FAQ

1. What is the average longevity of a Bakken well?

This is probably one of the most asked questions I see. Everyone will opine on this one. Right now, the decline rate is such that the wells are probably marginal producers after seven years. 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. At least that's my understanding.

2. What is the status of the "fill in the blank with the name of your favorite well."

I may not have that data because I don't subscribe to the NDIC database. If you cannot find the status of a certain well, pose your question on the Bakken Shale Discussion Board. If the data is available, it's likely someone will provide the information.

3. 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. The typical well in North Dakota right now "drains" 640 acres. Therefore, the mineral owner with 10 mineral acres only has 1.56% of the 640 acres that that particular well drains. 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 * 0.20) 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.

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.

4. What is meant by fracking?

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."

5. What is the typical spacing of oil wells in North Dakota?

This will change over time. At the beginning of the current boom, most wells were spaced at either 640 acres or 1280 acres. I refer to them as "short laterals" or "long laterals," respectively. In early 2010, the state ruled that operators did not have to request permission to go to 1280-acre spacing and that appears to be the norm. However, more and more requests for 2560-acre spacing are being seen for multi-well pads. These wells will all be long laterals -- stretching the diagonal distance of two sections, about two miles.

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, affects one section, whereas a "long lateral," 1280 acres, affects 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 1280-acre spacing in North Dakota but now these longer laterals seem to be the norm. (Oasis, November, 2009; EOG, December, 2009, are both recent examples. Someone has opined that 90% of Hess' 130 wells in ND are long laterals.)

A 640-acre well has a lateral that is about one mile long; a 1280-acre well has a lateral that is 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:  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 EcoPads along the Williams County-Divide County border. January 22, 2010.

Update: CLR announced its first Eco-Pad; it will be in McKenzie County.

6. When will the EOG/BNI railroad oil tanker operation become operational (Stanley, ND)? Are there plans for more such terminals?

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.

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 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. By the way, this comes with a newly revised EUR of 280,000 boe 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.

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. However, having said that,  the record IP in the Williston Basin is 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 -- sometimes I forget that I have this site, and I could forget to post a new record well.

9. What is "pooling" and the Pugh clause?

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. Pooling is easier to describe: instead of finding every last mineral rights owner and contracting with each mineral rights owner on an individual basis (lots of time wasted), the producer/operator asks the state for permission to "pool" all mineral rights owners, thereby setting remuneration based on agreement reached with a majority of the mineral rights owners. It appears that the right to pool is the last step in the paperwork/bureaucratic process before preparation for drilling actually begins.

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). 

11. What is an Eco-Pad? What are "Dakota Candles" and "Orion Belts"?

Click here for information on Eco-Pads. "Dakota Candles" and "Orion Belts" are terms I use for multi-well sites. 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.

12. What is the "IP"? And the 24-hour 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 early 2010, more and more companies were switching to 24-hour flowback as their initial production number. This results in a) more confusion; and, b) significantly higher IPs (with subsequent more horrific decline rates. 

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. In WLL's June, 2010, corporate presentation, WLL stated the cost was $10/bbl.

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."

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?

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.

15. What is the average daily oil production coming out of North Dakota?

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.

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. 

Sixteen Reasons, Connie Stevens

17. Can you discuss the thinking of infill wells?

Gladly, by directing you to a discussion group. It is my understanding that the issue of infill wells in the Bakken in North Dakota is still being explored. With a well in almost every section of the Parshall oil field, EOG is now ready to experiment with infill wells. But it is still very early in the game to be talking a whole lot about infill wells.

18. How long will "the Bakken" last? 

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; 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 4,693 active wells in North Dakota in 2009. How many permits (wells drilled from these permits) are being granted on an annual basis in North Dakota? 2006: 422 (195); 2007: 497 (336); 2008: 953 (734); 2009 626 (208). Obviously the numbers inside the parentheses (wells drilled) will increase over time (as the wells are drilled). March 10, 2010.

21. How soon does a company stimulate a well after completion of drilling?

This varies. Buried deep in this site one learns that EOG spudded a well on January 19, 2009, but did not plan to fracture stimulate it until July, 2009. I assume that most wells are fractured within a month of when drilling is completed but I do not know. I will watch for more examples.

22. What is meant by a "top lease"?

I have no idea, 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. The takeaway: 30 years of drilling in North Dakota [until 2030] and oil production in North Dakota until 2100 (the Bakken formation).

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.

26. How much does it cost to drill a horizontal well in North Dakota?

"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

27. How long does it take to drill a Bakken well?

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. 

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.

29. Regarding the GIS map at the NDIC website, why is there not an icon for a rig where there is "drilling" depicted (the open green circle)? The well has been drilled to depth but is waiting to be fracked, completed, and/or placed on the confidential list. Answer provided by "David" at Bakken Shale Discussion Group.


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Updated March 21, 2010.