Thursday, June 20, 2013

"A Major Fracking Project" -- Something New? More Of The Same? New Company In The Bakken? -- June 20, 2013

Rigzone is reporting:
Southwest Engineers Inc., a full-service civil and environmental engineering consulting firm, announced it has signed an extensive agreement with Earthwater Resources Inc. for a major project on the Bakken Shale oil and gas zone in North Dakota. The project includes drilling and transporting water from a previously undiscovered, nontraditional, groundwater resource to multiple filling stations for the successful fracking of oil and gas wells in the region.
That was from a press release no doubt.

Now, Earthwater Resources?
From Waterworld, the same press release:
A major fracking project on the Bakken Shale oil and gas zone in North Dakota is underway to include drilling and transporting water from a previously undiscovered, nontraditional, groundwater resource to multiple filling stations for the successful fracking of oil and gas wells in the region.
So, we have:
  • WAWS
  • independent water providers
  • EarthWater Resources / Southwest Engineers

Wyoming Shenanigans -- Update; EPA Closes The Books On This One

The Wall Street Journal is reporting:
The Environmental Protection Agency said Thursday that it would drop an investigation that had linked contaminated water to natural-gas drilling in Wyoming, in a boost for Encana Corp. and other firms that practice the drilling technique known as hydraulic fracturing.
The EPA will allow the state of Wyoming to continue the investigation but doesn't "plan to rely upon the conclusions" of its previous study, the state and the agency said in a joint statement. 
Platts tweeted this:
Wyoming to take lead in study of Pavillion-area groundwater pollution, as US EPA backs away from linking it to fracking.
The tags will take you to the many other posts regarding this subject.

Wells Coming Off The Confidential List Friday

24101, 316, Samson Resources, Bakke 3229-5MBH, Ambrose, t41/13; cum 6K 4/13;
24249, 441, G3 Operating, Poeckes 1-14-23H, Climax, t4/14; cum 6K 4/13;
24265, WI, Enduro Operating, MRPSU 19-24, Mouse River Park, no data


24101, see above, Samson Resources, Bakke 3229-5MBH, Ambrose:

DateOil RunsMCF Sold

 24249, see above, G3 Operating, Poeckes 1-14-23H, Climax:

DateOil RunsMCF Sold

Notes From Another Planet -- Page 4

June 15, 2013: an enquiring mind wonders why the production numbers for four (4) wells didn't show up on the NDIC April production report. I have no idea what he/she is talking about; those wells show on my copy of the NDIC April production report. It also appears, based on other threads at the site, some folks are unaware of the staggering infill program that has begun in the Bakken. Some are aware of the program, but some are unaware of it.

June 13, 2013: enquiring minds are struggling with the definition of "increased density." It is a natural progression from wildcat to drilling out established oil fields. The definition can be found in multiple locations but even this site has the definition; it is simply another name for "infill" well. There are so many story lines here but I won't get into them. Too many inconvenient truths. This is one.

June 12, 2013: in this thread, an enquiring mind is asking for location of the wildcat mentioned at the very beginning of the thread. I assume they are talking about a wildcat well on the confidential list that is about 25 miles southeast of Minot:
June 11, 2013: An enquiring mind says Lynn Helms has suggested 48 wells/1280-acre spacing unit. If that's an accurate quote, two comments: a) not likely the norm for the Bakken; and/or b) by the time they get to that many wells/spacing unit, they will be moving to EOR. I am unaware that Lynn Helms actually said that, and I have not been able to find a link. Elwood provided the link: This would be in the "better Bakken" and a) it would not be the norm; and, b) in general, everything Helms has said has been pretty much come to pass, just as most of what Harold Hamm has said has come to pass. [One day later: expected as much -- interesting to see how one rant shuts down the discussion group.]

June 11, 2013: This might be interesting to follow -- a series of OXY USA wells in Manning oil field. [One day later: "or not."]

May 30, 2013: an enquiring mind wants to know the permit numbers for the eight wells that Surge is cancelling. They are listed here That was easy.

May 8, 2013: I always enjoy these little bits of cocktail chatter. It helps one understand the Bakken. An enquiring mind is asking if anyone knows whether the horizontals will run north or south with regard to #25328 and #25329. It is said that "25329" is not shown on the map; in fact it is, if one zooms in. Based on how far they are set back from the section line, my hunch is both will run south. If they were going to run north, they would have been sited closer to the section line. That's my hunch. For what it's worth.  However, the name of the wells provide the answer. Both #25328 and #25329 are "Tuhy" wells, which means both horizontals will run south; if they ran north, they would be named State Lazorenko wells. #16451, a Gerald Tuhy, well is in the same section as #25238 and 25329, and Gerald Tuhy runs south.

May 4, 2013: enquiring minds are not yet talking about the 23 cases in this month's NDIC hearing dockets in which the oil industry is assessing risk penalties against non-participating owners; the results (which won't be broadly accessible) will be interesting.

