Replies to This Discussion

Permalink Reply by Mark P on May 31, 2012 at 9:48am

You can run calculations to determine oil in place volumes

Need values for porosity and water saturations as well as Bo (oil expansion factor - relates oil in reservoir to volume on the surface)

Of course, oil in place is just that. Key then is the recovery factor that one uses to figure what COULD be recovered over time.

No familliar with TMS recoveries, but Eagle Ford values run in the 4%-6% range

Permalink Reply by Randy K on May 31, 2012 at 9:51am

How many feet of recoverable pay is in Eagleford?

Permalink Reply by Mark P on May 31, 2012 at 9:59am

Net pay in the Eagle Ford varies from roughly 50-60' to over 200' depending on the area.

 

Permalink Reply by Randy K on May 31, 2012 at 10:14am

Are they drilling wells where theres is 50'-60' of pay?

Permalink Reply by Mark P on May 31, 2012 at 10:20am

A few - jury still out on economics. Oil is there but question is it enough to make money

 

Shallower depths than the TMS - 6000-7000' TVD (true vertical depth) 

Permalink Reply by Joe Aldridge on May 31, 2012 at 12:19pm

Thanks Mark,

Your knowledge and input is much appreciated.  

Permalink Reply by Bernell McGehee on May 31, 2012 at 3:20pm

The original LSU study suggested 50 barrels of recoverable oil per acre/foot of high resistivity shale.  It also estimated 300 barrels of oil in place per acre/foot of high resistivity shale.  So, their estimate was 17% recoverable at the time.

Permalink Reply by Randy K on May 31, 2012 at 3:47pm

So what's the total amount of recoverable oil?  

Permalink Reply by ShaleGeo on May 31, 2012 at 3:50pm

No one knows yet. It will take time to see if the trend is economic. So far it isn't.
Jay

Permalink Reply by Dion Warr on May 31, 2012 at 6:06pm

Jay:

The latest Anderson completion seems to be pretty close, if not entirely there, do you not agree?  Obviously with a new completion you never know what the actual decline curve and future dynamics would look like, but based on a "typical" shale curve (for whatever that term is worth), it would appear to be near break-even at current average price evaluations, wouldn't you think?

Permalink Reply by Mark P on May 31, 2012 at 8:08pm

I'm not ultra familar with the recent TMS completions - is this the well that was being touted earlier this month? 1000+ BOEPD IP rate or something like that?

But you are right - it is not the IP but the actual production and decline rates over the first couple of years that tell the story on EUR. A lot of the big Eagle Ford IP wells (i.e. over 3000 BOPD) never come close to actually producing at those rates.

Like in the Eagle Ford, I think (IMO) that the how these wells are flowed back post frac and subsequently produced, artificially lifted, etc. will be critical issues to maximizing EUR's.

Permalink Reply by Mark P on May 31, 2012 at 4:10pm

Lots of questions - how much area is being frac'd and drained?

Using the LSU numbers, an 80 acre drainage unit with 135' net pay should recover 540,000 BO plus associated gas.

This is my opinion, but the 17% recovery factor that the LSU study is citing is on the high side. Eagle Ford recovery factors have been widely cited by industry as running in the 4% to 6% range. This is based on a lot of info including core and detailed reservoir analyses.

Using a 5% recovery factor and 80 acre drainage with 135' net pay, you only get 162,000 BO recoverable. This should be economic IF you could really frac and drain this size of unit.

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