Dew Point temperature of Natural Gas

L

Thread Starter

Lucky

At site we are having 2 GE frame 9E machines of dual firing capability. Natural gas and Napatha.

During natural gas operation, to heat it, we are using Indirect bath heaters(IDBH). it consumes around 1000 SCM of gas per day to raise the temperature of the gas flow (32000 SCM/hr @ ~28 Bar) from 32 deg C to 42 deg C during summer. My guess is Dew point temperature (DPT) of natural gas will be below the 0 deg C. i have discussed the same with our operation team but no body is agreeing to stop it (IDBH). their point is condensate MAY form. unlike 9FA. i guess 9E do not have any pre-request for Natural gas temperature at its inlet.

Natural gas composition (% Mole Fraction) - CH4- 93.4%, C2H6- 1.86%, C3H8 - 1.60%, Isobutane- 0.32, n-butane- 0.45, Isopentane- 0.13, CO2- 1.38, N2- 0.13, Sulfur- NIL.

i have googled but nowhere i found any formula(s) or any method to calculate the DPT of Natural gas (of different compositions) at different temperature and pressure.

Looking forward for help from the members to save natural resources.
 
Lucky,

I would imagine the turbines at your site have DLN-I combustors, because that's usually the only reason for heating natural gas--to prevent condensation of natural gas liquids which can lead to primary zone re-ignitions which means emissions can't be minimized because the turbine won't remain in Premix Steady-state.

Some turbines use natural gas heaters to actually improve turbine heat rate (cold gas actually requires some energy to heat it up which means some of the gas is used just to heat the gas). But, it doesn't sound like this is the case.

I have only seen dew point temperatures listed on natural gas test results--performed by a testing laboratory. Dew point is dew point, and by that I mean that it's the temperature of the gas at which condensates begin to form--whether that gas is air or natural gas. I'm not sure how one would test for that at site without specialized equipment. And, it depends a LOT on where the gas comes from. Some wells and sources have more entrained natural gas moisture than others. If your site burns LNG which can come from any of a number of sources around the world at any time this is much more important--preventing natural gas liquids from condensing.

I have been to a couple of sites which did NOT have DLN-I combustors where the local natural gas was known to have a very high moisture content and the dew point of the natural gas was not very much higher than the gas temperature. In those cases, natural gas heaters were used to prevent liquids from condensing and collecting in low points of the gas fuel system piping which, when a sufficient volume had collected, would be pushed along very suddenly into the combustors and cause high load spikes and in some cases exhaust overtemperature trips.

So, based on the information provided it's not really clear exactly why your site uses ("requires") natural gas heaters.

If you have a recent natural gas analysis report from a reputable testing laboratory that shows the dew point of the natural gas you are now burning has at least 50 deg F of superheat, then I believe it would be possible to shut down the gas heaters--but I would suggest you confirm that with the packager of the gas turbines (GE or BHEL or ???). But, if your natural gas source changes or can change with very little notice, then it is incumbent on you to be very diligent in getting an analysis of the gas--either from a testing laboratory or from the natural gas supplier (sometimes they have this information) and review the operation of the natural gas heaters.

In my experience, most machines which burn naphtha are required to start up and shut down on another fuel (natural gas, for example) and then transfer to naphtha at either FSNL (rated speed) or at some low load. When starting on natural gas, there are lots of high pressure drops across the gas valves which can lead to condensation of natural gas liquids which is not good for the turbine if they eventually make their way into the combustors (again, resulting in load spikes, or speed increases during acceleration, but certainly exhaust temperature spikes and possible trips--but mostly, just high thermal stresses which are not good for hot gas path parts life).

I don't believe you can determine dew point (or superheat) from natural gas constituents--but if you have the constituents in some report <i>for the natural gas you are currently burning</i> then you likely have the dew point value on that same report--or the natural gas superheat value (which is kind of a dew point measurement).

Also, you should find some information about required natural gas superheat temperature in Sect. 05.02.nn of the Control Specification document provided with the turbine and auxiliaries. If it's not in that document, it's recommended you ask the turbine packager to be sure of the requirement for your site. It's <i>usually</i> 50 deg F, but it could be different for your site, or GE may have changed that value in recent years.

Please write back to let us know how you fare in your endeavour to save then environment.
 
you have exceptional dry gas, in you case C3 drops out first, so condensation is not an issue for the temperature ranges you are concerned with..

preheat the gas as the first responder indicated.
you can calculate dew point using the usual real gas models (Redlich-Kwong, etc.) or get actual tests, but neither will protect, if pipe line feed changes and that is the concern.
 
Swoosh... control members are very quick.

Sir, We do not have DLN combustors at site for GE 9E machines, we use DM water to minimize emissions.

As you correctly said, we are not using the heaters for performance improvement.