April 15, 2013: It looks like one enquiring mind is about to be voted off her own island. Unless I'm missing something, her recent note suggests that she is questioning the authority of the NDIC to allow more than one well per spacing unit. She may be correct. I don't know. Two issues: the code was written for "pools" and conventional reservoirs; and, unintended consequences. I have said many times, those mineral owners with one well in the "very best" Bakken will have at least 12 wells before this is all over; those in the "good" Bakken will have at least 8 wells; and everyone should have a minimum of 2 wells, maybe 4 wells. (My numbers have changed over time as the Bakken experience has changed.) One individual has written me who has two wells and he expects to have at least 24 wells before this is all over. I think we're too far down the road to put the genie back in the bottle, but my hunch is that anyone seriously arguing for only one well per spacing unit in the Bakken will be, as I said, voted off the island. Her other alternative is to win one of the three statewide offices that would make her a member of the NDIC.

April 12, 2013: it looks like following the Bakken Shale Discussion Group is about ready to come to an end for me. I've learned a lot from the site. Teegue is an incredible fund of knowledge. But the contributors are starting to become downright nutty. 

April 11, 2013: scroll down to the April 11, 2013, discussions at this thread to see the folks who are getting ready to sue the Bakken operators are starting to get their facts together regarding fracking. According to the "the enlightened one," fracking has two "faces." I suppose that's possible. I would have assumed the fracking was radial in nature, but perhaps the fracking is designed to frack along two faces. It would be quite a trick. It is interesting that they have stumbled upon the fact that natural fracking extends from "zero" to "infinite" and every point in between. That is absolutely accurate and makes this whole issue very, very problematic. In some areas there may be no natural fracking; in other areas the natural fracking may be so extensive, manmade fracking is hardly needed. Obviously that would affect the size of the spacing units if done "scientifically/geologically." This is going to get very, very interesting, very, very quickly.  

April 5, 2013: It appears enquiring minds are ready to spend their money for lawyers. I've seen this movie before and it's not going to be pretty. Wow, I'm glad I don't hold any mineral rights. There is a recurrent theme at the discussion group that some folks are worried that oil companies are going to hold leases by production and then not drill wells. Not gonna happen. All they have to do is look at the GIS map server and look at the monthly dockets. CLR, OAS, BR, and KOG, just to name a few of the more prominent names are pretty much Bakken-centric and can't quit drilling -- not at these prices. And if the price of oil plummets, mineral rights owners would be better off if the companies waited to drill anyway. Sure, companies with plays elsewhere, like Hess and EOG, might be not as concerned about drilling in the Bakken, but my hunch is that these examples are far and few between. Everything I've read suggests operators are drilling as fast as capex, takeaway capacity, workforce, and environment allow them to drill. Another author who said it much better than I (said it).

April 3, 2013: where's Dufus? Elwood needs to take his comments on Mr Helms over to the water cooler

April 1, 2013: sounds like they need to take this to the water cooler. It sounds like someone doesn't understand the bureaucracy. Maybe we should let the Feds regulate the oil and gas in North Dakota.

April 1, 2013: an enquiring mind has an unfounded worry. But folks could provide him/her a lot of information if he/she provided permit numbers, or legal well names. If folks want information, they have to come at least halfway with information. But to answer his question: he will have at least four more wells if he has one well in the Bakken. And, so, yes, he will see a lot of dime. And $100 bills.

March 31, 2013: someone is as tired of "Wormy" as I am.

March 31, 2013: I see enquiring minds are asking about overlapping 2560-acre spacing units. A quick explanation can be found here I'm sure Dufus will see this as a land grab by the nasty oil companies. And, yes, the individual at his post is missing something.

March 29, 2013: the disparity in the knowledge about the Bakken is incredible. The boom began in 2000 in Montana; in 2007 in North Dakota. I have been posting up to ten (10) Bakken posts daily since 2009; some days more. And still there folks who don't know the basics when it comes to the Bakken. I see some enquiring minds are wondering what "LOC" means when it comes to NDIC oil and gas permits. To the best of my knowledge, "LOC" does NOT mean "site is being prepared." Based on what I've seen, "LOC" means a permit to drill at a specific location has been issued. If "LOC" means a site is being prepared there a lot of sites that seem to take forever to be prepared (#21387 was issued a permit back in April, 2012, and is still "LOC"). In addition, QEP spent a lot of money preparing a site for #18956 for naught; that permit was cancelled if that's what LOC means. 

March 23, 2013: Rufus, I see, can't see beyond her own wells. (same link as an earlier one) What a dufus. The first thing that caught my attention was the the fact that it was likely that the operators in the San Juan Basin were eying Bakken-like shale. Then I noted the potential, about 6 billion bbls, very similar to the USGS estimates for the Bakken. And then this: the more states that embrace fracking, the better it is for all of us. Nothing like "scaring" folks away from "her" discussion group. That was the first time I saw Will at the discussion group; what a nice welcome from Rufus.

March 20, 2013: with the NDIC site now down for five days, I see that folks at the Bakken Shale Discussion Group are starting to post stories about the very interesting, highly prolific, much talked-about San Juan Basin in New Mexico. 

March 9, 2013: well pad surface rates.

