- The Rolfstad Presentation (a PDF - PowerPoint Presentation)
- each one percent increase in recovery rate yields huge increase in EUR for the field
- 48 wells/spacing unit, Lynn Helms, January, 2013
- How EOG is paying for its wells in six months, June, 2013
- scrolling through trends
First and foremost, no one comprehends how big the Bakken is except the guys in the oil patch with years of experience. No matter how much hype you think there is about the Bakken, the fact is: it is huge. It now accounts for 12% of US oil production.
Although there is some Williston Basin Bakken activity in southern Saskatchewan and eastern Montana, the Bakken, for all practical purposes, is centered in four counties in North Dakota (Dunn, McKenzie, Mountrail, and Williams) with some additional sweet spots in the southwest (Stark County) and the northwest (Divide County). But for all the articles on the Bakken, it really is only a small geographical area. I doubt visitors to North Dakota who do not go west of Minot or Bismarck will notice much oil activity. Tourists on I-94 on their way to Yellowstone this summer might be surprised at the amount of activity at Belfield when they stop to gas up, but it will be a momentary observation, and then they will be on their way.
The tea leaves suggest the farmers and ranchers impacted by the oil industry are reaching a breaking point. The mantra that agriculture and the oil industry can co-exist will be explored at an upcoming conference. In the long run, twenty years from now, I am confident farming and oil can co-exist; in the short term, I am not so sure. A lot of folks were under the impression that there would be one well on each section or perhaps one well on each spacing unit (most of which are now two sections in size). But it is clear that in the heart of the Bakken, there will be far more than one or two wells per section.
I don't think the average density of wells has reached even two wells/spacing unit in the Bakken and yet the challenges for the farmers and ranchers appear to be increasing, not decreasing. The housing situation is bad, very bad, seven years into the boom, but the challenges faced by the agricultural industry seem to be worse, and getting worse. It has to do with dust, roads, inconvenience, and "way of life."
The NDIC has developed a "master plan" for development that seems to be as good a plan as any to "save" western North Dakota for dual use (oil and agriculture). [By the way, solar farms do not lend themselves to dual use, and I'm not even sure how much wind farms lend themselves to dual use. Solar farms do not co-exist with farming.]
But it is not going to be one or two wells per spacing unit. The number of wells per spacing unit will go to 2, 4, 6, 8 - who do we appreciate -- wells per spacing unit. This summer there are two or three projected test projects to see if 24 wells, and then 48 wells, can be placed on one or two pads for one spacing unit.
If there is this much difficulty with one or two wells/spacing unit, imagine 14 wells/spacing unit. Two thousand truck-trips on average to drill one well (I can't remember if it's four thousand one-way or two thousand round trips, but it hardly matters). There could be as many as four pipelines required for each pad: fracking water, brine/waste water, crude oil, natural gas.
Much more could be written on this.
The challenges the farmers and ranchers are facing could result in the Bakken boom ending badly in the near term. By "badly" I mean increasing rancor among mineral owners, surface owners, ranchers, farmers, oil companies, politicians (county and state), etc. A state moratorium on building any more pads is not far-fetched; letting companies drill the heck out of existing pads, but no more pads. Free market capitalism seems to be moving things in that direction, regardless.
There is now more than enough takeaway capacity for OIL if one believes the experts. North Dakota is producing about 800,000 bopd. It is said that rail provides 800,000 bopd takeaway capacity and pipeline provides 500,000 bopd takeaway capacity (if I haven't gotten the figures turned around). The glut at Cushing as been resolved; for the past three weeks the amount of oil at Cushing has decreased. Bakken oil is being piped and railed to the East Coast; the Bakken is singularly responsible for saving two or three East Coast refineries.
California now imports eight (8) times more Bakken oil than it did this time last year. Eight times more. Bakken oil is railroaded/piped to Oregon, where it is loaded unto marine vessels and shipped to California. California will not allow any more pipelines to be buried, and the railroads are probably maxed out; there are geographical chokepoints over the mountains going into southern California, and, of course, one has the Rocky Mountains farther north.
There are enough drilling locations to keep the Bakken operators busy through 2030. And then after that, there is the Tyler, the Spearfish, the Madison, and the Red River. Most folks felt that the Madison and the Red River were tapped out, but that was before a) oil hit $100 on a sustained basis; and, b) new technology came along. The reason that the Tyler and the Spearfish are not being drilled now is simply because the Bakken is pricing the other formations out of business: there are no oil service companies available, or manpower available, to drill these other formations. They are all in the Bakken.
It is said that not one operator has made any money in the Bakken yet. That doesn't mean individuals haven't made a lot of money; it's just that oil companies continue to invest more money in drilling than they are currently receiving in payback. There are many, many articles on this. But the oil companies aren't drilling out of the goodness of their collective hearts; they are in the Bakken to make money. Someone has said that oil companies are counting on making their money on P2 (P1 = proved reserves; P2 = probable; and, P3 = possible). As I understand it, when a well hits oil in a P2 play, that area becomes a P1 play. When Harold Hamm suggests a 903 billion barrel reserve I assume he is talking P1 + P2 + P3.
The Bakken is an oil play, not a natural gas play, but it has a huge amount of natural gas, also. Folks talk about Bakken oil production being choked back due to lack of infrastructure support. That is true, but it is mostly due to lack of infrastructure support for natural gas. Until there are enough natural gas processing plants in the Bakken, oil production will be choked back. One cannot simply lay natural gas pipelines. Before natural gas can be placed into the "system," it has to be processed, cleaned, various components separated for various reasons. If natural gas is not processed and placed into the "system," it is flared.
The Bakken is an oil play. Currently the Bakken has two competitors for rigs and workforce: the Eagle Ford in the West Gulf Basin, south of San Antonio; and the various formations in the Permian Basin, west Texas.
All three (the Bakken, the Eagle Ford, and the Permian) require water for fracking. It remains to be seen whether water will be the discriminator among the three but there is no lack of water for fracking in the Bakken. There may or may not be a "true" water issue for fracking in Texas but it could certainly become a political issue. Time will tell. But again, there is no shortage of water in western North Dakota for fracking.
The number of active rigs reflects the degree of activity in the Bakken, but not necessarily the production. The rigs have gotten more efficient; the operators more effective; fewer rigs are producing more oil. There is now a general consensus that the number of oil rigs in the Bakken will range between 180 and 220. Currently, there about 186 active rigs on any given day. The high was 218; the post-boom high sits at 194; the post-boom low hit a scary 179.
Over time, the estimated ultimate recovery (EUR) for Bakken wells has gone up. It now ranges from 300,000 bbls to more than one million bbls over the lifetime of a Bakken well.
When the boom began, time was more important than money. Now that acreage has pretty much been spoken for, money is more important than time. Operators are concentrating on decreasing the cost of completing a well. The costs for wells range from $5 million to $14 million, it seems. And, of course, it seems folks are comparing apples and oranges when talking about well costs: for me, it's impossible to figure out what some companies consider "cost of wells." And, of course, it seems the bonus money paid for the lease is not part of the cost of the well; that bonus money will be amortized over several wells as time goes on.
TO BE CONTINUED (MAYBE, IF THE SPIRIT MOVES ME) -- The spirit never moved me. -- I last looked at this on November 26, 2013.