February 7, 2013: "
... premium members get production figures in advance." One can get production numbers from "basic services" for $50/month. Production numbers are also free in a monthly report but they lag about a month.
Regardless, here are the oil production/runs for the four wells requested for December, 2012:
- 19585: 16 days -- 2,023 / 1,991
- 20980: 31 days -- 7,435 / 6,860
- 21006: 31 days -- 9,472 / 9,784
- 21007: 31 days -- 9,881 / 9,671
February 2, 2013: I see
enquiring minds are talking about commingling. My two cents' worth. I can guarantee the enquiring minds that the operators know exactly how much oil is coming out of each well. The production from each well is measured/valved before it goes into the tanks. One reason permission to commingle is required dates back to when various grades of oil from different formations were commingled. The crude oil from each of these commingled Bakken wells may vary, but if they do, the variance is minimal. This will not affect one iota one's royalty payments. The second issue raised by the second comment at this thread raises the issue of spacing, which, of course, has nothing to do with commingling. The comment suggesting that spacing favors the operator and not the mineral rights owner(s) is an opinion, not based in fact. Here's an easy example: if the spacing made a proposed well uneconomical, it wouldn't get drilled in the first place. Mineral rights owners in the Bakken are doing just fine, and they are going to do even better going forward. Most never expected one well on their land, much less fourteen wells. 'Nuf said. [Update: Teegue says the operators don't necessarily track each individual well once they are allowed to commingle oil from multiple wells. I assume that's accurate; Teegue is a credible source. I find it incredible that oil companies would be able to get away with this; it seems incredibly easy to measure/monitor oil coming from each well before it is commingled. It seems it would be in the operator's best interest to know how a particular well is doing.]
January 31, 2013: this comment was sent in by CRC earlier today:
Outside of the Bakken and the Williston Basin the rebirth of the Permian
Basin is very interesting. The way the Cline and other tight shale oil
formation are developed will be a nice example of the old way of
drilling by vertical wells spread all over the place in a section of
land and the new spacing units with all the wells on one pad. I'm sure
they are doing that in the Eagle Ford because it is a tremendous savings
in drilling and developing of the wells.
This is a very interesting observation. Dufus and others would have placed 6 vertical wells over each section for 160-acre spacing rather than on one pad. We would have had six (or more) pads on each section of land; we would have had individual roads to each pad. The expense would have been incredible, but worse, the amount of farmland lost would have been incredible. Whether smart or lucky, the NDIC did the right thing for the majority of North Dakotans. Those NoDaks who hate oil wells could have easily seen six or more pads on each section instead of one pad with multiple wells had other folks been in charge. Just an observation.
January 30, 2013: if there is one thing enquiring minds do not like, it is posts about the stock market, investments, and investors. I learned that the first time I posted. Smile. So, it was with some interest when I read a post from Dufus about OXY some time ago, and now
we see another individual posting on Hess as an investment.
Handle with care.
January 25, 2013: speaking of amusing sites,
enquiring minds are developing a very nice thread on the potential of the Bakken. Hopefully the moderator will allow the thread to develop. Smile. One expert argues that additional wells will negatively impact neighboring wells. A year from now we should have some data, starting with the fourteen wells CLR is drilling in one spacing unit in the Antelope oil field. The simplest data point to follow if looking at Bakken potential: the takeaway capacity. The consensus is that North Dakota oil takeaway capacity will be 1.5 million bopd by the end of the year (2013). I forget when such capacity is to double to 3 million bopd but I think its by 2017 if not a whole lot earlier. But the 1.5 million bopd by the end of 2013 was quoted just a few days ago by a reputable source.
[It has been argued that the oil companies have said they could effectively drain one spacing unit with one well; that seems to have been a stretch in hindsight, but if one well could effectively drain one spacing unit, it sure would have taken a lot of time. I suppose taken to its extreme, one could argue that one well could effectively drain the entire Bakken, it being a continuous reservoir. Now, that's amusing.]
