Questions on HRSG design 1

[threeS]

Questions on triple pressure with reheat HRSG:-

1. The material of HRSG superheater and reheater are usually T22. If change to T91, the thickness of the tube can be reduced. I think this can help to reduce the cycle fatigue. Is it correct?

2. For vertical HRSG, all headers are outside the gas path. But for horizontal HRSG, are the headers usually inside the gas path?

3. Is horizontal HRSG usually insulated internally?

4. Is top supported horizontal HRSG popular ? Top support means with a steel structure just like conventional coal fired boiler.

Can anybody help?

 

[LSThill]

Hi ericwong (Mechanical)

Need more information: Design Pressure, and Design Tempature? Operation Temp. and Pressure?

 

[threeS]

Hi Isthill

Pressure: 110kg/cm2(HP) 40kg/cm2(IP) 10kg/cm2(LP)
Temperature: 540C(HP), 560C(IP/Reheat), 200C(LP)

Are they sufficient?

 

[nambi]

2. Not all horizontal HRSGs have the headers in gas path. I have seen the Heders outside the gas path. A sepearation is made with plate along with accessories to take care that gas doen't escape. The headers are insulated externally.

3. Although it is not mandetory to insulate internally, it is only on economy part that the insulation is done internally, because the plate (material) slection (incase of external insulation) for the GT exhaust conditions will end up costing more

Atleast they insulate internally till inlet of HRSG. If a water wall is present then ofcourse u hv to insulate externally.

 

[davefitz]

1. T91 tubes will be thinner wall and marginally lighter, but can withstand a greater overheat without experiencing creep damage. They are more difficult to weld ( 400 F preheat, PWHT accuracy + - 25 F). P91 main steam line and outlet headers are much thinner ( about 48% thickness of P22 hdr at 1060 F) and thus can be started up ( main steam temp ramp rate ) can be about 4 times faster for the same amount of thermal stress and fatigue damage. P91 is recommended for desing main steam temperatures over 1000F ( ie, frame machines) but P22 is recommended below 1000 F ( aero derivative machines).

2. If the plant is a cycling merchant plant , I would highly recommend a vertical HRSG, as it has much better cycling capability without experiencig loss of tubes and piping due to fatigue damage, although it may be 20% higher first cost. For a base loaded utility unit , a horizontal HRSG may suffice.

 

[hrsgguru]

1. The use of T91, and more importantly P91, for superheater and reheater tubes and headers/piping will help increase fatigue life in the hot end of the HRSG. Reducing the wall thickness reduces the thermal stresses imposed on the system every time the unit undergoes a temperature cycle (start-up, shut-down, or maybe even a significant load change). This is but one of many items to consider when optimizing design for improved fatigue cycles.

In repsonse to davefitz's comment, the type of gas turbine doesn't influence material selection since it's the steam temperature that drives the design temp of the tube/header and not the gas turbine exhaust temp. Often on aeroderivative turbines, a duct burner is used to raise gas temps well in excess of 1500°F (815°C) anyway. And, of course, similar types of temps can be seen with duct burners on the frame machines as well.

2. For horizontal gas flow units, the headers can be somewhat isolated from the gas path with baffles, but are almost always within the casing. Since there is ideally no flow of turbine exhaust gas behind the baffles, the headers should not see temperatures in excess of the steam/water that they carry. The tube bundle headers should not be confused with the external header collection piping that join headers on larger HRSG.

3. Horizontal units are typically internally insulated (i.e., cold casing design) throughout the hot gas path - up to or near the outlet expansion joint/stack. A hot casing design with a horizontal unit is very difficult to achieve due to significant expansion problems between the support columns. A vertical unit can be more easily designed in either a cold or hot casing design. In my opinion, a hot casing design is only warranted with fuels that present corrosion problems (i.e., sulfur bearing liquid fuels).

4. Top-supported horizontal units are almost certainly required for units with tube lengths over 15 feet (5 m) or so. Industry experience with large, bottom-supported, horizontal units has been very bad. Consequently, most suppliers of horizontal units only provide top-supported designs. Most of the advantages used by suppliers of vertical gas flow units is gathered from the problems seen in bottom supported horizontal units. These days, a properly designed horizontal unit should perform as well as a vertical unit in a cycling, merchant power plant. Just make sure you carefully specify the cycle duty for the plant and ensure that the vendor's design addresses the spec.

 

[davefitz]

hrsgguru:
Truly correct that P91 use is based on the final steam temperature: if unfired, the aeroderivative final steam temp is usually below 1000F so P91 would not be justified, but if fired to over 1000F final steam temperature then P91 headers are justified , and P91 tubing is always justifiec if recieving radiant heat from a duct burner.

