Replies to This Discussion

Permalink Reply by jffree1 on August 10, 2011 at 4:25

Tracie, this is a layman's definition but Choke refers to a mechanical device placed in the flow line to restrict and control the flow of gas.  It is usually expressed in 64ths of an inch on fixed chokes or it can be a decimal value on adjustable chokes.  A 64/64 choke would be full open flow.

As to the effects on production rates... basically, the smaller the choke... the less gas produced but it will flow at higher pressure.  Opening the choke reduces the flowing pressure.  There are as many schools of thought as to the best way to flow a shale well as there are operators, I imagine, but generally they are mostly using a "smallish" choke (less than 20/64), initially, where in the beginning of the play it was fairly common to see shale wells with 24/64 or larger choke.  Some of these wells are so over-pressured that they have to be flowed on a bigger choke until the pressures come down a little and then they are choked down some more. 

To you gas guys... sorry if I didn't get that exactly right but I gave it my best shot.

Permalink Reply by Skip Peel - Mineral Consultant on August 10, 2011 at 4:32

Good explanation, jffree1.  Accurate and stated so as to be understandable for a layman.

Permalink Reply by Craig Wascom on August 10, 2011 at 5:39

Now here is what may be a really dumb question. Do they choke oil wells?

Permalink Reply by jffree1 on August 10, 2011 at 6:19

The short answer is yes, they do.

Permalink Reply by Les Bamburg on August 10, 2011 at 9:40

Jffree, that more standard approach for the Haynesville Shale are choke sizes of 20/64" to 26/64" while the "restricted" choke size is generally in the 14/64" to 16/64" range.

 

Normally choke sizes are increased (opened) over time until flowing pressure reaches line pressure (~ 1000 psi).  I assume the operator would decrease the choke size initially when a well is dropped into a lower pressure gathering system (~ 300 to 500 psi).

 

Most natural gas wells are produced initially on choke to avoid damaging the formation and/or downhole and surface equipment.  Chokes can be located on the wellhead or in the flow line upstream of the production separator.

Permalink Reply by jffree1 on August 10, 2011 at 14:51

Thanks, Les.  I've been told that some operators flow on a bigger choke initially with the more over pressured wells and then choke them back some after the first two or three weeks or so.  Others, in the south counties, are sticking to the restricted choke range from the get go, it appears.  I guess when we have enough production data over time down here we will be able to see who has the best plan (or the best rock?).

Permalink Reply by Les Bamburg on August 10, 2011 at 16:27

Jffree, generally EnCana, Shell, Exco & Chesapeake are using the traditional approach while Petrohawk, Questar & Crimson are following the more restricted choke practice. 

Permalink Reply by Karen Perry Kent on August 13, 2011 at 9:38

Thanks, this helped me understand this process.

Permalink Reply by Tracie Wolfford on August 10, 2011 at 16:09

Thank you. I love this site and can always count on jffree1 for my answers.

Permalink Reply by Steve on August 7, 2013 at 6:07

What does the well operator look for to determine when a choke size should be increased or decreased in a producing oil well - rate of oil dump? What does the well's production equipment(seperators or whatever) tell them that says you can increase the choke size? Goodrich stated in a Q&A today that they listen to the well?

Permalink Reply by jffree1 on August 28, 2013 at 6:44

Steve,

Once again from a laymans understanding... oil wells behave a bit differently than a dry gas well. Some will flow from formation pressure, for awhile, and others will require some sort of artificial lifting mechanism, the most familiar being a pump jack, right from the getgo. It is not uncommon to see an oil well, or one flowing lots of condensate, operating on a fairly large or full open choke but with low flowing pressure (compared to a high pressure gas well). But, the idea is to maintain, at least, the minimum flowing pressure required by the gathering system, if there is one, or flow into a holding tank and if the formation pressure is not high enough to do that then a pump will have to be used to lift the oil. Lack of pressure and an open choke doesn't mean no oil can be produced... just that an artificial means will have to be used to overcome the lack of formation pressure. Each well will behave a bit differently (but within an expected "norm" for the field) & will decline in flow rate & pressure, over time, and I think that is what they mean by "listen(ing) to the well".

 

 

Permalink Reply by Steve on August 28, 2013 at 7:57

Thanks for that explanation. We are watching the flow rates on wells in the TMS and see that the operators are opening chokes  in increments from 14/64 to 28/64 within a few weeks of initial flow test - then at some point within a month or so they decide to install artificial lifts. To the west and south(in the Feliciana Parishes) of where the current Amite and Wilkinson County wells are being drilled, the formation is deeper -13.5 to15k ft. and should have more gas/be more overpressurized. Some are wondering whether the additional depth and higher gas pressure could have a significant impact on flow rates and EURS, assuming the oil is there in similar  quantities as in the East TMS?  Goodrich said, after looking at the Devon logs, they didn't see much change in geology throughout the TMS. Any opinions?

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