20324, 1,963, BR, Midnight Run 21-1TFH, Union Center, t12/11; cum 211K 5/18; look at the production jump in 5/18; API - 33-053-03439; no frack since 2011; note huge production jump which would suggest a re-frack, but FracFocus has no data for a re-frack:
March 6, 2015: from a reader over at the Discussion Group -- I did a little 3-D mapping of these wells and it looks like the north
pad targets the upper Three Forks with the exception of one well that is
lower. The south pad is just the opposite- all but one wellbore in the
lower Three Forks, one in the upper horizons. Thank you. I will go back and use the terminology that the operator used. Comment: I just went back through the file reports, updated what I found in the wells below, and agree with you 100%. Thank you -- I was unaware of the differences in the formations in this area, the Antelope Oil Field, the Sanish pool. Much like the Sanish Oil Field, Whiting.
March 6, 2015: by the way -- note that according to the NDIC this well -- completed back in 2008 is still flowing without a pump (caveat: sometimes NDIC data is not updated -- there have been instances in which wells have been put in and the NDIC still shows the well as "flowing" without a pump, according to some readers. I would not have first-hand knowledge of that. But again, look at this, still "F" for flowing without a pump:
17214, 443, Hess, AN-Evenson-152-95-0310H-1, Three Forks (geological report, though application said Bakken NOS), 2 sections, open hole, 1.4 million lbs, t11/08; cum 226K 6/19; (off line March/April/May 2014); off line as of 6/19; remains off line 9/19;
March 6, 2015: the note below is very long, and my original comments come somewhere near the bottom/end of the post. The reader who first noted these wells responded to my comments and added some new thoughts. These are his thoughts, edited to fit the narrative below.
Looking at the drilling unit to the west of these wells might provide some additional information. The drilling unit immediately to the west is where the Bice 1-29H well was drilled, which is the very first Three Forks well that CLR drilled (as far as we are aware).
When the "companion" middle Bakken Bice well was drilled, there was much discussion regarding communication between the two. If I find the original post, I will link it later (it won't be hard to find).
The reader sorted the Hartman wells out, based on the order in which they were fracked (my spelling, not his). The reader felt that in the case of TF2 and TF3 (second and third benches, respectively), the second well fracked is doing much better than the first. The question: if there is communication, are frack solids from the second well interfering (plugging) the earlier fracked well?
The reader also noted that although they are into a few months of production, the water production has stayed the same for the last two months, but oil production has increased by over 20%. Looking at the new tank battery scheme, it appears the oil is transferred directly to the pipeline network whereas the salt water waste is trucked out. The question: is water removal bottle-necking oil production?
The reader also noted that fracking these Hartman wells used volumes about twice that used on the Hawkinson wells and the Hartman wells are spaced about half the distance of the Hawkinson wells. Result: the volume of frack solution per volume of reservoir is actually 4 times greater than that used in the Hawkinson wells. Observation/comment: it's possible the Hartman wells are still in the flow-back / clean-out stage; if so, production numbers may improve going forward.
Excellent observations and questions. The most frustrating thing is that operators are managing production (choking back) because of the low prices and if the production of these wells fall, it is hard to determine if it was due to purposeful choking back or if due to well dynamics regardless of price. The writer makes a great observation about the amount of salt water that has to be trucked away.
Finally, a note on spelling. I know the spelling of frac / frack and its variations is a sensitive subject to many, especially the roughnecks in the field who first broke open the Bakken. The reader who provided the notes above prefers to use "frac" and so it was me to who changed the spelling to keep the blog consistent. I apologize for stepping on the toes of those folks who prefer the alternate spelling. No disrespect is meant.
Original Post
This is going to be a really, really long note. First the data, and then some comments.
