Tuesday, June 25, 2019

WTI Above $58; Oasis, CLR Each Report A Nice Well -- June 25, 2019

Note: still on the road -- a cross-country trip. Blogging will be minimal. 

Wells coming off confidential list today -- Tuesday, June 25, 2019: 76 for the month; 265 for the quarter;
Active rigs:

Active Rigs6265583076

RBN Energy: Northeast gas takeaway capacity vs production in 2019.
The Northeast gas market has come a long way since 2013, when it first began net exporting gas supply to the rest of the U.S. The past several years were marked by dozens of pipeline expansions to relieve takeaway constraints and to balance oversupply conditions in the region; as a result, takeaway capacity is finally outpacing production growth. How much spare capacity is there now, and how long will it be before production growth hits the capacity wall again? Today, we continue our series on Northeast gas takeaway capacity vs. production, this time examining the utilization of pipes in the Northeast-to-Gulf Coast corridor.
The Wells Coming Off Confidential List Today

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

Reader Provides Very Good Notes Regarding The Bakken From 2017 -- June 24, 2019

I'm on the road traveling so my notes will be short.

However, a reader provided two really, really long notes in reply to a recent post regarding the production numbers and permits in the Bakken in 2017.

Those comments are at this post.

They are very good notes, and I will get back to them, spend some time on them, tomorrow, or more likely Wednesday.

Driving cross-country with minimal stops.

In fact, to make it easier for readers, I think I will bring the comments up here.

The first comment from the reader:

General comments:
1. Yes, productivity growth has been impressive. What's even more impressive is getting such improvements NOW, ten+ years into the ND Bakken play. You would think that such improvements would tail off. Late innings and all that. But instead, perhaps a lot of the earlier wells were not done optimally so there was room to improve.

2. How long improvements continue, who knows. In addition to just running out of knobs to twist, there is the issue of exhausting the Tier 1 land. For instance, EOG drilled through their extremely awesome land by 2010 or so (Sanish or Parshall, can't remember). But then after that average EOG productivity went down, not up. So sweet spot exhaustion can happen.

3. In general, you have to look at number of completions as well as average production. The reason is "high grading" (and the opposite) when prices move down/up. IOW, if you drill much fewer wells, you tend to drill the best ones. Thus, average productivity goes up, just from "culling the herd" to keep the best cows only, not from making them all better at making milk. However, there are other analyses, you can do, that tend to show there is MORE than just high grading going on. The wells in similar locations are just better now than earlier.

4. I would be very careful of assuming that IP translates all to higher well EUR. I am a Bakken booster and so is Rystad Energy. But we both agree that decline is faster for bigger wells. Sometimes companies try to glide past this point (not lying, but not explaining). On the opposite side, you have peak oilers, who say it is all front loading, no EUR improvement.

4.1. My seat of the pants estimate is 50% front loading, 50% EUR improvement. So if the IP doubles, figure the EUR goes up 50%. Note that even just the acceleration helps the well make a better investment because of time value of money. But if you are a landowner and see the first month double, don't expect the total well to be double forever. Will also decline faster.

4.2. I don't have any deep reason for the 50%/50% guess on acceleration/EUR. It's just half-way between the extremes and feels right by gut. Intuitively, when you do a bigger frack, you are probably doing BOTH cracking rock that would never crack (new oil) as well as making it easier for oil that would take a long time to get to the wellbore, to get there a little earlier.

5. By ~2010, perhaps earlier, the whole basin had mostly moved to two-mile laterals. So the improvements are not from getting longer, but better.

The second comment from the reader:

Specific comments:

Production average IP Numbers
Per shaleprofile.com, plus analysis:

3-month IP* (#wells)
2005: 6,750 (30)
2006: 9,502 (74)
2007: 17,529 (163)
2008: 25,184 (428)
2009: 24,036 (469)
2010: 28,304 (776)
2011: 27,389 (1,235)
2012: 28,408 (1,798)
2013: 29,926 (1,984)
2014: 32,063 (2,160)
2015: 32,865 (1,423)
2016: 40,445 (723)
2017: 46,733 (971)
2018: 49,197 (1,229)


a. 2006: significant improvement in productivity, more wells drilled also. Still very small amount so presumably this was all real improvement.
b. 2007: more wells and higher production both. This is getting better and not from down grading.
c. 2008: Another large improvement and in spit of doing even more wells.
d. 2009: Similar productivity and number of wells to 2008 (a stall in improvement).
e. 2010: 15% improvement in productivity and almost double the well count. Great year.
f. 2011: Flat productivity. But much higher well count. So keeping things on track despite down grading.
g. 2012: Slightly more productivity, but many more wells.
h. 2013: Similar to 2012. Slightly more productivity and wells.
i. 2014: About 10% productivity increase and with slightly more wells. Good year.
j. 2015: Same productivity, but a drop in well count. Not a great year.
k. 2016: Large increase in productivity, but big drop in well count. This was partially high grading. But also some improvement of technique (can see in other analyses of top wells, coming). But hard to disentangle how much was high grading and how much completion improvement.
l. 2017: 15% improvement in productivity and slightly more wells. That is getting better despite downgrading. Great year!
2018: 5% more productivity improvement and in the face of doing more wells. Another good improvement year, but not as big a jump as 2017.

[Net, net: yeah, 2017 was the big change.]

*This is the 3 calendar month IP. So, the first "month" will average being a half month long. Also, the well is offline some amount of time from operations, etc. These make the 3 month IP smaller than in a perfect test. But if you look year to year, it's apples to apples, since the average impact is probably similar. In addition, this is the 3 month oil cum. No gas, no BOE. But gas is a pain anyways and gets almost no money. ND only. Bakken and TF only (no Red River, no Madison). And horizontal wells only.