Updates
April 29, 2013: Rune Likvern, who wrote the first "Red Queen" article for The Oil Drum has a follow-up, asking: Is the typical NDIC Bakken tight oil well a sales pitch? Rune is still fascinated by the decline curve of Bakken wells. I think he misses the point: the important metrics are a) EURs, and, b) internal rates of return. I can guarantee that oil companies are not throwing $10 million into a well to hype a sales pitch. With regard to EURs, the important metrics to track: a) original oil in place; b) additional pay zones (four benches in the Three Forks); and, c) improving recovery rates. Would it matter if all the oil was drained from a well in one year if it provided 100% return on one's investment. I think not. In fact, it might be kind of nice: drill that well, make a 100% return, and then reclaim the land for farming after one year. The real question is this: is secondary and tertiary production feasible from the Bakken using current technology? It looks like the industry has 30 years to work on that problem.
October 9, 2012: Mike Filloon's response to the Red Queen fairy tale.
October 1, 2012: with adequate takeaway capacity, Triangle Petroleum says break-even point is $45.
September 26, 2012: It looks like the folks over at the Bakken Shale Discussion Group have found this article, also. Note: do not reference the MDW blog if you visit the BSDG -- you will be voted off the island. Smile.
Original Post
The Oil Drum has a very, very long article, highly analytical, highly statistical article regarding the Bakken.
The article has two themes:
- the horrendous decline rate of the Bakken is concerning
- the break-even point for Bakken oil is $90
The article begs an obvious question. I will be interested in seeing the comments. The article was just posted so there has only been one comment.
Bonaparte's Retreat, Segawa Shinji, instrumental
Bonaparte's Retreat, Willie Nelson
**********************
If you find The Oil Drum article depressing, this should cheer you up.
Reply to a comment.
Here's the reply:
Thank you; agree 100%.
1. The million bopd seems to be a nice round number, but the Bakken is made up of many, many oil companies, and they will do for their company what is best; they individually won't be worrying about total basin production.
2. I've blogged about this before, but a major component of valuing an oil and gas company is how well that company manages its reserves. There is no reason to sell oil at a discount once you have your leases held by production. Perhaps it would be best to produce enough oil to meet certain "internal" targets, but to manage the reserves in such a way that one sells oil when the price is higher, if you follow what I'm saying.
3. In other words, if the price of oil comes down significantly, oil companies will want to hold back on selling their oil at a discount. Obviously they have to meet their contracts and that's why they hedge (collars, etc).
4. As I've said many, many times, the business of the business is what shareholders are interested in. For me, the Bakken has proven itself. I will continue to champion it, and post/link stories about anticipated production numbers, but asset (reserves) management for an individual company is more important than production per se.
Again, if you follow me. [I would rather have my company well 50 bbls at $200/bbl, than 100 bbls at $50. Sure, production from 50 bbls to 100 bbls is doubled, but had the company waited for a higher price....you get the drift. Production is only part of the story.
So, switching gears. Pad drilling will introduce another wrinkle.
During the exploration phase, one could predict on a monthly basis how many wells would report an IP once they came off the confidential list.
During the transition to pad drilling, predicting could be more difficult. Let's say there are six wells on a pad. In the old days, once they drilled a non-pad well to total depth, they moved the rig, completed the well as soon as possible, and reported the IP; meanwhile the rig was moving to a new location and drilling. But on a monthly basis, that one rig was drilling a well, and perhaps that well or another well was being completed.
With pad drilling, they will drill to total depth, BUT they won't complete/frack the well. They will drill the next well. And they won't complete/frack that well. They won't frack any of the six wells until all have been drilled to total depth. So, we could see a month go by, or even two months, or even three months go by when no wells are completed by that one rig. All of a sudden folks are going to start getting worried; what happened; why aren't they completing the wells? It's an operational, scheduled delay. They will frack all six when the last well is drilled.
Once all companies are in the manufacturing stage this artificial backlog will take care of itself, but we could see some choppiness for one to two years as all-Bakken pad drilling gets into place. What I see so far on the GIS map server, it will be a long time -- maybe five years, maybe longer, before we are into all-Bakken pad drilling. So, there are many, many variables.
Right now, the most interesting metric is the number of new permits each month. A record was set this most recent month (July, 2012) and I suspect we are going to see some more records. According to the Director's Cut, there were 266 new permits in July, 2012 (surpassing the old record of 245 set in 2010). My records show 261 new permits in August but I don't count SWD wells, so maybe a new record in August. For September (only 30 days) we are on track for 253 new permits; it won't be a record but it will beat the 2010 record.
