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 Bill Hill on February 21, 2013 at 3:00pm

I agree. Gas is especially susceptible to these supply/demand fluctuations as markets are so local. The key for operators is to drill only when prices are high for the first year of production so they can pay off their capital costs and any loans they took out to drill. What is happening now is that operators are running to areas where costs and acreage are low and where oil is the main target: areas like the Bakken, Niobrara in CO, and Miss. Lime in KS

Permalink Reply by Bill Hill on February 21, 2013 at 2:50pm

I looked at the Antero production curve for a Marcellus well and its flat rate was around 1000MCFD for years 7-10.  Monthly income for the well would be 30 X 1000 X $3.80 X .85 = 

$96,000/month.  I don't know what lease operating expenses are out there but I am guessing between $2000 and $4000/month.

Also if a well costs $4million it looks like that investment is paid back before a year or around 1BCF.  Everything is gravy after that. This is why oil companies drill these wells.

Permalink Reply by Roger Pyle on February 22, 2013 at 4:52pm

They must be using a Cadillac of well drilling, or something else is driving up their costs.  Today's annual conference call from Cabot:

Pearce W. Hammond - Simmons & Company International, Research Division

I apologize if I missed this, but what are your current well costs in the Marcellus right now, and then where do you think that could trend to by year end?

Dan O. Dinges - Chairman, Chief Executive Officer, President and Member of Executive Committee

Well, since we've gone a little bit longer laterals and a few more stages, we're kind of between the $6 million, $6.8 million range. And again, from an efficiency standpoint, ongoing across-the-board trying to continue to drive cost out of the drilling complete side.

2z248p19vqnh9Permalink Reply by 2z248p19vqnh9 on May 10, 2013 at 5:23am

So in some ways - it is initially, basically like syphoning?...but there is the 'pressure dropoff' (as well as ground product depletion) - simultaneously?

Permalink Reply by Jack Straw on February 19, 2013 at 6:05am

RE: "Will it be possible to "re-frac" these wells?"

It will be possible to "re-frac" these wells .... if the economics makes this proceedure attractive.

Like everything else, economics will be the driver.

Also, there is always the possibility that better fracing technology will be developed in the future.

 

RE: "Or drill new laterals in between existing laterals to get to oil and gas left behind?"

Current drilling from pads has the laterals spaced about as close as the existing fracing technology allows. I would not think that future drilling of new laterals in between existing laterals would result in added production sufficient to justify the costs.

 

All IMHO,

                 JS

Permalink Reply by Jack Straw on February 20, 2013 at 4:58am

Dennis, RE: "To use Cabot as 1 example,they plan to drill the Upper and Lower Marcellus in some units in the NE. This will result in 500 foot spacing."

 

Do you have a link or reference for Cabot's procedure of separately drilling and fracing the Upper and Lower Marcellus?

I would like to attempt to learn more about the possibilities of doing this.

In NE PA, where the Marcellus is at its thickest, I can perhaps understand that separating the Marcellus into two stratigraphic units might make sense.

But, I still find this procedure a bit confusing.

The pressure field is such that both lithostatic and hydrostatic pressures are less above a well bore than below. In a frac (ignoring the jointing present), the easiest path for fracturing in a formation is up. 

I am not disputing what you have said; I just hope to find a source that will allow me to better understand what Cabot are doing (and why).

 

ALL IMHO,

 

                    JS

Permalink Reply by Bill Hill on February 21, 2013 at 3:03pm

currently wells are draining 320acres or maybe 160acres.  down-spacing will probably go to 80acres but at some point the pressure will drop and new wells will be less spectacular.  

Permalink Reply by melissa humphrey on February 20, 2013 at 10:56am

Marcellus like any shale gas has declines!. 60%+ in year one is normal.

Sahel gas wells in general will have deliverd 50% of their potential by yr 4-5, after than

the declines are expected to be 6-9%/yr until well death.

Hhaynesville starts off extra well, but has even faster declines.

FWIW

Permalink Reply by Mike Sero on February 21, 2013 at 5:05am

Fracking is a stimulation of the ground - and once the "TRUE" mother nature law of gravity etc... comes back in motion the true natural flow will occur.

Permalink Reply by Jim Brannon on February 21, 2013 at 8:11am

Can't a well be refracked, usually every 7 or so years?

Permalink Reply by Bill Hill on February 21, 2013 at 3:09pm

i think infill drilling, re-stimulation, new zones, and newer techniques will keep these wells producing for a long time

015334grltd9mPermalink Reply by 015334grltd9m on February 21, 2013 at 4:22pm

Funny that BP, Shell, XTO, Hilcorp, Gulfport, Hess, Consol, ......................................are throwing billions of dollars away only to decieve us according to some here.

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