March 1, 2013: very, very reliable source providing very, very interesting information. See Z-Man's input at this thread; looking for time-date stamp of 11:51 a.m., March 1: 
Re: the Polar - they're doing a 6 middle Bakken, 6 Three Forks pilot there (3 in the upper bench, 3 in the 2nd bench), wells 800 feet apart and in the TFS, 50' apart vertically ... testing communication on a bit bigger scale than they have in the past. Results by year end.
Over two years ago, one can find posts suggesting that the effectiveness of fracks in the Bakken suggested 500-foot separation. They're getting closer.
These are probably the wells Z-Man is referring to; this was taken from a post dated December 14, 2012:
With regard to the eight new KOG permits: all eight are in the same section - 27-154-98. There are already three other wells in this section, all on confidential status, which means that there will be eleven (11) wells sited in this section. So, these are the permits for this section (the P Wood wells are tracked here):
  • 24374, conf, KOG, P Wood 154-98-3-27-34-14H, Truax,
  • 24375, conf, KOG, P Wood 154-98-3-27-34-14H3, Truax,
  • 24376, conf, KOG, P Wood 154-98-3-27-34-15H, Truax,
  • 24604, conf, KOG, P Wood 154-98-4-27-34-13HB, Truax,
  • 24605, conf, KOG, P Wood 154-98-4-27-34-13H3, Truax,
  • 24606, conf, KOG, P Wood 154-98-4-27-34-13HA, Truax,
  • 24607, conf, KOG, P Wood 154-98-4-27-34-14H3, Truax,
  • 24608, conf, KOG, P Wood 154-98-2-27-34-15H, Truax,
  • 24609, conf, KOG, P Wood 154-98-2-27-34-16H3, Truax,
  • 24610, conf, KOG, P Wood 154-98-2-27-34-16H, Truax,
  • 24611, conf, KOG, P Wood 154-98-2-27-34-16H3A, Truax,
In addition to these, add these two:
  • 24649, conf, KOG, P Wood 154-98-3-27-34-14H, Truax, 
  • 24650, conf, KOG, P Wood 154-98-3-27-16-3H, Truax, (running north)
March 1, 2013:  I am eager to see the replies. I do believe this contributor has asked the same question some time ago.

Notes From Another Planet -- Page 3

March 1, 2013: after this post, I will be starting a page 4 of this highly popular segment of the MillionDollarWay. This should get everyone's attention. The site is actually inside Williston city limits according to the NDIC GIS map servers, in the northwest corner of Williston, and the northwest corner of section 15-154-101.  I believe this information is not new: this BEXP site has been discussed before. But it will be very, very interesting to follow. It appears Google maps now shows the pad. It is almost exactly two miles west of where the Williston bypass intersects "2&85" north of Williston. Compared to other single well pads in the immediate area it seems to be about two- to three-times larger.  There is currently one 4-well pad, three of which are on DRL status and run south; the fourth is still confidential. 

February 26, 2013: an enquiring mind wonders why a well has been placed on inactive status after only a few months of production. There are four wells on this pad; all wells look quite nice; one looks very nice. The scout ticket shows them all without a pump (F). My hunch is that now that all wells are in, CLR is ready to start putting in pumps. 

February 26, 2013: a reader inquired about a recent permit for a microseismic array. Perhaps this thread will develop into something. By the way, the microseismic arrays are one reason the Bakken has been so successful.

February 25, 2013: this is an interesting data point -- the price point for a multi-well pad in the Bakken. The writer at the link suggests $8,000 / 5-acre single well pad was what he remembers from a few years ago. He is curious what current multi-well pads "go for."

February 19, 2013: an enquiring mind asked about production number for two Big Bend wells; provided

February 19, 2013: an enquiring mind is looking for production data for five wells. It would be a lot easier if permit numbers/file numbers would be provided. Having said that, three of the wells are "Oil for America" wells and are "dry" for all practical purposes. The Sharon well had an IP for oil of "zero." The fifth well, an SM well, had an IP for oil of 23.

February 14, 2013: Yesterday I noted three interesting threads over at the Bakken Shale Discussion Group.

The third of the three, regarding 160-acre spacing in the Parshall oil field just got more interesting. It is important to note that I am not saying this is 160-acre spacing, others are saying it.

From that thread that started the discussion:
The first 160-acre spaced wells in the Core area, the Wayzetta 022-1509H and 149-1509H, had maximum rates of 1,185 and 1,265 Bopd, respectively.
  • 22703, conf, EOG, Wayzetta 22-1509H, the well file shows this well to be on a 1920-acre spacing unit, going through three sections, 9/10/15-153-90. The well is still on confidential, so Larry must have source of information to provide an IP. 
  • 22704, conf, EOG, WAyzetta 149-1509H, the well file shows this well to parallel #22703 -- 1920-acre spacing through the same sections, 9/10/15-153-90; the well file includes a drilling report suggesting this well has been drilled, waiting completion at time of filing. The well is still on confidential, so Larry must have a source of information to provide an IP.
February 14, 2013: an interesting question, five years into the boom, and I quote verbatim, the subject: "lawers of oil." The question: "we were hearing about diferent lawers of oil , above and below the backen , what has been the decission to drill for these lawers of oil ? or are they draining to towards the backen so need for more drilling?" Sort of reminds me of a question that was asked earlier.

February 10, 2013: this will be an interesting thread to follow. The thread has gotten a bit off-topic from how it started, but it will shed more light on the Bakken. An enquiring mind noted that a Three Forks well produced a bit of oil initially, and then no more oil, but only natural gas. Another voice who seems to know what's going on suggests that "fracking into a gas cap" is unlikely since "shales & 'shale-like' reservoirs don't have gas caps in the conventional sense.  So, something to follow.  I have seen this once before in the Bakken.

