8 replies to this topic

[kloroform]

hi all, 

 

i have an assignment for my practical work in a gas company. i should make a study about gas dehydration. i am a student, but this is a real problem. so maybe it is better if i post this in "industrial professional" section. i am sorry if this is not appropriate.

 

 

 

In the dry gas field (98% methane), water content shall be reduced to 7 lb/mmscfd from the natural gas before it is delivered to the buyer. gas analysis is routinely made, sample point is just around 1 kilometer from the buyer, from water contet from gas analysis result is 20 lb/mmscfd ( using ASTM D 5454-11 at 14,7 psia and 60F). in the processing facility, it is only separators and  compressor. the gas that will be dried in the gas processing facility, is at 110 F and 400 psia (downstream compressor and upstream separator)

 

1.

i have a confusion to decide the amount of water that shall be removed in gas dehydration unit (glycol dehydration unit). the example from GPSA book section 20 states that in inlet gas water content to absorber  is taken from Mcketta and Wehe Graph (fig 20-4). if I use the same method, water content in inlet gas  is around 100 lb/mmscfd (at 120 F and 450 psia), but the water content from gas analysis is 20 lb/mmscfd.

 

if i want to design glycol contactor, which one that i have to use as water content in gas inlet ? 20 or 100 lb/mmscfd ? because it will make big difference in glycol contactor design

 

i think i will take 20 lb/mmscfd as the water content  in gas inlet, but what is the function that graph ? just to make a prediction of gas ability to "hold" the water vapor ? but why GPSA design by using  Mcketta and Wehe Graph in the inlet gas water content

 

 

 

2. 

there is a reciprocating compressor in the gas processing facility, P suction is 400 psia, P Discharge 400 psia. T suction is 110 F and T discharge is 138 F. which on one is better ? to install gas dehydration unit in upstream or downstream of reciprocating compressor ? henry's law states that gas solubility is higher if partial pressure is bigger, so i guess it is better in the upstream of the compressor , but as far as i remember, the absorption is also better in the lower temperature . 

 

 

3.

is it possible to make water vapor removal by modifying the separator or scrubber, i mean by adding demister in the separator or scrubber ? it is impossible because droplet size is above 10 micron. am i wrong ?

 

thanks in advance

Edited by kloroform, 03 March 2015 - 04:58 AM.

[serra]

produced gas is normally saturated with water, that (saturated gas) is a common spec.,
Mcketta and Wehe chart (also called water dew point chart) at a given temperature and pressure allows to determine the saturated water content of gas,
alternatives to Mcketta and Wehe chart are procedures such as ISO 18453
(available in software as Prode) which allow to solve accurately phase equilibria for natural gas + water,
if there are points not well defined you should discuss the specs also considering different aspects, for example pressure and flow at wellhead generally declines over time and you may be required to optimize design and glycol circulation rates for different conditions,
there could be also additional requirements, for example in Europe we have limits for methane emissions etc. which may require to adopt electric pumps etc. etc.

In this group there are experts as Art who has provided Excel pages and many examples in previous threads...

[kloroform]

Serra,

 

Thanks for your respond

[ankur2061]

kloroform,

 

Pointwise response to your query:

 

1. For water content of natural gas refer the link below:

http://www.cheresour...ge-2#entry44003

 

2. Where is the reciprocating compressor located? What does it do? The water carrying capacity of natural gas increases with pressure. If the idea is to remove larger quantities of water from high pressure gas than the dehydration unit would be installed downstream of the high pressure gas compressor. Normally a bulk gas-liquid separator is provided downstream of the gas compressor and upstream of the TEG hydration unit to remove bulk water and heavier hydrocarbon liquids before feeding to the TEG dehydration. The design of the TEG unit can be done taking credit for the bulk separator and considering the feed to the TEG dehydration unit as bulk-liquid free.

 

3. Water removal from separators also depends on the design of the internals such as type of inlet device, and liquid de-entrainment devices such as demisters, vane packs and cyclones. A lot of design related to special internal devices is proprietary in nature. However, guidelines are available for certain common de-entrainment devices in the GPSA Engineering handbook.

 

Hope this helps.

 

Regards,

Ankur

[Art Montemayor]

I believe there is a typo error in Ankur's #2 response.  The water carrying capacity of natural gas DECREASES (not increases) with pressure.  That is why TEG contactors always are located at the highest pressure level in a process.

 

There are tons of information on the process in our archives and this is accessible through our SEARCH engine.

[Zauberberg]

I remember one case similar to yours, where actual water content of gas was significantly less than what you would normally have at saturation conditions.

