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Permalink Reply by smith1 on January 19, 2011 at 7:57

where on Sonris do you go to locate the above monthly figures for a well if we have serial #?

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Permalink Reply by Skip Peel - Mineral Consultant on January 19, 2011 at 8:10

Use the  link.  Select Wells By Serial Number from the search list.  Enter the S/N.  In the well file look down the page to the section titled, Lease/Unit/Well Production.

 

http://sonris.com/sonlite.htm

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Permalink Reply by smith1 on January 19, 2011 at 8:27

Thank you, I see that but why does it state completed as 7643 MCFD but below it states 8/1/2009 as 176254 MCF?

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Permalink Reply by Skip Peel - Mineral Consultant on January 19, 2011 at 8:35

MCFD = thousand cubic feet per Day.  The total monthly production reported on 8/1/2009 is 176,254 MCF.  The initial test was for 24 hours.  The production report is for a month.

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Permalink Reply by smith1 on January 19, 2011 at 8:57

Awww, thank you

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Permalink Reply by Bacon on April 29, 2010 at 1:17

From the STR Q1 conf call.

Brian Singer - Goldman Sachs

Can you talk in more detail on the Haynesville just specifically with regards to the chokes or the modified flow backs? What do you seeing some of those wells whether it’s the ones you announced to any prior wells that you choked back and what are your current views on EUR implications?

Chuck Stanley

We would view the results from this list of wells that we turned to sales in the past quarter its being comparable to the earlier wells that we completed and reported the higher rates and 20 million to 30 million cubic per day initial rates. These wells are being substantially choke back we are attending to minimize draw down at the formation in order to avoid any damage sort of reservoirs.

We have a small group of wells that we are practicing this modified flow back procedure on today and what we see is at any given point on the cumulative production curves a higher falling bottom hole pressure compared to wells that we flow back basically unconstrained. So after recovering a Bcf of gas, we’re seeing a 15% to 20% higher in flowing bottom hole pressure compared to a well that flowed back hard initially.

We don’t know exactly why, this behavior is occurring, but we suspect it’s a combination of more evenly de-watering the fractures along the entire length of the lateral potentially avoiding closure of the near well bore fracture and allowing for a complete dewatering and flow back of the entire length of the fracture and a few other sort of thesis on why it works, but the empirical evidence seems to suggest that these wells over the long haul going to recover more of gas than the well has floated back hard initially, because of lack of damage of total incomplete dewatering of the individual fractures.

Carl Kirst - BMO Capital

A follow-up from Brian’s question, the Haynesville check. How long do you need before you get comfortable that we actually will ultimately see higher recoveries? Is it another few quarters? Is it another few years? I mean, what's that point that gives you extra comfort that the modified flow back will indeed give you better results?

Chuck Stanley

I guess that totally, intellectually honest answer is, after the well has been depleted, one can surmise from a basically cumulative production versus pressure plot that if a well after recovering say 50% of its projected reserves as a higher flowing pressure than one that has been unconstrained, that the ultimate recovery

Of course, we can’t predict what will happen 10, 15 years from now, but if you look at it just from an MPD or present value perspective, you quickly overcome the apparent higher economic value of having well that will produce at 30 million or 40 million cubic feet a day for a couple of months and then decline very rapidly versus one that you constrain at 10 million or 15 million cubic feet a day and let it basically plateau for that period of time.

If you recover another Bcf of incremental reserves from the well, there is this concept from my youth about maximum efficient rate in oil and gas facilities and you can spend a lot of extra capital on well site facilities, separators, dehigh equipment, et cetera to accommodate a flush production rate of two or three times the stabilized rate on these wells and the economics for putting out additional facilities, additional top site facilities to handle a couple of months 25 million cubic feet or 30 million cubic feet a day rate, are quickly consumed when that well comes off at a fairly high decline rates. So we’re trying to not only manage production to avoid reservoir advantage, but we’re also trying to optimize returns here by focusing on the rate at which we generate the highest returns at any given gas price for the shareholder.

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