FAQ

Note: this page is getting very, very long with a lot of FAQs. I will start a second page of FAQs, starting with number 101.

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This is page 1 of FAQs.


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. This page is not always updated in a timely manner and some answers could be out of date. Or just plain wrong.

[Note: net acreage and prospects, by producer, click here -- new page, being phased in;
 net acreage and prospects, by producer, click here -- old page, being phased out]

New tax laws, flaring laws in era of low prices -- RBN Energy, September 25, 2015

Petroleum systems in North Dakota: source rock, formations, and cumulative production, January, 2013

Bakken production, graphic, January, 2013

August 8, 2018: data points re: the Bakken; this is what "we" know about the Bakken; only changes from September 2, 2016, list of data points):
  • 2Q18 CLR presentation: step change in well performance across the Bakken
  • North Dakota crude oil production hit an all-time record two months earlier than NDIC forecast
  • CLR now says its optimized completions results in 1.2 million EUR type curves
  • rarely, but not unusual to see 50K bbls production in one month
  • "standard" completion: two-mile horizontal; 60 stages; 10 million gallons of water; 10 million lbs sand; about 167,000 lbs of sand/stage; significantly less than 200K + in the Permian
  • MRO continues aggressive Biley oil field re-frack program
  • QEP begins re-frack program in Grail oil field
  • larger and larger drilling units, but standard horizontal unchanged: two miles long
  • Whiting adds "bolt-on" acquisition in 2018
  • Bakken oil operators now talk about positive cash flow
  • DAPL made all the difference in the world; Bakken often being sold for a premium to WTI (Cushing); Western Canadian Select selling at a discount of as much as $30/bbl due to inabilty to get oil out of Alberta
September 2, 2016, data points re: the Bakken Pool (Bakken and Three Forks); this is what "we" know about the Bakken (only changes from the February 2, 2014 list of data points will be listed):
  • $10 million/well historically; costs coming down; maybe $8.0 million in 2016;
  • 100,000 bbls in 6 months to 3 years; will produce for 25 to 39 years
  • 1,500 permits/year; drilling/completing about 750 wells/year;
  • 750 wells/year x $8.5million/well; $6,375 million/year drilling = $7 billion/year drilling
  • 8,000 active wells in North Dakota; 1,000,000 bopd; 90 bopd/well (California with about 60,000 active wells); North Dakota #2 in US production, behind Texas
  • 33 active rigs (incredibly low after 2014, when Saudi opened its spigots)
  • high density spacing; Oasis will drill 21 wells in one 640-acre section; 42 wells/1280-acre spacing in better Bakken
  • Middle Bakken; four benches in the Three Forks; the Three Forks will increase the OOIP estimates by about 60% (compared to the Middle Bakken only); the Three Forks through the Bakken, but seems to extend beyond the periphery of the middle Bakken prospect;Whiting tends to refer to the upper Three Forks in its northern ops area as the Sanish; Whiting tends to refer to the upper Three Forks in its southern ops area as the Pronghorn Sand 
  • occasionally one may see increased production in an older well after a neighboring well is fracked ("halo effect"); see FAQ #81 below; the phenomenon is said to be simply built-up pressure in the old well because it was shut-in for several months
  • North Dakota daily production: at this link, click on the "Director's Cut" at the very top
  • 2012 Bentek study suggests 2.2 million bopd; 3 billion cf natural gas/day 
  • one unit train (100 hoppers) carries enough frack sand to frack one to two wells (2014)
  • more than 75 semi-trucks (18-wheelers) of frack sand are required to frack one well (2014) [Update, December 31, 2016: for every 4 million lbs of sand, 100 18-wheelers are needed; for an EOG well fracked with 20 million lbs, 500 18-wheelers]
  • Lynn Helms, presentation: IPs increasing from 1,100 to 1,500 bopd; longevity of new Bakken wells increase by 5 years (from 30 to 35 years of production); EURs have increased by 25% for "new" Bakken wells compared to "old" Bakken wells
February 2, 2014, data points re: the Bakken Pool (Bakken and Three Forks); this is what "we" know about the Bakken
  • the Bakken is the largest continuous reservoir of oil ever found in the US; light, sweet oil
  • after the 2013 USGS Survey, officials doubled the size of the Bakken/Three Forks: 7.3 billion bbls recoverable; could be as much as 11 billion bbls recoverable (USGS)
  • one trillion bbls of original oil in place (OOIP) -- from a CLR presentation; subsequently back to 500 billion bbls OOIP
  • 8 wells/1280-ace spacing unit: 24 billion bbls recoverable oil
  • 16 wells/1280-acre spacing unit: 50 billion bbls recoverable oil
  • EURs: 400,000 to 1,000,000 bbls
  • 10,000 feet deep; 10,000-foot laterals; total "depth": 20,000 feet; 30-stage fractures; 3 million lbs proppants; sand and/or ceramics; EOG is doing huge fracks: 60 stages; 10 million lbs sand only
  • $10 million/well historically; costs coming down; maybe $8.5 million/well in 2013
  • 100,000 bbls in 6 months to 3 years; will produce for 25 to 39 years
  • 2,000 permits/year; drilling/completing about 2,000 wells/year; on track for 2,500 permits in 2013
  • 2,000 wells/year x $10 million/well; $20,000 million/year drilling = $20 billion/year drilling
  • 7,000 active wells in North Dakota; 980,000 bopd; 100 bopd/well (California with about 60,000 active wells); North Dakota #2 in US production, behind Texas
  • 185 active rigs (range 180 - 195) 
  • high density spacing; Oasis will drill 21 wells in one 640-acre section; 42 wells/1280-acre spacing in better Bakken
  • Middle Bakken; four benches in the Three Forks; the Three Forks will increase the OOIP estimates by about 60% (compared to the Middle Bakken only); the Three Forks through the Bakken, but seems to extend beyond the periphery of the middle Bakken prospect;Whiting tends to refer to the upper Three Forks in its northern ops area as the Sanish; Whiting tends to refer to the upper Three Forks in its southern ops area as the Pronghorn Sand 
  • fracking a new well improves production of a neighboring, existing well ("halo effect")
  • North Dakota daily production: at this link, click on the "Director's Cut" at the very top
  • 2012 Bentek study suggests 2.2 million bopd; 3 billion cf natural gas/day 
  • one unit train (100 hoppers) carries enough frack sand to frack one to two wells (2014)
  • more than 75 semis of frack sand are required to frack one well (2014)
FAQs
1. What is meant by this shorthand:
  • 22594, 1,303, Whiting, Solberg 44-11PH, Bell, t7/12; cum 33K 11/12; F; 
  • Translation: permit #22594 reported an initial production (IP) of 1,303 bbls of crude oil (not crude oil equivalent which would include natural gas and condensates); the operator is Whiting; and the legal name of the well is Solberg 44-11PH. This well is targeting oil in the Bell oil field. It was tested during the month of July, 2012 (specific date not provided though the company provides the exact date); the well has produced a cumulative of 33,000 bbls of oil; the date (11/12) is the last date I checked at the NDIC website (it may be "out of date" -- no pun intended); the "F" means that the well is flowing on its own, not requiring a pump; if the well was on a pump, "AL" for artificial lift would have been used instead of the "F."
2. How many wells will "they" drill in a section? How many wells in all in the North Dakota Bakken? 
It is estimated that up to 50,000 wells will be needed for the Bakken Pool. -- current as of May, 2013. The number of wells per section continues to increase. Goldman Sachs has a graphic, 2016, suggesting 320-acre downspacing is the norm in MB and TF-1. Back in August, 2012, the NDIC dockets suggest there would be up to 16 wells in a 1280-acre spacing unit in the "core" Bakken. In the June, 2013, dockets, the "norm" for 1280-acre spacing units seems to be increasing to 10 wells but CLR is moving toward 17, 24, or more wells per spacing units. In late 2013, CLR had pilot projects for 34 wells in a drilling unit of 1280 acres (two sections). And:
In a January, 2013, presentation, the Director, NDIC, suggested that it may take as many as 48 wells/spacing unit to drill out some areas of the best Bakken. At the time he said that, most spacing units were two sections. Therefore, Lynn Helms was suggesting as many as 24 wells/section in the best part of the Bakken which includes productive formations from the middle Bakken through ALL lower benches of the Three Forks.
3. 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 (this site is down)