Some time ago I talked about heel-to-toe wells neighboring toe-to-heel wells. A reader over at the discussion group noted these ten wells demonstrating that pattern: six wells run north (heel-to-toe) and four other wells run south, in the opposite direction, toe-to-heel, relative to the six wells running north (if that makes sense). See screen shot of all ten wells:
The six wells sited in section 10-152-95; all six run north into section 3:
28395, 969, Hess, AN-Evenson-LW-152-95-1003H-2, Three Forks B1, 4 sections, 35 stages, 2.4 million lbs, Antelope, t1/15; cum 166K 9/19;
28072, 1,336, Hess, AN-Evenson-LW-152-95-1003H-1, Bakken NOS (application; geologic report -- upper portion of the middle Bakken), 4 sections, 35 stages, 2.4 million lbs; t1/15; cum 192K 9/19;
27798, 1,032, Hess, AN-Evenson-152-95-1003H-9, Three Forks, second bench (application and geological report), 2 sections, 35 stages, 2.5 million lbs; t1/15; cum 184K 9/19;
27797, 1,044, Hess, AN-Evenson-152-95-1003H-8, Three Forks first bench (application and geological report); 2 sections, 35 stages, 2.3 million lbs; t12/14; cum 153K 9/19;
27796, 949, Hess, AN-Evenson-152-95-1003H-7, Three Forks second bench (application and geological report), 2 sections, 35 stages, 2.2 million lbs, t12/14; cum 117K 9/19;
27795, 910, Hess, AN-Evenson-152-95-1003H-6, Three Forks first bench (application and geological report), 2 sections, 35 stages, 2.2 million lbs, t12/14; cum 156K 9/19;
The screen shot of these six wells:
*************************
The four wells sited in section 3-152-95; all four run south into section 10:
25698, 1,056, Hess, AN-Evenson-152-95-0310H-5, Three Forks NOS (application; though the geologic summary says middle Bakken), 2 sections, 26 stages, 1.8 million lbs, t6/14; cum 118K 9/19;
25699, 1,253, Hess, AN-Evenson-152-95-0310H-4, Bakken NOS (application, and geologic summary), 2 sections, 26 stages, 2.5 million lbs, t5/14; cum 212K 9/19;
25700, 1,263, Hess, AN-Evenson-152-95-0310H-3, Three Forks NOS (application, though the geologic summary says middle Bakken), 2 sections, 35 stages, 2.5million lbs, t5/14; cum 266K 9/19; (off line Nov/Dec 2014)
25701, A, Hess, AN-Evenson-152-95-0310H-2, Bakken NOS (application; geologic summary a bit hard to sort out), 2 sections, 35 stages, 2.5 million lbs, no test day but active and producing, s5/14; cum 166K 9/19; (off line Nov/Dec 2014, and still off line January 2015, but apparently back on line February 2015)
A screen shot of these four wells:
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A singleton well further to the east, running south, sited in the same section as the 4-well pad, section 3:
17214, IA/443, Hess, AN-Evenson-152-95-0310H-1, Three Forks, 2 sections, open hole, 1.4 million lbs, t11/08; cum 226K 6/19;(off line March/April/May 2014); off line as of 6/19; remains off line 9/19;
*********************************
Comments (these are all personal opinions; I have no training or background in the oil and gas industry; these opinions may be completely wrong; no one else may agree with me; there may be typographical and factual errors on this page; I don't always double/triple check postings; if this information is important to you, go to the source, starting with the NDIC):
these are all incredibly good wells
the operator sometimes listed the pool as the Sanish; other times, the operator listed the pool as the Three Forks; I listed them all as Three Forks (I do not know if there is a fine distinction between the Three Forks and the Sanish in the Antelope field)
these wells are all so similar (and so good) that it's really hard to tell if there was any advantage to drilling ~ half of them from the south, and ~ half of them from the north, but it certainly looks like this was done for that purpose, as a test; they easily could have all been drilled on the same pad in the north or the south
bottom line: I don't know if it made a difference drilling them in opposite directions
****************************
The "Halo" Effect Of Fracking
One question the reader did not ask about was the "halo" effect of fracking wells near existing wells.
The most recent fracking was done too recently to be able to tell with one exception.
Look at #25700. This well is one of the older wells, tested back in May, 2014. It came off line when neighboring wells were fracked in the January, 2015, time-frame. After the neighboring wells were fracked in the January, 2015, time-frame, #25700 was put back on status. It's very subtle, and may not mean anything, but prior to that neighboring fracking it produced 11,373 bbls in 31 days; after the neighboring wells were fracked, that same well produced slightly more (11,729 bbls) in 2/3rds the time (only 20 days). In fact, it's slightly worse: prior to the fracking, it got down to less than 9,000 bbls in 30 days and then less than 6,000 bbls in 26 days. Obviously the data is minimal, and there could be other factors (the operator could have modulated the production for some reason prior to neighboring fracking), but it certainly appears there is evidence of the "halo" effect.
