Replies to This Discussion

Permalink Reply by Les Bamburg on July 3, 2011 at 3:40

Parkdota, an operator's projected decline curve incorporates their planned adjustment of the choke size as a well depletes.

 

For example, a well may initially have a flowing pressure of 7500 psi but this will decline (along with the flow rate).  As this flowing pressure approaches line pressure (~ 1000 psi) the operator would gradually increase the choke size to almost full open over time.  At this point the well would be switched to a low pressure system and the choke size would likely be reduced again for some limited time period.

 

Some operators start wells at a larger choke size (~ 22/64") and have a larger 1st year decline.  Others use the more conservative choke size (~ 14/64") and have a much flatter 1st year production curve.    

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Permalink Reply by adubu on July 3, 2011 at 4:35

Les B-- of course it's early in the history of shale to know how to obtain the best EUR production and life of well-- to date and comparing to conventional vertical wells what appears to be best choke size early in life of well-- I get the ideal if you pull too hard early you will decrease EUR in long run--- I guess you want to balance the right choke at the right time. What's most experts say to date.

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Permalink Reply by Les Bamburg on July 3, 2011 at 9:06

Adubu, this is still mixed opinions on the optimum choke size (traditional -vs- more restrictive) and it varies by area of the play.  In some cases the same operator is using different approaches in different areas (analogy -- driver -vs- short iron).

 

Also, since operators are trying to optimize economics (example - NPV) rather than EUR the optimum choke size is also a function of natural gas price profile.  I also believe completion and fracture treatment design are significant factors. 

 

EnCana & Chesapeake are more traditional in approach while Petrohawk & Questar are generally using smaller choke sizes. 

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Permalink Reply by Parkdota on July 3, 2011 at 14:33

Les, does PSI correlate to flow rate?  If so, wouldn't a well that comes in above average on both counts last longer than the 25-30 year standard? 

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Permalink Reply by Hale Yayuh on July 3, 2011 at 16:09

Huh? There is no standard. And a 25-30 year life is certainly not a given. Don't buy all the hype.

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Permalink Reply by BirdDawg, plain ole' idiot on July 3, 2011 at 16:57

Hale Noyah,

Huh? What hype?

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Permalink Reply by adubu on July 4, 2011 at 3:20

BirdDawg-- Hale Yayuh must take the NY Times News Paper you think

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Permalink Reply by BirdDawg, plain ole' idiot on July 4, 2011 at 15:09

I think so Adubu.

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Permalink Reply by Hale Yayuh on July 5, 2011 at 2:13

Just a very concerned mineral owner. A lot is at stake and there is much to be concerned about.

Permalink Reply by Les Bamburg on July 4, 2011 at 3:29

Parkdota, generally a well with a high flow rate and high flowing pressure indicates a strong performer that could have a longer economic life and higher EUR.  I always look at rate, pressure and choke size to get a more complete picture of a well.  The more restrictive choke size reults in a lower rate but higher flowing pressure. 

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Permalink Reply by dbob on July 4, 2011 at 5:27

Just a general comment, and I don't have a lot of direct knowledge here, but operators could also adjust production rates to meet capacity/deliverable and/or pressure targets on gathering systems; to adjust the quality of gas going to a treatment plant or into another pipeline system.

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Permalink Reply by Parkdota on July 4, 2011 at 6:10

Les, thanks for the info.  All the data I've gathered and used in custom excell programs shows the wells lasting at or longer than 30 years depending on the many various factors.  On this site I've read discussions talking about the end of a well's life where they become uneconomic for the operator to keep flowing and they are thus shut down.  I've been using sub 200/mcfd as that shut down point although I don't fully understand why they would turn the well off if it is still producing. 

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