maximum practical extent improves considerably the global efficiency of the combined cycle.
At Barka, the condition with full power production and desalination facility at part load is not considered a continuative operating point, so the condensate return temperature is foreseen always around 95-100°C. A pressurized deaerator was chosen. It has a minimum operating pressure of 1.2 bar. This may be increased to maintain its operating temperature 10°C higher than condensate return or, with the gas turbines fed by diesel oil, to have the HRSG feedwater temperature over the exhaust gas acid dew point temperature. The stripping steam comes from the LP steam header, at MCR load, but at electric part load, with burner thermal input also low, the energy still available in the exhaust gases may be exploited, re-circulating water throughout HP Eco back to the deaerating tower where it flashes.
This system has quite a good effect on cycle efficiency and it is applicable where the heat, required by degassing purpose, is limited because the re-circulated HP feed water is at 100 bar pressure and its flashing may be easily managed with small flow rates.
The possibility given by a vacuum deaerator consists in a large heat recovery capability in the HRSG tail, provided that operating cases foresee scenarios with very low condensate return temperature associated with part load of the supplementary firing system. The HP Eco re-circulation application results, in this case, higher in cost and more complicated.