Skip to comments.PN Bakken: ‘Wake-up call’
Posted on 01/19/2013 8:22:54 AM PST by thackney
North Dakota has now recorded back-to-back months in which the massive Bakken petroleum system has failed to live up to production expectations.
Reasons behind lackluster performances in October and especially in November have led the states top oil man, Lynn Helms, to issue a wake-up call for those who believed the good times would continue unabated.
Weve gotten very used to the increase in production, almost regardless of what was happening out there, Helms, director of the Department of Mineral Resources, said in a Jan. 11 conference call.
For the first time in 19 months, North Dakotas oil production declined in November, the most recent month for which production statistics are available. Output fell 2.2 percent, from an average 749,212 barrels per day in October to 733,078 bpd in November.
Our expectation was for a 2-to 3 percent increase, Helms conceded.
Storm blamed for slowdown
Winter storm Brutus was blamed for most of the November decline. It brought operations to a halt for several days and, more telling, exposed infrastructure shortcomings, in particular the heavy dependence on trucks and a snow and ice-vulnerable road system to transport fracking water and other materials to drill sites and production to rail and pipeline terminals. When you encounter something like that winter storm, you have to shut wells in, you cant use the oil, Helms said, noting that the number of new wells waiting to be hydraulically fractured and put on production in November jumped by 50 to 410 because of bad weather.
The huge backlog in hydraulic fracturing jobs has evolved into a major headache for the department, Helms said, adding that during the first half of 2012, service companies assured the state that they would be bringing in lots and lots of workers and equipment to the Williston Basin to catch up on the work. Several of the largest companies alone hired an additional 1,500 workers to address the problem.
Colder weather ahead
And the trend seemed to be going in the right direction, Helms said. Now we have two (slow) months in a row as we enter colder weather, where fracking has really slowed up. We may be finding ourselves in a paradigm where the winter months are much more difficult than anybody had anticipated. And it is a serious concern. Ironically, as Helms answered questions from reporters on the Web and live from the state capitol in Bismarck, N.D., much of the Midwest was being hammered by yet another snowstorm. And though it appeared the brunt of this storm was going to skirt North Dakotas oil patch, I think it could have some impact on January production, Helms said.
December was a relatively quiet month.
North Dakota also has become a state thats all about Bakken production, with most of the oil patch concentrated in a fairly tight four-county area, making it particularly susceptible to disruptions, Helms said. Williams County caught the worst of the November storm, experiencing the snowiest day in more than 110 years.
Helms wake-up call
So, (its) unlike the state of Texas where they have Eagle Ford, they have the Permian Basin, and they have East Texas all producing, Helms said. All our eggs are sort of in one basket. Thats why I call it a wake-up call. We are so in tune with Bakken and Three Forks development, so dependent on truck transportation, and so dependent on hydraulic fracturing. Underground pipelines to transport warm fracking water to drill sites, rather than by truck, would help alleviate the problem, Helms said. He noted that the state is working on legislation to establish rights of way and easements, so we can bury those pipes six feet underground.
North Dakotas oil production did increase in October, but at a much slower pace compared to previous months. Factors that contributed to Octobers underperformance also contributed to Novembers decline operators transitioning to higher efficiency drilling rigs and implementing cost-cutting measures at the end of their 2012 capital budgets.
Rapidly escalating well costs consumed capital spending budgets faster than many companies anticipated, and uncertainty surrounding future federal policies on taxation and hydraulic fracturing impacted capital investment decisions, Helms said in his January Directors Cut report.
Rig count down again
The Williston Basin drilling rig count averaged 184 in December, down from 186 in November and 188 in October. The count stood at 181 on Dec. 11. The all-time high of 218 rigs was reached on May 29, 2012. The utilization rate for rigs capable of 20,000-plus feet is down to about 80 percent, and for shallow well rigs to 7,000 feet or less utilization remains about 60 percent, according to the department.
There were 8,101 producing wells in November compared to 8,035 in October, a gain of 66 wells.
Drilling permits issued in December stood at 154, down from 211 in November and 370 in October.
Drilling permit activity was lower in December due to the number of holidays, Helms noted in his report. We continue to have a sufficient permit inventory to accommodate more multi-well pads, the desire to not build locations during winter, and the time required to publish hydraulic fracturing rules if required.
Crude oil takeaway capacity reportedly remains adequate to keep up with a majority of oil now shipped by rail to East Coast, Gulf Coast, and West Coast destinations.
