Updates
Disclaimer: in a long note like this there will be typographical and factual errors. I have not spell-checked the note yet; will do that later. A reader provided the November 26, 2018, update, but I transcribed it; any errors are mine, not the reader who sent me the great note. Most of this is factual, but there are some opinions in the note, and it is not easy to separate fact from opinion on my blog in many cases.
November 26, 2018: a reader was kind enough to send two long notes regarding the Yellowfin wells. It is hard to give justice to these notes: the reader really shared a lot of information which helps me understand the Bakken better. Some of the information gets deep into the weeds, but will help newbies understand why pad sites are sometimes situated where they are. It also explains the cooperation among surface owners (usually farmers), operators, and government agencies (usually the state) to get this stuff done.
So, let's begin with the great note from the reader.
First: note the location of the Yellowfin wells in the graphic below. The horizontals will run south; the pad site is "outside" the drilling unit. We see this all the time in the Bakken. There are many, many reasons why this happens. In the case the reader wrote:
There is irrigation in the east half of section 6-151-98. The Gariety was drilled west from section 5, then south on the east edge of section 6. The Yellowfins were drilled southwest and then directly south in section 6. Oil pumps and tanks don’t work well on land with center-pivot irrigation systems. The Johnsrud 6-7-2 and 3 are both on higher ground (the latter wells are not seen on the graphic below; they are about a half-mile / mile to the west).
Second: when I first saw the location of the Yellowfin pad, I was unsure which way the horizontals would run. After a bit of superficial sleuthing, I was pretty sure they would run south but didn't mention that in the original post. But note how the Yellowfin pad is directly north of two other pads; it seems like a lot of unnecessary de-conflicting -- but see first comment above. The reader wrote, to repeat, the horizontals will run southwest, bypassing the pads to the south, and then run south into section 6. I should have caught that based on the legal name of the Yellowfin wells.
Third: so this is where we stand, putting the two first two comments together. The Yellowfin wells most likely would have been sited at the same latitude as the Johnsrud wells to the west. So, in fact, if I'm following this correctly, the Yellowfin wells are "Johnsrud" wells. One wonders why they weren't named Johnsrud wells? Now we're really getting into the weeds. LOL.
Fourth: now to the real meat of the reader's note. So, now we will start over with the numbering:
1: the Yellowfin wells are a Newfield test of increased density in the core area of the Bakken. All t three Yellowfin wells are middle Bakken wells; they are located 500 and 660 feet of the existing wells in the same zone. They thread their way between the Johnsrud 6-7-2 (#23906) and the Johnsrud 6-7-3 (#23908); and, the Gariety (#30398), and, the Holm (#25864). This will become apparent when the Yellowfin wells coming off confidential / tight-hole status this week.
2: the first month's production looks promising but it will take some time before the toal impact on all seven (7) wells will be known. Hint: see "Three" coming up next.
3: After the Yellowfin wells were completed, Newfield applied to the NDIC for fourteen (14) wells on the adjacent 1280-acre units to the east and south of these wells. Big hint. By the way, this is why companies like to keep their wells "confidential" as long as possible.
4: now, comparing these Newfield wells to another increased density program -- this one by Whiting. Whiting has developed increased density on their McNamara unit north of New Town. After their first year of production, Whiting shows very strong results for both the new wells and increased estimated ultimate recovery (EUR) for the original wells which were drilled on wider spacing. [We've talked about this before; Filloon has not talked about it but his graphs show it.]
5: the reader added, if 160-acre spacing proves to be economic in some areas of the Bakken it will have a major impact on the percentage of total oil and gas recovery in those units.
5a: if each unit could recover 3% to 5% of total oil in place, eight (8)-same zone wells could give 24% to 40% ultimate recovery! As the reader noted: we've come a long way from one well drilled corner-to-corner in a 640-acre unit in the early days of the Bakken.
