Later, 10:09 a.m. Pacific time: soon after posting the original post, a reader sent me a couple of comments and a link to a great set of graphics.
The first comment regarding natural gas in the original post:
Look at the Utica. Very interesting how it has higher gas productivity than any play other than the Marcellus. Better than the Hyanesville. And still improving rapidly. May be on its way to being the second best gas play. Also, check out the amount of new oil from the Utica. I think of it as a gas play, maybe a wet gas play, but still wet. But 200+ bopd/rig is a lot of oil for a gas play. Yes, the layer is deeper than the Marcellus, so expensive to drill...and has some of the same takeaway issues. But it is really amazing how it has come from nowhere over the past two years. It's no longer just a dream, but a legitimate growing contributor.N.B. This is an important observation from a reader. Then, the second comment, regarding the difference between the Bakken and Eagle Ford:
The Eagle Ford has IPs which drive its higher new oil per rig productivity (over the Bakken). And much closer to markets (better pricing). But the declines are faster (more Bakken wells will remain as strippers, more EF wells will be abandoned). See link below. This helps justify continued drilling in the Bakken, because economics rely on the production all the way out.I was not aware that the Eagle Ford had decline rates even "worse" than Bakken decline rates. Interesting. I learn something new every day. I assume I should have known this but completely missed it (but I think I know why).
The reader sent the link (a pdf) that compares the decline rates for the various plays.
This opens up a whole new avenue of discussion. Because I lack experience in the oil and gas industry when I get into these new discussions, I could be way off base. I may be way wrong on these things as I go into uncharted territory. The rest that follows is opinion and a recollection that could be in error.
When I read that phrase from the reader, "more Bakken wells will remain as strippers, more EF wells will be abandoned," it immediately reminded me of something the new EOG CEO said recently about re-fracking: it would be easier to simply drill a new well than re-enter/re-frack an old one. That now makes sense ... from his perspective.
I believe EOG has a bigger presence in the Eagle Ford, and if push comes to shove, EOG would prefer the Eagle Ford to the Bakken (my opinion). If it is accurate that wells are likely to be abandoned sooner in the Eagle Ford than in the Bakken, then it would make sense about simply drilling a new well rather than re-entering an abandoned well. An active well, however, even a stripper well, would offer additional options (re-work, re-enter, re-frack) than an abandoned well.
I recently posted an example of a stripper well that was re-fracked. At the time, I did not mention that it was a stripper well. (At least it meant stripper well status; I do not know if the request was approved.)
Link here: random update of 17118. When I posted the update on that BR well, there was one more item that I alluded to but did not post. I had some thoughts but was not ready to post them. What I did not mention specifically was that #17118 met "stripper well parameters" as spelled out in the letter requesting stripper well determination dated January 25, 2013.
This is a great example of a well that, although a stripper by definition, found new life when re-fracked.
That pretty much closes the loop on #17118 except for one more item, but that, too, will be left for another day. The reader provided a huge amount of information; it takes a bit of time for it all to sink in, and I don't want to go too far out on a limb with bad reasoning.
I know I did not articulate the information above as well as I would have liked, but I think folks get the gist. If it's confusing, ignore my comments, and simply read the reader's second comments, and look at the linked pdf.