From a reader who follows the Bridger wells and the Dvirnak wells (and I assume other wells in the area) pretty closely sent some notes and comments. There are two Dvirnak pads: one is completed and producing (two wells) and the other pad has three Dvirnak wells on
DRL status.
The reader writes, the most recent Dvirnak pad had gone from TA (temporary abandon) status on January 27, 2016; followed by a notice on February 19 to reclaim the pit; and, then, a new pit request on May 13; and is now back to drilling as of May 25, 2016.
To some, it may seem like a lot of unnecessary activity.
The reader wonders whether all this activity was related to NDIC rules requiring drilling to commence within a reasonable period after first spud, or whether the changes were due to economics and/or other reasons.
- 30139, drl, CLR, Dvirnak 4-7H2, a Three Forks second bench well, permit dated 12/4/2014.
A sundry form received February 10, 2016, has the [boiler plate] request that I see frequently when I visit EOG file reports: "[The named operator] respectfully requests permission to temporarily abandon [the named] well. [The named operator] plans to complete the well once commodity prices improve." This is done after the spud, and after casing was set and cemented and then tested for any leakage.
And as the reader noted, the reserve pit was reclaimed and re-seeded.
This particular well was originally spud 10/30/2015. Now, in May, 2016, they have brought the "big" rig into drill this well, and I assume the others as well.
A sundry form received May 18, 2016, suggests that drilling was ready to resume on this 6-well pad. Once drilled to depth, the operator has two years to complete the well, during which time the well is referred to as a DUC (drilled, uncompleted).
The reader noted the incurred costs that must be associated with reclaiming a pit, only to repeat the process a few months later. There would be many story lines here, many opinions, many thoughts, but it is what it is (at least for now) and the benefits of requiring this "digging a ditch only to refill it" mentality probably outweighs the alternative. Just my two cents worth.
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On another note, the reader writes:
In the next unit to the west [of the Dvirn pads noted above] the Weydahl 4-36H1 has been on production with new enhanced completion technology? With just over 10 months production I would think CLR is happy with that result?
From the NDIC:
- 29555, 1,497, CLR, State Weydahl 4-36H1, Corral Creek, Three Forks, 17 total drilling days, gas exceeded 4,000 units, 29 swell packers, sundry form says IP was 2,238, 30 stimulation stages, 5.8 million lbs, t7/15 (sundry form says 6/15), cum 186K 4/16; (note: the file report also copy of frack data for #29955, which was probably placed here by mistake).
Production profile:
| Pool | Date | Days | BBLS Oil | Runs | BBLS Water | MCF Prod | MCF Sold | Vent/Flare |
|---|
| BAKKEN | 4-2016 | 30 | 17144 | 17049 | 3823 | 20468 | 20468 | 0 |
| BAKKEN | 3-2016 | 31 | 14285 | 14522 | 2972 | 12821 | 12632 | 189 |
| BAKKEN | 2-2016 | 29 | 14693 | 14855 | 3118 | 13783 | 13519 | 264 |
| BAKKEN | 1-2016 | 31 | 17339 | 17045 | 3763 | 17216 | 17216 | 0 |
| BAKKEN | 12-2015 | 31 | 16956 | 16955 | 3720 | 17099 | 17099 | 0 |
| BAKKEN | 11-2015 | 30 | 19403 | 19644 | 4427 | 19842 | 19842 | 0 |
| BAKKEN | 10-2015 | 24 | 15371 | 15282 | 3506 | 13684 | 13513 | 171 |
| BAKKEN | 9-2015 | 30 | 25156 | 24727 | 6651 | 17575 | 15511 | 2064 |
| BAKKEN | 8-2015 | 20 | 15846 | 16142 | 5332 | 16396 | 16283 | 113 |
| BAKKEN | 7-2015 | 28 | 25131 | 25499 | 8778 | 26250 | 25636 | 614 |
| BAKKEN | 6-2015 | 9 | 4461 | 3718 | 659 | 11892 | 875 | 11017 |
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Continuing
The reader also noted:
In most recent CLR quarterly earnings conference call Oklahoma activities were the main topics, they didn’t say much about the Bakken. But I did hear the comment that enhanced well completions in the Bakken were turning out better than expected. Proppant for Weydahl works out to about 615# per foot of perforations. When they talk about Scoop completions they talk about proppant in pounds per foot. Like now they are using 2,500# per foot in the Scoop. Four times as much as the North Dakota Bakken Weydahl frac job.
That was my impression, also: not much said about the Bakken.
A summary was posted here. That's a nice 30-second fracking data point: 650 pounds per foot in the Bakken vs 2,500 pounds per foot in Oklahoma.
The reader also noted:
Another comment I have heard about SCOOP is that infrastructure and take away capacity is a non-issue. There are several refineries in the state, much gas collection/processing due to a mature environment from previous activity, and they have Cushing. In the SCOOP operators can go balls to the walls in terms of production and not have to worry about over whelming infrastructure.
In the current pricing environment, I doubt there are takeaway constraints in the Bakken, but if oil ever gets back to $100+, all bets are off.
Back to the Weydahl and the Bridger wells
in the Bakken with regard to natural gas production:
Weydahl went on line in June I believe, a few months later the Bridger 4,5,&6 which is a few miles SW went on line (using CLR enhanced completion technology?). There was a big surge of new gas in the pipeline system in that immediate area at that time. If you look a couple miles to the west at the Whitman 2-34H which is still flowing and has produced 1.44 million barrels to date, during September the amount of gas flared was almost ½ the gas produced. So there was a big spike in gas flared for a few months from Whitman at that time.
Which leads me to this rambling point. Even just a few years ago when companies like OneOK were trying to figure out where to put gas collection lines, size them, build/size booster stations, and build/size processing plants to handle gas production they ended up under sizing based on where potential production rates are today.
If you look at each generation of production output in areas that have been producing for 10 years, each new pad and updated completion technology far surpasses the previous generation it appears to me.
The early productivity of the new Bridger wells are blowing away the first and second generation wells of the same time frame. Another interesting point about the last generation of Bridger wells is that the early leader in production was the H1 well but since then the MB and H2 production have passed it.
Wow, there is so much incredible information in those last three paragraphs. I was aware of some of the story lines, but not all. It would behoove readers to read closely those last three paragraphs to get a good feeling for the Bakken.
Some notes for newbies:
- this takes me back to the very beginning; I think folks often forget how incredible the Bakken is
- the Bakken is considered an oil field; 94%+ of hydrocarbon produced is oil, but the amount of natural gas produced is not trivial
- the technology keeps getting better and better; the completion processes keep improving
- technology and skill of the roughnecks and geologists: drilling times dropped from 60+ days to 10 days or less
- completion techniques (fracking) keep improving
- although the middle Bakken will probably be bigger than the Three Forks when all is said and done, there are some who suggest Three Forks wells may actually be better than middle Bakken wells
- there are indications that the second bench and the third bench of the Three Forks will turn out to be quite nice
- the halo effect may or may not be in play in some situations
- "we're" gonna need more natural gas processing plants
- the Bakken may be landlocked (keystoned, and CBR-restricted) but at the present, but it is incredibly compact: the entire ND Bakken takes up less than a third of the state (surface area); for the most part it is concentrated in four counties; and, even in those four counties, has a small number of sweet spots, conveniently located around Watford City, Williston, and Tioga.
A huge "thank you" to the reader for sending such a long note from the field. Much appreciated.
