Gas Hydrate Concern -- Need real world experience 1

[processeng2014]

Hi all,

I was wondering if anyone could weigh in on the subject of "when do hydrates REALLY become a problem". I need real world experience with gas production to balance what ProMax is predicting for hydrate formation.

I am currently studying a gas pipeline which will be transporting about 5 MMCSCFD (12,750 lb/hr) at lower velocities (5-20 ft/s) underground for about 10 miles. The ground temperature is expected to reach 60 F, and ProMax is giving warnings about hydrate formation being reached around 67 F.

There is about 20 lb/hr of water entering the pipeline with the gas, so even if this does "freeze", will it really make a difference in actual operation? Will the hydrates necessary plug the pipeline or can the be entrained and moved with the flowing liquid? Do some operators "roll the dice" and see if a problem exists before deciding to inject methanol?

Thanks

 

[zdas04]

Hydrate prediction is far more dependent on pressure that assumed ground temperature. You didn't say what pressure you were planning to operate at.

I see hydrate problems in surface manifolds and in roadbore casings with double vents. Rarely see hydrates form in pipe buried in dirt.

Is the water entering the line in liquid form (doesn't participate in hydrate formation) or as water vapor (which would equate to about 96 lbm/MMSCF which is consistent with fully saturated methane at 67F and 150 psia).

I've seen office engineers specify prophylactic methanol injection, but I've never seen anyone who has ever seen a field install it. Methanol is horrible stuff (the MSDS sheet gives me nightmares) and injecting it because of some simulation is reasonably irresponsible. Beyond that, I've never seen it work. We inject it into places where injection is convenient and it accumulates in the first low point.

David Simpson, PE
MuleShoe Engineering

Law is the common force organized to act as an obstacle of injustice Frédéric Bastiat

 

[MortenA]

David,

I take it that you dont have experience from the North Sea? Here injection of MeOH is quite common. We operate several satellite platforms where the LG sometimes may not be dry and the we inject MeOH - and if we dont then we get hydrate and they DO plug up the LG pipline or annulus (or both or wthatever). 5 MMSCFD is not a lot - i think it might be along our LG consumtion rates but im not sure. Our LG lines are around 4" and the pressure in the 140-150 barg ande and the line is exposed to sea water. We dont inject it when its water dry only when its not (that would depend on which compressors are avaiable). And i dont think our operation is that uncommon.

Continious inject in multiphase tiebacks tends to go toward MEG because its easier to recover.

What do you mean by "Is the water entering the line in liquid form (doesn't participate in hydrate formation)"? While hydrate formation can take place in any phase - as long as there is water and light alkens or co2 - free water tends to promote hydrate formation and is generally considered nescessary for hydrate formation as far as i know? I believe that kinetics is important as to why hydares often is less of a problems that what models predicts and the fact the properties of the hydrates e.g. their tendency to aglomerate depends very much on the operating conditions.

Best regards, Morten

 

[zdas04]

When Amoco was drilling Thunder (nee Crazy) Horse in the Gulf I got involved in the Flow Assurance (I think every ME in the company did to some extent, we were pretty scared about the possibilities), but never in the North Sea. My point of view is reasonably low pressure onshore gas. Methanol injection in my world has been quite the disaster. I understand that that there are places where it is vital. MEG and TEG injection have been better, but still not terribly effective.

The thermodynamics of hydrate formation requires that the matrix (water) be in gaseous form. Liquid water will tend to kill the reaction (but is rarely 100% effective at killing it). The reason that people see hydrates in the presence of liquid water in places like the North Sea and Deep Gulf is that the hydrates form from the in situ water vapor and partially block lines which causes a big dP that accelerates evaporation and the newly evaporated water forms hydrates (and leaves behind phase change scale) that feeds the problem. Without the trip event the liquid would stay liquid and would freeze based on the steam tables as long as there is an adequate heat sink to remove the latent heat.

David Simpson, PE
MuleShoe Engineering

Law is the common force organized to act as an obstacle of injustice Frédéric Bastiat

 

[MortenA]

Interesting, never heard that before. Quoting fra D. Sloan, Hydrate engineering (SPE Monograph vol. 21 (2000)) sec 2.2 "Three condtions promote hydrate formation in processes. 1. Free water and natural gas components must be present.... The water in hydrates can come from free water produced from the reservoir or from water condensed by cooling the hydrocarbon fluid..."

But i guess that the process that you describe is hard to distguish from _not_ having free water since it seem to me what you are saying is that the neuleation of the hydrate takes place in the gas phase but that the gas must be close to water saturation (normally this will also mean that there is a liquid water phase prensent)?

Dr. D. Sloan (from the Colorado school of mines) is usually considered quite knowledgeable about these things and have among other things received the Katz award (GPA) for his work in this field.

Best regards, Morten

 

[zdas04]

I'd never question Dr. Sloan or his qualifications. There is obviously something here that I'm missing.