I did not check the depths, but I assume all the depths were similar since they all were targeting the same pool/formation.
To re-cap, look for evidence of the "halo" effect in this well:
25700, 1,263, Hess, AN-Evenson-152-95-0310H-3, Three Forks, 2 sections, 35 stages, 2.5million lbs, t5/14; cum 266K 9/19; (off line Nov/Dec 2014) (as of 4/17, no data for a re-frack over at FracFocus):
Pool
Date
Days
BBLS Oil
Runs
BBLS Water
MCF Prod
MCF Sold
Vent/Flare
SANISH
1-2015
20
11729
11406
1030
21041
0
20844
SANISH
12-2014
1
679
453
20
1197
0
1197
SANISH
11-2014
0
0
0
0
0
0
0
SANISH
10-2014
26
5796
6267
836
23718
9041
14677
SANISH
9-2014
30
8672
8402
929
31378
15983
15395
SANISH
8-2014
31
11373
11474
1108
36027
3646
32381
SANISH
7-2014
31
16887
16972
1357
44499
7663
36836
SANISH
6-2014
30
21511
21227
1936
41923
3676
38247
SANISH
5-2014
24
33113
32708
4575
37444
154
3729
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More Evidence of The Halo Effect?
Is there any evidence of the "halo" effect in the Evenson well quite a bit farther to the east?
Below is the production profile of that well (#17214) just prior to the neighboring fracking in the January, 2015, time-frame, and right after. The monthly production has declined quite significantly by this time, so it's not easily visible, but note that prior to the neighboring fracking, we were seeing 1,200 bbls/month; after the neighboring fracking we started to see around 2,400 bbls / 31 days. When looking at production, be sure to look at total number of days of production in any given month. It's subtle; I wouldn't bet the farm on it, but it is interesting.
SANISH
8-2014
21
1462
1361
35
1638
1638
0
SANISH
7-2014
31
2189
2267
44
2534
2534
0
SANISH
6-2014
26
2590
2054
22
3561
3561
0
SANISH
5-2014
0
0
0
0
0
0
0
SANISH
4-2014
0
0
0
0
0
0
0
SANISH
3-2014
0
0
217
0
0
0
0
SANISH
2-2014
21
725
767
17
1452
0
1452
SANISH
1-2014
31
1193
1193
9
2531
0
2531
SANISH
12-2013
31
1309
1472
28
2732
0
2732
SANISH
11-2013
29
1446
1413
43
3072
2417
655
***************************************
One Pipeline Not Vetoed By President Obama
Pipeline co-writer Brian Carman dead at age 69. From wiki:
The Chantays were formed in 1961 when five high-school friends decided to start their own band. Bob Spickard, Brian Carman (co-writers of "Pipeline"), Bob Welch, Warren Waters and Rob Marshall were all students at Santa Ana High School in California, when a local group called the Rhythm Rockers inspired the five to form the Chantays. In December 1962, the group recorded and released "Pipeline," which eventually peaked at No. 4 on the Billboard Hot 100 in May 1963. The track also peaked in the UK Singles Chart in 1963 at No. 16. The Chantays recorded their first album in 1963, also titled Pipeline, which included "Blunderbus" and "El Conquistador." Their follow-up album was Two Sides of the Chantays in 1964.
Hess has two active wells running south-to-north in Hawkeye oil field, and today has permits to run wells right next to them but in the opposite direction, north-to-south. It will be interesting to see how close they put these new horizontals to the old horizontals. Based on surface locations, the separation appears to be about 600 to 800 feet (don't quote me on that; just a quick calculation).
Later, 12:47: the more I look at this, the more I have to agree with the individual who provided the first comment questioning "cemented liners." It sounds like KOG's cemented liners for completion is simply the "old" plug-and-perf method of fracking. And the little I know about it suggests that the swell packers technique is more effective in the Bakken. But that's just my two cents worth, coming from a non-specialist with no formal (or informal) training in the oil and gas industry.
