The latest Update on Bakken and North Dakota LTO production is out.
ND Monthly Bakken Oil Production Statistics (Bakken Only)
ND Monthly Oil Production Statistics (All North Dakota)
Bakken production in February was 888,398 barrels per day and all North Dakota February production was 951,350 barrels per day. Some revisions were made in the past production numbers. Only the last three months were significant however. Listed below are the actual production changes, per month, for the last three months:
Month Bakken North Dakota
Dec 13 -45,528 -40,284
Jan 14 6,542 -2,218
Feb 14 16,643 16,224
The Director’s Cut for this has not been published yet. I will update this post when it has been. There were 119 additional wells in the Bakken and 79 in all North Dakota. That means a lot of North Dakota Wells were shut down.
A Bismark engineering firm has calculated the probable Bakken Peak.
Competition from Texas, winter expected to limit ND oil production
MINOT, N.D. – North Dakota oil production, which is poised to break the 1 million barrels per day benchmark, will peak at 1.2 million to 1.5 million barrels per day over the next five years, limited by winter weather and competition from Texas, a Bismarck engineering firm said this week.
I have charted that prediction below. The figures are the average yearly production.
The Director’s Cut finally came out:
Comments:
The drilling rig count was pretty much unchanged from Jan to Feb and the number of well completions was up slightly from 60 to 70. Days from spud to initial production decreased 8 days to 114. Investor confidence appears to be growing. There were still over 100 wells shut in for the Tioga gas plant conversion in an attempt to minimize flaring, but the biggest production impact was still the weather. February had 18 days with temperatures 5+ degrees below normal. Add to that 4 days with wind gusts too high for completion work and progress is slow.
Over 95% of drilling still targets the Bakken and Three Forks formations.
At the end of Feb there were about 650 wells waiting on completion services, a decrease of 10.
There have been a lot of headlines lately prompted by the EIA’s latest partial release of their Annual Energy Outlook 2014. There have been dozens of articles proclaiming that the EIA has predicted the US will be energy independent by 2037. Here is just one of them:
US to become self-sufficient in oil production in 23 years
A US government report expects that the United States will become self-sufficient in oil production by the year 2037. This means that oil imports are expected to fall to zero as a result of increases in the local production of domestic crude supplies, including in North Dakota’s Bakken field and Texas’s Eagle Ford formation.
Really now? Well I have read that report and as much as I would like to slam the EIA’s predictions, they said no such thing! The EIA presented three possible scenarios for US crude oil production out to 2040. The reference case, the one they deemed most likely had US importing about one third of our oil in 2040. The low oil case had us importing about 40% of our crude Oil in 2040. Only the high oil case had us importing no oil in 2040.
In fact their reference case is really quite pessimistic. Here is their Eagle Ford reference prediction:
The Estimated Ultimate Recovery from Eagle Ford Wells is already falling:
Year EUR in thousand barrels
2008 36
2009 57
1010 117
2011 153
2012 191
2013 169
Now the EIA did have a High Oil Resource Case where we become energy independent by 2037. Among other things they include:
EURs for tight oil, tight gas, and shale gas wells are 50% higher
They are already falling but if they turn around and go 50% higher then….
Additional tight oil resources as well as 50% lower well spacing (i.e., wells are closer together), with a downward limit of 40 acres per well …….
That’s 16 wells per square mile. Now that is some tight spacing for laterals two miles long.
Long-term technology improvements beyond those assumed in the Reference case…
Even the reference case assumes technology improvements, but to get to energy independence we must have even more and better technology improvements.
More resources in Alaska and in the lower 48 offshore, including the development of tight oil in Alaska and 50% higher technically recoverable undiscovered resources for other Alaska crude oil and the lower 48 offshore…
We need to find some of that undiscovered tight oil in Alaska. There must be some up there somewhere, and some more undiscovered in lower 48.
The development of lower 48 onshore oil shale (kerogen), with production reaching 135,000 barrels per day by 2025.
Yeah, that Green River Kerogen will help out a lot.
But what about the whole US of A, what is the EIA’s reference (most likely) projection for that?
This projection was apparently made last fall well before all the data were in. As you can see they were a bit optimistic with their reference case. Anyway the reference case has us peaking, or very near it in 2016. Then after a short plateau we head down, big time.
If the EIA’s reference case is anywhere close to being correct then World Peak Oil is definitely in this decade. Without the USA’s input, crude oil has already peaked. US shale oil is the only thing keeping us off the peak. And now even the EIA is, in their reference case, predicting the peak in US production.
We are only human and we are born optimists.
If we weren’t we would drown our kids like kittens.
But being optimists we believe the preacher when he tells us there is a better place beyond this vale of pain and sorrow and tears.
I have polled a large subset of my acquaintances informally and there are only a couple except professional scientists and people I know thru blogs such as this one who aren’t complacent about the future.
They believe there are serious problems to be sure but they also believe ”they ” will fix everything up ok.
It is that third ” they ” wherein the trouble lies.
Mac,
I feel as though I’m going to be leaving my grandchildren a planet that won’t be fit to live on; I’m absolutely convinced of this. At times optimism just seems like fraud by another name but, really, pessimism is a cop out as well.
So, what do you recommend? I my view, you just admire the beauty that can be found everywhere and live your final days helping out those that deserve it. Does it achieve anything to lecture those less well informed? Probably not.
So we’ll just keep trucking on, try not to make too many more mistakes and, avoid drowning kids like kittens, even if they deserve it. Right?
Doug
P.S. Hope Ron doesn’t ban us for maudlin ramblings — like he probably should!
I don’t know when you first realized the supposed light at the end of the tunnel is a fire that is going to consume us but Ron has been a confirmed doomer longer than I have.
But to the best of my knowledge he is not expecting the world to go to hell in a hand basket in the next few years barring some potential catastrophe such as WWIII.
Nor do I expect a short term collapse.
I do however expect some pretty hard economic times from here on out compared to the last few decades of constant growth.By ” here on out ” and ”short term” I mean the next decade or two.
But my time scale is only a guess and there are many ways the cards could fall that would result in the Four Horsemen riding globally within any given year.
The situation in the Ukraine right now could for instance escalate thru bad luck and mismanagement into WWIII. Or a really nasty combination of positive feedback loops could develop sooner than projected and runaway warming could hit the world really hard in a decade or two rather than half a century from now.
The likeliest trigger of really big troubles for the next decade or so in my estimation is a shark fin decline in global oil supplies which could put enough pressure on national leaders to tempt some into starting resource wars which may spread uncontrollably.
ukraine and poland have a role to play in the neocon scheme of things.. they are intended to cause economic trouble for russia that will lead to regime change in russia that will lead to necon russian retaking control of russian energy
US neocons need to control russian energy if they’re to achieve their “benevolent global hegemony” and “full pectrum dominance” and those US neocons apparently expect russian neocons to cooperate
it’s as simple as that
.
the trouble with putin started when he repossed russian energy and media from russian neocons… by 2004, the russian neocons had been purged, many of them fleeing to israel
the US retaliated by recruiting lots of former USSR states and satellites into NATO… but that hasnt worked out so well towards neocons regaining control of russian energy… putin is till popular, so there’s no danger of him being deposed by popular unrest
so it’s back to ukraine’s original function… causing trouble for putin that can lead to some phony war with russia… shooting war, economic war, whatever
the neocons are the biggest threat to our ability to deal rationally with peak oil and global warming, but maybe they’re not rational… maybe they’re haywire
the best of all possible outcomes, from a neocon standpoint, would be another ground war in europe that would reduce europe and russia to shambles again… thus eliminating two centers of power that might resist US neocon “benevolent global hegemony”
…and when’s this supposed “benevolence” gonna show up, anyhow?