The discussion relates to this well:
  • 21484, 1,483, BR, Bartlett 31-16TFH, t9/12; cum 2K 12/12; with the following production:

PoolDateDaysBBLS OilRunsBBLS WaterMCF ProdMCF SoldVent/Flare

February 7, 2013: update: my answer was incorrect; the unusual spacing unit was due to the boundary of the National Park; my explanation following is incorrect;  an enquiring mind noted an unusual spacing unit. The Bakken spacing unit for the following wells are noted, according to the NDIC GIS map server, to be a 1600-acre spacing unit encompassing sections 5, 8 and the northeast half of section 17-140-100. There are several1600-acre spacing units on the GIS map server and there are 1700-acre spacing units that are similarly unique. The odd-shaped spacing units allow the spacing unit to fit inside a designated oil field. The NDIC had a couple of options: change the boundaries of the oil field, or designate a unique spacing unit that fits the existing the oil field. It makes a lot more sense for the oil company / the NDIC to simply "fit" the well into the boundaries of the existing oil field. There are two wells in this peculiar-shaped spacing unit:
  • 24236, drl, Whiting, Babeck 31-5PH, Park,
  • 24237, drl, Whiting, Babeck 41-5PH, Park,
The spacing unit is interesting, hardly unique, and easily explained. [Again, I'm wrong, but we got the answer: it has to do with the National Park boundary. A huge "thank you" to "anonymous" for the explanation. From my perspective, it seems the unusual spacing was not capricious or arbitrary, but has a reasonable explanation. ] 

Notes From Another Planet -- Page 2

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.

Notes From Another Planet, Page 1

September 28, 2012: elsewhere they are talking about the decline in the number of active rigs in North Dakota. It was opined that when a major operator is down to four (4) rigs in North Dakota, "peak drilling" is in the past. That "major operator" has never had more seven rigs in North Dakota (during the current boom) and even back in February, 2011, had plans to cut back to five, and decrease the number of frack teams to two. The number of active rigs in North Dakota has decreased, but I'm not sure the number of wells completed/month has decreased. Investors should see some nice reports going forward: the price of oil is trending up and drillers are producing more oil in North Dakota WITH fewer rigs. The "Bakken rigs" are (much?) more expensive than the traditional rigs, it should be noted.

September 26, 2012: enquiring minds remind us that a second (or third or fourth or ...) lease is not needed on acreage where there is already a producing well (don't take this out of context; there are exceptions). However, that's not the reason for the post. A comment is made at the link regarding "perjury." Pretty strong words. It references the argument of large spacing units vs small spacing units. A review of the dockets suggest that Bakken spacing units are growing in size, not getting smaller. I am not yet aware of more than a handful of Bakken spacing units getting smaller (and they may have been small to begin with). It will be interesting to see if existing1280-acre units (or existing 640- or 2560-acre units are broken into smaller spacing units going forward). MDW will be watching.

September 18, 2012: Tami, elsewhere, is wondering "where Continental Resources, in relation to a Newfield well, came from." Okay. See my note of August 20, 2012, below. Continental Resources is one of the biggest operators in the Bakken, and is one of the leading promoters of the Bakken. CLR recently acquired some Newfield acreage (including the wells). MDW posted this:
Press release, Oct, 2011: acquired 22,600 net acres --> 923,270; from NFX for $275 million (small production; 8 drilled/unfracked wells) at: It's too bad some sites make this blog off-limits. This blog is considered "nonsense" by some. Whatever.

September 18, 2012: elsewhere they are talking about Mountainview Energy; a quick glance here might help.

September 18, 2012: see my August 20, 2012, note below. I am glad to see that he found the answer on his own, but, again, come on, guys, we've been blogging about the Bakken for a couple of years now, and the boom is at least five years along in the North Dakota Bakken, maybe 12 years along in the Montana Bakken. There's no such thing as a dumb question, but some questions have been answered so many times, ...

September 14, 2012: inquiring minds had questions about a well, permit/file # 19468. It was opined that the pump was put on in August, 2011. In fact, one can tell that the pump was more likely placed in January/February, 2012, time frame. In August, the well was off-line only 6 days, hardly enough time to put in a pump. On the other hand, in January/February, the pump was off-line 39 days in January/February, 2012, the time consistent with putting in a pump. In addition, the data provided by the NDIC confirms that the status of the well, "AL," was 2/7/12 -- February 7, 2012. This data was all available to the individual answering the question. [Update, September 16, 2012: I see that after I pointed out the obvious error, Elwood provided a much better (and no doubt, correct) response. I'm not sure about the comments regarding production decline due to a new well, but Elwood is probably correct.

August 30, 2012: elsewhere an interesting question was asked: does the size of the flare correlate with oil production? This is my understanding. The flare may correlate with the initial production but does not correlate with ultimate recovery (over the life of the well). Think of natural gas as the bubbles in a bottle of Coca-Cola, with the liquid being the crude oil. When the top of the Coca-Cola bottle is opened quickly, the liquid spurts out, being carried out by the bubbles. If one opens the cap very slowly, and/or if the Coca-Cola goes "flat" for any reason, the liquid will not come spurting out. Regardless of whether there are bubbles or not in your bottle of Coca-Cola, all things being equal, the amount of liquid is the same.