Later, 12:08 pm: see first comment below. The questions: is anyone other than KOG using cemented liners in the Bakken? Has KOG switched to cemented liners as a matter of course, or are they testing various completion methods? Is cemented liners "old" technology, common technology when fracking Bakken wells? This UND-EERC source would suggest that cemented liners are neither innovative nor preferable to other methods. This is the conclusion of the UND-EERC source:
Since horizontal drilling became standard practice over the past two
decades, all of these completion methods have been
utilized in the Bakken. However, the uncemented, preperforated
liner isolated with swell packers has become the most commonly
employed method of completion in most Bakken wells because of its
high degree of fracture control and long-term success rate.
This linked article breaks out four key areas it says must be watched:
production
cash balance and credit facility
hedge situation
cost-cutting measures
First, production: The Motley Fool is correct. KOG has some of the best acreage in the Bakken, and based on recent IPs, some of the best wells.
Second, hedge situation: currently, KOG is using swaps and "no premium" collars; in hedging transactions, KOG will either receive cash from, or will have to pay cash to, its counterparties in the transaction.
Third, cash balance and its credit facility situation: good, bad, or indifferent regarding its financial situation, KOG provides a glimpse of the potential and the risk of drilling in the Bakken. In 2009, KOG's CAPEX was $27 million. Two years later, in 2011, its CAPEX was $260 million, and for 2012, the company estimates it will spend $650 million to meet production goals. Wow. KOG now has a $750 million revolving line of credit.
Finally, cost-cutting measures. Drilling times, completion techniques, reduction in time to complete wells, lease operating expense. Several data points:
according to the article, KOG has cut drilling time to five days, representing a 3-day reduction
using cemented liners for completing a well (more on that later)
using "zipper fracs" to decrease time to complete a well; completed two well pads in 8 to 10 days by using "zipper fracs," which are made possible by microseismic fracture mapping
bringing lease operating expenses down to $5 range per barrel
cost-cutting measures most helpful in areas (of Williams County) where wells are not as good; KOG expects an internal rate of return fo 20%, assuming well costs of $7 million to $7.5 million EURs of 300,000 bbls
KOG's completed wells cost between $10 million and $10.5 million but hopes to reduce costs by another 5- to 10% in 2013.
Now, about those cemented liners:
In terms of completion, the company is making solid progress by using
innovative techniques, such as cemented liners. This is a completion
technique that involves cementing the liner throughout the horizontal
wellbore, which has the benefits of greater wellbore stability, greater
control of fracture initiation, as well as improved well serviceability. [See first comment and update.]
Long before they started talking about seven and eight long horizontals in a spacing unit in the Bakken, I pointed out that fracking seemed to be effective only about five hundred feet radially (1,000 feet diametrically) and predicted that we would eventually see horizontals paralleling each other about 1,000 feet apart. That is now happening on a regular basis; my hunch is that the separation will narrow.
I have also opined that the farther one gets from the vertical, the less effective the production (for any number of reasons), and I predicted that we would eventually see toe-to-heel horizontals paralleling heel-to-toe horizontals. I now have a great example (and there are others).
At the NDIC GIS map server, go to section15/22 T154N-R91W. Currently there are eight wells in these two sections. The horizontals from these eight wells do not all drain sections 15/22.
The wells:
17080, 2,096, Whiting, Niemi 44-22H, t10/09; cum 459K 12/16;
18507,1,946, Whiting, Lahti 24-22H, t6/10; cum 516K 12/16;
19502, 2,720, Whiting, Niemitalo 31-15XH, t2/11; cum 406K 12/16;
20415, 362, Whiting, Laukala 34-22TFH, t9/11; cum 133K 12/16;
21273, 273, Whiting, Lahti 41-15TFX, t12/11; cum 123K 12/16;
21348, 312, Whiting, Lahti 31-15TFX, t12/11; cum 151K 12/16;
21438, 370, Whiting, Lahti 14-22TFH, t11/11; cum 172K 12/16;
21546, 537, Whiting, Lahti 12-22TFH, t3/12; cum 167K 12/16;
The following two horizontals parallel each other, one toe-to-heel; other heel-to-toe
17080, 2,096, Whiting, Niemi 44-22H, t10/09; cum 459K 12/16;
21273, 251, Whiting, Lahti 41-15TFX, t12/11; cum 123I 12/16;
Granted, one is in the Three Forks, and one is in the Middle Bakken.
As noted above, there are eight (8) wells in these two sections; I could easily see another eight wells in these two sections (again, the horizontals would drain neighboring sections in some cases). But to the surface owner, one would see as many as 16 wells in these two sections.