.
map: neocon and NATO aggression, pipelines,
here’s the map… notice the sequence of NATO expansion… the first big wave comes arter the USSR disintegrates…
http://imagizer.imageshack.us/a/img31/6865/8h6x.jpg
the second big wave comes after putin finished reclaiming Russian assets from Russian neocons
and the main media has been down on putin ever since…
the putin hate has gotten worse lately, despite the fact that he’s gone out of his way to avoid confrontations by building pipelines that bypass necon trouble spots…
but instead of the “western” press acknowledging putin’s efforts, we get non-stop condemnation of putin for his supposed aggression…
…when all he’s doing is defending himself from neocon aggression
It’s a Darwinian world and as I see things people who are so sure the USA is generally in the wrong are naive or misguided. There is certainly such a thing as right and wrong in international relations and America is certainly wrong in some instances.
But we haven’t had to recruit former Russian subjects- they remember all to well what life was like under Moscow’s thumb.
The only real reason I still tend to think of myself as a conservative is that the intellectual left has had it’s collective head up it’s collective but for the entire last century plus.
When you had t escape the old Soviet Union at risk of your life and Polish coal miners literally could not afford soap to wash up after a shift underground the left was still telling us how great things were in the commie countries.
I was reading what was actually happening.
IF anybody wants to know something about the history of modern Russia they should start with Solzhenitsyn .
If any body thinks the current Russia is really any different than the Russia of twenty or thirty or forty years ago they don’t understand that the same sort of people still run the place.
We aren’t saints but any country we occupy you can come and go pretty much as you please.The Russians built walls- literal walls- around their empire.
As a matter of fact the only proximate reason we have a serious terrorist threat problem in this country today is that we allow people from places we have invaded to come and go almost as they please inside this country.
And being human they want it back.
We aren’t going to mess with the Russians the way we do with countries such as Iraq and Iran.
The Darwinian power balance is such that they can do pretty much as they please in their own backyard and we will have to either like it or lump it.
The Russians have the wherewithal to push back and they have the real currency that the world runs on these days -oil.
the USSR is dead and gone… maybe you havent noticed… and maybe russians learned something from their experience then
…and you got to admit that russians nowadays are not publishing their intention to estavlish benevolent global hegemony and full spectrum dominance, they’re not acting, for twelve or thirteen years, like then emant to establish their global hegemony
.
neither did russians say they needed a new pearl harbor to get their projeject rolling, nor did they, a year later
the setup stinks to hihg heaven, but that’s how the system works… and russians’ main sin is that they understand how it works
the jewish neeocons will never forgive russians for that understanding… meanwhile, the US coporate fascists and deathwish chrisitans and their political commissars are along for the ride
and maybe, just maybe, there’s a brit or two lurking in the background, figuring they’ll exploit zionist stupitiy, religious fanaticism and american muscle to recover some of their lost glory
and the opium trade goes on… and on… and on and on and on
I will say this one more time, then I will quit this thread…
the Russians understand how the system works, they are not bamboozled by a bunch of neocon propaganda, and that’s why the US neocons and the neocon media are scared of russia
Wadosy,
My, my: what a cynical view you have. And here I thought we were just flooding the world with Peace, Freedom and Liberty. I certainly wouldn’t want my Grandchildren exposed to such leery language: it sounds, you know, well, apostate! (Do I need a little round yellow face here?)
Doug
Conspiracies of more than one person are always shaky. Too much money to be made writing books for a conspiracy to stay secret.
As for Russia, they are draining a lot of money from their enemies every single year. There is rather a lot of talk now that money that can be whimsically printed is not the sort of thing you want to drain from your enemies.
Rather you may want food shipped, or slave labor — or maybe something like “the price is $105/barrel, or $85/barrel if you cut your defense spending in half”. Now that is the way to play for keeps.
U.S. crude exports could counter Russia in 90 days -Hess CEO
http://www.reuters.com/article/2014/04/10/usa-crude-exports-hess-idUSL2N0N225T20140410
Most recent four week running average data from the EIA showed that the US was dependent on net imports of crude oil for 47% of the crude oil processed in US refineries.
We clearly have a crisis situation regarding the math skills of many US oil and gas executives, and we need a nationwide remedial math program to teach them how to do simple arithmetic.
Nice job Ron, thanks.
I talked to my sister today who lives down by Bellingham. I talked about CC in the conversation, of course. She said the Seattle papers are all about exporting oil and energy independence. When I told her the facts, (basically Jeffery’s data above), there was silence. She cannot believe msm is actually lying or that inept. Neither of us can explain why this message is the prevailing theme of the day?
Does anyone have a credible opinion as to why? Surely, US leaders and business shakers are not this stupid. What is going on?
Paulo
Paulo
Its simple. The left hand knowth not what the right hand is doing.
Syeve
The problem with us being so gullible is that we are almost all of us -meaning the ones involved in saying things that influence public opinion- ready willing and well skilled in lying on the grand scale.
We routinely lie and we routinely expect every body else to lie as well whenever it suits their needs.
Telling lies is the primary job of just about anybody in a position that calls for substantial communication with the public with only a few exceptions.
For instance any public announcement from the National Education Association is invariably couched in terms of the ”welfare of the children”.
I was once a member and listened to the national president speak for two hours about what we the teachers wanted and hoped to get.Kids weren’t mentioned even once in this entire address to the convention.
My best remaining true blue liberal friend from my long hair days will get bent totally out of shape if you ask to copy a forty year old record from his extensive collection.
But he thinks it is perfectly ok that the Obama administration has lied almost every day and several times most days for the last four years about Ocare because he supports health care being socialized and if confronted about this simply shrugs and says EVERY BODY DOES IT in private with an old friend like me.
In public he changes the subject or talks about poor people without health care and simply does not ever acknowledge the lies.
(Personally I think socialized medicine is the future and will be glad to see it arrive but any realist must admit that Ocare is probably the worst managed and worst written law in living memory.
I don’t think it will be repealed outright and the democrats and the country are long term winners in terms of history because of it.
But I think it is so badly implemented that it will result in the republicans making a clean sweep of the federal government next elections.
If I am right this means we are looking at a political disaster on the environmental front.)
This friend is perfectly honest personally and has a bachelors degree from a highly regarded university and a masters from the University of Virginia and he is active in conservation circles in Virginia.
This institutional lying is the norm in most instances involving most issues and it is a perfectly adequate and more than adequate explanation for so many conservative people believing global warming is a hoax.
They don’t know enough science to judge for themselves and they are so used to being lied to and to lying to everybody else that it never even occurs to them that climate scientists may be on the up an up.
And if they do happen to understand the science and they are if not willing to actually lie about it they almost always will refrain from calling out their political allies for doing so.
The average tea party type that is screaming for nobody to ever get a subsidy is generally well aware of the fact that he himself gets numerous subsidies unless he is a dimwit foot soldier.
These include interest deductions for mortgages for instance and the increase in business that results from spending on highways if he is in the construction business or auto or oil business.In the case of the dimwit foot soldier he is probably paying less than half what he collects. It costs anywhere from seven grand and up annually to keep a kid in a public school for instance.
The AMA and the bar associations are pretty much the same – they do publish some useful stuff that is good to know about health and law if you go looking for it but any public announcement almost invariably turns out to be tailored to the needs and desires of the members of these associations rather than the best interests of the country as a whole.
