FAQ

Note: the information was believed to be accurate at the time it was posted. The oil industry is dynamic and things are changing particularly fast in the Bakken. Statistics with regard to the Bakken might not be updated.

[Note: for acronyms, click here.]
[Note: net acreage and prospects, by producer, click here.]


Q: As of October, 2011, how many wells need to be drilled to hold leases as of right now? 5,000. Link here (it's a regional link that will break soon).  How many wells are being drilled per month? 167. How many months would it take to drill 5,000 wells at a rate of 167? 30 months. At a rate of 200/month? 25 months. As of January, 2012, there were 6,600 active wells in North Dakota. At the same time, there were 49,000 active wells in California; both states producing about the same amount in January, 2012, but North Dakota jumped ahead of California in early 2012.


1. How many wells will "they" drill in a section? How many wells in all in the North Dakota Bakken? 39,000 wells; 6 wells per 1280-acre spacing unit. Click here. Harold Hamm, CLR/CEO, as recently as October 26, 2011, estimated 48,000 to 50,000 Bakken wells; he stands by his estimate that the Bakken/Three Forks has 24 billion recoverable bbls of oil.

2. What is the average longevity of a Bakken well? See also question 18.
This is probably one of the most asked questions I see. Everyone will opine on this one. For an interesting layman's discussion of "the decline rate," click here.

In its June, 2010, corporate presentation, BEXP estimates the economic lifespan of its wells to be 35 - 39 years. Many 'legacy" wells (Madison, Red River) continue to pump after 30 years of production.

The horrific decline rate is a well-known phenomenon for the Bakken wells. However, it appears that the producers will keep these wells producing as long as possible. New technology comes along, especially the opportunity to "re-frac" and thereby extending the lifetime of the well. Producers are not allowed to "cap" oil wells in North Dakota which is allowed elsewhere. When a producer abandons a well, it is plugged with cement and cannot be re-entered. If one wants to go return to that location, the entire process starts over.
3. What is the status of the "fill in the blank with the name of your favorite well."
For $50/year, one can subscribe to "Basic Services" at the NDIC website which will provide an incredible amount of information about every well drilled in North Dakota. If you don't feel like subscribing, pose your question on the Bakken Shale Discussion
Board. If the data is available, it's likely someone will provide the information.
4. What is meant by fracking?
Fracking is a method of "breaking open the shale" to increase the amount of oil recovered from the formation. Here's a nice 5-minute video of fracking. Or click here and scroll down. How much does it cost to frac? How long, how many workers involved? Click here and scroll down to "Degas." For correct spelling of "fracking," see FAQ #34. "Super-fracking" is a new term seen for the first time in late 2010; it refers to fracturing with greater than 40 stages.
For more clarity on fracturing and types of fracturing, "Degas" provides some more information. When you get to this site, scroll down to "Degas." 

PDF white paper on Halliburton's SurgiFrac technique. 
Slide 7 of this presentation provides some data points regarding vertical well fracking and horizontal well fracking. 
5. What is the typical spacing of oil wells in North Dakota? How is spacing determined? See also "160-Acre Spaced Wells" and "320-Acre Spaced Wells". See this thread for discussion on how spacing is determined in North Dakota.
This will change over time, but right now, most wells are spaced at either 640 acres or 1280 acres in North Dakota. I refer to the horizontals as "short laterals" or "long laterals," respectively. A short lateral is "one mile" long; and, a long lateral is "two miles" long.

In North Dakota most townships have 36 sections and most sections have 640 acres. (The townships and sections along the state border may be truncated). Therefore, a "short lateral," 640 acres, is spaced for one section, whereas a "long lateral," 1280 acres, is spaced for two sections. One can see examples of both, side-by-side, at the NDIC GIS server (map).

It is my feeling that Whiting (WLL) pioneered long lateral drilling in North Dakota but now long laterals seem to be the norm. (Oasis, November, 2009; EOG, December, 2009, are both recent examples. At the time I first posted this, someone wrote to tell me that 90% of Hess' 130 wells in ND are long laterals.)

Historically, a 640-acre well had a lateral that was about one mile long; a 1280-acre well had a lateral that was about two miles long. Remember, a section is one square mile (one mile wide, one mile long); a township is generally six miles on a side; 36 square miles. And as long as I'm rambling, the federal government gave the local school district the mineral rights in one section (generally, I believe, section 16) in each township. States were given authority to give local school districts additional sections; North Dakota gave sections 16 and 36 to the schools.

