Preamble, Disclaimer, And All That Stuff
Rigzone's look at the future of shale in light of the oil glut and depressed oil prices.
I don't think I will post any excerpts of the linked article above. I have it saved elsewhere; most of these articles eventually "disappear," requiring a subscription later on to access them (a word to the wise).
I scanned the article linked above but I didn't read every word. I think there is a huge story line that was mentioned in another Rigzone article but not in this most recent one.
Looking at that previous Rigzone article and then at this most recent one (linked above), I think we will see an essay soon at Rigzone or elsewhere about another lesson learned with regard to US shale which I am trying to express in the rambling notes below. Developing an unconventional oil play is entirely different than what has gone on before.
What follows is personal opinion; what looks like facts may in fact be wrong; I'm not looking up staff to confirm (I discuss this in my "welcome/disclaimer" pages).
If any of this information is important to you, go to linked sources throughout the blog; don't take my word for it; I make a lot of factual and typographical errors.
There are three unconventional plays that account for about half of all unconventional oil right now: the Permian, the Eagle Ford, and the Bakken.
Of the three unconventional plays (remember, the Permian has both conventional and unconventional aspects) the Bakken is the most mature in terms of development and understanding of the geology.
Within the Bakken, the middle Bakken is well delineated. This is not true for the other payzones within the Bakken pool. A lot of work has been done on the upper bench of the Three Forks, the Sanish, and the Pronghorn Sand(s), but even those formations are not delineated as well as the middle Bakken.
The lower benches of the Three Forks are hardly delineated at all; that delineation was just beginning when the slump in oil prices began. And, of course, we know almost nothing about the Tyler or the Lodgepole (not the reefs) formations.
The Bakken is 90 - 96% oil across the Basin.
The Eagle Ford is still in the early stages of being delineated; I have no idea how many pay zones there might be in the Eagle Ford, just as we did not know how many pay zones there would be in the Bakken until several years into the boom. The Eagle Ford has areas that are predominantly oily and other areas that are heavier in condensate. The general areas are known but the Eagle Ford came in later than the Bakken and delineation is probably less clear than the middle Bakken.
The Permian is even less delineated with regard to its unconventional plays.
Then across the US there are several other unconventional plays; perhaps the Niobrara is #4. Then a half dozen others.
All figures below are 2014 US dollars.
At $150 oil, operators will explore every shale play and every area within every shale play.
At $100 oil, operators will still explore the better shale plays but start to concentrate on development of delineated fields.
At $75 oil, operators will pretty much discontinue exploration in even the best plays and emphasize development and infill wells.
Somewhere between $80 and $65 oil operators will start to circle the wagons, not only discontinuing exploration in the newer shale plays but will discontinue exploratory drilling in the three big US shale plays.
At $50, the circling of the wagons will become obvious to even the most casual observer. It's possible oil could get so low that all drilling in all US shale might stop but that seems incredibly unlikely.
Below $80, shale operators will start to demonstrate just how flexible they can become.
I don't now enough about the Permian or the Eagle Ford to comment, but I bet they are similar to the Bakken.
First, behind the scenes, the Bakken operators are going to extract savings from the oil service operators. Earlier I posted an example of where Sanjel was providing almost a 50% discount for some services. Sand and ceramic will come down in price (more on that later).
In the Bakken, almost everything of interest or of value is now held by production. If one wants to look how an oil company can leverage that, look at at the Grail oil field on the GIS map server. Operators can move their rigs to the best areas in the Bakken.
In the Bakken, it's all about location, location, location.
This is where it gets very, very interesting. When I first started blogging, long-time readers might remember that I always used $50-oil in looking at the economics of any well.
Everyone says that Bakken wells have gotten more expensive over the years, but it seems they forget the other side of the coin: the wells are also much more productive. And the exorbitant lease bonuses have been paid. And more infrastructure is in place. I remember all the challenges with just getting water to the wells for fracking; that's not even talked about any more.
When I first started blogging, it was taking 40 - 60 days to drill to total depth. At $50-oil, operators are going to have access to the best rigs, the best geologists, the best locations (where they know the geology) and they are going to routinely drill to TD in less than 14 days. They will maximize the efficiency of their rigs -- look at what we learned about Whiting just a few days ago -- moving back and forth between wells on the same pad, letting the cement casing cure/set in one well while drilling the neighboring well and then moving back to the first well.
When I first started blogging, it was my hunch that the total cost of the well was pretty much 50 - 50: 50% for drilling and 50% for fracking. I've looked at the costs of some of the wells one year ago compared to the wells this year and it seems the cost to complete a well is about the same today as it was a year ago (in some cases, the cost has come down). Drilling times to total depth have decreased significantly; if the cost to complete a well has remained the same and the drilling time has decreased significantly, one has to assume that fracking costs have increased significantly. That makes sense.