Leasing activity extremely slow
North Dakota leasing activity is said to be extremely slow, mostly renewals and top leases in the Bakken-Three Forks area. Williston Basin natural gas production of 782,078 thousand cubic feet (mcf) per day in November was down slightly from Octobers 797,785 mcf per day.
Construction of processing plants and gathering systems was also severely affected by weather, Helms said, noting that U.S. natural gas storage is up to 11 percent above the five-year average.
This indicates continuing low prices for the foreseeable future, he added. North Dakota shallow gas exploration is not economic at near term gas prices.
Natural gas delivered to Northern Border at Watford City, N.D., is down to $2.85 per mcf, resulting in a current oil-to-gas price ratio of 31 to 1. But the high liquids content makes gathering and processing of Bakken gas economic. Additions to gathering and processing capacity are helping with the percentage of gas flared dropping to 29 percent. The historical high was 36 percent in September 2011.
Oil prices drop in December
North Dakota sweet crude averaged $77.09 per barrel in December, compared to $80.86 in November and $87.00 in October. The price stood at $87.25 per barrel on Jan. 11. The all-time high reached $136.29 on July 3, 2008. Meanwhile, the number of rigs actively drilling on federal surface in the Dakota Prairie Grasslands was reported to be down to zero. But the number of rigs drilling on the Fort Berthold Reservation has increased to 28 with four on fee lands and 24 on trust lands.
There are now 793 active wells 96 on trust lands and 697 on fee lands producing 135,380 barrels of oil per day 6,730 from trust lands and 128,650 from fee lands. There are 113 wells waiting on completion.
Additionally, there are 291 approved drilling permits 266 on trust lands and 25 on fee lands, with 1,479 additional potential future wells 1,426 on trust lands and 53 on fee lands.
In other developments draft Bureau of Land Management, BLM, regulations for hydraulic fracturing on federal lands have been published in the Federal Register. The comment period closed on Sept. 10, 2012. BLM received over 170,000 comments and has indicated a final rule will be published mid-2013.
Also, Draft Environmental Protection Agency, EPA, guidance for permitting hydraulic fracturing using diesel fuel has been published. The comment period closed on Aug. 23, 2012. EPA received over 97,000 comments and has set a target of spring 2013 for final guidance document publication.
Winter storm Brutus hits, the place temporarily loses its staffing (even hardy guys have a limit to how hardy they are) and output suffers, and oh heavens the sky must have fallen.
What's this meshugas??? (Craziness)
Going to have to get some major oil & gas pipelines up in that area, shipping the oil by rail will not be enough with the production increases.
Another , “Unexpected?”
Bakken is not going anywhere. If anything, there is not enough infrastructure to keep up with production. The cold weather decrease means nothing in grand scheme of things..
They drill about 140 new wells per month. Each of those starts producing oil at about 1200 barrels per day.
But the MOST IMPORTANT parameter is not being advertised. That is that every single well they have drilled starts to decline its output as soon as it starts. There is talk of 30% decline rates/year. That means that 1200 bpd is down to 650 in just 2 years.
The reason that is the MOST IMPORTANT parameter is that there are 4000+ wells declining every single day and they add only 140 new ones per month. This is sprinting up a down escalator whose steps are moving downward at an increasing speed.
You can outdrill that acceleration . . . for a while. But it’s important to understand every such month that goes downward in production is several feet downward on the accelerating downward escalator that has to be made up by even faster sprinting.
This is not a good miracle to bet the nation’s life on.
That sounds like nonsense to me.
Why would you build underground pipeline to a well site that needs hydraulic fractured ONE TIME, then not again for years or even more than a decade? Are they fractured at any real frequency in the Bakken?
Well said. The fact is the wind and snow made travelimg almost impossible.
My company shut us down.
Frac here then frac there. It takes them longer on the bakken sometimes. I don’t know why.
On the jonah natural gas fields slumber j would set up on one location and run tubing to frac many wells from the same locatiom
Just shows the need for pipelines. There are several more pipelines underway. Meanwhile, a winter storm can affect the numbers. Its life in the oil patch.
Cold weather in North Dakota in mid-winter. Who’d’ve thought it?
Seriously, if companies can work in Alaska, they can learn to work in North Dakota. It will just take a little experience and a little adjusting to conditions.