August 25, 2012: elsewhere "Burke" wants to know about 163-100-7. This would be permit/file number #22516. It is a St Mary well still on confidential; based on other wells in this area, this well will most likely be a long lateral going north into sections 7 and 6, Colgan oil field. If so, it is already in production, with 1,998 bbls run in June, 2012. Runs were first recorded in May, 2012. [Update: November 22, 2012: this is a Three Forks well; t7/12; cum 43K 9/12; -- not bad for a well this far north.]
August 23, 2012: elsewhere "Platestealer" is asking about a Hess 6-well pad. Here the results are, updated through more recent reporting period.  For newbies, it should be noted that Eco-Pad is a copyrighted name by CLR and refers to a CLR 4-well pad (I don't know if CLR limited it to a number of wells, or simply a multi-well pad). But Hess is drilling multi-well pads, not Eco-Pads, as far as I know.  For more on CLR's eco-pads, click here.

August 23, 2012: elsewhere Andrew says Hess permits #19454 and #19452 are expired but the NDIC site, today, says status of both permits are "LOC." Nothing about being expired or canceled, according to "Get Well Scout Ticket Data." The GIS map server does show the permits as expired. My hunch is that the paperwork is in the mail. I've seen this before, but maybe they have expired. #19456, RS-Ball-157-90-2227-1 was just completed 6/12; with an IP of 197 (typical for Clear Water oil field).  #19457 on that same 5-well pad was also completed 6/12 with an IP of 149.  [Update, September 15, 2012: "guppy" is correct -- the well files have a statement by Hess that it wanted to renew the permits; the request could easily be missed by the folks at NDIC.]

August 22, 2012: elsewhere they're wondering when #20557 comes off the confidential list. That permit has been canceled (EOG, Liberty 24-2531W, Parshall);  it was canceled July 26, 2011 -- over a year ago.  "Wormy" is usually on top of things.

August 22, 2012: Clifford asks one of the best questions about wells regarding pumps. I don't think a lot of folks understand the concept to which he alludes. Great question; great observation.

August 21, 2012: see note below, dated August 20, 2012. Today we get this query: is there any explanation why a certain well (#19731) produced only 3,350 bbls in June This well produced 5,765 bbls of crude oil in June; the company sold 5,634 bbls of crude in June; and it produced 3,350 bbls of water. It's a nice well.

August 20, 2012: this note will come off sounding a bit "catty," so I apologize in advance. It has to do with this thread, linked.  I have no idea why folks have not learned to provide file numbers for wells in question; names would be nice, but there are so many wells with similar names that they can be confusing. In this case, neither the name of the well, nor the file number was provided. So to get the data, one has to go through a series of links/web pages to find the data. If the file number had been given, the answer could have been arrived at a whole lot sooner. I am not the only one who has mentioned this; it has been mentioned by others, including "Karen" who did a great job for years providing data for that discussion group but quit some time ago. Despite all she provided for that discussion group, she was never properly thanked, at least that I can recall. But I digress. Here's what caught my attention and the reason for the post: I am  amazed that folks who have been receiving royalties for years from the Bakken and follow various Bakken sites regularly still do not understand basic difference between "production numbers" and "runs." In this case, yes the well produced about 3,800 bbls of crude, but the company only sold ("runs") 3,400 bbls.  For newbies, this would be expected; but for those who have been receiving royalties for years and follow the Bakken on a daily basis, come on. The boom started in Montana in 2000 and in North Dakota in 2007, 12 and 5 years respectively now.

August 18, 2012: avoid this thread. Unless I'm misreading the first two comments, some folks think the Three Folks is "shallower" than the Bakken.  I'm probably misreading it.

August 17, 2012: folks are talking about the Dublin oil field; see questions asked. I tend to discuss things the way I would talk about them if having lunch at the Economart in Williston. So, here's my rambling thoughts. The Dublin field is one of hundreds of designated/named fields in the Williston Basin of which the Bakken is a part.
The Dublin field has not been all that exciting, so getting $1,150/acre is not bad. I would be happy with that. With electronic transfer, you should expect to be paid within 30 days after signing the lease (I don't own mineral rights; have never gotten a lease; have no personal experience, but that's common sense. But the oil companies in the area are very, very busy, and it could be much longer, I suppose before they get all the paperwork complete.) Getting a lawyer involved is easier said than done, especially when you live overseas, and I wouldn't worry about that.  Twenty (20) percent "royalty" is standard in the Bakken.

A section is 640 acres, one mile square, or one square mile. Each side of the section is one mile long. Spacing units are generally 1,280 acres now. Companies are drilling one well into each spacing unit to hold the lease. Once they have a producing well on a spacing unit, they hold the spacing unit/the lease as long as the well is producing.  Once they have their first well, there is less urgency to drill more wells in that unit.

Back of the envelope calculations: this is how you calculate how many bbls of oil you "own" based on 20%/160 acres/1280-acre spacing.   For every 1,000 bbls of oil that is taken out of that 1280-acre spacing unit, you "control" 160 acres.  So, 160/1280  --> 12.5 percent. However, you will receive only 20 percent of that, or: 2.5%.  So, for every 1,000 bbls of oil that is taken out of the 1280-acre spacing unit, you would get 25 bbls. Assuming I did the math correctly. I often make mathematical errors, so I welcome corrections.  If they net $75/bbl, you would get $1,875 for every 1,000 bbls from that well.  Your royalty check will also include some payment for dry natural gas and wet natural gas by-products coming up with the oil.