Before the slump in oil prices Filloon predicted that frack sand prices would go "parabolic" and there were stories this past year that fracking sand was getting very, very expensive (and hard to find). When I first started blogging, a million lbs of sand was quite remarkable (look at the previous post: the two MRO wells used about 250,000 lbs of sand for stimulation). Then BEXP did the unthinkable: routinely using 4 million lbs of proppant. There are still a lot of wells being stimulated with less than 3 million lbs of sand. But for quite some time now, EOG has been using massive amounts of sand, upwards of 14 million lbs. In a recent presentation, CLR said that massive amounts of proppant is the key, and recently CLR completed a well with 19 million lbs of sand.
At $50 oil, operators are going to show just how flexible they can be. They are going to stop fracking, but they are going to keep drilling.
Remember the CLR Atlantic pad in the Baker oil field? At a time when oil was selling for $100+, CLR was willing to hold off on all production on that 14-well pad for 18 months until all wells were fracked. If CLR was willing to hold off production for 18 months when oil was selling for $100+, one can only assume they are more willing to hold off completing a well when oil is selling for $50.
Operators hedge their oil (CLR recently made news in this area), and have contracts to provide a certain amount of oil for a certain price. My hunch is when times get tough, they will make their contracts, but not deliver non-contracted oil at spot prices. Hedging will get many operators in the Bakken through the first half of 2015 if not all of 2015.
Now back to fracking. At one time, early in the boom, it was said that EOG did not frack in the North Dakota winter; I posted that, got some pushback so don't know how accurate that is. I noted that the definition of a North Dakota winter for a planner in Houston is different than the definition of winter for a roughneck working in freezing rain (or a late spring snow) in April in North Dakota.
The point is that fracking is going to start slowing down, though drilling might not slow down quite as much. We've already seen hints of that based on the past three "cuts" from the Director. The amount of drilling is more than just a function of the number of active rigs.
As noted earlier, when I first started blogging, the cost to complete a well was probably 10-40-50 (pre-drilling/drilling/fracking). The middle Bakken is quite mature now; I would bet that the cost breakdown is closer to 2-28-70. If that's too extreme, then 2-38-60. Again, the point is that the real cost of these middle Bakken wells is now shifting to completion/fracking.
The Decline Rate
The bad news about a middle Bakken well is its decline rate. The good news about a middle Bakken well is its decline rate. Off-shore, deep-sea drilling requires years of planning. Didn't Shell or BP take two or three summers just to get one drilling ship into the Arctic, and they still haven't started. How many years has the Kashagan been tied up? A decade?
But in a nicely delineated middle Bakken, the operators simply minimize their fracking, waiting for prices to move back up (which will eventually happen, at least according to Peak Oil theorists), and then start fracking at their convenience and time of choosing. Again, using the CLR Atlantic pad as an example, 18 months from pad building to production (the exact duration may be somewhat inaccurate, but you get the point).
CLR "sold back" all its hedges resulting in $440 million; prior to that, I seem to recall that CLR had an unused $2 billion credit facility (again, from memory and I could be way wrong). The point is that for $500 million, CLR can drill a lot of wells and frack them later. I'm going way out on a limb here but who's to say that 500,000 lbs of sand in an open hole frack to tide one over during a period of depressed oil prices and then come back in and do a bang-up frack when oil is back up. Again, that's the beauty of the dreaded Bakken decline rate. The production, the big money, is up front. The first year or two.
Shale is incredibly more flexible than deep-sea drilling. Rigzone (I believe it was) suggested that when push comes to shove, CAPEX will go to deep-sea drilling and not to shale. But that was the first six months through the first year. After that, the CAPEX goes back to shale. That makes sense; you don't stop a deep-sea drilling in the middle of things; it takes six months to a year to complete a project, but if during that time, the slump in oil prices appears to be long-term, or there is likely to be huge volatility in the price of oil, folks will pull back on deep-sea drilling and concentrate where they have more flexibility -- e.g., on-shore conventional and off-shore conventional.
We don't hear much about on-shore conventional, but prior to the slump in oil prices, every so often there was an article on transferring unconventional technology to on-shore conventional plays.
The sustainability of the Bakken and the survival of operators is an issue of liquidity, no profitability, and the cooperation of credit facilities.
Just some idle thoughts. No conclusions or predictions. Just some things that run through my mind. For every point made much more could be written. It will be interesting to watch this play out.
The metrics I'm following:
- IPs (24-hour production -- company specific)
- IPs (90-day production, Bakken-wide)
- number of active wells (daily)
- number of wells waiting to be fracked (monthly report)
- circling of wagons (concentration of activity in the sweet spots of the Bakken)
- infill density (family names)
- permitting projections
- operators who remain most active