Update: this whole issue will become more difficult to define over time. Producers/operators still request permits based on specific spacing (currently, most commonly 640 and 1280 acres) but with multiple wells and multiple laterals being drilled from one pad, comparing one well to another well should get more difficult and/or more meaningless over time. That's my opinion. Others, I'm sure, will disagree.

Update:  An example of how fast things are moving in North Dakota, EOG has been granted a permit for 2560-acre spacing and placing six (6) wells in one section, each spaced 50 feet from the next in a straight line. CLR, I believe, has a plan to put its Eco-Pads along the Williams County-Divide County border. January 22, 2010.
Update: CLR 's first Eco-Pad was programmed for McKenzie County.
6. When did the EOG/BNSF railroad oil tanker operation become operational (Stanley, ND)? Are there plans for more such terminals?  For most recent update, click here, May 8, 2010. New update, October 6, 2010. As of October, 2011, there were at least a dozen crude-by-rail oil loading facilities operational, almost completed, or being proposed in western North Dakota. (See tag/label "Rail" at bottom of the blog.)
The EOG/Stanley operation was scheduled to come on line in February, 2010. In fact, it came in early: the first train left Stanley, North Dakota, on New Year's Eve, December 31, 2009.  Initially one 100-unit train will depart daily with plans to run as many as four trains per day. EOG, in its April, 2010, presentation, said two trains/week were running. ND state spokesman said at one time three trains / week were running.

Update, July 30, 2010: capacity of this facility is 100,000 bopd; currently loading/shipping 30,000 bopd.
Note: when oil produced exceeds capacity to ship, the value of ND oil at the wellhead can drop as much as $12 per barrel from the benchmark price; with adequate capacity to transport oil, that figure may drop to as low as $3 - $4 per barrel.
In March, 2010, county commissioners approved a new railroad oil loading facility just outside of Dickinson, ND, which should be operational by October, 2010. The Dickinson terminal (98 miles southwest of Stanley) is also expected to ship 60,000 barrels of oil in one unit train on a daily basis.
7. How much oil can one reasonably expect that a Bakken well will produce over the lifetime of that well?
The individual core Bakken well will now produce 1 million bbls of oil over the lifetime of the well (based on composite of information publicly available; my opinion only; current as of January, 2012).
The oil industry refers to this figure as the estimate of ultimate recovery (EUR). Back in 2007, EOG opined that the EUR from each of its wells in the Parshall could be 750,000 barrels of oil equivalent. In January, 2010, CLR opined that dual laterals will add another 400,000 barrels to the EUR. This is less than, but comparable to the EUR for wells in east Texas (Texas Barnett Combo). It should be noted that EOG sits in one of the "sweet spots" in the Williston Basin and their wells are probably going to return much, much more than the "average" well in the basin. But there are "crazy numbers" out there.

In November, 2010, Harold Hamm (CLR/CEO) opined that the "typical" Bakken well will have an EUR of 518,000 barrels. In May, 2011, James Volker (WLL/CEO), opined that the average Bakken well will be 300,000 bbls/well EUR. October, 2011: I believe Harold Hamm has increased his estimate to 603,000 bbls/well EUR.
8. What is the record IP to date in the Williston Basin?
Again, the initial production of any well, self-reported by the producer, is becoming less meaningful over time. Having said that, it looks like the record IP for a Bakken well is now 5,200, a Newfield well (July, 2011): 18691, 5,200, NFX, Wisness Federal 152-96-4-2H, Westberg, Bakken.
Two earlier wells: a Whiting well which had an IP of 4,761 boepd: file #17612, 4,761 boepd IP, Whiting, Maki 11-27H, Mountrail County, Sanish field.  This is still current as of February 20, 2010. Since then, BEXP claims to have set a record with the Sorenson 29-32 1-H, #18654, with a 24-hour flowback of 5,133 bopd. However, the NDIC reported an IP of 2,944. BEXP also reported the Jack Cvancara 19-18 #1H in the Ross project area with a 24-hour flowback of 5,035.
New record in the Bakken, November 3, 2011. The Tarpon Federal 21-4H is a Whiting Petroleum operated well and had a 24-hour initial production (IP) rate of 7,009 barrels of oil equivalent (BOE), setting a new Williston Basin record for a Bakken well.
Whiting said this was a record TFS well at the time, early 2012, file #20526, Smith 34-12TFH, 2,446, 102K in first 4.5 months.
9. What is "pooling" and the Pugh clause?
The Pugh clause is a clause in the leasing contract in favor of the owner to preclude the driller from holding the leases in unproducing land for extended periods of time. The Pugh clause is too complicated for me. See this site. If you know of a better site, let me know. Here's a bit more on the Pugh clause.  For a discussion of the "vertical Pugh clause," click here. For a definition of pooling, click here, and then follow the FAQ to pooling. Although I can't say this for sure, when I see a pooling request come before the commission, I see it as one of the last steps before they start drilling. This might be a better explanation of pooling.
10.  How much can I expect to lease mineral acres for? What is the record oil lease?
This is impossible to answer; there are too many factors to consider. I will try to remember to watch lease rates and post them, but it seems for the acres with least likelihood to produce, the acres may go for as little as $100/acre. In 2009, it was common to see $2000/acre, but in some places they actually went as high as $8000/acre (very, very unusual). You may want to search this discussion group for a better answer: the Bakken Shale discussion group.