An editor of a major publication dependent on advertising from the ” business as usual ” crowd is generally replaced with in a year if he crosses a certain line and upsets the customers of the business as usual guys with hard fact stories about future increases in gasoline prices for instance.
There aren’t many publications that aren’t dependent on such advertising.
The facts can be mentioned someplace buried in the middle of back of the paper- where very few people will notice– but never emphasized on the front page for fear of losing the meal ticket of the business which is the advertising dollar.
If all this is not enough there is the fact to be considered that most of the mass media belongs to conglomerates which also own other businesses dependent on happy go lucky oblivious to the facts consumers for their survival.
.
Ignorance and lies are the coin that allow civilization as we know it to continue to exist as we use up Mother Nature’s one time gifts.
Item 1: A CEO maximizes profit. Exporting crude will improve their profits.
Item 2: There is no obligation from a CEO to worry about who is thinking what about energy independence. He’s a human being. He acts in a human way, to defeat his competition and thereby increase the money his company makes.
Item 3: If you were paying his salary, that’s what you’d want him to be doing. Not spending his time ranting on TV interviews about how people have it wrong about energy independence. That’s not his job.
Jeff,
You just don’t get it do you? Do Not Despair: God will provide.
And if anyone says I need to add a little yellow face they need a brain transplant, not lessons in Elementary School arithmetic. This “supplying Europe with fuel to counter the Russians” gives the word pathetic a new meaning.
Doug
Hi Jeffrey,
“We clearly have a crisis situation regarding the math skills of many US oil and gas executives, and we need a nationwide remedial math program to teach them how to do simple arithmetic.”
No, I’m pretty sure they all know how to do simple arithmetic, I think what they need is a course in ethics where they learn that lying and misleading others for their own personal benefit is wrong!
Anyways everywhere I look, I still see everyone with the the pedal to the metal, full speed ahead and damn the torpedoes. We are getting closer and closer to that washed out bridge and the am going to guess that most of those oil and gas executives know full well that this gravy train is going to derail at full speed. They just don’t give a damn as long as they’ve got theirs…
Cheers!
Fred
US politicians are so desperate to look powerful in the face of a country on the back side of its days of global influence (due to huge debt loads, relying on QE to fill the gap between high priced oil and what the economy needs to generate growth), they are willing to pretend the US can extend it’s mighty arm to the EU by substituting for Russian oil and gas. It’s like an old ex-heavyweight boxer pretending he still has what it takes to knock out the current title holder, aimlessly lunging at a laughing, more powerful adversary.
I say Congress should overturn the ban on exporting crude right away. The Emperor’s lack of clothing would be revealed that much sooner.
I am thinking of starting an online petition demanding a change in the law, so that we can export crude, followed by an increase of 2 mbpd in our crude oil imports from Russia, so that we can then export 2 mbpd of crude oil to Western Europe.
Gotta look at who owns the tankers. There could be big money to be made buying shares just before the law passes.
Karen,
That would be best, the sooner we focus our mind and effort on moving to a post carbon economy the better.
That said, I’m not sure what all those diesel car driving Europeans are going to do with low diesel fraction American LTO. Export the excess refined gasoline back to North America?
Something that Jim Hansen pointed out to me. Thank God we are not dependent on imports of petroleum from Russia:
http://www.eia.gov/dnav/pet/hist/LeafHandler.ashx?n=pet&s=mtxim_nus-nrs_2&f=a
Feb 2013 production rise was north of 40K bpd. Can’t look back further than that because choke norms and fracking stage count were different, as was ceramic vs sand proppant changes.
This looks like a very weak February, much like January was weak.
The blurb earlier today looking for 1 million bpd either March or April looks unlikely. 112K bpd increase in 2 months is way over the top.
Ooops, no, for all NDak they probably can get to a million in April. Was looking at Bakken.
IMO you left out the more interesting parts of the “Competition from Texas, winter expected to limit ND oil production” news article.
KLJ CEO Niles Hushka presented the projections to the Legislature’s Interim Energy Development and Transmission Committee this week.
Conservative estimates show it will require 40,000 wells and 20 years to complete drilling activities in the Bakken and Three Forks formations. Some projections put the total well count in the North Dakota Williston Basin as high as 120,000, the study says. North Dakota had 10,100 producing wells in January, including 6,935 Bakken and Three Forks wells.
Hushka said companies are expected to complete an average of 2,100 to 2,300 wells per year over the next five years in North Dakota. The main reason they won’t drill more wells is a limit on how much money they have to spend, he said.
“Companies have other places to invest their money,” Hushka said. “We are in direct competition with the Permian and the Eagle Ford. It’s cheaper to drill in the Eagle Ford and they don’t have winter, which is a significant factor.”
The industry is shifting to what Hushka called “batch drilling” and “batch fracking,” in which multiple wells are drilled at the same location, followed by fracking of those wells in a condensed time period.
That allows the industry to gain efficiencies, but it also has some logistical challenges. For example, Bakken wells require an average of 1 million to 1.5 million gallons of water for fracking. If an operator is fracking 10 wells at one location, it would require 10 million to 15 million gallons of water.
And 3 million pounds of proppant per well. So a pad has to have some godawful big storage. Not real clear what the point would be. You don’t get more oil drilling all the wells in a compressed time from one pad vs doing them one at a time from that pad.
Though maybe there are a few pad admin positions that would not need to be paid as long. Doesn’t seem like a big price tag.
“Hushka said companies are expected to complete an average of 2,100 to 2,300 wells per year over the next five years in North Dakota. The main reason they won’t drill more wells is a limit on how much money they have to spend, he said.”
This was briefed to the legislature. This is the big item. How many jobs there are going to be. Yup, they collect royalties on flow, but they also get income tax on truckers.
It will occur to someone at some point that optimally they should hold production at 900K bpd rather than ramp it, because that will keep tax revs flowing longer.
It’s like buying anything in bulk, you get a better unit price buying all at once versus one at a time. That’s why they want to do batch drilling and fracking.
I don’t know anything about drilling for oil beyond what I have learned studying peak oil but I have been a rolling stone all my life and some of the places I collected a little moss includes some really big construction jobs.
There are almost always some substantial economies of scale involved in doing things as big and as fast as possible.
Such advantages include getting more hours per week of use out of machines that cost well into the high sixes and even more such as fracking trucks which probably cost well into the sevens.The less time they spend on the road and waiting sitting around waiting for a well to be ready the better in terms of return on that investment.
It is far more profitable to wear out a machine in three or four years that it is in five or ten although true industrial quality machinery seldom wears in less than five years even running it two shifts year around.
One reason that it costs so much to get a construction job done that involves earth moving and trucking the soil is that the equipment is poorly utilized.
If you go to an auction where dump trucks are sold it is quite common to see them that have been driven less than twenty five thousand miles a year.
Road tractors that are used by cross country truckers usually have five to seven hundred thousand or even more miles on the odometer with in five years.
Maybe. I’d think the company is buying in bulk anyway for months of fracking single or multi wells, so no price help there.
The savings I am talking about have little to do with the purchase price of expendables such as diesel fuel and and chemicals but mostly rather the higher utilization of many tens of millions of dollars worth of machinery and skilled labor.
Having a million dollar machine sitting around not working is just like having an empty apartment or restaurant.The capital cost is enormous and to cover it you need to keep it productively working as many hours as possible.
The income to be had from running a truck an extra week this year as opposed to next year at the same rate and with constant money is worth substantially more than it would be a year from now since the money in hand is worth so much more than money in the bush.
