Staggering Statistics

The Bakken keeps rockin'.

See also, Crazy Numbers, Part 2.  One well in this current boom will soon surpass one (1) million barrels of oil produced; four others have surpassed 500,000 barrels each.

I keep going back to re-read the Rocky Mountain Oil Journal front page story, February 26, 2010 - March 4, 2010, on the record North Dakota oil production in 2009. See earlier post.

Here are some phrases from that story:

"North Dakota shatters oil production record..."
"The horizontal Bakken has again been the impetus for the meteoric rise..."
"This remarkable increase...for the second year running, the largest oil producing state in the Rocky Mountain region."
"...the most active area for drilling..."

These are pretty powerful phrases from a matter-of-fact source.

I was happy to note that my database was right on target. I recorded 626 new permits in my 2009 database; the RMOJ said there were 623. Not bad for an amateur who compiled data from daily activity reports and not agency-compiled totals.

There are so many tidbits of interesting information in that article and the numbers are staggering. For example:

1. The breakdown of the data, in some cases, does not include production from wells still on the confidential list that began producing in 2009. The numbers are already phenomenal, and to think that not all of the production was captured in some areas. (My understanding is that "total production" was captured, but the breakdown of the data by county or field might not have been available because some wells were still confidential.)

2. "Everybody" talks about the Bakken, but few realize that the Bakken pool includes at least three oil-producing formations, and maybe as many as five.

3. The most prolific formation in 2009 was the Bakken pool, but that doesn't mean other formations are inconsequential. Production from the Red River B formation dropped 19 percent, year-over-year (2009-2008), not because there is less oil to be extracted from that formation, but rather the tremendous interest in the Bakken pool. At the current price of oil, I can bet that if the Bakken were to go away tomorrow, the operators would turn to historical formations like the Red River B in a heartbeat. They are returning to the Lodgepole, and they are re-entering old Birdbear wells. Right now, there's a race on to see what the fields have and what wildcats might find; it will take hundreds, if not thousands of wells to sort the Bakken pool out, and "we" still have a dozen other formations to attack and re-attack. And those are "old" formations. With wells costing a fraction of a Bakken well, EOG and others are now going into yet another formation, the Spearfish.

4. My hunch regarding the Red River B is validated by the fact that the primary targets for seismographic study in 2009 were the Bakken, the Three Forks Sanish, AND THE RED RIVER.

5. Only three states out-produced North Dakota last year: Alaska, California, and Texas. But when "they" say "North Dakota," we're only talking about the northwest, the far west, and a bit of the southwest areas of North Dakota. It's not like "they're" drilling in the whole state. I don't think it's even one-third of the state. Granted, that's also true of AK, CA, and TX but it would be interesting to compare total acreage involved in oil production in the four states.

6. The RMOJ estimates that total footage for JUST the horizontal portion of the wells drilled in North Dakota was equivalent to 693 miles. Laterals are either one mile long (short laterals) or two miles long (long laterals), whereas each well to the Bakken goes down about two miles before going horizontal. Thus, conservatively, one can double the number of miles that have been drilled in 2009: that's a lot of steel and a lot of cement. And a lot of manhours. (Are we still allowed to say "manhours"?) 1400 miles: that's 2 1/2 round trips between Fargo and Dickinson. And we're not even talking about all the pipeline laid to move the oil once it's been brought to the surface. And that's just one year.

7. Folks keep second-guessing "how good" these wells are and whether the operators/drillers are getting better. Well, if one does the math on the numbers provided in the second paragraph of the RMOJ story, the average Bakken well produced an average of 101 bopd in 2009 vs 84 bopd in 2008.  That's an increase of 20% and the cost of the wells has actually decreased over the past year by some calculations. The average EOG well in the Parshall produced 288 bopd in December, 2009.

8. Oh, by the way, how did these Bakken wells compare to Red River B wells in 2009? The average Red River B produced 119 bopd -- 19% more than the average Bakken well.

9. The majority of oil produced by the second-largest producer, Burlington Resources, was still from the Red River B in 2009 but that should change over time as BR aggressively targets the Middle Bakken.

10. And again, one-third of the oil produced by Continental Resources, the #3 producer in North Dakota comes from horizontal Bakken pool wells; two-thirds of their production still came from the Red River.

11. Whiting jumped to number four in North Dakota production. How much did its average well produce in 2009? 310 bopd.  Whiting is primarily in the Sanish oil field.

12. I've opined often that Hess' wells seem to be lackluster compared to other producers and the numbers bear this out. Hess dropped to fifth place. Without knowing the number of wells Hess has, I cannot determine the average Hess well's daily production. But get this: before Hess went horizontal into the Bakken pool, it concentrated on vertical wells in other formations. How many formations do you think Hess targeted with these vertical wells? One? Two? Three? Four? Five? Try eleven: Deadwood, Devonian, Duperow, Heath, Madison, Ordovician, Red River, Sanish, Silurian, Spearfish/Charles, and Stonewall. The Lodgepole was not mentioned. And the Lodgepole holds the record for the best well ever in North Dakota. Yeah, there are a few formations yet to fully exploit.

13. Something tells me the numbers will be even more staggering one year from now.

14. "They" say the Bakken will continue to be drilled until 2031 at which time the Bakken will be completely drilled, but production, obviously declining over the years, will continue until 2100.That's just the Bakken.

Oh, one last thing. Here's a very, very average Bakken well, the Charlson 44-32H. It's IP was an unimpressive 512 bopd, before "they" changed their methods for calculating IPs. At exactly one year the Charlson 44-32H produced an unimpressive 60,000 barrels. But at $80/barrel, that works out to $4.8 million at the wellhead, about the cost of the well. Some of these wells are going to keep on producing for twenty years, although they may get down to 25 barrels/day. But once the well is paid for, even 25 bbls/day at $80/bbl works out to 3/4 of a million dollars per year. If the average Bakken well produced 84 bbls of oil per day in 2008, and the new wells were producing thousands of barrels/day in the first couple of days, you know that there are a lot of low-volume wells in North Dakota that keep chugging along. "Stripper wells" in Pennsylvania and Texas are economically viable producing less than 10 bopd.  Some stripper wells can be active for decades.

I still maintain that fracking extends out only 400 feet from the borehole (dual-lateral tests tend to support that reasoning), meaning that for optimum recovery, drillers may be able to put in as many as six wells in a 640-acre spaced unit. And drillers are already re-fracking wells that are less than ten years old.  And we haven't even begun talking about enhanced oil recovery.

Yes, I remain inappropriately excessively exuberant.

Oh, I can't help myself, one more thought. All it takes is one monster well to change everything. Maybe the 557 horizontal wells drilled in North Dakota last year were put in for one reason only: to keep the cash flow coming, to drill the next well, hoping it might be the "really big one." Something tells me oilmen don't look back; they keep looking for that next big one. Good luck to all.