Bakken wells have a horrendous decline rate. Even if it's a great well, the production will drop off quickly. Early on, a good well might produce 5,000 bbls/month, but over time, it will go down to 300 bbls/month. Every well is different. Again, I am talking with you as if I was talking over lunch. This is not legal information; it is just idle chatter, and I would enjoy hearing other people's thoughts on these numbers. If you explore this blog, other sites, you will get a feeling for the Bakken and the production of a Bakken well.

In the best Bakken, they will be drilling 8 wells/spacing unit. Zenergy has already requested to put up to eight wells/spacing unit in Dublin oil field. It will be a very long time before they get that many wells in the Dublin oil field.

I will update the initial production numbers (IPs) and the cumulative production of wells already producing in the Dublin oil field area. 

I assume you have a 5-year lease; that is standard. The company has five years to drill a well on your lease if that's true. They generally drill as soon as possible. They need to get a permit from the state to drill; that has not been accomplished yet as far as I can tell.

If they get a permit, it will show up on the map at the NDIC website. Once they get a permit, they generally start drilling within the year, but not necessarily. Permits are good for one year, but they are easily renewed on a yearly basis. The permit is between Crescent Point Energy and North Dakota; nothing for you to be involved in.

Right now, it's simply wait and see.
August 13, 2012: a nice little discussion of a "pipe stem hole." But that's not the reason I posted the link. I posted because they mentioned a "workover rig." In the conference calls for 2Q12 earnings for two different Bakken-centric operators, the issue of work over rigs came up. It appears that, at least for one operator, a ratio of 1.5 work over rigs to drilling rigs is their desired norm; that same operator or another operator (I forget) indicated they were looking to find six (6) more work over rigs. 

August 6, 2012: I remember Rufus kicking me off the board some years ago because he thought I was "pumping" stock. Now, I see he is linking the transcript of OXY's earnings conference call. Interesting. It is particularly interesting he chose OXY: I recently singled out OXY and its comments about the Bakken. But back to the original point. "Milliondollarway" has nothing to do with investing; I resisted incorporating information about investing on the blog, but it was obvious that it was impossible to separate the Bakken from investing if one wanted to learn as much as possible about the Bakken. I guess others are starting to see that. After 12 years into the boom.

August 3, 2012: Five years into the Bakken boom, "GJ" has noted that water is being brought back to the surface when the well first starts producing (when the IP is reported).  The initial water that returns to the surface is mostly the water used in fracking. After that initial regurgitation, water brought to the surface is salty water, having nothing to do with the water table (fresh water). That water brought to the surface is an expense for oil companies to remove and place in salt water disposal wells elsewhere in North Dakota.

August 1, 2012: in the August, 2012, NDIC dockets, there were several cases requesting new stratigraphic limits for the Bakken. I think the first comment at the link is wrong but the discussion might be interesting to follow, assuming anyone else responds. [Yes, others responded, and as usual, Teegue posted an outstanding comment. He brought up a couple of issues, one that has been problematic for "newbies" like me for years. It was nice to find out that it wasn't just me that was confused. For those interested in this subject, skip all the chatter at the link (except for background) and go directly, do not pass "go," to Teegue's comment.] [Later: it appears that a couple of folks at the linked discussion group can post "water cooler" gossip even if others cannot.]

July 26, 2012: a query about Hebron field; I've been curious myself.
[Later: now we now, see the August 22 - 23, 2012 dockets -- 18453, CLR, amend Hebron and/or Squires-Bakken; create 2 overlapping 1920-acre units, 6 hz wells on each (12 wells); create an overlapping 1920-acre unit, 1 well; create an overlapping 3840-acre unit, 4 wells; create 2 overlapping 2560-acre units, 2 wells on each (4 wells); create an overlapping 256-acre unit, 14 wells (not a typo); create 2 overlapping 2560-acre units, 12 wells on each (24 wells);  create an overlapping 2240-acre unit, 12 wells; a total of 71 wells?, Williams County;
July 20, 2012: price differences for the same Bakken oil; transportation, contracts, etc.

July 17, 2012: "this is a WOW!" Llano -- with a 6,800-bbl IP.  [Yes, and that was a huge typo. I assume the intern has been fired.]

July 11, 2012: folks are talking about price of shipping by railroad

June 24, 2012: this thread suggests another reason for a perceived backlog in fracking. In some cases, it is possible that road restrictions or other reasons are keeping frack crews from getting to a well. It's always something. 