In his September, 2016, presentation, Lynn Helms says new Bakken wells are now expected to produce an additional 5 years, increasing longevity for new wells from 30 years to 35 years. 
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.
4. 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 (this site is down) If the data is available, it's likely someone will provide the information.
5. What is meant by fracking? What is the record number of frack stages in the Bakken?
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 (this site is down) and scroll down to "Degas." For correct spelling of "fracking," see FAQ #35. "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 (this site is down), "Degas" provides some more information. When you get to this site, scroll down to "Degas." 

Slide 7 of this presentation provides some data points regarding vertical well fracking and horizontal well fracking. When the Bakken boom began, the fracks were a single stage, but they quickly move to 14 stages or so. Twenty stages was common for a long time, and then in 2012, or thereabouts, operators were moving to 36 stages. BEXP talked about 60-stage fracking back as early as 2010, I believe. EOG reported a 62-stage frack, September 5, 2013, after two (if not more) earlier 50+ stage-fracks in the Bakken. 
In the mainstream media, "fracking" is always preceded by the phrase "the controversial process." This is apparently the "AP writing style."
How long does it take to frack a well? In March, 2014, KOG presented some data suggesting some very short times to frack multiple wells on a pad using "zipper fracks."
6. 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 (this site is down) in North Dakota. Reuters provided a nice update, May 8, 2013, on spacing, to include a section on the North Dakota Century Code.
The standard is 1280 acres (2012). Starting in 2012, we started seeing more overlapping 2560-acre spacing units, though they had been in NDIC hearing dockets for several years. The original purpose of the 2560-acre spacing units was to capture oil along the section lines, but the number of wells being proposed suggest that there may be more to 2560-acre spacing units than simply capturing otherwise lost oil along section lines.
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. There are a limited number of super-long laterals (3 miles/3-section-long horizontals).

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.
7. 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.
8. How much oil can one reasonably expect that a Bakken well will produce over the lifetime of that well? All updates after August 22, 2016, are now tracked here.
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).
Richard Zeits suggests EURs of 1.3 million bbls could be possible in the best Bakken that QEP holds, June 7, 2013.
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 October, 2011, Harold Hamm (CLR/CEO) opined that the "typical" Bakken well will have an EUR of 603,000 barrels. In May, 2011, James Volker (WLL/CEO), opined that the average Bakken well will be 300,000 bbls/well EUR. 
9. What is the record IP to date in the Williston Basin? Note: as of November 13, 2018, FAQ #9 will be updated at this post. [No longer updated, December 8, 2021.]
October 16, 2018: 32972, 8,887, MRO, Lamarr USA 13-23TFH, Reunion Bay, fracked 6/25/2018 -- 7/9/18; 10 million gallons water; 88% water by weight 11% sand by weight, t8/18; cum -- ; (19446 - TAT USA 13-23H); see this post;
September 12, 2018: 32971, 8,702, MRO, Whitebody USA 14-23H, Reunion Bay, fracked 7/9/18 - 7/25/18; 10 million gallons water; 88% water by weight12% sand by weight, t8/18; cum -- ; (19446 - TAT USA 13-23H); see this post;
August 9, 2018: a number of MRO wells in Bailey oil field with huge IPs.