Here is one discussion on lease rates, back in April, 2008. Since then, rates have gone up considerably depending on location.

But record leases were those recorded in the late-2009 North Dakota land lease sale (somewhere I read that at least one lease sold for $8,000/acre: I will try to find that lease, but regardless, the numbers are spectacular). In February, 2010, it was reported that 120 acres in a relatively mediocre (but potentially exciting) field was leased for $7,300/acre, working out to $4.7 million/640 acres (one section). In the May, 2010, lease sale, another record was set: $12,500/acre in an undeveloped area.
11. What is an Eco-Pad? What are "Dakota Candles" and "Orion Belts"? What are "stand-ups" and "lay-downs"?
Click here for information on Eco-Pads. Slawson often puts two wells on one pad; I call them "Slawson snake eyes" because that's what they look like on the GIS Map Server at the NDIC home page.  "Dakota Candles" and "Orion Belts" are terms I use for a series of wells but not on a single pad. [I no longer use these terms.] I assume many of them are along a pipeline route.  Dakota Candles are a series of wells on one site running north and south; Orion Belts are a series of wells on one running from east to west. The direction of the series of wells on one site makes no difference. It is just shorthand for me to help remember these sites. "Stand-ups" and "lay-downs" are commonly used phrases in the Bakken: a stand-up is a long lateral running north-south; a lay-down is a long lateral running east-west.
12. What is the "IP"? What is flowback.
"IP" stands for initial production. This is a self-determined and a self-reported number provided by the producer. Each producer can determine its own method for determining the initial production of a new well, but it must be based on 24 hours of production. Obviously, this means that the numbers can be easily manipulated and many seasoned oil analysts put no stock in these numbers. Unfortunately, these are often the only numbers one has to work with early on. Whether IPs are that reliable or that reproducible, I think one can get a general idea of the helpfulness of the IPs by following them over time. At the end of the day, the best data point may be the cumulative oil produced at the end of the first year, and at the end of the fifth year, but that's a long time to wait, and not always easily available unless one subscribes to the NDIC database. If interested, here is a discussion thread regarding IPs, as well as a link to decline rates in the Bakken. One more personal note: if a legitimate company was found to be inappropriately manipulating IPs, the state agency regulating the industry would probably step in; and, investors would probably lose faith in the company.  It's likely that comparing IPs within one company is internally consistent but it may not be accurate comparing IPs from producer to another producer.
Here's another great discussion on IPs: for the same well, NOG (a partner) reports an IP of 1,998, while Hess (the producer/operator) reports an IP of 570. That's a huge spread. Looking at the monthly production, it is obvious that Hess reported the initial 10-day average whereas NOG reported the first day's production, or even possibly the first hour and then multiplied by 24. Hess is an established company and one well has minimal impact on its overall operations; NOG is a small company (one could argue it's a penny stock out of Denver) and one big well can greatly influence investors.
In 2010, we started see more companies report "flowback" rates: the high rates of oil production in the first 24 hours. I think some companies even took the best one-hour of production and multiplied it by 24 hours to get a 24-hour flowback. Many consider this number nonsense and has little to do with IP and absolutely nothing to do with EUR.
13.  What does it cost the operator/producer to extract a barrel of oil equivalent  (BOE extraction cost) from the Bakken?
I have refrained from talking about the BOE extraction cost because I think the numbers can be manipulated even more than the IPs. However, more and more folks are asking that question, and I will start posting some numbers as I see them. I doubt I will go looking for them. For me, it's not worth the effort. BEXP and WLL have been particularly forthcoming with their estimates of their BOE extracton cost in their corporate presentations which are easy to access at their home page. I was unable to find comparable reporting by EOG. In general, in 2009, the number I saw most frequently was $12 - $14 to extract a barrel of oil from the Bakken.
On page 5 of the 4Q, 2010, Hess earnings conference call, Hess said "the Bakken is robust at $40. It returns the cost of capital at $40. So that’s why we feel very confident kind of pulling the trigger on the Bakken now and aggressively going after a five year program." In NOG's earnings statement for 1Q11, NOG spokesman said production cost was $4 - $5/bbl.
14. What information is available for a well on the confidential list, what is the definition of a completed well, and how long can a well remain on the confidential list? Update, October 28, 2011 -- it appears that NDIC is transitioning from the  use of the word "confidential" on the daily activity reports and is now referring to those wells as "tight hole." This is because the period before the well is actually spudded is "tight," not confidential. The "confidential period" starts when the well is spudded. It also happens that once off the confidential list can be returned to "tight hole" status, further muddying the issue. What follows is the generally accepted definition.
The following was taken from the Bakken Shale Discussion Group thread. When I locate NDIC information on this subject, I will post that. "All information furnished to the director on new permits, except the operator name, well name, location, spacing or drilling unit description, spud date, rig contractor, and any production runs, shall be kept confidential for not more than six months if requested by the operator in writing. The six-month period shall commence on the date the well is completed or the date the written request is received, whichever is earlier. If the written request accompanies the application for permit to drill or is filed after permitting but prior to spudding, the six-month period shall commence on the date the well is spudded."