Bottom line: expect some choppiness in well completion during the transition stage to pad drilling. Best metric to follow to predict the future with regard to well completion: new permits (now setting records).
Oh, one last thing: don't forget "wet" natural gas. The "wet" natural gas to oil ratio is increasing and "wet" natural gas is valuable; not as valuable as oil, but more valuable than most lay folks know. This is a long note, and there may be typographical errors. The Apple autochecks spelling and does some strange things.
So, that was the reply. Not ready for prime time, and needs to be re-done later as a stand-along post.
I believe that the bottom line is "cost". Currently, operators appear to be getting wise in ways to cut the high cost of drilling an average Bakken well. The utilization of multi-well pads,newer and more efficient rigs, etc. will hopefully reduce these extremely high drilling costs thus lowering these figures.
ReplyDeleteOnce secondary recovery programs have been attempted for a sustained period of time these analysis will have to be revisited.
ReplyDeleteContinental has had very good luck with their Cedar Hills secondary recovery in Red River B. I have heard Harold Hamm say that CH recovery system will be their model for the Bakken.
The average sell price of oil last quarter was between $78 and $82 depending on the company if I recall. CLR, OAS, KOG, and NOG had good quarters.
ReplyDeleteThe bakken business cycle is really transforming. During the go go days of the start up ( 2007-2011) price was not an issue, doesn't matter if we make money, get in and play hard. As more and more have stated the bakken has moved from exploration to manufacture, it is ran like a business in which the only metric that matters is ROI.
ReplyDeleteThis is interesting to me in that its no different than a start up business that evolves. Remember the start up days of Amazon, they lost money on every transaction, what was their answer? Increase revenue, sell more books. Today, they worry about making money on every transaction.
Another item that surprises me is the doom and gloom that is coming out of the woodwork. Part of it is attributable to the fact the easy money has been made in the bakken. If you got in five years ago with real estate or a business you have done okay. If you start today, you need to know what you are doing and have tempered expectations.
I agree completely. We are barely into the manufacturing stage, and I think a fair number of operators are still not there.
DeleteRegardless, I posted the article for archival purposes. It will be interesting to see what the Bakken looks like in ten (10) years. I don't have the same curiosity that two UND professors have, looking out 300 to 500 years.
The bakken has surpassed every naysayer that has come along. Just do some simple math, total wells to be drilled is approximated at `30,000. Now use whatever long term production number that you want. (40bbl/day) 1,200,000 bbl /day. I don't think his numbers add up. The red herring in all of this though is that this is all with current technology. Look how much that has changed in the last 2-5 years alone.
ReplyDeleteIt should also be noted that North Dakota, with 7,000 active wells, is outproducing California, with 60,000 wells.
DeleteSome people see lemons. I see lemonade. In other words, I see a potential for a brand new business segment in the bakken to keep production high and the Red Queen at bay.
ReplyDeleteThe lemonade would be...Supercritical Co2 re-fracturing services with coal power plants supplying the gas as a cheap by product.
The Governments could do their part by giving tax incentives for carbon sequestration.
The power plants could sell their carbon credits on the open market for big bucks.
Oil and gas wells could be refracked when production reached a certain level.
It's a big red apple waiting to be plucked.
http://www.newscientist.com/article/dn22232-fracking-could-be-combined-with-carbon-capture-plans.html
The interesting aspect about super critical Co2 fracking is its a 3D
frack instead of 2D that H2O provides.
It's all about viscosity.
We know the oil and gas are there in large quantities. How do we get it out?
Go with Flow.
I, too, am an optimist. It will be interesting to watch this play out.
DeleteOn another note, I wonder if the decline rates are a red herring? How would the Bakken be viewed, how would the Bakken be developed, if there was no decline rate but the EURs remained the same with longevity of 30-year wells? I don't know if a) that's a dumb question; and/or, b) if anyone understands what I'm saying.
But 7,000 wells in North Dakota outproducing California with 60,000 wells seems to be an interesting data point.
Denbury ( dnr ) ticker had a pdf in the presentation section and they showed EOR cost of production at $30.. Niobrara at $58 , and Bakken at $ 85.. so they alsocompared eagle for , Permain.. so go to denbury .com
ReplyDeleteThank you. It seems one can find almost any $number for cost of production. Depends on what is being measured.
DeleteI was unable to find the report, sounds like an interesting read. Maybe I'm looking at this too simplistically, but assume a company has acreage in three fields, with the leases in each field tied up with a producing well on each lease. If ROI is the deciding factor, wouldn't you first drill additional wells in the field with the lowest cost of production, and lastly in the field with the highest cost of production? That would not seem to bode to well for the high-cost fields (e.g., the Bakken).
