Enquiring Minds Want to Know: Random Notes On the Bakken From A Different Planet -- Page 1

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A random look at what they're discussing elsewhere

August 26, 2013: I don't think I've read anything as "stupid" as what I'm reading now. We are six years into the Bakken boom on the North Dakota side of the state line, thirteen years on the Montana side of the state line, and some folks who should know better, still don't have a clue.  For the activist environmentalists and for the folks over at the Bakken Shale Discussion Group who don't know which side their bread is buttered on, the operators should simply shut in all wells flaring natural gas. 

This is what these guys are complaining about. Some fields are so remote, it is not cost effective to put in a natural gas pipeline and if the well is to remain on-line, the natural gas must be flared. Let's take one of those fields as an example. A typical well in the Baskin is producing 4,000 bbls of crude/oil month and 4,000 MCF of natural gas. The field is too remote for a natural gas pipeline at this time (perhaps not in the future). A mineral owner getting 20% royalties would get $72,000/month at the wellhead for the crude oil (at $90 oil) and $4,000/month for the natural gas (at $5 natural gas). So, right now, the mineral owner, who probably inherited his land from his grandfather to begin with, is receiving $72,000/month and losing a potential $4,000/month due to flaring. The only way the flaring will be stopped is if it is mandated by the government that all flaring is to be stopped. The mineral owners seem to be arguing that they want all flaring to stop so that "their" natural gas is not wasted. So, these guys are willing to give up $72,000 a month just to make a point that $4,000/month of natural gas is being wasted. Maybe if things work out right, the operator will put in a pipeline so they get their $4,000/month and the price of oil will drop to $50/bbl and they will get $40,000/month for their oil. [4/72 = 6% -- about what I'm being told is the ratio, so my numbers are not far off.]

Idiots.

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: http://www.milliondollarwayblog.com/2010/10/areas-of-interest-in-bakken-by-producer.html. 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.

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:

• 18566, 1,204, Whiting, Cvancara 11-14H, Alger, t11/10; cum 88K 3/12; 
  

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.]