The obvious question is "when is a well considered to be completed?" For wells that will be fracked, the well is considered "completed," when the well has been fracked. This has been the opined explanation for many EOG wells coming off the confidential list in January and February, 2010. EOG typically doesn't put a well on the confidential list until it has been completed.

If a well has not been fracked at the time the well comes off the six-month confidential period, the status remains listed as "DRL." It will remain on "DRL" status until 30 days after it is fracked. Once the well is fracked, the producer has 30 days to test the well and file the report with NDIC. 
15. What is the average daily oil production coming out of North Dakota? [Update, October, 2011: Production is hitting new records almost monthly. I track monthly production at "Directer's Cut" which is linked on the sidebar at the right. Right now, daily production is about 450,000 bbls, and could soar to 1 million by 2015.]
At the end of 2009, North Dakota was producing about 250,000 barrels of oil per day. With a new pipeline project completed and the introduction of EOG's railroad tanker project, oil capacity increased by about 110,000 barrels per day. It will be interesting to see if North Dakota reaches that capacity (360,000 barrels/day) by the end of 2010. Note: in March, 2010, it was announced that another railroad tanker project, this one at Dickinson, will be operational as early as October, 2010. If that comes online, then one can add another 60,000 barrels to current capacity estimated to be 360,000 barrels/day, reaching a new capacity record of 420,000 barrels per day. For now, 2010, consider 350,000 bopd coming out of North Dakota with ramp up to 400,000 by end of 2011 if prices for oil stay high.
16.  What cities and towns in North Dakota are most affected by the Bakken?
Williston (northwest) and Dickinson (southwest) are the two largest cities in "the Bakken." Next comes Watford City, Stanley, and Bowman. Smaller towns include Tioga (home of the first well in North Dakota, discovered by Hess in 1951), New Town, Alexander, and Ross. Dickinson is impacted by large number of oil workers living there.
17. Can you discuss the thinking of infill wells?
Gladly, by directing you to a discussion group. It is my understanding that the issue of infill wells in the Bakken in North Dakota is still being explored. With a well in almost every section of the Parshall oil field, EOG is now ready to experiment with infill wells. But it is still very early in the game to be talking a whole lot about infill wells.
18. How long will "the Bakken" last? See also question #2.
Obviously that question cannot be answered with any degree of certainty. But in January, 2010, analysts suggested North Dakota's oil output will increase to 400,000 bopd by mid-2011, and that level of production will be sustained for 10 - 15 years.
Industry experts suggest that the drilling program will not be completed until 2030, and that production will continue to at least 2100.
19. What oil fields in North Dakota are "in play"?
Various oil fields are looked at in more depth elsewhere on this blog. At the sidebar on the right, scroll down to find updates of various fields.  The Parshall oil field and the Sanish oil field have been the most prolific fields in the current boom. Other fields of interest: Big Bend and Van Hook; Charlson and Fayette; Clear Water; Little Knife, Jim Creek and Murphy Creek; Alger; Painted Woods, Squires, and Round Prairies.
20. How many active oil wells are there in North Dakota?
For me, this question is irrelevant, but I see it is often asked. According to the NDIC, there were 5,331 active wells at the end of 2010, up from 4,693 in 2009. How many permits (wells drilled from these permits) are being granted on an annual basis in North Dakota? 2006: 422 (195); 2007: 497 (336); 2008: 953 (734); 2009 626 (208). Obviously the numbers inside the parentheses (wells drilled) will increase over time (as the wells are drilled). March 10, 2010.
21. How soon does a company stimulate a well after completion of drilling?
This varies. Buried deep in this site one learns that EOG spudded a well on January 19, 2009, but did not plan to fracture stimulate it until July, 2009. EOG does not frack wells between November and March. I assume that most wells are ideally fractured within a month of when drilling is completed but I do not know. However, due to the increased number of rigs in North Dakota and the increased pace of drilling, fracking has become the bottleneck to completing a well. In early 2010, a wait of six months was being reported to have a fracking crew in place after the well had been drilled. Halliburton announced in early 2010 that is fracking crews would now be working 24 hours/day to try to minimize the backlog.