June 21, 2012: elsewhere questions have been raised regarding four new wells on proposed 2560-acre spacing where two producing wells are located, each on 1280-acre spacing. This is an instructive case. I was hoping more knowledgeable folks than I would weigh in; it would help newbies to understand the Bakken. We are going to see a whole lot more of this. [Update: Teegue has provided an outstanding answer to the question raised at the linked thread. The justification provided by the drilled for 2560-acre spacing had to do with the 400-foot off-sets from the edges of the spacing unit (generally section lines). His answer also provides an answer to an issue I've never understood: Zones. Great answer. Needs to be read by all.]  As long as the driller drills four wells in a 2560-acre spacing unit, I do not see the downside of a 2560-acre spacing unit. Even three wells in a 2560-acre unit would be better than one in a 1280-acre unit.
Issues and answers as I see them:
  • wells are permitted for specific spacing units; those spacing units stay with the wells. For example, 160-acre spacing for a Madison well will remain 160-acre spacing even if a 1280-acre spaced Bakken well is permitted. In this case, two CLR 1280-acre spaced wells are currently producing. It appears the case is pending to determine the spacing, but most likely four CLR wells will be permitted on 2560-acre spacing. If so, it won't affect the spacing of the two wells currently producing.
  • each horizontal will be a two-section lateral, but will be spaced for four sections; in this case the four sections are all in a north-south line. Anyone owning minerals in any of these four sections will participate in all four wells. Theoretically, I guess, it's as good as one well on 640-acre spacing. 
  • The writer worries about "poorer" sections to the north "diluting" the value of the "better" sections to the south. Assuming that is an accurate assessment of the "north sections" vis a vis the "south sections," mineral owners don't have to worry about "dilution." They participate in all the wells. Even if a mineral owner owned only 10 acres in the toe of the southernmost section, she would participate in oil being produced from the toe of the northernmost section. Sweet.
That's how I see it. I could be wrong. Four wells on 2560-acre spacing --> one well/640-acre spacing (all mineral owners in all four sections participate in all wells). Obvious one well/640 acres is better than one well/1280 acres. The four wells are close together and they are CLR wells, so a 4-well Eco-Pad is possible, but it looks like their will be two closely spaced pads based on the NDIC GIS map, but I am quite unsure about that.

June 20, 2012: the folks over at the Bakken Shale Discussion Group have also noted the relationship between CLR and BR with regard to the Midnight Run wells

June 17, 2012: Bakken oil millionaires are talking about their first paycheck, but look at those taxes. Wow!

June 14, 2012: Elsewhere "schmitty" mentions probate.
This is a great time to talk about probate and mineral rights. Do whatever it takes to get your property to whom you want it to go before you die. If at all possible, don't let anything go through probate. Probate will tie things up for quite some time but that's a minor problem compared to the bigger problem. Having done title searches I can tell you it will take hundreds of hours to sort out who owns what minerals, and for lawyers those are billable hours. After three generations of North Dakotans, oil rights have been spread out among thousands, and the proportions have grown smaller and smaller. In many cases, one can almost guarantee that any potential for mineral rights will be lost in probate. You might as well assume most of your oil money will be lost in probate if you area a small player. Many would recommend a family trust.
June 14, 2012: Elsewhere it is being noted that operators are starting to put in three to four wells per section. Allen provides a nice update on Newfield's second Charlotte well.

June 13, 2012: Elsewhere Tj is asking what is meant by open hold fracture completion.

Baker Hughes animation

June 13, 2012: Elsewhere I see Rufus is now following the stock market

June 13, 2012: Elsewhere jbird is asking if there is an error in the legal description of two Hess wells. There are no errors. These two wells are about 50 feet from each other on a 2-well pad. One horizontal will jog over to the west a bit and run north through sections 7 and 6. The other horizontal will go straight north through sections 8 and 5. The two wells will parallel each other.  [Add, June 16, 2012: the linked discussion group is probably the most-involved group of Bakken folks and yet the level of their questions remind us how little so many folks know about the Bakken. Twelve years into the Bakken boom, I find it incredible.]

June 11, 2012: Elsewhere Tj is asking where to find fracking data. I understand there may be several websites that have that data such as FracFocus. The source of course is the NDIC web site. The "milliondollarwayblogspot" often posts fracking data taken from multiple sources. The MDW blogspot is "searchable." It's best to search by file/well/permit number.
June 10, 2012: file under "No Such Thing As A Dumb Question."  Elsewhere "Platestealer" is asking how many folks employed by the operator actually work on a rig. I was quite surprised by the excellent answer.

June 5, 2012: Elsewhere "Platestealer" is looking for a source for aerial photos. An excellent source for aerial photos is Vern Whitten Gallery. Another source is  Robb Siverson. There may be other sources at this blog, but this is a start.  (Here's another one: Overland Aerial Photo which I missed but is also at the blog at this link.)

June 4, 2012: Bazel wonders about the decline rate in the Bakken. Here are the cumulative of some of the wells noted:
  • 19731, 1,800, BEXP, Irgens 27-34 1H, East Fork, Williams; t9/11; cum 59K 4/12;
  • 20639, 2,901, BEXP, Judy 22-15 1H, East Fork, Williams; t9/11; cum 93K 4/12;
  • 20640, 2,597, BEXP, Irgens 27-34 2H, East Fork, Williams; t9/11; cum 62K 4/12; 
As Mark Twain was reputed to have said, I would rather have a free-flowing IP of 5,000 bbls, than a 1/2" choke with 0 bbls. I don't think investors are watching IPs as closely as mineral rights owners are. See poll.

June 3, 2012: "Eastern MT" elsewhere wants to know about #22374, Whiting's Quale. A bit of the story can be found here. Whatever you do, don't mention the "Million Dollar Way." As usual, Teegue provides some great information. Whenver Teegue posts, you can be sure he/she posts some good information.

May 29, 2012: CLR assumes some Newfield wells? Here are the wells. It will be interesting to see if anyone answers the query. I am surprised that after eight hours, no one has made a derogatory comment about the blog that was mentioned in this query. About now I would expect someone to say the blog that is mentioned is all nonsense. The wells transferred from Newfield to CLR were reported in the May 16, 2012, daily activity report. It will be interesting to see if someone points that out in an answer to the query. [June 1: it appears no one dares touch this query with a 9-foot pumping rod, not even Rufus.]