The truck payment, taxes, and insurance and the driver’s salary all must still be paid.You make some money only after these mostly fixed expenses are covered.The marginal cost of running the truck after that is mostly fuel and maybe overtime for the driver.
Once you hit the break-even point you can net big money barring bad luck.That is the goal and the way to achieve it is to finish a job at a profitable negotiated fixed price in less time than budgeted and move your men and equipment to the next job.
Well, we will likely be “self – sufficient” in oil in 20 years. Just not at the level they think.
Yup. You’re self sufficient if you kill off 100 million people and consume 8 million bpd.
But that’s linearism (a new ism). That’s where you presume one number tracks another. Truth is you get down to 200 million via nuclear weaponry, and that only lasts a winter, at the end of which you get down to 20 million — who consume pretty much no oil, which is good because they won’t be producing any, either.
Unless some well armed and sneaky raiders or old age get me and I make it thru the wars I will be consuming some oil- not very much but enough to keep a tractor running a few hours a month. I have the steel drums ready to store as much as I can put my hands on writing bad checks if necessary when hot crisis hits.
We will eat almost all the saddle horses if any left outside survive in the event of war and draft animals are so few nowadays that they will be for all practical purposes non existent as far as buying one goes.
But there will be plenty of tractors sitting around free for the taking for anybody who can manufacture some fuel.Good sense leads me to think I should learn how to extract oil from soybeans or something along that line.
The marginal utility in terms of money of the last gallon will be enormous.I have often said I could better afford twenty dollar diesel easier than I could use a horse under current conditions.
In the hypothetical case of growing the last acre of corn to make my own meal lacking a horse I would gladly pay any price rather than try to spade up that acre by hand at my age.
The organic wackos always forget the horse or oxen have to eat, too. You’ll be harvesting acres of hay to get them thru the winter, not just acres of food to get you thru the winter.
The ugly little secret of the bold and adventurous US western pioneer is most fled back east when they had a crop failure. Only a very few stayed the course. The Mormons in Utah had a lucky stretch of good years, but that wasn’t so everywhere.
OFM Wrote:
“Good sense leads me to think I should learn how to extract oil from soybeans or something along that line.”
WoodGas:
http://www.journeytoforever.org/biofuel_woodgas.html
OFM Wrote:
“I have the steel drums ready to store as much as I can put my hands on writing bad checks if necessary when hot crisis hits.”
When the crisis does hit, I very much doubt they will accept payment in checks, or ever dollars. When the crisis begins to unfold the dollar become worthless. Best to add a Gallon to your stock pile ever week or two.
Still I have my doubts. My money is on WW3. The US continues to pour its military muscle all over the world. Sooner or later something or somebody is going to snap. Even a minor skirmish or accidental discharge between the US and other world powers can quickly escalate. Once the Nukes start flying it will be a matter of couple of weeks before the nuclear spent fuels pools start to catching fire. I don’t think anyone will survive it.
Wadosy,
You aren’t just ranting-you are raving.
As in raving lunatic. Forgive me but when people start in talking about Jewish neocons and their never forgiving the Russians for ” understanding” and death wish Christians and zionist stupidity and such other such stuff–you are beyond deluded.
There are power games being played of course but right and wrong as viewed from some idealistic perspective that involves pathological hatred of the US and the UK is utterly irrelevant to reality.
We have the upper hand in some respects. The Russians have it in some other respects.
Both countries will do pretty much as they please in terms of relations with other countries and drive bargains that are as advantageous as possible.
Right and wrong in this old world is mostly determined by strength of arms and alliances.
Mother Nature does not deal in right and wrong.
Have you any knowledge of a Russian girl’s band called Pussy Riot?
I suggest you check into what has happened to the women who are members of it over the last couple of years.
We are as I said earlier a long way from saints.
But considering the power we have and what we could be in terms of being bad, we are actually pretty decent.
Yes the old USSR is gone and good riddance.
But most of the culture that prevailed during soviet times still prevails in Russia today.
It is true though that the Russians are making great progress towards becoming a modern country and that in another generation if they are lucky they might actually be a country with laws and respect for law.
In the soviet days if you had power and money you were called a commissar. These days in Russia if you have power and money you are rightfully called a robber baron.
Incidentally the days of the US as top dog are probably numbered. The days of the British as top dog were numbered back in the WWII era.
We are probably heading into a period of history wherein there are three or four major centers of power with none of them able to dominate the world stage. There will be China and countries in her orbit, Western Europe, Eastern Europe/Asia meaning Russia and countries in her orbit, North America dominated as usual by the US , and South America dominated by Brazil.
Right and wrong will have nothing to do with this coming about.It is as natural a process as a parasitic wasp depositing it’s eggs in a caterpillar.
I am hoping that I will be able to anticipate the crisis sufficiently early to stock up on diesel and fertilizer and a few other key items before everybody else has the same idea.
I always keep enough on hand anyway to run as a family subsistence operation for a couple of years.
And most likely the checks would be good.
But if I happen to be short of cash on a day I think WWIII is about to get rolling I won’t hesitate to write them and worry about covering them later. 😉
I live a long way from any likely nuclear targets and have high hopes that the world will still be a livable place after a nuclear war.
It won’t be if they shoot off all of them of course.
“A US government report expects that the United States will become self-sufficient in oil production by the year 2037”
Yes, but only because there won’t be anyone exporting oil in 2037. We will have to get by with a lot less oil by then (or not and collapse).
Fracking and horizontal drilling work best in the U.S.
State-owned energy companies in China and other parts of the world have spent billions in recent years partnering with domestic energy companies to learn how to best recover oil and natural gas from tight rock, but learning how fracking and horizontal drilling work might not be enough.
One reason oil and natural gas drilling has been successful domestically is because many of those who are inconvenienced the most stand to profit on the effort.
“We’re the only country in the world where you own your mineral rights down to the center of the earth unless someone already sold them under you,” JAStanislaw Group founder Joseph A. Stanislaw said Thursday at the University of Oklahoma’s Energy Symposium.
England is attempting to gain public support by requiring some of the profits be given to the local community, but Stanislaw said that likely is not enough.
“That’s very different from putting it in my own back pocket,” he said.
Shale basins are found throughout much of the world, including Russia, China, Europe, South America and Africa. In many of those areas, however, the basins are far from pipeline, sand and other infrastructure….
“We have the space. We have the technology. We have the resources and the political will,” Devon Energy Corp. CEO John Richels said of producers in North America. “You have to have all of them.”
All shale basins don’t have oil (condensate). For example, Poland.
Devon might have all the space, technology and will in producing shale energy, unfortunately they just haven’t made any money.
Devon spent $5.8 billion more on CAPEX than operating cash flow over the past three years.
Steve
Steve,
“You have to have all of them.” However, If you spent $5.8 billion more on CAPEX than you got back from operating cash flow over the past three years then you are bankrupt. I don’t know a debit from a credit, these are the words of my accountant.
Doug
I updated my numbers & graphs on the individual ND wells based on the latest NDIC report. It’s all ND, not only Bakken, although Bakken represents by far the largest part.
See below the following 4 graphs regarding all individually reported wells (that had error-free data) in ND, since 2007 :
1) The average monthly output of wells over their life time, from the year they started production, counting from their peak month (labeled 0). Interesting to see here is that 2010 wells seem to be going strong, while 2013 wells seem to drop faster in output. Still, the differences are not too big, and don’t value the last data points of each sequence too much, as other wells from that same year still need to pass through that point in their life cycle. E.g. the drop of the 2013 wells on month 13, represent the January 2013 wells, that have now reached the 13th month of production after their peak month.