22. What is meant by a "top lease"?
I believe that is when someone wants to drill on land already leased, but there is no indication that the original lessor will drill any time soon; the interested individual pays the original lessor and/or the owner of the mineral rights pays for a "top lease" to begin drilling sooner. I don't know the details, but "Teegue's clarification" deep in that thread is enlightening.
23. Is there a "basic analysis" of the current Bakken boom?
Yup: right here. I don't know if this document is dated. I downloaded it February 13, 2010, and the document itself suggests that it was published in 2010.
24. What is the difference between "boepd" and "bopd"?
Barrels of oil equivalent per day (boepd) includes natural gas.  "Bopd" is only the oil.  Generally speaking, one can divide the number of cubic feet of natural gas by 6,001 to get the equivalent of oil. The number can vary depending on quality of the natural gas but 6,001 seems to work well every time I've used it. Note that there are different grades of oil: sweet oil is most expensive. North Dakota oil is sweet oil. Likewise, natural gas has different amounts of energy and much more difficult for me to understand. Natural gas quality is defined in British thermal units (BTU).
25. Can you talk about the confusion between the Bakken formation and the Three Forks Sanish formation as it relates to the "Bakken pool"? See this posting. Related to this issue is whether the TFS and the Bakken communicate?
Continental Resources (CLR) recently completed a test to determine whether the Three Forks Sanish and the Bakken are separate formations. Interestingly enough, in that report, CLR projected that these wells, one of which was drilled in 2008, will see an increase of 400,000 additional barrels over the lifetime of those wells, out to 2029. Yes, out to 2029, twenty years from when these wells were drilled. And these wells were not all that outstanding to begin with. Note: EOG has estimated that their good wells in the Parshall have an estimated ultimate recovery of 700,000 barrels, so an estimate of another 400,000 barrels is almost incredible. Click here for the referenced report. Also, see this article on a short discussion of the Sanish formation.
26. How much does it cost to drill a horizontal well in North Dakota? [Update, October, 2011: wells continue to increase in cost, now up to $10 million for a long lateral. Half the cost can be attributed to fracking.]
"Currently cost estimates for a 22-stage frac job for completed Bakken Three Forks wells is $5.4 million, and we are keeping that relatively flat from last year."  March, 2010. Since then, the price to drill a typical Bakken seems to have increased significantly, to $7 million, based on corporate presentations. August 1, 2011.
27. How long does it take to drill a Bakken well? (I updated the answer on March 17, 2011.)
Drilling a well and completing a well are two different things.
The drillers in North Dakota are setting new records in completing wells. There are two components for completing a "Bakken well." The first component is drilling the well; the second component is fracking the well. 
It used to take 30 - 45 days to drill a well; "they" are now drilling wells in about 25 days.
Once the well is drilled, the operator must then wait for the fracking crews to complete their job. For various reasons, fracking is not always done immediately after the well has reached total depth. WLL, conference call, July, 2011, says they are reaching total depth in 15 days, and recently reached the target formation (Bakken pool) in 14 days.
Fracking can take anywhere from one or two days to as long as 12 days. Sliding sleeve fracturing can be accomplished in one to two days; plug and perf takes significantly longer.
Having said all that, this may be the record for completing a well in the Bakken. Before clicking on the link: who do you think has the record? a) BEXP  b) WLL  c) EOG  d) HES
28. What is meant by "Zone I, II, III, and IV" and spacing units? Click here. Also here for EOG spacing strategy first noted in 2010. It is my understanding that the state determines the spacing for a given oil field, such as 640-acre spacing in the Parshall oil field. However, some oil fields are very big, and the state has broken the field into "zones." The zones may have different rules, including spacing rules.