May 29, 2012: a bit chippy? Defensive, insecure, anti-investor class?

May 24, 2012: This is why the Geico "rock" commercial resonates -- at least one person thinks the NDIC is limiting drilling to one well per section. We are five years into the boom. Thousands of news stories later and thousands of posts elsewhere and we still see these comments. 

May 19 2012: Elsewhere "Blackjack" is wondering what the difference is between "runs" and "production."  See my discussion of this subject here.

May 16, 2012: Elsewhere Craig is looking for a site that tracks historical data comparing "ND Sweet" and WTI.  My "Data Links" site has that information. It should be noted that the best site (SemCrude) does not include a better comparison, light Louisiana sweet (LLS), unless I missed it.

May 15, 2012: Elsewhere "Barney" has asked an interesting question regarding the legend on the NDIC GIS map server. His question is yet to be answered. If no answer is forthcoming in the next couple of days, I will try to remember to take a stab at it.

May 12, 2012: Elsewhere "Gary" is asking if #22882 and #22883 will be running from sections 21 to 14. We are now into the fifth year of the Bakken boom, and I think the Bakken Shale Discussion Group has been up almost that long. Gary's question provides a bit of insight how far we've come in understanding the Bakken. To say the least, that would be a long lateral. To answer the question, these two wells will most likely parallel:
May 4, 2012: Elsewhere "Barney" asked how to find section-township of a well when only the name of the well is given. The fastest way I know is to locate it on the NDIC GIS map server. Simply go to the map server, click in "Find well" and type in just one word of the well's name.

April 4, 2012: Elsewhere "blacksheep" asked if a well could be placed back on "confidential status" multiple times.  The answer is "yes," a well taken off the confidential list can be placed back on it; it seldom happens, but I have seen examples. Teegue says: "... it happens only when a recompletion is later attempted in a different pool than the pool targeted in the drilling permit."

If that is accurate, Oasis must be going after a new pool with the Clark well in the Tyrone oil field north of Williston.

Elsewhere "jbird" wants to know: has #20755, HA-Dahl-152-95-0706H-2 been fracked? This Hess Three Forks well in the Hawkeye field is still on DRL status.
From the file report of the Dahl well: "During the lateral operations Hess wanted to deviate to the east of the already drilled and producing HA-Dahl 152-95-0706H-1 Middle Bakken lateral to investigate an anomaly that appeared when seismic lines were run in the area. This area of interest was thought to be a naturally prouced fracture zone in the Three Forks Formation, with the possible fractures being caused by the generation of hydrocarbons from within the Bakken Formation. Operations geologists and engineers thought these natural fractures may help increase the production from HA-Dahl-152-95-0706H-2 Three Forks well. During the time when the well bore passed through the area in question there were noticeable increases in total gas concentrations. On the morning of 1/9/12 at ~ 0810 hours CST, a possible fracture was crossed and a 4,600-unit gas show was recorded. This gas show was accompanied by a flare that was ~ 50 feet in height. This gas was quickly circulated out by the rig crew and drilling was resumed." [No mention was made whether roughnecks had to change their underwear before continuing work.] Several other formations were also evaluated as potential pay zones.
See comment below: this well is about a mile west of another big well, the Mogen well. Go to this link for more information, and then look at the location on the GIS map server. This is huge.
"Scout" wants to know about #21378, EOG's Wayzetta 124-3334H. That well is still on DRL status. [The whole issue of "tight hole" status and "DRL" status" can be confusing. See FAQs, question 14: EOG typically waits until well is completed before it places the well on "tight hole" status.] It was spud(ded) 10/2/11, so it is also still within the six-month "tight hole" window.  The nomenclature, "124" is interesting. No doubt the "124" is simply chronological numbering of the Wayzetta wells. In T153N-R90W, EOG has 53 wells/permits. Of these 53 permits, there are 39 Wayzetta wells; the lowest number is #2 (if there is a #1, I missed it). The highest number appears to be 157. That's a lot of Wayzetta wells planned. The earliest Wayzetta permit is #16733 (now a salt water disposal well); the most recent permit is #22704. The first Wayzetta well appears to have been spudded in January, 2008:
  • 16961, 1,064, EOG, Wayzetta 8-11H, short lateral, s1/08; t4/08; cum 377K bbls 2/12; producing about 3,000 bbls 2/12;
I haven't gone through the entire list yet, but the Wayzetta well with the most production to date, may be:
  • 16991, 1,383, EOG, Wayzetta 9-03H, short lateral, s4/08; t7/08; cum 672K bbls 2/12; producing 7,000 bbls 2/12
Mark provides a nice short explanation how royalties work:
If one owns/leases 10 acres in a 1280-acre unit, one will get 1/128th of the royalty on the well.  If you have a 3/16ths royalty on your lease, your payment will be 1/128ths x 3/16ths, or 0.0014648 times the income on the well, which means you get $0.14 for every barrel produced (at $100/barrel).   If the well produces 100 barrels a day, you will make $14.00 per day.  Note that these wells will typically decline fast, so your initial payment will not be sustained. [That $100/bbl in the Bakken is at the high end; contracted/hedged price may be $100, but spot price is significantly less.]