August 2, 2018: MRO with an IP of 7,448 -- Reunion Bay; see this post.
August 1, 2018: still on confidential, but for first full month of production, 95,959 bbls of oil; #30541, Bruin, Fort Berthold 151-94-26A-35-4H, Antelope; see this post;
June 29, 2018: Whiting, #33120 and #33121, with 70K+ and 80K+ in first unconstrined month;
May 3, 2018: Marathon, #33493, 8,160, MRO, Mark USA 11-1H, Antelope, Sanish pool, t4/18; cum -- 
May 2, 2018: Marathon -- a number of records, it appears
April 18, 2018:
  • 33415, 7,572, MRO, June USA 31-2H, Antelope, Sanish pool, API - 33-053-07958; 9.4 million gallons; 84%, t3/18; cum --
December 31, 2017:
  • 33398, 3,291, WPX, Hidatsa North 14-23HX, Reunion Bay, huge well; if this is not a typo, could be a new record: 83,607 bbls in the first full month
December 22, 2017:
  • 32888, 6,278, MRO, Forsman USA 44-22H, Antelope, Sanish, 45 stages; 15 million lbs, t12/17; cum --
From the Whiting 1Q15 transcript: The Flatland Federal 11-4TFH well produced at an initial rate of 7,800 BOEs per day during a 24-hour test of the Three Forks formation, making this the very best well in the basin. The Flatland Federal 11-4HR well produced at an initial rate of 7,100 BOEs per day during a 24-hour test of the Middle Bakken formation.
From a November 11, 2014, post (see also the November 25, 2014, post, same subject); The first well, in the Middle Bakken formation, was completed with 94 stages and was flowing 7,120 BOE/d on October 10, 2014, according to the operator. When the well was completed, it established a world record for number of stages in a single well.
Soon after, an offset well in the Upper Three Forks formation was completed with 104 stages. This well was flowing 7,824 BOE/d on October 11, 2014. This was a hybrid completion comprising 97 NCS GripShift cemented casing sleeves, with seven NCS BallShift cemented ball-drop sleeves in the lower section of the well. In both wells, all stages were successfully fractured.
More to follow: in 2Q14 earnings report, WLL: Tarpon Well Completed in 2nd Bench of Three Forks Flowing 6,071 boepd. Not a record in the Bakken -- see Statoil's #23992. But still, this is huge for the second bench.
Statoil reported an IP of 5,417 on September 26, 2013: #23992, Beaux 18-19 7H, Banks oil field. Based on its IP for natural gas (9,663), this well had an IP of 7,083 boepd. 
Statoil reported an IP of 5,387 on July 19, 2013: #23387, Beaux 18-19 4H, Banks oil field. This might be a new record (this is the IP for crude oil only).
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.
Statoil reported on July 10, 2013: 23385, 5,070, Beaux 18-19 6H, Banks, t6/13; cum -- ; 7 days to drill the lateral; I did not see completion data; 31 swell packers planned; 
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 (this site is down) 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.
10. 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 (this site is down). For a discussion of the "vertical Pugh clause," click here (this site is down). 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.
11.  How much can I expect to lease mineral acres for? What is the record oil lease?
A reader informs me that mineral acres in the reservation recently went for $27,300/acre. -- February 15, 2014.
The late summer QEP/Helis deal may have priced "core" Bakken at $30,000/acre (or more). -- August 29, 2012
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 (this site is down).

Here is one discussion on lease rates (this site is down), 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. In the January, 2013, BLM lease, Slawson paid $19,500/acre for an 80-acre tract in Mountrail county.
12. 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.
13. 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 (this site is down) 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 (this site is down) 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 (this site is down). 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.
14.  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.
15. 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, April 10, 2015: see this post for NDIC completion rules.  
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 with regard to "confidential": "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 (this site is down) 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 (this site is down). As late as April 28, 2012, folks are still discussing the definition of "DRL" (this site is down). My explanation may / may not be entirely correct, but it's the best I can do with the information I am provided. It should be noted that no NDIC spokesman has told me I am wrong, nor has the moderator at the Bakken Shale Discussion Group.

