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Permalink Reply by Robert Duke on December 17, 2010 at 7:03

Thanks Frank, good additional info.  I was sort of wondering why a device like this had not yet been put into play, as it allows you to fine-tune to the production you want.

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Permalink Reply by Les Bamburg on December 17, 2010 at 7:12

Robert, most operators would not attempt to fine-tune production from the hundreds of individual wells.  Instead they would monitor daily production and determine the appropriate time to increase the choke size.

Permalink Reply by Jack Blake on December 15, 2010 at 13:08

HS wells flow hot ( at least the couple Jack has touched), in fact many have coolers  on the well site to reduce the temp of the gas prior to it going through the sales meter. 

I've encountered situations where it may take a day or two to calibrate an adjustable choke and have the software working so you could see the choke size on a screen, but even in this scenario I (and everyone I know) would guestimate the size in 64th of an inch.  You would not record the choke size in a percentage form.

Chokes are always refered to and discussed in 64ths of an inch. The denominator is always 64 when talking chokes.

I tell you what is hard for Jack to get wrapped up in his mind is that with these HS wells you flow them thru the casing for the first few months and then run the production tubing.  Having the smaller diameter tubing increases velocity and therefore keeps the well producing where the well would waterlog if you kept flowing it thru the larger diameter casing. I learned this on GHS and it kind of makes sense to me, but I need to get a Petroleum Engineer to discuss this with me a bit more to completely understand it. 

One of the big differences between HS wells and the Gulf of Mexico wells Jack works with is in the GOM wells you always run the production tubing before producing the well, no matter how great the pressure you do not flow it out of the casing.  Maybe it is because of rig mobe / demob costs.  Jack don't know.

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Permalink Reply by Robert Duke on December 15, 2010 at 13:25

Hmmm, okay.  Thanks much for the info Jack.  The whole water thing has me a little puzzled overall.  I have read that "conventional" wells, not in shale, will waterlog with time, and that various things are done to keep that from happening, but most folks here seem to think that the bulk of water you see in the HS wells is backflow of frac fluid, and if you see a lot at first, it might indicate lower frac success.  I've still seen DT-1's, say a year out, producing water, though, so who the heck knows.  Anyway, good to understand the coil tube a bit better.  I am also gathering that your dual choke comment (freezup problem) is only applicable to the shallower verticals you mostly work on then.

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Permalink Reply by Les Bamburg on December 15, 2010 at 17:26

Robert, it depends on the reservoir.  Some gas reservoirs are depletion drive and never produce significant water.  Other wells will either water out in water drive reservoirs or load-up in partial water drive.

 

Frac water flowback rates decrease with time but will continue for the life of the well.

 

By the way, the production tubing installed in wells is not "coiled tubing" but rather just straight joints of screwed pipe.

 

Freeze-up issues happen with high pressure flowing wells that have a lower reservoir temperature than the Haynesville Shale.  That is the reason some wells require a line heater. 

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Permalink Reply by Robert Duke on December 15, 2010 at 20:33

Hi Les,

Thanks for additional info; starting to get a picture.  I thought I had seen the term "coiled tubing" somewhere, but a straight tube certainly makes more sense if you are trying to accelerate the gas flow to keep the water moving out.  Also, if the "production tube" standard is 2 3/8 inch, per below, then we get a more realistic view of the amount of choking being done, and how much you can let off - so "wide open" must correspond to around 152/64th's - means a typical choke down around 20/64th is only about 1.7% "open" in terms of the production tube cross section.  Interesting.

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Permalink Reply by Les Bamburg on December 16, 2010 at 3:44

Robert, a coiled tubing unit is equipment brought in temporarily to perform certain operations on a well such as drilling out plugs between frac intervals.

 

http://en.wikipedia.org/wiki/Coiled_tubing

 

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Permalink Reply by Robert Duke on December 16, 2010 at 6:10

Ah ha! Got it.  They both come in at the end of drilling/fracing, but one earlier than the other.  Thanks much.  The wiki article was indeed helpful.  It looks like wikipedia is making an effort to improve energy and energy tech coverage; something folks here that are in the industry might want to make a note of and keep track of to insure it does not get heavily politicized.

Permalink Reply by Les Bamburg on December 15, 2010 at 17:19

Jack, I believe the production tubing may cause an issue in 1st week or two when flowing back high volumes of frac water plus excess proppant.  The high flowing pressure can handle the lower velocity of flowing thru production casing without loading up.  After the well cleans up and water rate drops then the operator can install the production tubing (typically 2&3/8).

 

By the way, which areas have you worked?  I put production facilities in South Pelto, Ship Shoal, Eugene Island & West Cameron. 

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Permalink Reply by Jack Blake on December 16, 2010 at 11:04

I've worked east of there- South Timbalier, West Delta & Main Pass fields.

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Permalink Reply by Les Bamburg on December 16, 2010 at 13:24

Jack, I had a co-worker that installed production facilities in the Main Pass 73 area but I never made it that far east.

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Permalink Reply by Jack Blake on December 16, 2010 at 15:02

Back in the day I did time at MP-69.

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