29. What does the abbreviation "HBP" stand for?
The abbreviation "HBP" stands for "held by production." A lease is generally good for three-to-five years; if no wells are drilled, or if wells are dry, the leases expire at the end of the stated period. However, if there is production from a well affected by a certain lease, the terms of that lease last as long as the well is productive.) [Note: the lease is different from a permit. The permit is issued by the state allowing the well be drilled. Permits expire after one year, but can be easily renewed for a $100 filing fee.]
30. Do drillers fracture wells during the winter?
This is EOG's standard operating procedure (scroll down the thread): frac only from April through October. Wells drilled from November to March are not fracked / not completed until April. Once completed, they remain on the confidential list for six months, meaning that a well drilled in November might not come off the confidential list until almost a year later. SOPs will vary among drillers.
31. It seems obvious, but what does the phrase "plugged or producing" mean as used on the daily activity report? For a short answer, click here.

32. The Enerplus Resources (ERF) presentation references "waterflood." What is meant by "waterflooding"?
Waterflooding is a secondary method of oil recovery. Once a field is pretty well drilled out, operators can force water down previously producing wells to force oil into wells that are still producing. Air can be used to do the same thing, but is more costly. It is called fireflooding. Click here and scroll down the thread a ways for more information. Wells that are no longer producing in North Dakota are plugged with cement or converted into salt water disposal wells. I assume the NDIC needs to grant permission to use these secondary methods of oil recovery. Waterflooding works for conventional wells in conventional fields with pools of oil; I am not convinced -- in fact, I doubt -- that waterflooding will work in horizontal, fractured, unconventional shale/rock such as the Bakken. By the way, CO2 is a tertiary method. Both waterflooding and CO2 injection are forms of enhanced oil recovery (EOR).
33. How does one know for sure that the bore head is where the oil company says it is with regard to horizontal wells? GPS technology is used, and the position of the bore head is known to a position within feet.

34. Is it fracing, frac'ing, or fracking?
The industry uses the first two, although I seldom see "frac'ing." The media uses "fracking." My site uses, and I believe one of the first sites, to use "fracking" exclusively. My hunch is that "fracking" will become the preferred spelling. Investopedia uses "fracking."
35. What is unitization? This appears to be best the answer from most reliable source, posted July 1, 2011:
"Basically, under untization, the spacing units disappear and the entire  field boundary lines become a big spacing unit, where all the owner within  the field share in production from the entire field, which is allocated to  the owners by an agreed upon formula. The field becomes one big "spacing  unit," because the oil is being artificially forced across would would have  been the old spacing unit boundaries by the secondary recovery methods  (i.e., waterflood, CO2 etc.).  There will be a hearing or a number of  hearings with the DMR.

The state law requires that 60% of the mineral ownership approve of the  unit, and I believe votes are weighted by amount of acreage owned in the  unit. Most of the larger, older, conventional (i.e., non-Bakken) fields have  been unitized in ND -- Beaver Lodge, Blue Buttes, Fryburg, Big Stick.  The only one I'm aware that was defeated by the mineral owners was in Little  Knife field (Madison pool), and I think most would agree that such action  left a lot of recoverable oil in the ground.

