Look at the GPSA Engineering Data Book, Figure 20-3. If you need the answer to your question for work, then you need to buy a copy of GPSA--there isn't a better reference book for the Oil & Gas business.
Morten, David, and Monagas are giving you some sound advice and counseling. If you are doing any work with and on natural gas you should have the latest editions of the GPSA and John Campbell’s books and information. Both exist in state-of-the-art electronic versions. Campbell has now electronic volumes that furnish you with the software to work the problems with ease and speed. Both can be obtained through the Internet and are reasonably priced – for the information they contain.
With regards to the water content of natural gas, for many years Smith Industries of Houston, TX (now Hanover) supplied invaluable data design data in their manuals and catalogs. One of their famous saturated water vapor in natural gas graphs has made it into an EPA PDF document that is worthwhile obtaining for that and other reasons as well. You can find the curves on page 20 of “Replacing Glycol dehydrators with desiccant dehydrators” which is found at:
That is an interesting EPA document. I've never seen deliquescent driers called "desiccant dehydrators" before. Usually the term "desiccant" is reserved for things in the mole sieve family.
The problem that they fail to mention is that the salt disolves at an alarming rate when pressures get low (I'm seeing gathering-system pressures all over the world well under the 50# where the Smith Chart stops). When you are trying to dry 2,000-4,000 lbm/MMCF gas to 7 lbm/MMCF you find that you need truckloads of replacement salt. Since (according to the document) one lbm of salt removes 3 lbm of moisture, a 1 MMCF/d stream with 2,000 lbm/MMCF of water would consume 600 lbm of salt/day to get to 7 lbm/MMCF. You have to pick your locations pretty carefully.
As usual, by making a posting interesting to you, it has succeeded in drawing out even more excellent, free consulting observations and comments from you. As a service to other interested engineers you’ve correctly identified the price behind the “carrot” being offered by EPA. Nothing comes cheap or easy – much less field natural gas dehydration problems. As you astutely note: “You have to pick your locations pretty carefully”. You also have to consider what is applicable in your application – and the consequences.
I inserted my post not only because it answered the request for a database on natural gas water content, but also because it touched on what could be a need for field dehydration. If so, the issue of alternates to TEG units has come up more and more in the last two or three years. The EPA employs the use of the term “desiccant” in the generic sense. Molecular Sieves, Activated Alumina, and Silica Gel (unlike the deliquescent chemicals like Calcium and Lithium Chloride) fall into the category of adsorbent desiccants. The adsorbents rely mainly on van der Waal surface forces to attract and hold on to water molecules. The deliquescent family employs the ability to hydrate themselves (thereby consuming the water vapor humidity in the natural gas) and form a liquid brine – thereby changing physical state. The adsorbents can be regenerated in-situ; the deliquescents can’t be salvaged for re-use without exorbitant expense and operation – therefore, they have to be collected as brine slurry and disposed of on a batch basis.
In order to comply with P/L specs of 7 lbm/MMCF and utilize the low-capital, simple application of deliquescent chemicals, one has to start out – as you correctly imply – with a substantial process pressure in order to reduce the amount of water existing in the feed gas. Here, it should also be noted that the higher (> 500 psig) pressure is not sufficient in itself; a “lower than normal” line temperature is also required. Note that if your line temperature is higher than 50 oF, you pretty well have an application that can’t be applied. This, of course, means that EPA is assuming that 50 oF (or lower) gas is available at the well head – which is not the usual case.
Without the availability of site operators and common utilities like electricity, the dehydration of well head gas has a difficult task in replacing the TEG system with either the adsorption process or the deliquescent dryers. Additionally, there are safety concerns involving the opening and closing of pressure vessels on a routine basis for the purpose of replacing (or “making up”) Calcium Chloride. The safe and efficient venting and disposal of natural gas as well as the sluggish and corrosive brine is of some concern. “Bridging” of the chemical pellet beds is common in some installations and plugging of lines can occur if not designed or operated correctly.
As always, the inherent remoteness and natural pressure decline of a natural gas well are characteristics requiring ingenuity and resourcefulness in order to maintain successful safe operation in the field
Thanks for the kind comments. I've never been able to make a salt dryer work for a full well stream at low pressures. On the other hand, fuel-gas freezes are the number one cause of compressor down time during the winter in climates that support freezing. I've successfully used them in fuel-gas service, but never for full-stream in low pressures.
One of my clients is working on an inventive approach to reducing the amount of salt that is consumed in a fuel gas applications. This device (patent pending) uses a Ranke Hilsche Vortex tube and runs the cold side into the salt dryer. The hot side (and the lion's share of the water) goes back to the compressor suction scrubber. My calculations show that this should reduce the amount of salt consumed to about 1/4 for a better quality fuel gas (when you go from saturated at 60F to 40F the amount of water the gas can carry to the salt dryer goes way down, all the liquid that condenses is thrown to the hot side and out).
Salt dryers have a definate place, but I'm not sure the EPA report communicates where that place is. For many reasons, full-stream dehydration below about 150 psig is an outrageously expensive proposition.
The equation given by you could be of great help. But where, whom, how, or what reference(s) does it carry? Is it a general relationship for natural gas (NG) with a specific gravity of 0.6? Or does it apply to heavier natural gases? Does it apply to NG at any pressure?
Could you give us some background, basis, or origin in order to place some degree of credibility and accuracy on its results? Otherwise, how can we engineers offer this relationship as a credible solution to a client/employer? Equations are useless for serious application without the proper identification of origin, derivation, basis, or references.
That relationship has been posted in these fora several times. I've compared it to GPSA 20-3 and at 100F and 14.73 psia the empirical equation is 32% high because it is a semi-log straight line and the data has a definate curve to it. I've developed an equation that matches GPSA within 2% over the whole range, but I don't share it, and it is a BUNCH more complex than the one provided above. At 500 psig and 80F the equation above matches GPSA within 16%.
If you want easy, then there are a bunch of semi-log straight lines out there.
That is a very well worded comment on answers we give. Often, we forget that while we know the source of the answer, other readers do not. Star to you for the reminder.
"Do not worry about your problems with mathematics, I assure you mine are far greater."
Albert Einstein
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