The qualification of " a properly desinged horizontal unit" is suitable for cycling is clear. I have yet to find suc a properly designed unit, regardless of the vendor's claims. Chronic problems in horizontal HRSG's are related to:

a) lack of tube flexibility in vertical tubes between top and bottom hdrs leads to tube stub-to header weld cracking and outright failure when tube-to-tube temperature differentials innevitably occur. The vertical HRSG's can easlily provide adequate flexibility to allow high tube to tube temp differentials. One vendor offers a desing with single row of tubes per header, with full penetration welds, but even this has limitations on allowable DT.

b) inadequate drainage capability at lower headers leads to water accumulation and water carryover to tubes due to CTG purge events or spray attemporator overspray/ lack of mixing , leading to high tube to tube temp differentials as in (a)

 

[hrsgguru]

davefitz:

I feel that we're getting a little off-track from the original questions raised by ericwong which by now have been answered.

The debate about horizontal versus vertical HRSGs could go on for days and days and still be inconclusive. Each design has its merits and each has its flaws. Some of the perceived flaws are legacy and simply don't exist in some offerings where the lessons of old have been learned.

 

[davefitz]

unfortunately, the "legacy" designs remain the standard offering for nearly all horizontal HRSG's , and it takes signifcant effort on the part of the client to ensure the spec contains specific provisions to ensure the standard offering is not going to fail at time = 1 year + 1 day.

 

[threeS]

thanks to everyone giving your valuable advice.

The HRSG I specified is triple pressure with reheat. The HP steam temperature and hot reheat temperature are around 566degC. So I think it is appropriated to specify the T91 for final superheater and reheater.

Regarding vertical or horizontal HRSG, I decided not to let the Bidders free to quote.

What do you think ?

P.S. davefitz : What do you mean about "specific provisions" for horizontal HRSG, is it provisions for cyclic loading?

 

[davefitz]

Yes, specific provisions for cycling include:

a) HP drum metal temperature monitoring thermocouples in the mid wall and near-ID to monitor the startup thermal stress, as per TRD 301 annex 1 or EN-12952-3 Annex B

b)full penetration stub -to-header welds on all headers operating above 800F

c) attemporator spray transfer pipe minimum mixing length of at least 0.15 sec transit time from spray nozzle to downstream distribution header and/or monitoring thermocouple

d)LP and IP economizer feedwater control valves located at outlet of these economizers

e)LP economizer ( preheater) to be provided with recirc pump

f)HP and IP economizers shall not share a common header ( separated by an inernal baffle)

g)flexibility of feeders from HP downcomer to HP evaporator inlet headers to be suitable for 10,000 cycles at 100 C temperature differential

h) fatigue analysis required of flexibility of all interconnecting boiler piping. In general , a HRSG designed for fast cosntruction rarely has adequate flexibility in the interconnecting piping.

 

[threeS]

davefitz:

Thanks

I agree Items a-c.

Item d: According to my knowledge, all HP, IP and LP economizer feedwater control valves are located at outlet of economizers. Why such arrangement can reduce cyclic fatigue?

I agree Items e & f

Item g: Do you refer to vertical HRSG ?

Item h: In ASME Section I, there is no requirement on fatigue analysis. Am I right? So what standard do you refer to?

In addition, I think the top supported pressure parts and casing can help reduce the cycle fatigue. Agree ?

 

[davefitz]

item d: Most horizontal HRSG's I've seen place the feedwater control valve at the inlet of the IP and HP economizer, and some actually placed the LP control valve at the inlet of the preheater. The placement of the feedwater control valve at the outlet prevents steam boiling abnd 2 phase flow unbalance and instability during startups and also full load operation, but increases cost by the addition of more relief valves. If such flow unbalances are permitted to occur, they cause fatigue damage to the tube stub-to-header weld ( zero flexibility in horizontal HRSDG's)

item g- this flexibility is required of all HRSG's. During a cold startup, the steam initially generated in the HP evaporator causes a high pressure drop in the drum separators and prevents normal water circulation down the downcomer. Instead, the hot water from the first row of evap tubes flows down the last row of evap tubes without flowing thru the drum to the downcomer. This causes a 100 C temperature difference and I have seen feeders break off due to lack of flexibility. A broken feeder will not only cause an outage; it can cause a fatality.

h) correct. It is a problem that ASME I does not contain the word "fatigue" in the entire text. The ASME I rules are generally evolved for designing large base loaded units that startup less than 1000 times in their life. The European boiler codes have had cyclic fatigue addressed since 1970. As a result, a vendor who sells a boiler designed to ASME I has complete license to make any claim he wants and to use any design method he chooses to justify his claim that the boiler is designed for cycling. In my opinion, it is better to use a technical code that is based on a negotiated consensus between vendors and users, and not rely on the "used car salesman" approach to technical claims.