January 20, 2013: This question has been resolved at the link, noted at 9:45 pm est, January 21, 2013: an enquiring mind has the same question I do. How does one sort out mineral rights with 5,000-foot laterals on 160-acre spacing that is about 2,500 feet x 2,500 feet. See also the January 16, 2013, note below. Of all the folks who post at that discussion board, I think there is only one who might have the answer. It will be interesting if ell1949 gets an answer. [Several hours later, 3:40 pm: no response to ell1949's question; not unexpected.] [January 29, 2013: I see Dufus is back. Regardless of which side you are on regarding spacing units in the Bakken, two things jump out at me: a) there is a lot of 20/20 hindsight by folks who are making out like bandits with 14 wells on their acreage; and, b) everyone was on a steep learning curve with regard to developing the Bakken. Iraq had their way of dealing with oil wealth; North Dakota had its way. We're all on earth for only a few short years. Those of us fortunate to have it so good, should enjoy it, instead of calculating "what might have been" with another 0.0000003% royalty. IWWJWD.]
January 18, 2013: either I will learn something, or there is some wishful thinking by some (usually I'm wrong, so maybe I will learn something, but I digress.
An enquiring mind says that #20502, Hagen 23-13H, sited in section 13-148-101, is a directional/horizontal well that goes southeast into section 24-148-101. This is a Madison well, and according to the NDIC site, the spacing is yet to be determined (ICO). The enquiring mind says the well extends into sections 14 and 23 to the west; I don't see that at all. I have no idea why someone would think that a Madison well in sections 13/24 would be associated with sections 14/23. It will be interesting to see how this one is answered, assuming someone answers.
[It has been explained; the enquiring mind was looking at the Bakken spacing, when in fact, this is a Madison well. Had this been a Bakken well, yes, the other sections would have come into play. A good question, in hindsight.]
January 16, 2013: elsewhere they continue to discuss spacing in the Williston Basin. It should be noted that some folks continue to compare apples with oranges. In this case the Bakken Pool is being compared with an entirely different pool. Also, comparing apples to oranges, horizontal wells are being compared to vertical wells. In addition, I never see the economics of the well worked out from the oil companies' point of view when this issue is discussed in this context. Beating a dead horse. From my perspective, the NDIC is doing a great job for the citizens of North Dakota when it comes to the Bakken. They seem to "get it."
[Update: second post at the link above -- wow, even folks who have followed the Bakken for quite some time, don't understand the issue with flaring. I am (negatively) impressed. Wow. And suggesting the NDIC is pushing too much drilling. Yeah, I guess "we" need more regulation; let the regulators determine how oilmen manage their assets. Wow.][With
SSN's permits for four (4) Bakken wells with 160-acre spacing posted January 18, 2013, will further the discussion. Smile.]
January 4, 2013: a contributor has remarked on
EOG's results with regard to water injection.
January 2, 2013: an enquiring mind wants to know the difference between "IP" and "IP-30." Apparently this question has flummoxed the discussion group, so I will jump in. The "IP" as generally reported is a self-determined (determined by the operator) production of oil coming from a well in the first 24 hours. Different operators have different ways of calculating this initial 24-hour production. The "IP-30" production is the average amount of oil a well produces over the first 30 days of production. Some analysts also track the 60-day average and the 90-day average, which, I suppose, is written as IP-60 and IP-90 in shorthand. Note: be careful to note the difference between "bopd": barrels of oil per day; and "boepd," barrels of oil equivalent per day, which includes natural gas in addition to oil. [By the way, that question was posted at the discussion board on December 31, 2012. As of January 3, no one had answered the question. Speaks volumes about the contributors to the group. No doubt, folks have found the answer. Smile.]
December 22, 2012: an enquiring mind is wondering whether #22952, Hess, GO-Dahl A-156-97-2536H-2, is a middle Bakken well or a Three Forks well.