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. 
16. What is the average daily oil production coming out of North Dakota? [Update, June, 2012: 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 900,000 bbls, and could soar to 1 million by 2014.]
June, 2012: 660,000 bopd.  
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.
17.  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.
18. Can you discuss the thinking of infill wells?
Operators are now routinely planning for up to eight wells on spacing units in the better Bakken. I have seen some requests up to 14 wells on one spacing unit. See hearing dockets, linked at the sidebar at the right.
19. How long will "the Bakken" last? See also question #2. And how does the Bakken compare with other tight oil plays in the US?
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. In 2016, this was the EIA's analysis of how the Bakken compared to the other tight plays in the US.
20. 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. Two of the best fields: the Grail and the Truax. 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 Prairie.
21. How many active oil wells are there in North Dakota?
August, 2016: 13,239
For me, this question is irrelevant, but I see it is often asked. According to the NDIC, there were 6,662 at the end of 2011. 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 (208); 2007: 497 (374); 2008: 953 (734); 2009: 626 (529);  2010: 1,684 (1,334);  2011: 1,939 (770). Obviously the numbers inside the parentheses (wells drilled) will increase over time (as the wells are drilled) -- June 15, 2012.
22. How soon does a company stimulate a well after completion of drilling?
Update, posted September 21, 2014: prior to pad drilling, fracking was subject to availability of frack spreads (to include personnel, equipment, and proppant), winter weather, and road restrictions, but that was about it. With pad drilling, everything has changed. Generally speaking the same pre-pad-drilling constraints still exist. But now, "operational constraints" come into play. Generally, operators will not frack a well that reached total depth (vertical plus horizontal) on a given pad until all wells on that pad have reached total depth. The first-best example might have been CLR's 14-well Atlanta pad in Baker oil field southwest of Williston in 2013 time period. That pad was watched closely, and it seemed to take forever to get the wells on that pad completed/fracked. It may have been a full 18 months from the time the first well was spud on that well until the 14th well was fracked.
Original: 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.
23. 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" (this site is down) deep in that thread is enlightening.
24. 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.
25. 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).
26. 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.
27. 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.]
August, 2016: the few operators actually drilling in North Dakota suggest that it costs about $8.5 million for a deep middle Bakken or Three Foks well; many say their target is $8.0 million; others say they are getting prices down to $6 million
August, 2012: Newfield says $10 million for a long lateral; QEP says $11 million; anecdotal comments suggest as much as $20 million/well. 
August, 2011: "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. 
28. How long does it take to drill a Bakken well?  See timeline from "permit to drill" to first royalty check. In late 2013, the expectation (not always met) is that the well will reach total depth in less than 20 days, and will be fracked over several days. Due to pad drilling, wells may not be fracked until all wells on a pad have reached total depth. If there are fourteen wells on a pad, and only one rig is drilling the pad, it could be twelve months before the wells are fracked.
August, 2012: Lynn Helms says drillers are reaching total depth in 20 days; one operator recently reported a total depth in 13 days, and I saw one well that appeared to have reached total depth in 8 days of drilling.
May 1, 2012: 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 (this site is down) Sliding sleeve fracturing can be accomplished in one to two days; plug and perf takes significantly longer. A June 10, 2012, note about length of time for fracking.
Having said all that, this may be the record for completing a well in the Bakken (this site is down). Before clicking on the link: who do you think has the record? a) BEXP  b) WLL  c) EOG  d) HES
29. What is meant by "Zone I, II, III, and IV" and spacing units? Click here (this site is down). Also here (this site is down) for EOG spacing strategy first noted in 2010 (zones were not mentioned in this thread). I used to think that once an oil field was defined, the rules for that oil field, including the size of the spacing unit was set "for life." That is inaccurate.  When an operator requests a permit, he also requests the spacing unit; generally these are established with the first well in the field and subsequent wells in that field have the same spacing unit. This is because spacing units are based on geology/production expectations, and the field is generally felt to be uniform. If, at a later date, a driller requests a different spacing unit within a defined field, the NDIC must approve and the driller must present a satisfactory argument. If the field is overlayed with a new spacing unit for a new well (or new wells), the field will now have zones. I assume if a Bakken formation has multiple zones in a given field, the first zone was/is 640 acres; the second zone, 1280; the third, 2560. The fourth zone may be 320; and the fifth zone may be something else. And, of course, the sequence may be completely different depending on the how the field is developed.  The zones may have different rules, including spacing rules. Teegue briefly mentions "zones" at this thread (this site is down).

30. What does the abbreviation "HBP" stand for? Leases and permit renewals?
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: one example: BR's #17781, Golden Creek 44-23H, the permit, in 2014, had been renewed five (5) times.]
31. Do drillers fracture wells during the winter?
This is EOG's standard operating procedure (this site is down): 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.
32. 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 (this site is down).

33. 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 (this site is down) 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).
34. 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.

35. 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."
36. What is unitization? This appears to be best the answer from most reliable source (this site is down) 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  (this site is down). 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.
37. 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.
38. What are the names of the townships in Mountrail County? Click here.

39. 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." The Bakken Shale Discussion Group has a nice discussion on "plant products" (this site is down).
40. How are decline rates calculated? Click here (this site is down).

41. What is the current estimate of recoverable reserves of oil in North Dakota? Compare with Saudi Arabia here.
Update, June 7, 2013: this is very, very clear -- Denver conference. CLR: the Bakken plus TF1 at 3% recovery rate, 24 billion bbls; add TF2, TF3, and TF4, and maintain 3% recovery, and CLR estimates 32 billion bbls. Every 1% in incremental recovery factor translates into an additional nine billion barrels of estimated ultimate recoverable reserves in the field.
Update, August 29, 2012: CLR's corporate presentation suggests there may be close to one trillion bbls of original oil in place (OOIP), but from Leigh Price's estimate of 550 billion barrels. At 5% recovery, CLR states that up to 45 billion barrels of recoverable oil may exist in the Bakken. 
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. 
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.
41a. What is the defnition of "proven reserves"? Proven reserves are based on amount of oil that could be recovered in the next five years based on current technology and pricing.

42. 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.
43. 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.
44. 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.
45. What is "rig stacking"?  For an informal discussion, click here (this site is down).

46. This question will be tracked at this post: How much sand and water is used in fracking in the Bakken, beginning August 30, 2016. For archival purposes, I have left the previous updates. [Update: October 21, 2014].  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.] [Update: June 9, 2015. When I first started blogging, one million lbs of sand was common and then, as noted, BEXP pushed it to 4 million lbs. Maybe two years or three later EOG, with its own sand mines in Wisconsin pushed it to 10 million lbs for a long lateral. Now, EOG has used almost 20 million lbs in a long lateral.]
47. 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."