Don't hold me to this, but if you are leased -- and your leases are not currently held by production -- if your leases are included in the unit (and  assuming the unitization plan is approved), they will be considered to be under production, as you will receive royalties pursuant to the formula."
An earlier source said this, which I posted August 2, 2010: Whatever unitization is, it remains a "non-issue" in North Dakota as of 2010. Seriously, here the discussion begins.  Unitization is similar to pooling, but it occurs when producer(s) are ready to use enhanced oil recovery to maximize production from a common reservoir. With the Bakken being one huge continuous "reservoir" it's  hard to see how unitization could work, unless they do it by field, an arbitrary designation, in my mind, when it comes to the Bakken. Sixty percent of royalty owners (weighted) must agree to unitization before the NDIC will authorize it. To date, unitization has not occurred in North Dakota (August 2, 2010).
The NDIC hearing docket for August, 2011, will consider unitization of Lost Bridge-Bakken. The state is considering unitizing the Little Missouri State Park, October, 26, 2011.

36. How do you read an oil drilling permit?
Full page explanation right here. I expect this link to be broken some day; if it is broken, let me know and I will provide an update.
37. What are the names of the townships in Mountrail County? Click here.

38. With regard to proceeds on a royalty check, what do the letters "O," "G," and "P" stand for?
"O" for oil. "G" for natural gas. "P" for plant products.  As the gas is processed and purified for transportation, by products like natural gas condensate, sulfur, ethane, and natural gas liquids like butane, propane, isobutane, and pentanes are produced and sold. Source. On some royalty checks "P" will be abbreviated at "PPROD."
39. How are decline rates calculated? Click here.

40. What is the current estimate of recoverable reserves of oil in North Dakota?
In October, 2010, Continental Resources (CLR)/CEO (Harold Hamm) estimates the basin in North Dakota holds 24 billion barrels of recoverable reserves. That is more than five times the "original" estimate given two years ago (2008) by the US Geological Survey. Lynn Helms, director of ND Dept of Mineral Resources opines that there will be half that amount: 12 billion barrels.
Update, November 2, 2011: by hitting oil in a lower seam of the Three Forks, CLR/CEO Harold Hamm says that this has the potential to add incremental reserves to our estimated 24 billion boe of technically recoverable oil and natural gas in the total Bakken.
41. Plugged or producing?
Sometimes the first information we get about a well after it comes off the confidential list is simply that it is either "plugged or producing."  This simply means that the well has been completed and is either producing enough oil for the oil company to keep it actively pumping, or that it is pumping so little oil it is not economical to keep it going. A third possibility is, of course, a dry hole. In the current Bakken boom, there are no "dry" holes. Obviously that is an exaggeration; there is an occasional dry hole but it is very, very rare, and probably related to driller error rather than no oil. However, occasionally the amount of oil coming up from the well is not enough to make it an economical well, and it is plugged and abandoned. When one sees the first report of a well coming off the confidential list as "plugged or producing" in the Bakken, one can assume that 99 times out of 100, it will be a producing well. Some wells will be great; some mediocre; and, some pretty poor, but enough to keep them active.
42. What is meant by commingling?
We are starting to see more and more requests from an operator to commingle oil and/or natural gas coming from a certain spacing unit. Without commingling, the oil and/or natural gas that comes from a specific well is kept separate from the oil and/or natural gas produced by another well, even if the two wells are on the same pad. Obviously, it's a lot easier for the company to allow production from all the wells on a single pad to go into the same pipelines / same storage tanks. Likewise, for two wells very close together, even if they are not on the same pad, it makes economic sense to the operator to be able to commingle the production from both wells into one collecting system.
43. On more and more corporate presentations, I see references to "collars." What are collars?
From Sempra Securities: A collar, also referred to as "min-max strategy," is a zero or low cost hedging strategy that assures the Oil Producer a minimum / maximum price range for future oil sales.
Under a collar contract, the minimum possible sale price is equal to the floor price and the maximum possible sale price is equal to the ceiling price. For prices within this range, the Producer achieves the market price.
The contract is normally financially settled and often covers several pricing periods.
There is usually no up-front premium payment. Under a standard zero cost collar contract, the Producer can specify either the "floor" or the "ceiling" price level. The other price level is calculated by SET to ensure a zero-premium expense. If the Producer wishes, it can specify both price levels, but then it may incur some premium expense or income.
The Producer gains complete price protection from any prices below the floor price. However, in exchange for zero up-front premiums, any benefit from an oil price increase above the ceiling price is foregone.
The collar is, in many ways, similar to a swap, but it allows for greater flexibility through some market responsiveness. The collar outperforms a swap strategy if prices increase.
For a discussion of 3-way collars, click here.  This site suggests that a 3-way collar is unnecessary but seems to be used by those companies who got burned with rapid price declines in the past.
44. What is "rig stacking"?  For an informal discussion, click here.