The enquiring mind says the file report suggests this is a Three Forks well. I've made the same mistake in the past: mis-reading a sundry form. A sundry form does mention "Three Forks" but it is referencing a neighbor well for "comparison" purposes. But this well is most definitely a middle Bakken well; see the geologist's summary. Additional information: the well was spud July 8, 2012, and reached vertical depth on July 17. Total depth was reached on August 4. Fracked in 30 stages; 2.3 million lbs sand. Along the horizontal gas values were 75 - 7,500 and "several gas tests were done to ensure the accuracy of the equipment." The report did not mention the height of the flare, unless I missed it.
December 14, 2012: enquiring minds have been uncharacteristically quiet lately -- I can understand why.
December 11, 2012: please,
do not mention this site elsewhere; you will be kicked off the board. As my daughter would text, LOL.
December 11, 2012: some interesting reading today over at the other board. Of course, some of it does not make sense because several messages have been deleted. Whatever you do, don't mention the MDW at that discussion group; you will be "voted off the island."
December 10, 2012: Not often do we get such
an informative post elsewhere.
When you get to the link, scroll down about six posts, and read the
post by "Degas." This is an excellent resource for newbies.
December 8, 2012: In the process of looking for something else, I ran across this lively discussion:
reading through this discussion is entertaining. It is amazing how far "we" have come. As just one example:
"My belief is that a good separation for laterals is ~ 4,000 feet and a
good lateral length should be based on economics." -- posted March 4,
2012. I remember that discussion so well. Suzanne had asked a simple question and by the time the discussion was over, she was apologizing for getting so many people upset. So many of the original contributors to that discussion group have gone by the wayside. Just reminiscing on a Saturday night. Some folks appear to have evolved with the Bakken; others not so much.
November 29, 2012: So much for confidentiality, link here.
November 25, 2012: an enquiring mind wants to know why sections 1, 2, 3, 11, and 12, in McLean County are not yet permitted. Of course, not surprisingly, critical information, LIKE THE TOWNSHIP, is missing. But it is obvious it is T150N-R90W. These sections are under the river; there are a lot of sections under the river that are still not permitted. No conspiracy theories. I wonder if it might have to do with who owns the mineral rights under the river: US government (US Army Corps of Engineers); the state; private landowners)?
November 24, 2012: some time ago I referred to some of us being on different planets when it comes to thinking about the Bakken. I think Dave's position about sums it up best at
this post. Some folks must not be following the permitting activity or the monthly NDIC dockets.
November 21, 2012: elsewhere they are talking about how long it takes to get a permit approved. The answer is very, very enlightening and raises an interesting question in the process. First, the very interesting answer:
it rarely takes more than a few days to get a permit approved once the application is received. That is interesting: do you think that will hold true when the federal government regulates fracking in the Bakken? Remember, if the federal government regulates fracking, the in-box will contain hundreds of permit applications received daily from all across the nation. Just thinking about the bureaucracy is Halloween-scary. But I digress. But then this interesting question: once the first well is drilled, all further wells in that spacing unit are "discretionary." It is asked, rhetorically, if the first permit holds the entire spacing unit by production, why are seven more permits/wells required. (And, of course, in the future, it could be more than seven). I thought I misunderstood the question, but it is
explained in further detail here. I would love to comment but I have no dog in this fight. It is what it is. I wonder if there are Solomonic decisions needed based on the differences of pools vs continuous reservoirs? I wonder if North Dakota is unique (compared to Texas, Oklahoma, Pennsylvania) with regard to spacing units in continuous reservoirs elsewhere
?
November 9, 2012: I hope
Tami's question is answered. It will help educate folks on royalties. Tami claims she was told "her well" is on a 640-acre spacing unit, though now she is told it is on a 1280-acre spacing unit. She calls it the "1-Osmund well." That's why permit numbers are so helpful. The spelling was wrong; there is no "1-Osmund" well. It is the Osmond 1-3H well, #19090, East Fork field. The spacing is "two sections" and if she goes to the NDIC site, she will find the spacing on this well is 1,331 acres.
This phrase in her post does not make sense: "I was told I had 160 acres on 640 spacing with 20 net
acres." How does one get 20 net acres out of "I had 160 acres on 640-acre spacing"? So, if this question gets answered I will learn something.