48. 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]).
49. 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 (this site is down).

50. 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 (this site is down). [Update: Teegue says the length of time for temporary spacing is now up to 3 years (this site is down).]
51. Is there enough water for fracking in western North Dakota? More than enough water. Also: water is the least of our concerns.

52. What is meant by a "zip frack" or a "zipper frack"?  See first comment at this post. See also this post.

53. 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.
53. What is meant by "operated" and "non-operated"?  Follow this link.

54. 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. I have seen many instances of producing wells still awaiting spacing approval from the NDIC. It's always possible the paperwork has not caught up with the status of the well, but it certainly seems I've seen plenty of examples of "ICO" status on the file reports long after the wells have been producing.

55: How long can operators flare natural gas in North Dakota: 60 days, without a waiver (this may have changed in 2013). [Update: rules on flaring are changing in 2014; once the dust settles, if I remember, I will update the new rules. -- July 4. 2014.]

56. In production data, what is the difference between "runs" and "production"? See this post.

57. How long can a well be shut-in? See this thread (this site is down). Something tells me this is not the whole story. It is my understanding that if there is no production from a well in over a year, the NDIC can take action to consider it an abandoned well.

58. Oil is generally "measured" in barrels (bbls). Is the volume of natural gas liquid (NGL) ("wet" natural gas) also expressed in bbls? No, NGLs are generally expressed in gallons, according to a comment sent in by a chemical engineer.  Incidentally, some think the "additional" "b" comes from "blue barrels." From RBN Energy:
There’s one more aspect of NGL markets that must have been designed to confuse outsiders, because it certainly does.  NGL quantities are quoted in barrels.  NGL prices are quoted in gallons.  Really.  So I’ll sell you 10,000 barrels of non-TET normal butane for $1.36 per gallon.  It never occurs to NGL people to convert either the quantity to gallons or the price to a per barrel number.  They think of everything multiplied by or divided by 42.  Go figure.  And BTW, propane retail people do think in gallons - but that’s another story.
59. What is meant by natural gas liquids? RBN provides a great primer on natural gas liquids, or wet natural gas. Briefly: Natural Gasoline  - C5s; Normal Butane – NC4, Isobutane  - IC4. From the linked RBN post:
NGLs are sometimes referred to by the number of carbon atoms in their molecules.   Yes, even traders with no engineering background do this.  It makes you part of the secret NGL society.  Ethane’s chemical formula is C2H6, meaning that it has two carbon atoms and 6 hydrogen atoms, and in the market it is called C2.  Propane’s formula is C3H8, and it is called C3.  Butanes are a little more complicated and it is best that we not get into the molecular chemistry here to explain it (for me and for you).  Suffice to say that normal butane is called NC4 and isobutane IC4.  Finally natural gasoline is called C5 (even though natural gasoline contains C5 plus a lot of C6 and greater).   The more carbon atoms in a hydrocarbon molecule, the heavier it is.  So in the market, butanes and natural gasoline are called  ‘heavies’ or ‘heavy ends’.  Ethane and propane are  ‘lights’ or ‘light ends’.   Using these semi-technical terms keep others from understanding what NGL people are talking about, which of course is the objective.
59a. Butane, one of the two natural gas liquids that is also known as LPG (liquefied petroleum gas; the other being propane). In the U.S. context, we are generally referring to normal butane, that product used in U.S. markets primarily as a motor gasoline blending component, and to a much lesser extent as a petrochemical feedstock.

59b. How much NGL is North Dakota producing? A lot. 400,000 bpd in 2018; expected to increase to about 1 million bpd by 2035. See this post.

60. Royalty/mineral rights/royalties: Hess has a nice page for FAQs regarding royalties. Royalties must be paid within 150 days of first production without incurring an 18% penalty. The penalty  calculation: based on when oil was sold + 150 days.

61. What is the deepest well drilled in North Dakota? Click here. 

62. What is meant by "backwardization" and "cotango"? Click here for nice snapshot of example. "Backwardization" occurs when oil companies start emptying their storage tanks and selling oil because the current price of oil is better than the anticipated "future" price. In August, 2013, with the spot price of crude oil at $106, oil companies were emptying their storage tanks, anticipating $95 oil in 2014, and even lower after that. "Cotango" is a reluctance to sell oil, anticipating a higher future price, but oil companies have contracts to meet, so they begrudgingly sell their oil, but work hard at minimizing the "damage."

63a. What does the abbreviation "ULW" mean in some of the names of wells used by Burlington Resources? "Unit line well." The well will be drilled under or near the section line in a 2560 acre unit.   Other companies will likely come up with their own  “short-hand” notations for this type of well.

63b. What does the abbreviation "LL" mean in some of the names of wells used by QEP? A "line lateral?" Not sure exactly what "LL" stands for but it is a well whose horizontal drains an "overlapping 1280-acre spacing unit." The horizontal will lie along the section line/the spacing unit line.

