Determine Whether Liquid (in Gas) will Block a P/L

[SuperG]

Folks, I am working on a natural gas pipeline, which will experience liquid holdup. I am concerned that some of this liquid will travel down the pipe into a valley and eventually block the pipeline, preventing the gas from flowing...

How do I determine if this is a legitimate concern?

 

[moalarsa]

SuperG
Yes it is a main concern becaucse of many reasons the most important are
It may effect the pipeline effeciency
If this pipeline is ment for distribution it may fail the regulators installed for maintaing low pressure in the system and it may effect the gas supply to individual customer or some area and this can result into a main emergency as well. It is always a good idea to design a condensate Knock out vessels in a streap area and install some wet filters at valve asseblies and stations where you are regulating the gas flow
MOALARSA

 

[JOM]

SuperG,

Just curious - is the liquid water or hydrocarbon condensate?

If it's water you might like to read up on the natural gas pipeline explosion and fire at Carlsbad, New Mexico. Water had collected at a low point and led to severe corrosion and wall thinning.



Cheers,
John.

 

[Assumptions]

Do you have a compressor downstream?

 

[zdas04]

Natural gas always has some amount of vapor that is condensable at soil temperature. Pipeline spec tends to be around 7 lbm water/MMSCF gas. A mainline pipleine moving 100 MMSCF/day would contain 70 lbm of water - that's 8 gallons of water per day. Doesn't sound like much, but when the pipeline goes through ground water or under a river the water vapor will condense and collect in a low spot. In a month or a year the water will both block the flow to some extent and create an environment that allows for accelerated corrosion. A pipeline design and operating philosophy that doesn't account for this water has a high potential for catastrophe.

David

 

[Scipio]

I see the same thing quite a bit in the natural gas pipelines in my field. Liquid slugs in low points won't completely block flow, but it will add resistance as the gas basically bubbles through the condensate. Usually as long as you've got decent pressure on the line it's not enough to cause serious pressure losses, but on a low pressure system, say less than 100 psi, large slugs can block flow. I'd say compare the pressure of the gas to the weight of the 'tallest' leg of the liquid pocket, if the static head of liquid can't be overcome by the line pressure, you've got a problem and it's time to initiate a pigging program.

 

[chicopee]

Hi SuperG: I am somewhat at a loss how condensate can build up and collect to such a degree as to cause slugging. I do not know what the suggested gas flow velocities of gas are thru a pipe line but I would think that it has to be a couple of hundred feet per minute thus preventing condensate build up even in low spots. Secondly let's say that a 5' head of condensate was created, this is equivalent to 60 inches of water which is a small back up pressure when comparing to 100 psi (2743 inches of water) of line pressure.
The problem that I see is droplets of condensate flowing with the gas getting into station compressors. Water does not compress easily and damage to pistons and cylinder heads will occur.
I'll appreciate some comments concerning my thoughts

 

[Scipio]

chicopee,

Actually liquids can build up to significant volumes in pipelines, at least in raw natural gas gathering systems. Once you get into sales pipelines downstream of refining/upgrading it's not much of an issue. Typically a bare-bones gas well will have a two or three phase separator at the wellhead metering gas & liquid production. If the site is accessible enough and low volumes are produced, say 0.5 to 10 m3/day, the liquid is sent to a tank to be trucked out. If trucking isn't practical, the liquids are dumped back into the pipeline and sent downstream with the gas to be knocked out at a central site. Frequently to reduce hydrate and/or ice plug formation the water is tanked and the hydrocarbon condensate is sent downstream with the gas if you've got a three phase separator. Usually the liquid volumes are large enough that the liquid cannot be fully entrained into the gas flow, and settles out at low point, basically it just gets blown along the bottom of the pipe.

On sites with more process facilities, like a gas battery with dehydration facilities & compression, liquids are knocked out by an inlet separator, and further dried by scrubbers on the inlet of each compressor stage. Then, depending on the same production & accessibility issues I mentioned earlier, the liquids are either tanked for trucking out, or they're re-injected into the gas stream downstream of the compressor, usually either by a pump or blowcase.

Even if you've got no free liquid in the line however, say you've tanked all your liquids off the wellhead separator, it still wet gas, usually at a fairly high temperature - I've seen gas come out of even shallow wells above 20°C. As that gas travels down the pipeline, it cools to ground temperature, usually around 4 or 5°C here in Alberta. That cooling condenses more liquid out of the raw gas in the pipeline.

Trust me, very real problem, I've had to rebuild dehydrators and compressor skids that were destroyed due to the presence of condensate in natural gas pipelines.

 

[zdas04]

chicopee,
I design gathering lines for 36-100 ft/sec. For mainlines folks tend to use 5 psi/mile as an acceptable pressure drop. At 1,000 psig in a 30-inch line and 5 psi/mile the velocity calculates to 20 ft/sec. "A couple of hundred feet/minute" is 3.3 ft/sec which below what is known as "separator velocity" (i.e., the target velocity inside a vessel to allow separation of liquids and gases).

Water standing in a line under a river or through a bog is a very common source of corrosion and is also common as a source of liquid for slugs.

David

 

[SuperG]

Wow! That is some great information and wonderful comments...thanks everybody!

I am looking at ambient temperatures as low as 20F and I see the gas temperature gets to ambient very quickly (low flow rates). It was suggested I simply rig up for pigging every week, but I don't like to do that unless I can actually provide a quantitative reason. I am also looking at installing a knock-out vessel and separator near the top of the hill...calculations show no more liquids problems downstream of that. Then I merely truck off the liquids or build a parallel pipeline for the liquids. By the way, the pipeline leads into a processing plant.

Something else I did not realize (thanks zdas04) was separator velocities. I will have a look into what I will need for this case, but that's a matter for another time...

The bulk of the liquids are gas condensate, with some water, calculated 14.8 mole fraction at the beginning of the pipeline, then in a further separator only about 3.0.

Good idea about the static head, I'll calculate that and compare. And definitely need to consider the effects of corrosion.

Now here's something interesting...The other pipelines in the area do not consider any of these items...how is it they can operate? Now I feel like I am over-engineering this...Thanks everyone!

 

[Scipio]

Best guess as to why nobody else is considering it, they probably just know from experience what kind of problems they're going to have. In the field I work in, for instance, the majority of our individual shallow wells flow at less than 1 MMSCFD and under 200 psig, and have 3" or 4" flowlines to gathering stations. Usually we tank free water and send the condensate downstream, then inject methanol and corrosion inhibitor into the line.

If and when liquid loading becomes a problem, we either initiate a pigging program, or drop a small booster compressor on the wellhead to overcome the losses. Sometimes clearing a slug out of the line is as simple as shutting the well in for a few hours and letting the pressure build up to blow the slug down the line.

 

[SuperG]

I think that is an excellent guess. We will most likely install those features as a precaution anyway.