I went back and my sources (primarily a 1980's vintage course from the company that became JM Campbell). The formation of clathrate hydrates requires a super-saturation of the target gas relative to the matrix species. In a gas/water-vapor system this is the normal case, and introducing saturated or sub-saturated liquid water would tend to kill the reaction.

To get hydrate formation in liquid water, the water had to be saturated with dissolved target gas at a much higher pressure/temperature than is experienced at the hydrate-formation point. This makes perfect sense for hydrate formation to occur in liquid water in a deep, subsea, high pressure reservoir.

What I missed was that the requirement is for super-saturation, not a requirement for water vapor.

David Simpson, PE
MuleShoe Engineering

Law is the common force organized to act as an obstacle of injustice Frédéric Bastiat

 

[BigInch]

High pressures 400+ psi and cool temperatures <40F favor hydrate formation. Underground pipelines (especially low pressure gathering systems with buried pipelines) in moderate climates don't have the same problems, as the North Sea with high pressure pipelines and very cold water temperatures. Liquid water certainly helps hydrates form, but I believe liquid water is not necessary for the process. In south Texas, we only had hydrates freeze us up during very cold spells, < 30F for several days, and usually only at the well head to pipeline connections above ground.

Learn from the mistakes of others. You don't have time to make them all yourself.

 

[dcasto]

Go to Dr Sloans site for all the info and software on hydrates

http://hydrates.mines.edu/CHR/Home.html

400psig and under 40f? Now about hydrates at 900 and 75 F. Yes sir. Composition is the other important part of the equation.

Zdas, I've never seen teg injection, teg in mixers and staged contractors and then removed immediately because it gets to viscous to move below 50 degrees. Not picking, just clarifying.

BTW, I was one of Dr Sloans first students at Mines.

 

[zdas04]

In the conventional gas in Farmington one of the plant operators asked us to stop using methanol (this was a particularly nasty winter in the early 1990's) and start using TEG because they were having problems in their inlet dehys. Not sure what the problems were or why they specified TEG to solve them.

David Simpson, PE
MuleShoe Engineering

Law is the common force organized to act as an obstacle of injustice Frédéric Bastiat

 

[dcasto]

I'll tell you the problem one company is having with methanol. Up on the Canadian border when ambient temps are running -25F, the gas is flowing because of methanol. However, the liquids recovered from the gas are off spec because of methanol in them. Ooooopppps. They now need a ethylene glycol wash system then distill the methanol from the EG.

 

[zdas04]

Sometimes you have to wonder if the solution is really better than the problem.

I did a HAZWOPER course once where the mock incident we did was a large Methanol spill. First thing was pull out the MSDS sheet on methanol. What nightmare stuff that is. Lethal in small doses, causes organ cancer from skin contact, causes blindness on contact, several different ways to kill a person. And we carry buckets of it in the back of our trucks. I have nightmares about that mock incident 15 years later. Companies that have requirements to lock-out/tag-out locations and wear a full face shield to gauge a water tank allow people to carry open buckets of methanol and just pour it on a freeze. I'm not understanding the whole "it is more important to have a policy than to think about what we do" culture.

David Simpson, PE
MuleShoe Engineering

Law is the common force organized to act as an obstacle of injustice Frédéric Bastiat

 

[BigInch]

Just giving one possible point on a curve.
With higher pressures, higher formation temperatures are possible.

Learn from the mistakes of others. You don't have time to make them all yourself.

 

[MortenA]

BTW i dont disagree that MeOH is nasty stuff tht you would rather be without. I once did some engineering for a pharceutical plant: They used MeOH everywhere as a solvent and a reactant - and many of their reactor drained directly to the floor and then to a common drain header (inside buildings), That was a nightmare wrt. to fire since MeOH burns in very dilute concentrations with a colourfree flame... Of course IR will detect it but never the less.

 

[LittleInch]

The ultimate answer to the original question "when do hydrates REALLY become a problem" is that it becomes a problem if they actually block your line and turn your cash register off, not to mention the costs of hydrate plug remediation efforts. When you start to work close to what I term the hydrate formation "zone" is that the number of variables which act to decide whether one line plugs and the other doesn't is quite large - water content, degree of kinematic turbulence, start stop activities and of course pressure and temp.

I'm sure some companies if you are in the border zone just see what happens as many predictions of temperature, pressure and hydrates err on the side of caution. Some hydrate formation in the initial stages can appear like "slush" - I recall some surface laid lines in the desert where the operators were reporting "slugging", but only between 1 am and 5am - we worked out that the winter temperatures were enough to get in the hydrate zone but clearly not quite enough to cause a blockage. Then the sun came up and all was well again....

For your case I would recommend that you advise the client that the operation is very close to or within the hydrate formation zone and a risk of hydrate formation exists at the proposed operating temperature and pressure. Then it is up to them as to whether this well is important enough to spend the money to include an injection skid, but an injection point would seem a good idea at the manifold...

My motto: Learn something new every day

Also: There's usually a good reason why everyone does it that way