Some of us are old enough to have seen this several times, different plays play out, nothing last forever but it’s amazing how some things last. I’ve got Wolfcamp wells on the south end of the ranch that are over 50 years old that still make a few barrels a day (enough to keep them running). I’ve got Canyon Sands Wells on the north end that come in with 300 to 400 barrels a day but drop of to 15 or 20 within a year. Our upper section Cline Wells north of town are comming in at 400 to 500 per day with some still holding over 100 after a year. The well we’re drilling now is for the lower level Cline and we’ll see what this one does. On the Cline wells we’re making good wet gas and allot of it.
That sounds like a lot higher than the typical well. Or if they start anywhere near that point, they fall down fast. The average for the first 60~90 days is 234 barrels per day according to the North Dakota Industrial Commission, Department of Mineral Resources, Oil and Gas Division.
First 60 - 90 Day Average Bakken Pool Production by Well
There is talk of 30% decline rates/year.
There is more than just talk. The initial data is even worse.
Source for Graph:
North Dakota Department of Mineral Resources
“Ive got Canyon Sands Wells on the north end that come in with 300 to 400 barrels a day but drop of to 15 or 20 within a year.”
That’s maybe an average of 200 barrels a day for the year as it declines. That’s 73000 barrels at $80/barrel or $5.8 million coming out of a well that cost what, $15 million with infrastructure? These had better be rare.
I do realize the first and second data sets do not match with each other. Both are from ND government. ???
There’s oil there and jobs, but this is the most overhyped crap in the history of an industry built on overhyped crap.
That place is going to go into freefall production-wise and the day it is clear “tight oil” is not going to be anyone’s salvation, Brent will go to $200.
"Drainage! Drainage, Eli! Drained dry, you boy! If you have a milkshake and I have a milkshake and I have a straw and my straw reaches across the room and starts to drink your milkshake. I drink your milkshake! I drink it up!"
No sir our wells are running us about 2.5 to 3 mil per, thats flowlines and battery’s. We’re not drilling horizontals. We ain’t up with the big dog’s just yet.
Well I can’t drink your milkshake but I might get a little taste as long as it’s within my 40 acres. TRRC frowns on poaching.
When I suck it up my straw on my 40 acres, capillary action sucks it from all the surrounding 40-acre parcels.
“Seriously, if companies can work in Alaska, they can learn to work in North Dakota.”
I worked in the Alaska North Slope oil patch for 26 years. Bad weather is nothing new. Production goes up sometimes but it inevitably goes down. That’s just the way it is.
Oil wells typically produce large quantities of oil right after they are drilled, then gradually taper off. By that time all of the big expenses have (hopefully) been paid for. They do not get capped unless the operating expense exceeds the value of the oil being produced.
And thats the way it is.
Just so. I’m only an onlooker. But one obvious thing that occurs to me is that they should gradually build up gas storage facilities. Then they can fill these in the summer and keep them moving out on pipelines in the winter, to even things out.
Either that kind of solution, or live with the fact that it’s seasonal, like some of the Canadian gold mines.
We have a lot of natural gas storage in the US cycling summer to winter already.
From above “That’s just the way it is.” And it’s that way far more severely for horizontals.
On the graph, horizontals die vertically. Well known reality carefully NOT talked about by those who have to hype the drilling of the next well.
As for nat gas, the word is 40% of nat gas produced in the Bakken is flared. They are drilling so frantically and desperately fast to overcome that down escalator that they dare not pause to lay capture infrastructure.
And here is a delightful photo to prove it. See if you can find the huge city on a map making that huge swath of (gas flare) light in western NoDak on a map, or south of Austin where the Eagleford is flaring.
That’s what desperate, frantic drilling looks like, folks, and it’s not going to get any better. Ever.
If your trying to make a point ya lost me. Please explain in more detail.
Sir there was a time when the entire West Texas skyline was covered in flares, running major pipelines take time.
My suspicions lie with there is likely very little gas produced from the typical Bakken well compared to the oil. That gives little chance for profit on a natural gas payoff for the investment in all the gathering lines.
They are getting some extensions in the permitting, but that is not going to last forever. They are going to be forced to start recovering that gas.
PN Bakken: NDs gas woes
Week of December 02, 2012
Finding a solution to North Dakotas ballooning gas-flaring problem will require a very difficult balancing act that could take until the end of the decade to work out.
We have to balance the ability to build gathering systems against the waste that takes place with flaring, Lynn Helms, director of the states Department of Mineral Resources, said in a Nov. 20 Webcast.