 

[hrsgguru]

Item D - if the HRSG is properly designed and/or specified with an adequate approach temperature for ALL operating cases, steaming in the economizer is not an issue. Commissioning also goes smoother with the feedwater control valves located upstream. And ZERO flexibility? That is far too broad a statement to make regarding the horizontal designs. For example, the old ABB HRSG design (top supported, not bottom supported) had every bit as much flexibility as any vertical HRSG. And yes it was big pain in the you-know-what to assemble in the field. Every HRSG vendor has a different approach to tube-header joints - and some are better than others.

Item G - In the HRSGs that I have specified, purchased, installed, commissioned, and supported over the past nine years (about 20,000 MW of total combined cycle facilities), I've never seen this occur in a single, horizontal HRSG. 75% of the plants are merchant power plants that are frequently cycled through hot, warm, and cold starts.

Item H - While Section I does not address fatigue, Section VIII does and can serve as a guide to a vendor (many HRSGs are built in accordance with Section VIII particularly for oil and gas customers in states where the local Codes allow). This is one area where different vendors can definitely distinquish themselves with thorough analyses and due consideration to the project specifics. It helps if you have personnel on your side who can ensure that their analysis is relevant to your project, regardless of what technical code may be used as a basis.

I think that we need to step back from the details here a little bit and look at the bigger picture, though. We're citing all the reasons why one design might be better than another or why one design CODE might be better than another without really establishing what is really relevant. The most important item for the owner or owner's engineer to determine is the actual duty cycle and desired life for the HRSG (and plant). How many hot starts, warm starts, and cold starts are envisioned per year and for how many years of service is the plant to be designed? It is also necessary to specifically define what is meant by each start (i.e., hot start = 12 hours or a specific pressure drop in the HP section or whatever other criteria you wish to use).

You also need to specify all the operating scenarios that the unit will experience. This means complete combined cycle runs for the full range of ambient conditions for normal operating and gas turbine part-load cases. It also means cycle runs for start-up, STG bypass, shut-down, and other off-design cases. You'll also need to include cases with and without turbine inlet chilling and with and without duct firing if applicable.

If you do the analyses listed above, present this data to a reputable HRSG vendor, specify a fatigue analysis requirement, and specify a multi-year pressure part warranty (as in 48/60 month), you in return will receive a robust HRSG that will provide service in accordance with your specification. If you take short cuts, you may disappointed with the results irrespective of the HRSG's orientation (vertical or horizontal).

One other thing to keep in mind is that many HRSGs in the US market require duct burners and emissions control catalysts. Part of the reason that you don't see many vertical HRSGs in the USA is because many of the vertical HRSG vendors have little or no experience with either of these auxiliary systems.

 

[davefitz]

hrsgguru:
Almost right. Left out one big ommission.

When one actually monitors the true operating temperaure and temperature differentials of the tubes, headers, and transfer pipes during startups, purges, and trips, the actually experienced differentials have NO relationship to the assumed ( or numerically modeled ) differentials, which were the input to the designers' fatigue analysis. As a result, the designers fatigue analysis and detailed design does not adequately predict the cyclic loads imposed onthe components.

Some common examples of cyclic thermal stresses left out ( or underestimated) of these designer's ( admittedly well intentioned) models:

a) The HP downcomer to evaporator differential described before, monitored and measured during the first 10 minutes after CTG firing on a cold startup ( also- the most recent feeder failure occurred in Florida a fews years ago)

b) HP superheater and Reheater tube to tube temperature differentials in excess of 300F, related to inadequate spray header mixing length and/or lower header flooding following CTG purge ( very hot restart) with inadequate drain sizing

c)failures of tube to header welds when a set thru or partial penetration weld is used and with more than 1 row of tubes per header


d)LP preheater or economizer tube to tube temperature differentials during startups ( following zull demand for feedwater if LP drum swells, subsequently followed by slug feding of feedwater) in cases where the LP feedwater flow control valve is at the inlet and no recirc pump provided. Steaming of the economizer, 2 phase flow unbalance and flow mal distribution resulting in repeated, high tube to tube temperature differntials.

IN a sense, the standard method of designing a HRSG from behind a desk represents a sort of circular logic- if one assumes certain operating scenarios and designs for those assumptions, one can justify the design in a conversation, but that is no guarantee that it will work in practice. The design operating assumptions need to be confirmed and compared to in-situ field measurements of prior operating similar boilers to confirm all assumptins are valid- in particular , the standard simulatin programs do not predict any of the above issues, yet they occur just as sure as the sun comes up each morning.