64. What is the longest horizontal lateral in the Bakken? I track the longest horizontal laterals here.

65. Land owners vs the state: who owns the mineral rights under the water along the shore (riparian rights)?  ND Supreme Court:
[¶26] We conclude the upland owners' reliance on N.D.C.C. § 47-01-15 to support their claim to mineral interests under the shore zone of navigable waters in North Dakota is misplaced and the landowners have not cited any other factual support to show a grant of mineral interests by the State, or a successor to the State, to any specific upland owner. We therefore conclude the district court did not err in concluding the State owns the mineral interests under the shore zone.
Also, from eenews, January 2, 2014:
The North Dakota Supreme Court ruled that the state owns the so-called shore zone between the high- and low-water marks of the Missouri River that cuts through the Bakken. The Dec. 26 ruling, though, still allows private landowners to challenge the state's ownership in some circumstances. And there's still an open question about who owns the shore zone of the Missouri River on the Fort Berthold Indian Reservation.
66.  What is meant by "field" in the "oil patch" in North Dakota.
A field is an administrative term designating an area of the oil patch in North Dakota. A field is designated "geographically" (such as the Blue Buttes field) and by the formation (such as the Bakken) so that a particular field might be designated "Blue Buttes-Bakken." A field designating the Spearfish formation in the same field would be designated the "Blue Buttes-Spearish." Some areas in an oil patch, in this case, the Williston Basin are more productive than others. In these areas, wells can be placed more closely together. It would get tedious to do the same thing over and over, so the North Dakota commission who regulates the North Dakota oil industry, the North Dakota Industrial Commission, will designate an area as a certain field, such as the "Blue Buttes-Bakken" and establish rules for that field: where wells can be placed (how close to section lines, for example); how many wells can be drilled in the field; what the spacing units will be; etc. Oil companies can then more easily apply for a permit and be granted a permit when they meet the rules of that particular field. Of course, oil companies will often ask for waivers or deviations of established rules; over time, some of these waivers set the new norms. For example, most Bakken fields early in the boom were spaced for 640 acres; now (posted in 2014) almost all Bakken fields are spaced for 1280-acre units. Drillers who want to drill a well with a different spacing size (2560-acres, for example) need to ask permission.

When I first started blogging about the Bakken, I did not understand the importance of "fields." Now it makes a lot of sense.

In addition, folks who follow the Bakken recognize the great fields, and the fields that might not be so good. It helps them anticipate the value of a well in a particular field.

Some fields are as small as one section (640 acres); some are larger than a township (36 sections). I track fields here.
67. When did we first hear about the "lower benches" of the Three Forks formation? The best I can find is sometime in mid-2011. In addition to TF1, TF2, TF3, and TF4, are there other designations for these formations. BR seems to suggest they might refer to these benches as the upper Three Forks (first bench, B1); the middle Three Forks (second bench, B2); and the lower Three Forks (third bench, B3), suggesting they will not be targeting the fourth bench.

68. What is meant by "drl" or "drill status"? What is meant by "no production data" when a well comes off the confidential list and goes to drill (or drl) status? The complete answer is found at this post.

69. What are condensates? See this post. Richard Zeits, February, 2018, also had a nice post on condensates (light-ends; ultra-lights).

70. Why do we measure oil in barrels (bbls)? See this post.

71. Choked back. Posted August 22, 2015, during the 2014 - 2015 price slump. I use the phrase indiscriminantly without explanation in most cases whenever the well does not seem to be producing at historic "potential." There are many, many reasons why a well may not be producing at max -- perhaps local wells are being fracked and a particular well is taken off-line; most often I use the phrase "choked back" when I see a well producing less than a full 30 days / 31 days in any given month.

72. DUCS? http://themilliondollarway.blogspot.com/2015/08/wednesday-august-5-2015-part-iv-paa.html
They are reported as SI/NC -- instead of DRL, or A, or CONF, etc. It was an NDIC "thing," I believe. I'm not quite sure of the difference between DRL status and DUC status. I believe DRL means the operator plans to complete the well soon or is in the process of completing the well, and DUC (SI/NC) means that the operator will delay completing the well as long as possible....
73. How does the depth of Williston Basin formations compare to other "ultra-deep" wells? From a reader:
Per a 2005 report by Oklahoma State University, in 1998 there over 1,700 wells deeper than 20,000'. 52 of them were deeper than 25,000', of which 19 were in the Anadarko Basin.

By 2002, there were over a thousand wells in the Anadarko with an average depth of 17,600'. 
The Tiber well, drilled in the Gulf in 2009, was over 35,000' deep, one of the deepest wells ever drilled that found hydrocarbons.
74. How long do drillers have to complete a well once it is spud? Prior to October, 2014, it was one year. But with the severe slump in oil prices, North Dakota has given operators an additional year to complete wells once spud. Reuters has the story.

75. You used to put IPs in bold red, but now I see you are putting IPs in bold blue. Why?
I continue to put IPs in bold red. However, if wells go to SI/NC status first, I put the SI/NC in bold blue, and then every IP update from SI/NC status remains in bold blue. I didn't catch the early SI/NC wells, and I won't catch all the SI/NC wells, but the ones I do catch will be placed in bold blue. Wells that are never placed in SI/NC status will continue to have their IPs in bold red. 
76. What is the crude oil capacity of a unit train? A DOT-111 tank car can carry upwards of 35,000 gallons (830 bbls).
A typical unit train has 118 the tank cars. Each tank car holds about 714 bbls --> 85,000 bbls/unit train. If that is accurate, it won't even take a unit train to transport 24,000 bbls. Maybe 30 tank cars. The Olympians won't even notice them. Posted January 3, 2015.
77. Who are the top five North Dakota Bakken oil producers? The most recent information I can find is at the end of 2014 over at 24/7WallStreet. The data below is from 3Q14 or thereabouts and will change over time:
  • Whiting: 107,000 bopd; 885,000 net acres
  • CLR: 127,788 bopd; 1.2 million net acres
  • Hess: 63,000 bopd;
  • EOG: 293,500 bopd from all US oil fields; does not differentiat total production by field; 110,000 acres in the Bakken
  • Statoil: 50,000 bopd; 355,000 net acres in the Bakken
78. What is the status of flaring and natural gas production in North Dakota now that new rules have been in place for a year or so? A: North Dakota natural gas production hit an all-time record despite huge decline in the number of wells being drilled, and the number of active rigs. With only 29 active rigs in North Dakota (February, 2016), compared to 200 active rigs two years earlier, North Dakota his an all-time natural gas production record, and flaring is down to an incredible 11%.