So were looking at toward the end of this decade before we really get this flaring dynamic under control.
Gas production continues to increase at a faster rate than the more desirable crude oil, setting yet another production record in September at 793,546 thousand cubic feet, mcf, per day. Average oil output for the month was 728,494 barrels per day, also a record.
I don't think the big lines coming out of Canada running through the area around the Bakken run at full capacity anymore. Our Natural Gas imports from Canada have fallen a bit without any real loss in pipeline capacity.
For that data:
U.S. Natural Gas Pipeline Imports From Canada
I agree I’m just saying it takes time to catch up.
The point was not anything envirowacko. Don’t care about that.
Don’t really even care about the waste.
But I do care about the hype. This “story” is being leaned on for BS projections of US energy independence (always bogus phrasing since only oil brings food to grocery store shelves, and only oil drives the 400 Hp tractors that get it planted in 50,000 acres before planting season expires).
Sorry, digression. This field is being leaned on and hyped as the salvation of US oil production and elimination of US oil imports and it’s BS. Oil is measured in barrels/day. Not in barrels. It doesn’t matter what’s under the ground there if the rate it comes up peaks and falls.
There is some fracking going on in West Texas now, too, and the Eagleford is on that photo. They aren’t immune to geology. Their horizontals die vertically, too. You’re in the biz so you KNOW California is in freefall. You KNOW Oklahoma is down about 85% from the 1930s. You KNOW Illinois oil output is down a similar 75% from the 1930s. This isn’t going to reverse. This is forever. These shale plays are a blip on the relentless down escalator.
“I agree Im just saying it takes time to catch up.”
It does, and you have that time available on conventional vertical wells.
Horizontals die so fast you DON’T have time to catch up. That’s why it is so frantic. If you take time to get nat gas capture infrastructure into place, the oil output is avalanching so fast from your multiple wells that you start to lose enough cash to fund that infrastructure.
These shale plays are very short lived things. You gotta do them. The oil doesn’t do anyone any good underground. But they are not going to change anything. They will peak and fall. Steeply.
North Dakota sweet crude averaged $77.09 per barrel in December, compared to $80.86 in November and $87.00 in October. The price stood at $87.25 per barrel on Jan. 11. The all-time high reached $136.29 on July 3, 2008. Meanwhile, the number of rigs actively drilling on federal surface in the Dakota Prairie Grasslands was reported to be down to zero. But the number of rigs drilling on the Fort Berthold Reservation has increased to 28 with four on fee lands and 24 on trust lands. There are now 793 active wells -- 96 on trust lands and 697 on fee lands -- producing 135,380 barrels of oil per day -- 6,730 from trust lands and 128,650 from fee lands. There are 113 wells waiting on completion. Additionally, there are 291 approved drilling permits -- 266 on trust lands and 25 on fee lands, with 1,479 additional potential future wells -- 1,426 on trust lands and 53 on fee lands.Hmm, all time high during a POTUS election year, how odd. /s
Wellsites in the Bakken can be four or more miles apart (1280 acre spacing). Maybe that has something to do with Schlumberger not running lines to multiple wells.
Warm fracking water?
The economics of building a pipeline to transport fracking water to a wellsite would limit fracking operations to summer, and the pipelines would have to be surface and temporary or the backlog for completions would be determined by pipeline crews.
A buried line would be more expensive.
It has been done: Brigham built a temporary (agricultural/irrigation pipe --8 inch iirc) surface line to a location from Trenton ND, about 8 miles. The line saved them a fortune in trucking costs for the fracking of three wells, the pit from the first frac used to store the water was used to store water for two offset wells.
However, 8 miles is a pretty short distance to a water source, and this was done while the weather was warm. Multiple wells in that area made it more economical, as they were able to pump water overland from that pit to the other wellsites.
Most wells are farther from water, and building a temporary line more problematical over less friendly terrain. Regulation of storage pits has become more intense as well, even though the water was well water--something not readily available in all areas, especially in that quality and quantity.
As far as a permanent line to a well for fracking, you frac to find out what the well will do, there are no guarantees, and that would be a tremendous up-front expense for an unknown return.
Perhaps piping water to regional locations to reduce transport distances would be a plus, with the infrastructure available for potable water later on.
It may be that Director Helms is considering using the lines in to wellsites for oil/gas pipelines out, but that would likely involve different construction specifications. I think the goal there would be to reduce flaring gas.
