Depletion "Type Curves" from company websites show a dramatic drop in production after one year

The "Type Curves" from many of the company presentations seem to indicate that the gas/NGL output from horozontal wells will fall by ~75% within one year, and oil by ~50%.   Page 36 from the Antero presentation is one example.  Am I intrepeting this accurately?  Any comments will be appreciated.

 

http://www.anteroresources.com/wp-content/uploads/Company%20Website...

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Permalink Reply by Joseph-Ohio on February 22, 2013 at 8:54am
Blu,
Something has to create the pressure.
My intuition tells me it's mother earth over.
J-O
Permalink Reply by Bluflame on February 22, 2013 at 9:03am

Dennis,

  I agree..this is a good discussion. The "BOE" number can be misleading when comparing well economics. Since NG prices have plunged, and NGL prices are heading that way, we need to calculate the value of each component to get a valid assessment. Also, that's why the oil component is important.

BluFlame

Permalink Reply by LERRET on February 22, 2013 at 3:14pm

Again, single calcuations of a well does not tell you what any given well will do. They all vary. When we do a project involving say 10 or 30 plus wells, we run the numbers on them all. Often only 1 of 3 is "good" and the other two are weak or deplete rapidly although similar in depth. Sometimes we have 4 wells that produce similarly only to have one that is totally different and calculates either higher or lower.  Also, fraccing often results in fracking into the frac zone of another well which will allow one well to poach the reserves in an adjacent hole.  Also it is common knowledge in the industry that a given well may produce 80% or more of its gas from a single stage of a frac while the other stages produce little if any gas.

There formations are far more inhomogenous than first beleived. The fractures themselves are rarely uniform. The list below is a project and although in one of the better areas of the Fayeteville in Arkansas, it shows the calculations for wells with 3 yr. histories or better. There are some double the production estimat of others and the economic life equally different.  The decline rates were all over the map too. This was the same area that operators were claiming 40 BCF per section of reserves. By our calculations fully developed, few of them ever will achieve 20 BCF and the "6 BCF" per well figures are running 2 to 4 BCF at best and the weaker and older wells are rapidly approaching the end of their economic life.... BTW SWN lost most last Q largely over low prices in their shale plays.

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Permalink Reply by Bluflame on February 22, 2013 at 9:26am

Thanks Matthew,

  Earlier in this string, there was a reference to Arthur Berman who has the same opinion as James Hamilton. The Bakken Play may not be representative of the others as it is all oil and, I believe, tight sands versus pure shale. (I could be wrong about the tight sands) I've posted on other strings that I transited the Bakken Shale via Amtrak in Sept 2012. Every well I saw, and there were lots, had a pump jack.

   Nevertheless, the decline rate is for real. But we're still only able to retrieve about 5-7% of the hydrocarbons imbedded in the shale formations. It seems to me that opens the door for improvements in hz drilling technique and fracking technology to improve the recovery rate.

BluFlame

  

Permalink Reply by Joseph-Ohio on February 22, 2013 at 10:12am

To me, flaring off 30-35% is sinful in these days of energy dependence / so-called shortages !

How long would it take to develop and payoff a pipeline / plant infra-structure to instead gather it and sell it ?

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on February 22, 2013 at 5:57pm

"Berman has been changing his tune somewhat over the last couple years. As far as Natural Gas, he has been dead wrong as far as production costs in some locations. Dry gas can be very profitably produced at levels far below $5 in many areas, and well below $ 4 in the best areas. Encana is looking at Haynesville EUR's of 18 Bcf in their best area. "

That's simply not true.  Encana can find a very, very narrow space to make money off of NG at $4, but that is not indicative of the whole play.  And Berman's cost analysis comes from each companies 10K filings, which means it's the most optimistic project that a company is willing to legally give.  Gulfport is not making any money off of their utica wells right now.  They just aren't.  Their cost is almost $40/boe and they're realized price is between $40-42/boe, depending on their hedges.  That's not the crazy profit that they've been selling to their investors.  the landowners in those wells are doing great, but for GPOR to keep drilling they'll need to move out of dry gas and deeper into liquids.

0i7okn54zwbdoPermalink Reply by 0i7okn54zwbdo on February 22, 2013 at 7:03pm

His contention is a 22 year supply, prior to the establishment of the Utica.  It's still much more accurate than the government's hilariously misleading 100 year supply.  He seems to be the only one taking energy companies to task for their estimates that are at best questionable.  Landowners hate--hate--oil companies for so many reasons described on here.  Now a guy comes out and tries to keep the oil companies at least a little honest and landowners jump all over him and rush to the defense of the Chesapeakes of the world.  Chesapeake, who I said three years ago was Enron with better packaging, has been on the brink of collapse for years precisely because they just fibbed their way into OPM for these shale ventures that need much more price support than the current market is giving them.

Permalink Reply by Bluflame on February 22, 2013 at 10:41am

Matthew,

 I observed pipelines under construction in the Bakken during my trip last fall. 

BluFlame

Permalink Reply by Bluflame on February 22, 2013 at 4:43pm

Jay,

  I modified the spreadsheet to separate liquids into NGL's and Oil. For the Clay well, the numbers don't change much since the IP of oil and NGL's is very close. On other GPOR wells, IP of oil and NGL's are very different and the new spreadsheet could be useful.

BluFlame

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Permalink Reply by Bluflame on February 23, 2013 at 2:33am

Jay,

  There is still a flaw in the spreadsheet as prepared by our Penn State brethren. For the decline rate (as exemplified in the first year), they've assumed the entire year starting day 2 is produced at .3 of IP, making for an immediate 70% decline. Reality is that the decline should be gradual over the year, culminating in a 70% reduction in production rate at year end.

   In order to do this properly a logarithmic function would need to be built into the decline calculation. I'm sure the Penn Staters assumed that production fell off  the cliff (fiscal cliff?!?) day two for simplicity sake. At a point where we have some actual Utica decline data, I will build in a legitimate decline rate. Of course as has been noted by others, every well is different and we can only estimate from averages. In the meantime, the decline rate on our spreadsheet can be considered ultra conservative, which is probably a good thing.

  BTW...Are you sure the Walters acreage number is 169? I didn't look it up on the ODNR website.

BluFlame

Permalink Reply by Bluflame on February 23, 2013 at 2:47am

Jay,

  Just noticed the spreadsheet built in a re-frac Year 13. That's as good a guess as any, but considering the decline rate, I don't know why an E&P would wait that long.

BluFlame

Permalink Reply by Joseph-Ohio on February 23, 2013 at 2:55am

The graph shows that re-frac kicker nicely.

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