FAREWELL-TO-OVERLYHYPED-GAS-WELLS - TheMotleyFool.com

Farewell to Overhyped Gas Wells?

http://www.fool.com/investing/value/2010/03/23/farewell-to-overhype...

Toby Shute
March 23, 2010

Last month, I told you that the Eagle Ford shale play in South Texas is the "play du jour." Industry participants are piling into this play like
crazy -- from big boys like BP (NYSE:
qs-source-isssitthv0000001"">BP) and Chesapeake Energy
(NYSE: qs-source-isssitthv0000001"">CHK) to small fries like Rosetta
Resources (Nasdaq: qs-source-isssitthv0000001"">ROSE) and Swift Energy
(NYSE: qs-source-isssitthv0000001"">SFY).

Encouraging early results are now being reported regularly. But before we start scoping out the latest numbers, let's revisit the theme of well test PR hype.

I took a stand against 24-hour well test reporting last year, when blowout numbers were being reported in the Haynesville shale. In many cases,
those numbers are highly
misleading, as these flow rates tend to decline dramatically.

Take the case of Devon Energy (NYSE: qs-source-isssitthv0000001"">DVN), which reported a 30.7 million-foot-per-day stunner
late last year. On its fourth-quarter conference call in February,
Devon disclosed that after 90 days, the well was flowing at "a little
over three million cubic feet per day."

I'm a little less worried about these sorts of stunts going forward, now that the industry seems to recognize that lower initial flow rates should help to maintain pressure, avoid formation damage, and increase
ultimate recovery. Petrohawk Energy (NYSE: HK), for example,
announced in its fourth-quarter release that the firm is expanding its
use of "restricted rate production practices" in the Haynesville.

I'm still not crazy about 24-hour rates, and vastly prefer to see 30-day or peak-calendar-month rates, but I suppose there's also an argument to be made for getting new information to investors quickly. I
think I will back off my hard line against relaying this information,
but I will also try to put it in its proper context for you. That's
something the companies themselves are not always eager to do.

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Replies to This Discussion

Permalink Reply by Les Bamburg on March 24, 2010 at 3:21
Buddy, EnCana did not provide that information.
Permalink Reply by jffree1 on March 24, 2010 at 3:50
No, Jay, that one was 30.711 MMcfd for Devon & Crimson. Encana has one in La. @ 37 MMcfd, a new #1.
Permalink Reply by jffree1 on March 24, 2010 at 3:56
No biggie... I just wish they would put a name on it.
Permalink Reply by Buddy on March 24, 2010 at 8:35
Les: In another thread on this site said that the well was just south of Highway 514 (Crossroads) just off of 71 - it would appear to be the Brewer Well in 34-14-10 - possibly.
Permalink Reply by Lerret on March 24, 2010 at 15:03
Would it not be possible for Encana to announce a 37 MM IP on 24hr. test and then choke the well way back to a 16 or 18/64 choke for actual production?

Exactly and I think that is happening. What bothers me is that so many companies seem more interested in maximizing the "spin" about these wells apparently for investor consumption than giving a real assessment of the wells.

In part, this is a function of the inability to really predict the productivity of a well using logs. They are depending upon carbon content, pressures, etc. to estimate EUR.

EUR is only accurate when you have produced the last economic unit. Until then it is a guess and the earlier in the process you guess the less likely it will be right. I have been noticing however that where wells are reasonably close, the declines become increasing higher and the EUR appears to be dropping well to well. This suggest communication and perhaps these frac jobs are either going further out or are so inhomogeneous as to create communication from one well to the other.
Permalink Reply by Les Bamburg on March 24, 2010 at 15:47
Lerret, I am not really seeing any "spin" as EnCana did not even make a press release.

By the way, one has rarely ever been able to predict well rates from logs - even in the old days for conventional high perm offshore reservoirs. Hence the reason for well tests.

EUR's for shale gas wells seem to be estimated from type curves rather than the characteristics you listed. EUR's, OGIP's, etc have always been an educated guess which is the reason companies employ geoscientists and reservoir engineers.

Information suggests that EUR's are actually increasing with later wells rather dropping as you suggest. One would expect wells with higher initial rates to experience steeper inital declines. This does not appear to be related to well proximity.

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