79. What was the best Bakken well ever drilled? As of August 6, 2016, it was an EOG Riverview well, file #30286.

80. Is there a good article on fracking sand in the US? Yup, right here.

81. What do you mean by "halo effect" when neighboring wells are fracked?
When existing, neighboring wells are very, very close to new wells that are being fracked in the same formation, common sense suggests that some of the "new" fracking might extend to the older, existing wells.
In fact, there are numerous examples in which an existing well shows increased production after a neighboring well is fracked.
However, I have always had a concern that the increased production is simply a result of increased pressure building up while the existing well is taken off-line during the fracking of the neighboring well.
Once the older well is brought back on line the increased production is simply due to pressure that has built up and once the well has been back on line for a few months, production returns to what it would have been regardless.
That's why I call it the "halo effect" -- it is very likely that it is simply a build-up in pressure and has nothing to do with the fracking of the neighboring well per se. So, for now, the "halo effect" is simply an observation and I am not making any conclusion why it is happening. But yes, my initial enthusiasm regarding the "halo effect" and what I originally implied, may be (and is likely to be) completely wrong, and due more to my inappropriate exuberance about the Bakken than a rational explanation.
82a. What do you mean by Bakken 2.0? See this post. Two important data points:
  • I set October 19, 2016, as the beginning of Bakken 2.0
  • the event that triggered the Bakken 2.0 designation: the SM Energy announcement that it was selling some Bakken acreage/assets to Oasis
  • it appears Permian Shale 2.0 began with the WPX, Noble, and XOM announcements regarding acquisitions in the Permian -- late 2016/early 2017
82b. What do you mean by Bakken 2.5? See this post.
  • Bakken 1.0: began in the summer of 2007; it was originally tagged "Bakken101" and I continue to use the "Bakken101" tag 
  • Bakken 2.0: October 19, 2016
  • Bakken 2.5: April 10, 2018 -- correlates/corresponds with CLR's new completion strategies; North Dakota crude oil production to set new records; increased focus on the Permian vs the Bakken
  • Bakken 3.0: when the new USGS Bakken survey is released 
83. Record production of a Bakken well in one month? I had not been asked that question until I posted this well May 12, 2017, which produced 80,000+ bbls of crude oil in one month.

84. How long does it take to drill a Bakken well (two miles down, two miles horizontally)? At the beginning of the boom, it could take as long as 45 days, even longer on occasion. In 2017, it is generally about 15 days. However, in November, 2017, Lynn Helms said he was shown technology in which one well (with a 2.5 horizontal) was drilled in 3 days; its sister well was drilled in 4 days. It was in an interview that Lynn Helms made the comment and it's a bit unclear if the 3 - 4 days was from the initial spud to TD or if it was the horizontal only.

85. Definitions for length of laterals. Based on stories being reporting November, 2017, it appears time to formalize the parameters for laterals of various lengths in the Bakken (laterals only, not total drilling depth):
  • short lateral: 4,500 feet, one section
  • long lateral: 9,000 feet, two sections
  • extended long lateral: 14,000 feet, three sections
  • super long lateral: 18,000 feet, four sections
    86. In the monthly "Director's Cut," what is the source the NDIC uses for "price of Bakken oil"? The director uses the North Dakota Sweet price from Flint for his number. See this post.

    87. Comments about "primary recovery" in the Bakken.
    • at the beginning of the boom, the word on the street, was 1 - 3%
    • my calculations, early in the Bakken boom, suggested 5 - 7% primary recovery
    • Whiting openly talked about 7% primary recovery early on and I think there was talk of 12% primary recovery
    • it seems I've heard reasonable people talk about 20% recovery
    • Mark Papa of EOG fame actually suggested 50% recovery is the next shale breakthrough; 50% primary recovery, apparently, is the norm in conventional oil fields 
    88. What are the various "types" of crude oil and what the "benchmark" crude oils? Link here. Heavy sour graphic at this  post.

    89. What are operators using for "artificial life" (pumps) in the Bakken? See this post. 

    *******************************

    Overlapping Spacing Units

    Note: this was an informal e-mail in reply to an individual who did not understand "overlapping spacing units." This was posted August 3, 2013. For more on "overlapping spacing units," see this post.
    1. "Conventional" spacing units for unconventional shale: horizontals have to be "offset" from the section line (or the adjoining spacing unit by 250 to 500 feet so as not to "drain"/affect the adjoining spacing unit). I don't know what the offset rules are, but I know wells have to be 250 to 500 feet (or some arbitrary distance) from the adjoining spacing unit.

    2. That meant horizontal legs had to be a) 250 to 500 feet (or whatever the rules are) from the section line; and, b) had to end 250 to 500 feet (or whatever the rules are) from the section line.

    3. The well site and the vertical can be in an adjoining spacing unit, but the horizontal has to "begin" in the "correct"/permitted spacing unit.

    4. With conventional wells, no big deal.

    5. But with a continuous reservoir like the Bakken, there was a lot of oil that was being left behind with the "offset" rules. A section is 5,280 feet wide. Five hundred (500) feet on one side of the section line and 500 feet on the other side of the section line = 1,000 feet lost.  Fracking is only effective out to about 500 feet.

