Table: Performance of HRSGs designed with different pinch points

item	Unfired  A	Fired A	Unfired B	Fired B
gas flow,lb/h	150,000	150,000	150,000	150,000
temp to HRSG,F	900	1086	900	1062
temp to eco,F	407	419	388	393
exit gas,F	332	329	309	302
gas pr drop,in wc	4.2	4.6	5.4	5.8
steam flow,lb/h	22,107	30,000	22,985	30,000
water to eco,F	351	337	352	340
burner,MM B/h	0	8.1	0	6.9
pinch point,F	41	53	22	27
approach point,F	15	29	14	26
surf area,evap,ft2	13,227	13,227	16,534	16,534
surf area,eco,ft2	5948	5948	8922	8922

Analysis
Let the cost of fuel=$2.7/MM Btu(LHV basis),cost of steam=$3/1000 lb and cost of electricity=5cents/kwh. Assume 8000 hours of operation per year with 4000 hours in unfired mode and 4000 in fired mode.Also,let 4 additional inches of gas pressure drop across the HRSG be equivalent to 1.1 % drop in the gas turbine output,which is 4500 kw nominal(information on the power output and the reduction in power output due to higher gas pressure drop is obtained from the gas turbine supplier.Those interested in similar evaluations should obtain these data.)
Design B has the following operating cost differential compared to design A :
Due to higher steam generation in the unfired mode: (22,985-22,107)x3x4000/1000=$ 10,536
Due to lower fuel consumption in fired mode:(8.1-6.9)x2.7x4000=$12,960
Due to higher gas pressure drop of 1.2 in wc: 1.1x(1.2/4)x4500x0.05x8000/100=-$5940
Hence the net benefit of going with design B is:$(10,536+12,960-5940)=$ 17,556 per year in terms of operating costs. If the additional cost of design B is say $ 30,000,then the payback is less than 2 years,which is attractive. It is the author's opinion that these additional costs due to lower pinch and approach points are often not that signifcant when compared to the overall HRSG costs including the cost of drums,controls,instrumentation,burner,casing,auxilliary equipment etc.Hence in the long run it pays to go with  low pinch point design or a more efficient unit.Unfortunately several consultants do not pay much attention to operating costs and often go by initial investment only,which hurts the plant owners in the long run! A 5 to 15 % increase in inital investment to lower the stack temperature may well be worth the effort.. 
Consider Secondary Heat Recovery Surfaces
This again may be applied to single or multiple pressure HRSGs.One may consider secondary heat recovery surfaces such as condensate heater,deaerator coil or a heat exchanger system as shown in the figure above,which will help lower the HRSG exit gas temperature.
Heat Exchanger to preheat make up water
In this method,as shown in scheme a above,a heat exchanger is used to lower the feed water temperature to the economizer by preheating the make up water entering the deaerator. In  gas fired systems,which have little residual sulfur in the fuel,the limitation is the water dew point,which is on the order of 120-140 F depending on the % volume of water vapor in the exhaust gases.One should note that the feed water temperature should not be lower than the dew point of any acid vapor or water vapor to preclude corrosion concerns.Hence this method is suitable if the gas turbine or the HRSG is fired with natural gas only with no sulfur compounds.Also,the amount of make up water should be signifcant else the amount of energy recovered in the exchanger will be less,making it an uneconomical proposition.A simple evaluation as done earlier can determine the payback period. Note also that in these schemes a,b and c, the steam generation in the HRSG is not being increased;in schemes a and c as the make up water enters the deaerator at a higher temperature,the steam required for deaeration will be lesser,thus increasing the net steam output and the overall plant efficiency,while in scheme b,the deaeration steam generated will reduce any additional steam consumption in the deaerator.
Deaerator coil generating steam for deaeration
In this scheme b shown above,a deaerator coil is used to recover additional energy from the exhaust gases. The low pressure steam thus generated(on the order of 5 to 25 psig) is used for deaeration.Again,the deaeration steam required for the system will have to be significant to make this option economically feasible.Since the tube wall temperature is above the saturation temperature corresponding to the deaerator pressure(230 to 280 F),there are no corrosion concerns even with oil firing.The deaerator pressure may be raised slightly if necessary to increase the saturation temperature if the sulfuric acid dew point is higher. However the exit gas temperature can be lowered to only the saturation temperature plus the pinch point,while in scheme a and c the gas temperature can be lowered much below the saturation temperature of the deaerator steam.The surface area required for this scheme will be quite large as the log-mean-temperature difference is small. Also,the cost of this option is also high considering that it is a (low pressure)steam generator and requires a drum,controls,piping,safety valves,instruments etc.
Condensate heater to preheat the make up water
In this option,an exchanger (similar to an economizer) is used to preheat the make up water before it enters the deaerator,thus lowering the deaeration steam requirements.The make up water temperature entering the exchanger,the quantity impact the efficiency of this system.The tube wall temperatures will be quite low as the make up is often at 80 to 120 F.Hence one should be wary of corrosion concerns inside and outside the tubes as the tube wall temperatures will run well below the dew points of water vapor as well of  any acid vapors present. The tubes may be made of stainless or high alloy materials to alleviate these concerns.Condensing exchangers made of corrosion resistant materials may also be considered.The surface area required for this option will be quite small due to the high log-mean temperature temperature difference arising out of the low make up water inlet temperature.
Optimizing HRSG temperature profiles
By relocating surfaces such as superheaters,evaporators and economizers,particularly in multiple pressure units,one can strive to lower the exit gas temperature and thus improve the HRSG efficiency.  See the article on Optimizing HRSG temperature profiles using Simulation methods.
 Supplementary firing
As discussed in another article on generating steam efficiently,supplementary firing improves the efficiency of energy recovery. All the  fuel   fired goes into steam generation.Hence while planning cogeneration projects,it is worth considering fired units versus unfired units if more steam is required at present or in upcoming years.As discussed in the article on Efficient generation of steam generating additional steam in the HRSG makes more sense than generating it in steam generators.

In conclusion,consultants and plant engineers should spend considerable time in evaluating various options such as those discussed above and should not be deterred by initial costs. Operating costs,payback,life cycle costs,future steam demands etc must be studied.I have seen several specifications put out by consultants/engineers which are several inches thick and  having a lot of irrelevant information and hardly a page on steam parameters or evaluation of operating costs!! Then there was also a smart consultant who did not want to consider an economizer for his HRSG as he felt that there were cost overruns and they could exceed the budget limits!
Plant engineers and end users should challenge the studies performed by consultants/engineers and be more involved if the project is to be successful. The consultant/engineer walks away from the project after the contract is awarded but the end user or the plant owner lives with the HRSG for the next 15-30 years!

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