 

We had water-saturated stream at compressor suction (14 bara, 5 degC) and after compression to 36 bara and cooling to 45 degC (summer design case) there was no liquid water dropout since the calculated dew point at 36 bara and 45 degC was around 17-18 degC. Thus the water content remained unchanged after compression and cooling - it is just relative humidity that has changed.

 

You are basically asking if you should consider water content at compressor discharge conditions (and at 100% water saturation), or not. To answer that question you need to address the following:

 

1) Are the compressor suction conditions likely to change anytime in future? Is there a chance that water content of the suction gas will increase in future? If yes, make sure you consider the most conservative case.

 

2) Is any other stream going to feed the separator downstream of the compressor, and contribute to increasing water content of the mixed gas feeding the TEG Absorber? If yes, or if you are not sure, make sure you include some appropriate margin in the design.

 

Based on my experience, going for the most conservative case does not result in proportional increase in project cost. Absorber dimensions (diameter) will be determined based on the gas flow (not water content) so in both cases you will end up with Absorber of the same diameter. Only the Absorber height may change because higher water content of the inlet gas calls for taller structured packing (or higher TEG circulation rate, or both). So the only difference will be in size of the regeneration skids which is essentially determined by the glycol circulation rate.

[RockDock]

I would also add that high pressure sampling of natural gas can be tricky. Water content would vary greatly depending on the quality of the sample.

 

I would design it with for the 100 lb/MMSCF case. I would also do some ProMax runs to see what the impact would be if I decreased it to 20 lb/MMSCF. Your TEG circulation rate would go down. That would not impact the equipment much at all. I would just check my lean/rich exchanger, pumps and Gas/Liquid ratio in my columns. If they fall within specs, then your design can handle both cases. If not, see what the minimum TEG circulation rate would be to meet the equipment specs.

 

Additionally, you may take the approach of designing the system for 20 lb/MMSCF and seeing how much stripping gas you would need to be in spec with a 100 lb/MMSCF feed. Perhaps you just increase the circulation rate by 10% and introduce stripping gas. I would run the ProMax scenario tool to evaluate all those options.

[kloroform]

dear all, thanks for your informative responds

i want to ask the basic concept of water content determination, just to make sure  whether i have already understood or not. i hope you don't mind to help me again

 

i want to simplify the gas processing, into this location categories :

 

 

sweet gas 98% methane, sweet gas.

 

a. (Gas From Wellhead). let say it is 600 psia and 200F. at this point the maximum water content (according to Mcketta Wehe chart) is 700 lb/mmscfd. gas from the well is saturated with water, it means the relative humidity, RH = 100%

 

b. (gas processing facility). after going through separator and compressor, the gas condition before leaving gas processing facility is at 110 F and 400 psia. at this condition. the maximum water content (according to Mcketta Wehe chart) is 120 lb/mmscfd .

 

c. (at buyer). after leaving gas processing facility, the natural gas will be delivered to buyer in the pipeline along 65 kilometer. the gas analysis is done at 1 km before the gas is received by the buyer. at this point the gas condition is 360 psia and 80 F. according to mcketta and wehe chart, the maximum water content is 75 lb/mmscfd

 

my questions are :

 

1. how much water is actually at point b ? is the gas is still saturated with water ? i think it is still  120 lb.  or will it be less than 120 g  ? if the amount of water is less than 120 g, why this happened ?

 

2. at point c, the actual water amount is 13 lb/mmscfd. it means the RH is (13/75 = 17%), why  the RH is not 100%. because the of demister in the separator and scrubber ? or what ? . the water condensation amount in the pipeline is just (120-75 = 45 lb). is in't it ?

 

3. is it possible to demister to reduce water vapour amont in the gas ? or it just for free liquid ?

 

4. how do i find the reference to design reflux condenser still column in the TEG regenerator ? i can't find it in GPSA section 20 "dehydration". could you give recommended book ?

 

i am sorry if i repeat my questions, because i still don't get it. i hope you dont mind to enlighten me more. thanks in advance

Edited by kloroform, 04 March 2015 - 10:36 PM.

[RockDock]

This all really depends on the plant and the location of the dehydration unit. The gas will be 100% saturated with water until that point. Most plants have a spec of 3-7 lb/MMSCF for sales gas. I don't know what exactly is going on in your scenario at the gas processing point. Usually that means the gas is being fractionated into C1, C2, C3, ect... Your gas is already 98% methane. Perhaps you have some simple JT process to remove some of the remaining heavy ends...

 

I would expect the dehydration unit to be up stream of that to avoid hydrates and take advantage of the higher pressure.

 

The reflux condenser is just a coil at the top of the regenerator. The tube side is the rich glycol before the flash tank. The process side is the water vapor exiting the regenerator. When liquid forms, it just falls back into the column. There is not much to the design. You just want to maintain a temperature such that you have a small amount of reflux.