2) The average cumulative output from the wells per year. Also from this graph it looks as if the 2010 wells are going somewhat stronger than wells from older & newer years. Wells from 2013 started off better, but seem to decline slightly faster. Wells from 2014 are having the worst starts so far since 2010, but this could change later this year.
3) This graph shows the overall monthly output in ND. The objective was to visualize the contribution of wells from different years to the current output. E.g. you can see that wells from 2012 and later make up about half of the current production. Please note that these are monthly numbers, and as February has fewer days than other months, there tends to be a dip each February.
4) The last graph shows how many new wells each month started production, and for each month how much the average peak production was. The wells peaking in January 2014 were doing worse than other wells the last 2 years. It was already clear that fewer wells were added during Dec-Feb, with the whether probably being the biggest factor. Note that I deduce this from the detailed well information, so slight differences from the official numbers are possible. Also, I determine peak months of wells from their decline in the next month, which is why for Feb 2014 I can’t determine the peak performance yet, until I have the March data.
Excellent Post!
Just from eyeballing, total oil production from 2012 and earlier wells has already declined by about 40 percent.
Thanks & indeed. I noticed a mistake in my description of the 3rd graph: the output from wells from last & this year already contribute about half of the current production (so excl 2012).
“I noticed a mistake in my description of the 3rd graph: the output from wells from last & this year already contribute about half of the current production (so excl 2012).”
That is powerful stuff. 2013’s wells — and about 200 from this year, are HALF of total production?
Basically this says if you stop drilling production will be down by 50% next year — 500K bpd. No wonder there is such huge resistance to a price drop.
Enno,
Nice Pics, good job. One question: wouldn’t the fact that you’ve included all ND production skew your conclusions about relative decline rates? In other words, since the contributions from tight oil vs conventional were closer a few years back, wouldn’t that make it seem like LTO decline rates were lower then? But, then again, perhaps I’m just not seeing (hearing) something in the data; wouldn’t be the first time.
Doug
Doug,
That is a good observation, and I think that there is indeed such an effect. In graphs 1 and 2 it is clear that initial and cumulative production of the average well was lower a few years ago, and so were the decline rates. I think a large part of this difference is indeed caused by the changing of the ratio of conventional wells to the total. The data does not allow me to directly identify and seperate the 2. Dennis looks only at the Bakken part, so I assume that his data contains a larger ratio of LTO wells during these years.
Hi Enno,
Is it still the case that the “2007” curve includes wells from 2007 and earlier?
If so is it possible to pull the Dec 2006 report to eliminate wells from Dec 2006 and earlier from the 2007 curve?
Hey Dennis,
You are right: 2007 also includes all the years before. I will make that clear in a next update or use the 2006 dec data also, thanks.
Hi Enno,
Thank you for so graciously sharing your data with me.
Based on Bakken and Bakken/Three Forks wells only I used single wells and no filtering and eliminated wells from Jan 2007 and earlier so that 2007 represents only Feb to Dec 2007 (January 2007 data includes all wells from Jan 2007 and earlier that were still producing in Jan 2007). The well count on the right axis represents the number of wells used to calculate the average well, represented with the dashed curve.
Chart below. Note that Enno’s charts represent all North Dakota wells.
Mistake on vertical axis labelling, should be “Cumulative C+C (barrels)”
corrected chart below. Sorry.
Again, this is some really great work, Enno. I would like to thank you too for sharing.
Energy & Capital has been pumping shale gas stocks for years, now they are dumping them. If you get their daily email newsletter you know how they operate. They give you a link to a video that promises to tell you how to make millions. But what they are selling is not stock but reports, reports that for a fee will tell you just where to invest to make your millions.
But this time they give you a two minute video that tells you that all shale gas plays are a Ponzi scheme. Then they want you to watch another, likely much longer video, where they will pump another get rich report. I did not watch that one so I don’t know what they kind of report they are selling right now, I just know that I am not interested. But I did find the chart below quite interesting.
It’s all ONE BIG LIE!
See for yourself in this chart where the four biggest shale players (Chesapeake, Southwestern, Devon, and EOG) are actually losing money…
As outlined on a separate thread, I remember explicit or implicit recommendations by bloggers to get into Pacific Ethanol, Petrobank (the THAI process) and Shale Play stocks.
I suppose one could have made quite a nice return on investment by shorting the first two. We will see what happens regarding the the third stock category.
That chart is marked labyrinth consulting. that’s Art Berman’s shop?
Yes, I believe it is.
Arthur E. Berman Director, Labyrinth Consulting Services, Inc.
And this is one of his slide shows on Shale Gas.
A Perspective on Future U.S. Natural
Gas Supply and Price
Nothing about the Marcellus in Berman’s slide show. Long life?
So investor sentiment on shale seems to be turning. (Kind of surprising that a complete lack of profitability for five years hadn’t soured enthusiasm before now.) How long before the bubble pops, the shale companies can’t fund capex, and drilling tapers off–six months? A year? And once it does, what does US crude production barrels per day revert to?
As noted a few paras up, if you stop drilling, NDak output will be down 50% in about a year.
So with pre-shale US crude production of five million barrels per day, lack of shale drilling would cut out half the 3 million incremental shale production–so total US production would come to 6.5 million barrels per day after a year. And year 2 without new shale drilling would drop shale production in half again, to .75 million, which would come to 5.75 million barrels per day US crude production. (I would guess it would affect natural gas production as well?)
It will be interesting to see how this affects the 2016 election.
No, not that bad. First year decline is much steeper than year 2 decline. You’re right for year 1 of no drilling, but year 2 is less of a decline.
Well we are talking about natural gas here, not crude. Rigs are switching from gas to oil because they are losing their shirts with gas. Gas prices will have to rise but not soon enough to save most of these companies, or in time to save their investors anyway.
Yes, you’re right. Big difference between natural gas and crude, so my comments above don’t apply. But from the Kopits presentation, I wonder if shale oil is actually any more profitable than shale gas?
The Duvernay Shale play is a huge, rich gas, condensate reservoir in Western Alberta. It is estimated to be 30% larger than the Eagle Ford, with 433 tcf of NG, and 61.7 Gb of liquids. Money from Australia, China, and over 22 oil companies is now pouring into it. These include heavy hitters like ConocoPhillips, Shell, Chevron, and Encana. Well depth is 16,000 ft.
Interest in the Duvernay has increased because of its close proximity to the bitumen fields around Fort McMurray. Condensate, because it has a very limited capacity to produce transportation fuels (about 7%) has a limited market. The market that pays the best price is as a diluent to produce dilbit, which allows the extra heavy bitumen to be transported by pipe. Over half of the condensate used for making dilbit now comes from the Eagle Ford, which is 2000 miles away. The Duvernay is 200 miles away, and the transportation saving will amount to $15 – $20/barrel.
The Durvernay will obviously be able to supply the tar sands with diluent for as long as they remain operational, and very competitively with any present US supply. But, how will this affect US shale development, that has been able to buzz along because it held a captive market in Canada? Also, what will the Durvernay producers do with 433 tcf of NG that has to come along with the condensate? 433 tcf of NG is enough to supply the entire US market for 16.5 years.
The gas will be shipped, and it will be shipped south. There is nothing to prevent a flood of Canadian NG from arriving at, and dominating the US market.
“Encana CEO Randy Eresman admitted as much at the company’s annual meeting in Calgary last week when he suggested the company could give away the gas and still make money on the liquids.”
Our sources tell that the Durvennay will be supplying product to Fort McMurray in two and a half to three years. US shale producers could lose 40% of their market.