    6. So, somewhere along the line, they came up with the idea of "overlapping" spacing units -- spacing units that would "cross" section lines. This means that the horizontals can now capture the oil along the section lines.

    7. I originally thought that operators would only be using the "overlapping" spacing units for oil along the section lines, but it appears that "overlapping" spacing units will now be used just like other spacing units.
    8. If it were not for overlapping spacing units as much as 20% of the Bakken would be left untouched.
    *******************************

    I didn't want to delete the original "FAQs" so I left that data here for archival purposes.
    Many of the links below are broken. I have not updated them.

    FAQs 1

    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. [Update, August, 2012 - roughly 7,000 active wells in North Dakota; roughly 60,000 active rigs in California; ND outproducing California.]


    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. As late as April 28, 2012, folks are still discussing the definition of "DRL." My explanation may / may not be entirely correct, but it's the best I can do with the information I am provided. It should be noted that no NDIC spokesman has told me I am wrong, nor has the moderator at the Bakken Shale Discussion Group.

    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, June, 2012: 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 600,000 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?
    Operators are now routinely planning for up to eight wells on spacing units in the better Bakken. I have seen some requests up to 14 wells on one spacing unit. See hearing dockets, linked at the sidebar at the right.
    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 6,662 at the end of 2011. 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 (208); 2007: 497 (374); 2008: 953 (734); 2009: 626 (529);  2010: 1,684 (1,334);  2011: 1,939 (770). Obviously the numbers inside the parentheses (wells drilled) will increase over time (as the wells are drilled). June 15, 2012.
    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. A June 10, 2012, note about length of time for fracking.
    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 (zones were not mentioned in this thread). I used to think that once an oil field was defined, the rules for that oil field, including the size of the spacing unit was set "for life." That is inaccurate.  When an operator requests a permit, he also requests the spacing unit; generally these are established with the first well in the field and subsequent wells in that field have the same spacing unit. This is because spacing units are based on geology/production expectations, and the field is generally felt to be uniform. If, at a later date, a driller requests a different spacing unit within a defined field, the NDIC must approve and the driller must present a satisfactory argument. If the field is overlayed with a new spacing unit for a new well (or new wells), the field will now have zones. I assume if a Bakken formation has multiple zones in a given field, the first zone was/is 640 acres; the second zone, 1280; the third, 2560. The fourth zone may be 320; and the fifth zone may be something else. And, of course, the sequence may be completely different depending on the how the field is developed.  The zones may have different rules, including spacing rules. Teegue briefly mentions "zones" at this thread.

    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." The Bakken Shale Discussion Group has a nice discussion on "plant products."
    39. How are decline rates calculated? Click here.

    40. What is the current estimate of recoverable reserves of oil in North Dakota?
    Update, August 29, 2012: CLR's corporate presentation suggests there may be close to one trillion bbls of original oil in place (OOIP), but from Leigh Price's estimate of 550 billion barrels. At 5% recovery, CLR states that up to 45 billion barrels of recoverable oil may exist in the Bakken. 
    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. 
    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.
    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.] [December, 2014: EOG was one of the first operators in the Bakken to use "huge" amounts of proppant (EOG uses sand only) -- as much as 14 million lbs for a long lateral. It appears that, at this time, CLR may have snagged a record with 19 million lbs of proppant (almost all sand, some ceramic) on a well in the Bakken.]

    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. [Update: Teegue says the length of time for temporary spacing is now up to 3 years.]
    50. Is there enough water for fracking in western North Dakota? More than enough water. Also: water is the least of our concerns.

    50a. How many water trucks does it take to complete a well. A water truck typically carries 11,600 gallons of water. A well requiring 7 million gallons for fracking (on the low side) would take 603 trucks. 

    51. What is meant by a "zip frack" or a "zipper frack"?  See first comment at this post.

    52. 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. Another site discussing royalties.
    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. I have seen many instances of producing wells still awaiting spacing approval from the NDIC. It's always possible the paperwork has not caught up with the status of the well, but it certainly seems I've seen plenty of examples of "ICO" status on the file reports long after the wells have been producing.

    54: How long can operators flare natural gas in North Dakota: 60 days, without a waiver. [Update: the rules on flaring in North Dakota are changing in 2014; once things tend to settle with regard to the new flaring rules, if I remember, I will post that updated data -- July 4, 2014.]

    55. In production data, what is the difference between "runs" and "production"? See this post.

    56. How long can a well be shut-in? See this thread. Something tells me this is not the whole story. It is my understanding that if there is no production from a well in over a year, the NDIC can take action to consider it an abandoned well.

    57. Oil is generally "measured" in barrels (bbls). Is the volume of natural gas liquid (NGL) ("wet" natural gas) also expressed in bbls? No, NGLs are generally expressed in gallons, according to a comment sent in by a chemical engineer.  Incidentally, some think the "additional" "b" comes from "blue barrels." From RBN Energy:
    There’s one more aspect of NGL markets that must have been designed to confuse outsiders, because it certainly does.  NGL quantities are quoted in barrels.  NGL prices are quoted in gallons.  Really.  So I’ll sell you 10,000 barrels of non-TET normal butane for $1.36 per gallon.  It never occurs to NGL people to convert either the quantity to gallons or the price to a per barrel number.  They think of everything multiplied by or divided by 42.  Go figure.  And BTW, propane retail people do think in gallons - but that’s another story.

    58. What is meant by natural gas liquids? RBN provides a great primer on natural gas liquids, or wet natural gas. Briefly: Natural Gasoline  - C5s; Normal Butane – NC4, Isobutane  - IC4.

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