We have different sources for gas (but not using LNG) but before it reaches us, it will go through different filtration Processes. But we use to receives condensate once in a while as we have around 200 KM of dedicated line for our plant but the quantity increases during pigging process (pipeline cleaning through PIGS).

We have been operating from last 15 years, but we never faces problem due to condensate on GT. And the Gross Calorific value varies from 9500 kcal/scm to 9800 kcal/scm (in rare cases it has crossed 10,000kcal/scm also).

I’ll check with GE CPM for requirement of gas heaters.

Regarding startup, yes we also use either HSD or Natural gas for Naphtha start up. Regarding pressure drop, during normal operation our supplier receives gas at 34 bar and then control valve at their skid reduce it to 28 bar for our plant. Does it lead to that condensation that you are talking??

In report nowhere natural gas superheat value is mentioned. (apart from compositions, only Compressibility factor -0.9972, Specific gravity – 0.654, GVC and NCV at ISO6976 are specified) .
I have also gone through the gas specification document, but nothing regarding required superheat temperature is mentioned. And you described it will be nearer to 50 degF but at what pressure?

If any other data is required regarding this I’m ready to provide.
 
> you have exceptional dry gas, in your case C3 drops out first, so condensation
> is not an issue for the temperature ranges you are concerned with.

you said condensation is not an issue in my case by seeing the C3 content, but how?

and on what basis you are stating it is a dry gas?

please do reply.
 
The condensation point is calculated on the basis of your stated molar composition. That composition is extremely dry, since the components (in this case C3) only drop out at cryogenic temperatures.

As you pointed out, you stated composition is not what the combustors see.

Condensation is estimated using real gas laws, knowing the gas composition and the vapor pressures of possible condensibles.

By the way the %mole do not add up, do you have other gases present? renormalizing produces a gravity of 0.60 not the 0.65 you quote.
 
Hereby i am providing details from one more report of the NG, % Mole composition -
CH4- 90.04, C2H6- 3.99%, C3H8 - 2.21%, Isobutane- 0.41, n-butane- 0.57, Isopentane- 0.19,n-pentane- 0.17, hexanes- 0.34, CO2- 1.87, N2- 0.21, Sulfur- NIL.
Compressibility factor -0.9972, Specific gravity – 0.654, GVC- 9825.3 kcal/sm3 and NCV- 8876.5 at ISO-6976.

Earlier i have mixed up two reports, that's why Specific gravity might not be matching.

you said "Condensation is estimated using real gas laws, knowing the gas composition and the vapor pressures of possible condensibles" - but from where to get the vapor pressures at different temp and pressures?
and how did you calculate S.Gravity and approx condensation point??

and please guide me to calculate at least rough DPT for the above said composition at 33 degC and 28 bar...
and thanks for showing interest and guiding me...
 
basic stoichiometry

you'll have to consult text books to get started. Some portions of the calculation and fluid/gas properties are covered in various material property and chemical engineering handbooks.

even if you perform the calculations for you own use, in order to safely alter the operating condition of your GT, I recommend that you consult the manufacturer of the machine. More than a few calculations are involved.

Don't forget aspiring engineers have been fired for convincing the boss of a beneficial improvement that cost millions to repair.
 
the S.G. for the revised composition is 0.64.

the GCV and NCV can be calculated in similar fashion, but I have not done that.

The increase in C3 lowers the DP somewhat, but insignificant given the non-cryogenic operating temperatures you've specified.

In any event get you GT manufacturer involved, as they designed your system.
 
Hi CSA,

I could able to locate the Superheat requirement details document for Natural gas. it has formulas to calculate, Superheat temperature.

i have worked out and arrived @25bar (Gas pressure at turbine control system) -
Hydrocarbon superheat requirement to avoid condensation = 21.5 degF or -6 degC
Moisture Superheat requirement to avoid Moisture formation = 15 deg F or -11 deg C.

Superheat is the temperature difference between the gas temperature and the respective dew point.

Document also gives the Hydrocarbon dew point break point of -25deg F for 500 psia or less pressure. but the point is that formula has only one input that is pressure and no where they are considering gas composition.

can you please share your thoughts on this.

regards
 
Coutesy of CSA:

"If you have "a recent natural gas analysis report from a reputable testing laboratory" that shows the dew point of the natural gas you are now burning has at least 50 deg F of superheat, then I believe it would be possible to shut down the gas heaters--but I would suggest you confirm that with the packager of the gas turbines (GE or BHEL or ???). But, if your natural gas source changes or can change with very little notice, then it is incumbent on you to be very diligent in getting an analysis of the gas--either from a testing laboratory or from the natural gas supplier (sometimes they have this information) and review the operation of the natural gas heaters."

Hope your "Luck" doesn't run out, you'll need it.
 
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