Sir,
With respect, perhaps a reality check might be appropriate here. I’m not looking to smash your hopes and dreams but:
“…Potential acquirers must tread carefully. Results from the Duvernay so far have been all over the map. There have been some outstanding wells with phenomenal condensate yields, but there have also been results that have not been so good, Mr. Bouchard and Mr. Zack wrote in their report. Clearly, it is still early days for the Duvernay but as industry continues derisking the plays, this could ultimately become a meaningful source of local condensate supply for oil sands and heavy oil producers…”
http://www.theglobeandmail.com/report-on-business/industry-news/energy-and-resources/oil-sands-producers-eye-pipeline-condensate-sources/article16214558/
Doug
Hi Ron,
The biggest player in the Bakken is Continental, and based on their March 2014 presentation their GAPP net income is positive.
http://investors.clr.com/phoenix.zhtml?c=197380&p=irol-presentations
On the final slide they show 2013 net income of 764 million dollars.
Not GAAP,
Should be GAAP net income
Don’t know what’s being rebutted there, but minor heads up that it looks like a pretty solid 40% of CLR output is non Bakken.
There is some interesting talk of SCOOP, south central oklahoma blah blah. Their test results look pretty weak for oil, but they are talking it up as a liquids play and quoting BOE this and that with a portion liquids being north of 50%.
This is smelling more and more like airplanes don’t have a great future unless Pratt and Whitney start modding.
Hi Watcher,
Simply pointing out that Continental is not losing money at present according to GAAP (Generally Accepted Accounting Principles) measures.
I checked out EOG, one of the largest oil companies drilling in the Eagle Ford, for 2013 their GAAP net income (from the 10k) was 2.2 Billion dollars 2012 was 0.6 billion dollars and 2011 was $1 billion.
Again the point is that the players in the liquids plays are making money. When the price of natural gas goes up the shale gas players will make some money as well. In the mean time the shale gas operators are losing their shirts.
Hello Dennis, interesting that you should bring up Continental being the “biggest player in the Bakken.” The weather today in my area was lousy and I was bored, so I decided to take a look at a cumulative amount of oil produced through February by all 1,798 non-confidential Bakken-Three Forks wells reported in the NDIC database as being completed in 2013. I separated the data by the well operator designated in the database, which led to some interesting results.
For instance, 41 different operators are shown to have completed a Bakken-Three Forks well in 2013, but just six companies were responsible for nearly half of all the wells. Continental easily completed more wells than any other company, 25% more actually than the next most active company, but where things got more interesting is when the average cumulative oil output per well is separated by operator.
The average Continental well completed in 2013 has produced 53,984 bbl through February, placing Continental 25th out of the 41 companies in this measure. Meanwhile, the average 2013 Bakken-Three Forks well for the industry as a whole has produced 66,438 bbl through February, so collectively Continental’s wells are below average with regard to cumulative oil production.
I suppose one of the caveats here is that not all of the wells completed in 2013 were completed on the same date, so a company that completed more wells later in the year presumably would have a lower cumulative output per well simply because its wells are younger. A company could also potentially complete better wells earlier in the year compared to later in the year, or vice versa. Whether these things were factors here would need further investigation. However, I can say, having also calculated the average date on which each company completed their 2013 wells, that the average 2013 Continental well was completed on June 25, a slight bit earlier than many of its peers.
As for which company has had the most productive 2013 wells, that is easily EOG, whose 60 wells from 2013 in the database have produced an average of 182,135 bbl to date, or 82% more than the next highest company. This finding was not so much of a surprise for me, though, since EOG holds some of the “sweetest” acreage in the Bakken. Furthermore, EOG, probably more than any other company, has really been pushing the edge as far as completion techniques go. EOG has used 40, 50, and even 60-stage fracs and literally tons more proppant than competitors. There are many EOG wells, for example, that were completed with a nearly unbelievable 10-12 million pounds of proppant, almost always exclusively sand. By comparison, other companies generally complete their Bakken-Three Forks wells with around 30 stages and 3 million pounds of proppant, either all ceramics, all sand, or a ceramic/sand mixture.
There is a lot more I could write about what I found, but I think I’ll stop, lest this comment start to be construed as any kind of investment advice. That is not my intent, nor do I believe this blog is intended to be used for investment purposes.
“Meanwhile, the average 2013 Bakken-Three Forks well for the industry as a whole has produced 66,438 bbl through February, so collectively Continental’s wells are below average with regard to cumulative oil production.”
I don’t think I ever re-found a snippet / link that said CLR was changing procedures and choking output from their wells more than in the past. But I do know I saw it. They think it will improve EUR.
That can be an explanation.
As for investment advice, see if Hamm’s wife’s divorce attorneys’ lawfirm is publicly traded.
BTW, here are average cumulative production amounts through February 2014 for Continental wells completed in other years.
2010, 103 wells, 139,144 bbl avg. cum. oil, 173,544 bbl industry average
2011, 156 wells, 144,845 bbl avg. cum. oil, 143,528 bbl industry average
2012, 196 wells, 101,365 bbl avg. cum. oil, 107,481 bbl industry average
2013, 207 wells, 53,984 bbl avg. cum. oil, 66,438 bbl industry average
I realize you don’t have much use for investor presentations, but one of the most interesting things, IMO, that they contain are maps of where the company holds acreage. If you know where the sweet spots are, you can use the maps to get a sense of how good overall the company’s wells are likely to be.
Continental’s acreage map is probably most notable for showing that the company does not necessarily have acreage in the best of the best spots. For example, Continental is almost completely absent in many of the sweetest of the sweet spots in Mountrail County. It is also missing out on some key areas of east-southeast McKenzie County and northeast Dunn County.
I think in light of this, it is far easier to explain Harold Hamm’s incessant Bakken cheerleading, suggestion that 120,000 wells may ultimately by needed, tests of 32 wells per spacing unit (the tightest spacing yet developed), emphasis on “discovering” the Three Forks, estimate that the Bakken-Three Forks contains over 20 billion bbl of recoverable oil (an estimate that no other company has gone along with and was also, when released, six times larger than what the USGS said), repeatedly outlining plans to go “ears back” in the Antelope Field (probably the best underdeveloped acreage Continental currently owns), and even the mention a couple years ago while infrastructure was reaching a critical tipping point that North Dakota would be well served with 250 active rigs. Short of buying into the sweeter spots, which for several reasons is unlikely to happen at this point in time, to keep up with its peers in the better acreage, Continental probably has little choice but to unrelentingly drill more and more and more wells, more than any other company. Just more everything, basically. To do this, of course, Continental also needs more and more and more money. Which as a publicly-traded company is facilitated by a higher stock price, which brings us back around to Harold Hamm’s incessant cheerleading…
“Furthermore, EOG, probably more than any other company, has really been pushing the edge as far as completion techniques go. EOG has used 40, 50, and even 60-stage fracs and literally tons more proppant than competitors. There are many EOG wells, for example, that were completed with a nearly unbelievable 10-12 million pounds of proppant, almost always exclusively sand. By comparison, other companies generally complete their Bakken-Three Forks wells with around 30 stages and 3 million pounds of proppant, either all ceramics, all sand, or a ceramic/sand mixture. ”
Something fishy there. Recent study from some university buried back in the Ronpost threads indicated ceramic was vastly superior in terms of oil flow. But it was also more expensive.
This para above smells like limited ceramic supply and lease deadlines to get something drilled. It doesn’t smell like superior technique, per the univ study.
The avg is 3 million pounds of proppant per well (may or may not include the 1 million pounds of water also reqd, I think it does NOT incl the water weight), but that’s for 30 stages. If you extend stages, you’re gonna use more.