6. This increased density could move us to a new level in Bakken development.
7. One final comment on the Dahl 5-8-8HLWR. It appears Newfield had trouble drilling this well and now has decided to drill a "R"eplacement well, grass roots. This is often more economic than spending lots of time and money trying to salvage the original well. The Dahl wells are less than a mile east of the Yellowfin wells. [A big "thank you" to the reader on this: I had noted the "R" when discussing the Dahl wells earlier, but did not know the backstory.]
Original Post
The graphic:
The Newfield Yellowfin wells are in the upper left-hand corner:
- 34800, 815, Newfield, Yellowfin 150-98-6-7-7H, t818; cum 197K 2/20;
| Date | Oil Runs | MCF Sold |
|---|---|---|
| 9-2018 | 24700 | 49495 |
| 8-2018 | 5830 | 1586 |
- 34801, 811, Newfield, Yellowfin 150-98-6-7-8H, t8/18; cum 243K 2/20;
| Date | Oil Runs | MCF Sold |
|---|---|---|
| 9-2018 | 24059 | 48332 |
| 8-2018 | 3346 | 2001 |
- 34802, 869, Newfield, Yellowfin 150-98-6-7-9HLW, t8/18; cum 267K 2/20;
| Date | Oil Runs | MCF Sold |
|---|---|---|
| 9-2018 | 28561 | 58085 |
| 8-2018 | 2534 | 2427 |
The other wells in the graphic.
Two parent wells:
- 18641, IA/A/AB/1,856, Newfield, Newfield, Megamouth 1-8H, t8/10; cum145K 6/19; after being off since late 2016, back on line for 17 days in 1/19, but almost no production; little production through 6/19; remains off line 2/20; very intermittent production; cum 145K 7/21;
- 18741, 407, Newfield, Dahl 1-5H, Siverston, t7/10; cum 173K 2/20; for Dahl wells, see this post; huge jump in production after coming back online 5/19; from 700 bbls/month to 4,000 bbls/month; cum 177K 9/21;
- 25862, 1,312, Newfield, Holm 150-98-5-8-2H, Siverston, t3/14; cum 224K 2/20; no jump in production; off line as of 12/18 for most of the month; off line most of the month 1/19; cum 260K 9/21;
- 25863, 637, Newfield, Holm 150-98-5-8-10H, Siverston, t3/14; cum 148K 2/20; huge jump in production in 9/18; cum 152K9/21;
- 25864, 1,425, Newfield, Holm 150-98-5-8-3H, Siverston, t3/14; cum 257K 2/20; huge jump in production in 9/18; cum 270K 9/21;
- 30397, PNC, Newfield, Gariety 150-98-6-7-10H, Siverston, no production data,
- 30398, AB/1,891, Newfield, Gariety 150-98-6-7-4H, Siverston, t6/15; cum 290K 9/18; recently off-line; coming back on line as of 9/18; but only a few days each month; still off line as of 6/19, though one day in 6/19; off line 9/19; remains off line 2/20;
- 35573, 1,285, Newfield, Goliath 150-98-5-8-5H, Siverston, t5/19; cum 160K 2/20; cum 244K 9/21;
- 35389, 1,427, Newfield, Goliath 150-98-5-8-6H, Siverston, t5/19; cum 173K 2/20; cum 250K 9/21;
- 35574, 658, Newfield, Goliath 150-98-5-8-11H, Siverston, t5/19; cum 113K 2/20; cum 173K 9/21;
- 35391, 1,246, Newfield, Dahl 150-98-5-8-7H, Siverston, t4/19; cum 153K 2/20; cum 210K 9/21; off line 5/21; back online for five days, 9/21;
- 35390, dry, Newfield, Dahl 150-98-5-8-8HLW, Siverston, drilled to depth; fracking failure?
- 35516, 1,008, Newfield, Dahl 150-98-5-8-12H, Siverston, t4/19; cum 176K 2/20; cum 237K 9/21;
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