45. How much sand and water is used in fracking in the Bakken? Click here for update posted in early 2011. [October, 2011: I am starting to track fracking specifics: it turns out some companies, like Hess, are using less than 1 million pounds of sand to frack, whereas some companies like BEXP are using up to 4 million pounds of proppant (sand plus ceramics); and sometimes the amount of ceramics used is more than the sand.]

46. When I say "leases held by production are held for 'eternity'" what do I mean by "eternity"? Bakken wells are expected to produce for 25 - 30 years. As a retired investor, thirty years is well beyond my active investing lifetime. For me, 30 years defines my investing "eternity."

47. Permits and leases: how long do permits / leases last?
Permits are issued by the state and are "good" for one year; they may be renewed annually for $100. A lease is an agreement between the operator and the mineral rights owner. Leases are generally "good" for five years. If production is achieved before the lease expires, the lease remains in place as long as there is production (lease held by production [HBP]).
48. What happens if you refuse to lease where a driller wants to drill, and you don't own all the mineral rights? If interested, this thread provides a bit of accurate (and inaccurate) information.

49. What are the rules regarding temporary spacing?
A temp. spacing app. leads to a hearing which results in a approval or  denial of the app.  If approved, the temp. spacing order remains in effect  until further order of the NDIC.  If temporary spacing is involved, after  production is established in the "pool" on any of the temp. spaced units, a proper (permanent) spacing hearing is supposed to be scheduled by the NDIC. Right now, the proper spacing hearing is to occur 18 months after that first production.  The proposed new rules change it to three years.  Only one permanent spacing hearing is held for all the temp. spaced units in the entire field.  -- per Teegue, September 30, 2011.
50. Is there enough water for fracking in western North Dakota? More than enough water. Also: water is the least of our concerns.

51. Can you give me an example of how big a royalty check should be by owning "fill in the blank with the amount of mineral acres you own."
A mineral rights owner in North Dakota might mention over a cup of coffee that she gets "a 1/8 royalty" on her mineral rights That individual might have no idea what that means; I certainly did not know what it meant years ago when my dad would tell me that he would get 1/8th royalty if they struck oil where he owned mineral rights.

Here's not an uncommon example. Someone inherits or buys or is given 10 mineral acres. Let's say her well is spaced at 640 acres. Therefore, the mineral owner with 10 mineral acres has 1.56% of the 640 acres. Of that percent, the mineral rights owner will get 1/8th royalty (or 12.5%) of the oil. If one multiplies those two numbers (1.56% x 12.5%) one owns 0.20 percent of the oil that comes out of that well. It is not unusual for a Bakken well in North Dakota to produce about 300 barrels/day for the first month, but declines quickly after that. Multiplying the 300 barrels by the 0.20 percent (300 * 0.002) one gets 0.6 barrel/day. At $60/barrel, that would work out to about $36/day, or about $1,080/month. I don't know the tax penalty, but a 12% extraction tax would not be unreasonable so, at least $135 would be taken out by the state before you got your royalty check. There may be other taxes/fees I am not aware of, but at least that's a start. How much would it have cost you to buy those 10 mineral acres in the first place? At $2,000/acre it could have cost you $20,000 and there is every possibility that the land would never be drilled on. [Since the original posting, the wells have become significantly better. It is not unusual for a good well to produce 100,000 barrels in the first six months. If you have such a well, 0.002 x 100,000 bbls = 200 barrels. At $70/bbl, that could be as much as $14,000 for the first six months of production. Update, February 8, 2011.]

I am no authority or expert on this, so I could be wrong, but this is my limited understanding.  It will be tedious, but there is a long discussion regarding royalty checks, the time line for receiving a royalty check, and other information at this site. When you get there, scroll down to the comments. Lots of interesting information.
52. What is meant by "operated" and "non-operated"?  Follow this link.

53. With regard to spacing, what does ICO mean? ICO = Industrial Commision Order. The driller requests an unusual size  or shape for a spacing unit. Requires an NDIC hearing for approval.
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