Anyway, weather has traditionally messed with oilfield operations here, and the last two winters have been unusually mild. This one is behaving a little more like winter, and for outfits who have been spoiled by a couple of years of 'nice' winter weather, the adjustment may take a season or two.
I don't have to hype the next well, but I tell every royalty onwer I know to bank the first three royalty checks, and at least half of the next five, then see what they get because of the decline curves. I explain to them that the production falls off rapidly from IP, and usually ends up at the 150-200 BOPD mark after a couple of years. If they look at the first check and load up for Beverly Hills (Jed Clampett joke), they're liable to come back on a Greyhound when they can't make the payments. Most are older folks who are reasonably careful with their money anyway, and they fare pretty well--they just treat the money like a bumper crop, and don't count on a steady stream of it to continue.
Joe thats exactly what we did. We built one pit by our two water wells then staged 3 more coming around the nth side of the mountains all connected with 4 inch poly lines and polylines running to each well. When we finished we started selling water to Whiting who was drilling nth of us.
I hear ya on the royalty checks I’ve seen several go from riches to rags in just a couple of years. You try and tell them but they won’t listen.
“I explain to them that the production falls off rapidly from IP, and usually ends up at the 150-200 BOPD mark after a couple of years.”
This, btw, is another aspect of the hype. Specifically:
“This oil field is the future of America! It will be producing oil for the next 80 years!”
Be sure to include those exclamation marks. All those wells will be stripper wells in 5 years. In 80, maybe a handful will still do 2 barrels/day. The rest capped and abandoned. But those handful are there and thus “here we are 80 years later, still producing!!”
This is why reserves are not the critical parameter. Extraction rate is the critical parameter because rates are what consumption is all about. Extraction rate (aka production, but I’ve always hated calling it “oil production” — Mother Nature did the producing, the industry is just extracting it) is how one measures oil.
Don’t know if you guys have seen the study. Some Norwegian reasonably smart guy has looked at first 12 month output of Bakken wells now, vs first 12 month output of Bakken wells a year ago and two years ago. Just the first 12 months.
The number is falling. The conclusion he suggests is the low hanging fruit, the highest odds for big flow, were drilled first. Thackney guy up above noted that I quoted 1200 bpd as initial flow and that the graph showed lower. This is likely part of the same thing.
This field is just flat out overhyped.
You probably already know this, but Oklahoma is also one of the states seeing growth in oil production. Still early, but expected to continue to climb. This is not to be confused with easy (cheap) oil supply from the 30s.
haha yes, it’s climbing.
Like US new home sales. Celebrating and hyping 2 and 3% rises when it’s down something like 60% from 2005.
Oklahoma oil production was 780K bpd in about 1928. That was the peak. Now it’s at 260K. That’s down what, about 67%? And that’s with 85 years of technology improvements applied. So it was down 75%, has risen a smidgeon, and now it’s down 67%. Hallelujah!
Good call thackney on the whole easy vs not easy oil. I don’t measure easy in dollars. I measure in joules. How many joules did it take to build a 25 foot wooden tower on site, drill a hole and then stick a pipe over the gusher . . . . vs build a 30 story tall marine rig, stick a ten thousand horsepower engine on it, helicopter a crew to it, drive it for several months several thousand miles to the drill site and then drill in 2 miles of water to the sea floor and down another 10 miles below it?
Folks want to yell about liberalism and printing money . . . sorry, the reason civilization is disintegrating is because of that joules ratio. It is HUGELY more expensive joules-wise to get the 5.6 million BTUs of energy in 1 barrel of oil out of the ground than it used to be. The net joules coming out of the ground have been smashed by the end of easy oil — and this is forever.
Editing myself . . . hate hyperbole.
Not 10 miles under the sea floor. 4 miles. Typical deep water drill depths are 25,000 feet (which is so deep most of these “discoveries” of “BOE” is mostly E . . . Equivalent, i.e., natgas. Too hot that deep for oil to remain oil).
Sure, there are sweet spots, and these have been noted since development began. The initial barnburner discoveries near Stanley ND, and elsewhere in the basin had wells IP at over 3000 BOPD or equivalent. Not shabby at all. Other areas will produce less, and some not at all. I've worked wells which fit all of those, from a regional recordholder to a couple which fell outside the productive area, to wells in between, and have worked over 100 of the Bakken and THree Forks wells now.