Her question: "I was told I had 160 acres on 640 spacing with 20 net
acres and 3/16 base royalty which gives me a decimal of 0.005859375
-- they show me having royalty at 0.00093380, which is nowhere close
to what I was told from Landman. The guy from Continental said it was
1280 spacing, however even with this, it doesn't reflect a correct
royalty int number."
Working backwards. The 3/16 is likely correct.
(her net acres/total acres in the spacing unit) * 3/16 = 0.005859375
(her net acres/total acres in the spacing unit) * 0. 1875 = 0.00589375
(her net acres/total acres in the spacing unit) = 0.031433
So, if the spacing unit was 640 acres: 0.0314333 * 640 = 20 net acres (her figure)
If the spacing unit was 1280 acres:
(20 net acres/1280) * 3/16 =
(20 net acres/1280) * 0. 1875 = 0.002929, which, is, of course, exactly half of the above figure, and like Tami says, nowhere close to the CLR figure.
Wow, I would hate to be her landman when Tami telephones. My hunch: Tami inherited the acres, but so did a few other children/grandchildren over the years, or her grandparents sold a few of the mineral acres some time ago. The landman did not know about the other heirs. Idle chatter. I may be way off on this but it will be a learning lesson.
By the way, on 1,331-acre spacing, CLR's decimal of 0.0093380 works out to about 66 acres.
November 6, 2012: the boys have noted what Oasis is doing in the Cottonwood field: asking for 23 more 1280-acre spacing units and 8 wells on each.
MDW posted that several days ago.
November 3, 2012: enquiring minds don't dare mention the MDW blogsite by name
elsewhere -- otherwise they would be booted off -- but I have to chuckle. After months (almost two years) of no one talking about potash mining in North Dakota, I see that enquiring minds are talking about it. I posted the same update some weeks ago. I am flattered. Thank you, guys.
We need to spread the word
even if we don't reference the source.
November 1, 2012: NDIC defines Bakken/Three Forks down to the Birdbear. That's where it's always been scientifically/geologically.
October 31, 2012: still lots of chit-chat about the stratigraphic limits, but now
they are simply plain nuts. My hunch is that if NDIC does not approve the requests, the oil companies will simply wait "them" out. Most of their leases are now held by production. If mineral owners want to see more wells, they might want to work with the oil companies. Otherwise, the oil companies will simply wait them out. These guys are nuttier than fruit cakes. I think Dufus is the worst.
They need to move this discussion over to the water cooler. What used to be a pretty good discussion group has become a) entertainment; and, b) an exercise in futility. Again, it makes me glad not to be a mineral owner. Life is too short.
I'm Going Slightly Mad, Queen
October 11, 2012: an inquiring mind wonders about the sharp drop-off in production of a particular well in August; the well was taken off line for twelve days in August -- of course, there is never an explanation in real-time, but my hunch: they're putting in a pump.
October 10, 2012: an inquiring mind wants to know about
- 19051, drl, Surge, Eidsvold 1-10H, Wildcat, a Spearfish well; spud 6/8/10;
NDIC sent the operator a letter indicating that the well has not been completed or produced in over a year, and is in violation of Section 43-02-03-55 of the North Dakota Administrative Code (Abandonment of Wells). The rule that states that the failure to produce a well for a period of one year constitutes abandonment of the well. Any such well must be plugged and the site reclaimed. And the letter goes on.
October 9, 2012: enquiring minds noted the dry holes on today's daily activity report. Except for the Samson Resources Lodgepole well, it appears
these are changes in the operators' plans; not "true" dry holes in the sense that I think when I see "dry" holes. This gives us a chance to see how life on another planet sees this one.
[Update, October 10, 2012: so far, they've missed the reason for the "dry holes."]
October 5, 2012: enquiring minds are debating the issue of "free" vs the $50 annual basic subscription rate. I agree with David. And I own no mineral rights.
October 2, 2012: time for
this discussion to be moved over to "the water cooler." I'm waiting for the results of the hearing regarding
the requests to alter the definition of the Bakken/Three Forks stratigraphic limits.