Bakken Update: Frac Sand Pricing Could Go Parabolic As EOG Resources’ Well Design Revolutionizes Unconventional Oil Production
EOG Resources (EOG) pioneered fraccing shorter and wider fractures. Before this, operators were trying to create longer fracs in an attempt to garner increased shale surface area contact deeper into the shale. It was believed this would maximize recoveries, but it also created issues. Longer fractures are further from the well bore. This distance is difficult to bridge, as it has to push proppant over a greater distance. Less proppant is secured in the fractures and this increases crushing and closure of those fractures. This significantly decreases EURs. Thinner fractures also have less surface area, which creates greater pressures. These greater pressures require more resilient ceramic proppant, which is approximately 10 times more expensive than sand. Since EOG Resources creates shorter, wider fracs, it reduces that pressure allowing for the use of all sand fracs. The increased void created by this completion design requires more proppant. In some cases, these wells use up to a million pounds of sand for every 1000 feet of lateral. EOG first used this in the Eagle Ford and Permian Basin.
Frac sand can be on the order of 90% cheaper than ceramics, so, even if ceramics make the better proppant in theory, sand is often used in greater quantities. EOG is able to realize even greater savings with sand because the company bought a sand mine in Texas in order to self-source its sand. Finally, EOG also established the first crude-by-rail terminal in the Bakken in 2009, demonstrating to the contrary of some naysayers that shipping crude oil out of North Dakota in unit trains was a viable strategy. To date, this is still one of the few crude-by-rail terminals in the Bakken directly owned by the primary producer using the facility. Here as well, by owning its own facility, EOG is able to realize even greater savings over competitors.
Michael Filloon’s analyses on Seeking Alpha are some of the best in the business. If you are a registered member (free) of Seeking Alpha, there are a lot of supplemental production statistics to go along with the article excerpt posted above. You can also get the statistics if you buy a basic subscription to the NDIC data and look through the individual well logs there, which indicate, among many other things, how tight the chocking is, how many stages were used, how much water was used, and how much proppant, and what type, was used. The 3 million pound proppant average does not include water.
Good data. Nothing hugely at odds with what we’ve thought was going on, except my recall is the ceramic proppant pricing was more expensive but nowhere near 10X more expensive. That needs looking into.
There is a US firm making it. It’s not all shipped in from China.
My vague interest in the proppant is due to the sheer magnitude of the numbers and just how much weight the typical trucks and roads can carry. These numbers quoted elevate the truck trip number enormously well past 2000 trips in year 1 — noting only 40% of those were to haul oil. The rest was water, proppant and pipe. These sand weight numbers hugely increase truck trip count. Traffic jams simply have to become a limiting reality.
I’ll go back and look for the ceramic pricing quote I found . . . somewhere.
This ain’t it, but it’s a good link:
http://www.mineralrightsforum.com/forum/topics/proppants
Well, what the hell, here’s alibaba, pretty interesting:
Don’t look like X10
http://www.alibaba.com/showroom/price-of-fracturing-proppant.html
Prices there about $500/ton. So 3 million / 2000 lbs = 1500?
$750K for proppant.
No way in hell sand is only $50/ton. In fact I just found a source saying $300 (which incl transport and the alibaba quote was FOB).
See I wasn’t just being funny when I asked what if EOG is the next Enron. 😯 😈
The reason shale gas companies are losing money is that the price of natural gas has plummeted. It’s done this because there is not yet a global market in natural gas like there is in oil. Because there are plenty of oil tankers sailing the oceans and it’s not too hard to build an import/export terminal, traders are able to take advantage of any oil price discrepancies that appear on the global market.
With natural gas, however, seaborne trade is much more difficult. There’s no money in shipping a hold full of gas around the world, so they have to liquefy it to get a sufficient volume. This means liquification terminals at one end, de-liquification terminals at the other, and ships that can carry the stuff around at -162 degrees C. You’re talking about serious CapEx here.
It’s only in recent years that the big corporations have decided that it’s worth looking at establishing a seaborne trade in LNG. It is now starting to happen, with export terminals being built in the US and Australia, at least. What’s the attraction? Well, I went here:
http://www.eia.gov/dnav/ng/ng_pri_sum_dcu_nus_m.htm
And this is what I found:
Average 2013 Natural Gas Pipeline Export price: $US4.06/tcf
Average 2013 LNG Export Price: $13.36/tcf
Sure, there is a cost in conversion, but the price that natural gas fetches in Japan is just irresistable. Expect LNG exports to keep rising until the Japanese & US prices converge. And then see how the shale gas producers are faring. High depletion rates mean that the industry isn’t going to last anywhere near as long as the boosters are saying, but it’s low prices that are sending gas players out backwards. When the price comes back up, they’ll be making plenty of money.
Countries with substantial natural gas reserves are Russia, Iran, Qatar and Turkmenistan; all have really big projects in various stages of development. Australia, a long way down the list, is, likely to be a major player in the future.
I don’t know where (and when) you think the US will find exportable gas reserves. One possibility, I suppose, is the North Slope. In order to produce and export from Alaska would require building a lot of infrastructure over a long time period and the costs would be extremely high. Canada has major gas deposits on its version of the “North Slope” and discussions re development have been ongoing for decades – same situation as Alaska: Remote, expensive.
Qatar, where I have some experience, covers a large portion of the world supply of Natural Gas. As of 2011, reserves of gas in Qatar were about 896 trillion cubic feet which means the state contains 14% of all known natural-gas reserves, the world’s third-largest reserves, behind Russia and Iran. I cannot imagine the US competing with highly developed, strategically located sources such as this – assuming there are exportable reserves available.
Doug
The EIA shows that Qatar produced 5.5 TCF of dry processed natural gas in 2012, versus 24 TCF for the US in 2012.
Based on the Citi Research estimate of the underlying decline rate from existing US natural gas production (about 24%/year), in round numbers we have to put on line the productive equivalent of Qatar’s 2012 natural gas production every year, just to maintain current US production.
The greatest threat to Qatar’s enormous wealth is competition as other nations are challenging its LNG dominance. Australia is constructing plants that will more than triple annual LNG-manufacturing capacity to 85 million tons by 2018, surpassing Qatar, according to data compiled by Bloomberg Industries. Do you think the US will fit into this equation?
Doug
Most of this is coal seam gas. There is resistance from farmers.
http://www.lockthegate.org.au/
Australian LNG is going to Asia.
9/5/2012
Queensland plans to export more than 10 times the gas NSW needs (part 3)
http://crudeoilpeak.info/queensland-plans-to-export-more-than-10-times-the-gas-nsw-needs-part-3
This will lead to domestic gas shortages
http://www.smh.com.au/business/agl-raises-spectre-of-gas-rationing-if-gas-shortages-are-not-tackled-it-tells-the-nsw-government-20140316-34vgr.html
Increasing conflicts are likely
Based on EIA data, the ECI Ratio* for Australia’s natural gas was 1.5 in 2006 and 1.1 in 2012. At this rate of decline, Australia would hit zero net natural gas exports this year.
*Ratio of dry processed natural gas production to consumption
There are large undeveloped coal seam gas resources in Australia. There was no market for them here, because regular natural gas is cheaper. Then some bright spark noticed that overseas prices were high enough to justify the cost of LNG infrastructure.
The gas projects will come on stream in conjunction with the LNG facilities. Historical data, therefore, are misleading when used to predict future production.
Doug says:
“I don’t know where (and when) you think the US will find exportable gas reserves.”