The Three Forks, BTW was completely thought to be nonproductive.
Oops, but there is a gain to be had in that as well.
Believe it or not, even after over twelve years of working these wells, we're still developing new technologies to drill them faster, better, and produce them more efficiently.
Now, let me put this in perspective. In the Williston Basin, oil was first found in the 1950s. In that time wells have produced oil and/or gas commercially from eighteen different geological formations varying in age from Triassic to Cambrian.
Horizontal drilling has been applied to the Bakken, but I have worked horizontal wells in the Ratcliffe, Midale, Stonewall, and Red River, as well as the Bakken and Three Forks. Other formations may lend themselves to this production technology.
Prior to horizontal drilling, a 100 BOPD well was considered a fairly good producer. I'm not sure of the number, but, iirc about 30% of US production comes from stripper wells producing under 20bbls of oil per day. They all contribute.
The Williston Basin has been producing oil for 60 years. One of the early fields I worked in, doing re-entry horizontal wells proved the concept: Carbonate reservoirs are anisotropic, and even on a 160 acre spacing, did not yield their full load of oil after twenty years of production: the changes in production volume and even an increase in gas produced in one well when two laterals were drilled at 90 degrees to each other 1 year apart proved this.
Please note that another misleading bit of hype about the Bakken is that it is shale oil. The source rock for the oil is the Upper Bakken Shale, and where present, the Lower Bakken Shale, but the rock in the Middle Bakken is a combination (depending on where you are in the Williston Basin) of micricrystalline to fine crystalline dolomite, siltstone, sandstone, and fragmental limestone. This rock has porosity, even if the natural permeability is low as a rule, and because of the complex nature of the lithology involved, may not register correctly on porosity logs. The ability to model the rock types more efficiently based on density and sonic logs, and to better estimate porosity may yield better production forecasts.
The Basin will be producing oil for a long time to come, as long as there is a market for it.
The only questions are "How Much?" and from "Which Formation?"
As far as hype goes, actually, efforts have been made to NOT hype it, from reserves estimates to recovery estimates, by both the State and the USGS.
If you've been reading pump and dump stock newsletters, you might be getting a different story.
The rest of us (in the oil industry) can't just pull stakes, cash out and move on to selling electronic widget company stock next week.
Because I am a professional geologist, and I live in the Williston Basin, I make a point of never overselling the idea, and would lose credibility among my peers and the public alike if I portrayed the drilling boom here as anything it is not. I have seen booms come and go, and always have been one to preach economic caution in spending habits, both from the public coffers and in private life as well.
There will be plenty of fancy cars and bigger houses available when things slow down in due time, at relatively cheap prices.
That’s good data.
Of course stripper wells contribute. They contribute 5 barrels per day. That’s not going to pay the piper.
Global oil production is what, about 75 mbpd? Oil, not low joule NGLs or ethanol. Proper crude oil. Saudi Arabia is about 9.5 of that. Russia is 10.3. That’s 27% of the total from two places that do NOT do stripper wells. Did you know there are, after just what, five years of frantic drilling, more wells in the Bakken than in all of Saudi Arabia, drilled for 65 years? The Bakken is the poster child for destruction of the joules ratio of in vs out.
This is frantic, desperate drilling using millidarcy enhancement methods that KSA never has to use. They have wells that have flowed about 10,000 bpd for 40 years.
“If you’ve been reading pump and dump stock newsletters, you might be getting a different story.”
You must mean the news releases from Continental Resources, the largest company involved who own more leases than anyone else there?
BTW I do applaud the efforts of NDak’s geology folks to slap down Continental Resources’ hype, but they are failing utterly to stop NY Times hype or even Forbes, who have a reasonbly smart oil reporter.
I know of no horizontal Bakken or Three Forks wells which have been reduced to stripper status (in the current round of drilling, not those from the mid-80s which actually targeted the shales), and I have been working these since 2000.
That is a lot longer to get under 20 BOPD than the projections.
The tendency I have seen is for production to level off at between 10 and 20% of IP after a couple of years and decline more slowly from there.
I don't pretend to have all the data at my fingertips, but causing a panic would benefit some operators as smaller players came up short of venture capital and slowed down or sold out causing a sudden surplus of drilling rigs and service companies.
Oil prices versus drilling/completion costs can drive such a deflation of any 'bubble' present, just as we have seen in the housing market adjustments here.