DeleteThe "Oil Drum" report? Just double-click on the link -- in the very first line at the top of the post.
DeleteI think the basic point is that because of the combination of the decline characteristics and lower production rates on the more recent wells that have come online , rig count needs to "accelerate" in order for the basin wide production rate to increase. He seems to conclude that the current market price and outlook are holding back adding to the rig count at this time. As for total recovery actually achieved itwould be spread out over a longer period of time.
ReplyDeleteSo basically the article seems to take issue with the (widespread) forecasts of 1m and higher daily basin wide estimates Doesnt seem like a wild position and seems well supported by historical facts presented.
Wow, the rig count is not understood at all. When the Bakken started, it took up to 60 days to reach total depth; now they are reaching total depth in less than 20 days, and there is almost no "down" time in between wells using pad drilling. Any time I see rig count in the argument, I know folks are missing the point.
DeleteHave you heard any numbers here? Looks like Great Bear is happy with initial results......I can't get the link to paste, see adn.com and check out oil stories
ReplyDeleteYes, sometimes I can't get links to work either.
DeleteThis may be one of the stories:
w.adn.com/2012/09/22/2636242/great-bear-wants-to-speed-up-shale.html
Yes you are correct, the article focuses on well completion rate needing to accelerate and does not address rig count. As you point out, completion rates seem to be increasing with static or declining rig count.
ReplyDeleteThe point of the article still is that the author believes completion rates need to increase to offset production decline else basin wide production growth will level off short of the predicted 1m bold + numbers that are widely forecast. The article does not try to differentiate between rig efficiency increases vs adding rigs in order to continue to grow production rates.
I agree 100%. But there's a lot more involved. I wrote a very, very long reply but "blogger" won't take long replies, so I put the reply up in the body of the post below the videos.
DeleteThere is no reason to go postal on the article. All it is saying is that the technical factors currently present (I e decline rates, completion rate and average first year production) and the market (95$ crude) may result in a situation where total basin production may level off instead of going to the moon. There is focus on bringing costs down by such tactics as pad drilling and bringing lower cost frac technology on line. And yes, 150$ crude would make life simpler for operators. Bottom line if one buys the analysis which does present factual data, is that basin production rate is not as slam dunk to go higher.
ReplyDeleteYou are absolutely correct.
DeleteIn fact, from my point of view, it is now all about management of reserves. At $90/bbl, I am perfectly content with slowing down production. The price of oil will trend higher; I have a long horizon.
I wonder if the author of the study considered the impact of the current ability to expense certain drilling costs by the producers in his price per barrel break even calculation. I bet not. His break even seems high to me.
Deletelink to web site
http://www.oilandgasjointventures.com/tax-benefits.html
Intangible Drilling Costs (IDC): When an oil or gas well is drilled, several expenses may be deducted immediately. These expenses are deductible because they offer no salvage value whether or not the well is subsequently declared to be dry. Examples of these types of expenses would be labor, drilling rig time, drilling fluids etc. IDCs usually represent 60 to 80% of the well cost.
crager
I agree with you. I've never seen a break-even point that high in the Bakken. If that were true, I doubt we would be seeing the activity we're seeing -- or I'm missing something.
DeleteFor maybe the last week or so when I go to the NDIC active rig page it no longer shows the total rig count at the bottom of the page. Strange.
ReplyDeleteThey moved it to the top left of the page; now you don't have to scroll all the way to the bottom of the page to see the total rig count.
DeleteThanks Bruce.
ReplyDeleteoil drum is now a sell side mouthpiece. with the collapse of peak oil theory, its being repurposed. sell side research is based on the proclivity of analysis to find points for obfuscation. A system can be no better than its own sensory organs...the oil drums utility is what it is.
ReplyDeleteI don't know "The Oil Drum" well enough to reply, but the comments at this particular story ("The Red Queen/Bakken"), are full of misinformation and errors. The best one: ND oil is being trucked to Canada to be mixed with Canadian oil sands and piped east because Canadian pipeline system is much better developed than the US system.
DeleteThe only ND oil being trucked to Canada and put in Canadian pipeline system, as far as I know, is the Spearfish oil coming out of the far northern counties like Bottineau. In fact, Enbridge, a Canadian company, has specifically stated that only Bakken oil will go in its pipelines out of North Dakota.
Also some vague comment about oil fields petering out and then that's it. Tell that to DNR who is going back into these old oil fields with EOR and doing very, very well.
The comments are interesting to read, but lots of misinformation.