The “exportable reserves” will be found when export customers outbid domestic ones. They’re the same reserves currently being used to supply domestic customers.
Does anyone seriously think that a gas company is going to say “We know that we can get $US13.36/TCF in Japan, but we’ll pass that up and continue selling for $US4.06 here in the States”?
Yes there is a cost of conversion. And a cost of transport.
And in that cost of transport is loss of cooling. Heat is alleged to create 1% loss per day from these mega dewar/insulated tanks.
The ENI guy said LNG can’t get to Europe from the US for less than $9. GAZPROM delivers at $6.
Yes, pipeline is cheaper, so Russian gas can undercut LNG. They aren’t laying pipelines across oceans, however, so there is a regional glut in North America. Build enough LNG terminals and LNG tankers, however, and the North American glut will be relieved by LNG exports to high price markets like Japan. Prices will converge, but because of conversion and transport costs, they won’t completely equaiise.
An interesting tidbit: UN panel shows who’s responsible for CO2 emissions
CURRENT TOTAL EMISSIONS
At the time of the IPCC’s previous climate assessment, in 2007, the U.S. was the world’s top carbon polluter. It has since been overtaken by China, which now accounts for one-quarter of global emissions because of its rapidly expanding economy. The U.S. is No. 2 with 17 percent, followed by India (6.6 percent), Russia (5.1 percent) and Japan (3.7 percent).
___
Ron,
Excepting India, that seems like a list of the five countries (economies) that could afford to seriously effect anti-greenhouse-gas-emission efforts. Oh well.
Doug
Still, BW Hill, as long as your not hyping thanx for that semi heads up.
OTOH, Buffett owns BNSF and Gates owns Canadian Natl Railroad. No way in hell their staff didn’t do their homework.
We hold no interest in the The Duvernay, but some of our clients do. This is through their holdings in Encana, and SynCrude. The advantages of the Duvernay are obvious to the Canadian tar sands producers; $16 billion per year just in transportation savings from US suppliers.
A wide range of well performance is to be expected in the early stages of a shale field’s development. From what we are being told, there will be 13 rigs involved in exploratory drilling by the end of the summer. For holders of US shale interests, it might be a good time to review your portfolio.
http://www.thehillsgroup.org
I’m not sure this is an appropriate forum do be discussing the pros and cons of investment opportunities. The Duvernay plays may, or may not, be of interest to Canadian tar sands producers, however, our discussions focus on PO topics (with digressions into Global Warming matters).
Perhaps it’s enough to be informed of the possibility of the Duvernay Fm. becoming a non-trivial gas-condensate reservoir: which is indeed useful.
Doug
I was planning to put my profits from my Petrobank stock into Encana.
I bought $100,000 of Petrobank stock at $60 per share in early 2008, after reading the following 2007 Oil Drum article, co-written by an “arms length” investor in Petrobank (about the tremendous upside for the “THAI” process):
http://canada.theoildrum.com/node/2907
Unfortunately, I just realized that after a -82%/year return on investment, my $100,000 investment was down to about $700.
Of course, the $100,000 I put into Petrobank stock was all that I had left after I put $750,000 into Pacific Ethanol stock in 2006, based on a recommendation from an Oil Drum blogger.
Greetings, Mr. Leighton,
No disrespect intended, sir, but your comment about the Duvernay “MAY” be of interest to Canadian oil sand producers almost prompted me to bust out laughing. As the cost of producing the kerogen/oil sands is pegged as low as $16/bbl, the ability to be able to transport it economically through pipelines is of paramount concern to the owners/producers of this stuff.
To that end, diluting the oil sands with condensate – the resulting product (termed diluted bitumen, dilbit for short) – can be piped most anywhere at extremely attractive pricing.
BTW, our beaver-loving neighbors up north have a few non-Keystone XL alternatives in the wings. One of the most feasible is to build a $13 billion pipeline to an existing all-weather, deepwater port in New Brunswick. There is a 2,000 mile long pipeline already in place that can be utilized to facilitate this effort.
If the opponents of Keystone XL wanted to prevent development of the dreaded tar sands, they may well find their victory highly counterproductive, to put it mildly.
coffeeguyzz,
You misunderstand my meaning: I mean MAY to counter the idea of using this blog as an investment forum, not the potential importance of “local” gas-condensate sources.
And, there is not the slightest doubt in my mind that pipelines will go east and west and when they do Canada will actually be able to sell its oil for real world prices, for a change. If we (I’m Canadian) are going to develop the tar sands this should be done under our terms not via the existing “free trade” sham. If the world can survive burning all of its tar, oil, gas and coal is another matter entirely.
Doug
As the cost of producing the kerogen/oil sands is pegged as low as $16/bbl,…
Coffeeguyzz, oil sands are not kerogen and kerogen is not oil sands. There is not even the remotest similarity between the two. And kerogen sure as hell cannot be turned into oil for $16 a barrel. Kerogen is not being turned into oil anywhere in the United States or Canada. I seriously doubt that it ever will be. But if it is the cost will be much closer to $200 a barrel than $16 a barrel.
And if you say that the oil sands can be mined and oil produced at $16 a barrel, could you please provide a link that supports such a figure?
Evening, Mr. Patterson. The January 6,2014 posting from the Canadian National Energy Board (www.neb.gc.ca) called 2015 Update Q&A stated that operating costs for extracting bitumen ranged from $6 to $14 per barrel while the supply costs ranged from $14 to $24 per barrel … seemingly incredibly low figures.
While I am aware of the distinctions of the many forms of hydrocarbons, my juxtaposition of kerogen/oil sands was a hasty attempt to differentiate from tight oil … even as we are all aware that bitumen is the soluble portion of kerogen.
Best Regards, Gerard
Hi Gerard. The cost of production per barrel of Canadian oil sands oil depends on who you listen too. From the Canadian “Globe and Mail”:
Crude glut, price plunge put oil sands projects at risk
So-called “in situ” projects, which use wells and underground steam injection to extract oil sands crude, are less vulnerable, with a break even of about $60.
Existing Alberta oil sands projects tend to have solid economics. The first segment of Royal Dutch Shell PLC’s oil sands mine, for example, runs at cash costs in the $30s per barrel. The more recent expansion, however, needs $75 to break even.
As to whether the Canadian oil sands are from kerogen or not, you need to read the entire article linked below. I have posted only the last paragraph. There were two theories as to how the bitumen formed in the oil sands. The “kerogen” theory has largely been discredited. Now it is known that the bitumen began as regular oil, from kerogen of course, but buried miles deep and cooked at “coffee pot” temperatures for a few million years. Then it migrated toward the surface. It met no “cap rock” so it migrated all the way to the surface. The lights were either consumed by bacteria or evaporated.
How are oil sands and heavy oil formed?
Micro-organisms present in the sandstone slowly consumed the hydrocarbons, beginning with the lightest. The heavy oil and bitumen now being produced from the area are the remnants of that migration. They are still the world’s largest known hydrocarbon resource deposit, but scientists believe the amount of crude oil digested by the micro-organisms was two or three times what remains.
The Duvernay plays may, or may not, be of interest to Canadian tar sands producers, however, our discussions focus on PO topics
The Canadian tar sands produces more crude than all the US shale industry combined. The US shale industry is eminently connected to the tar sands because of their need for them as customers. There would be only a fraction of US shale production without the Canadian tar sands.
The world has an abundance of condensate fields, and much of that reserve is from high permeability fields. Arun, in Indonesia, Shtokmanovskyoe in Russia, South Pars in Iran, Cupiagua in Columbia are just some examples. There is so much condensate that its production from any field is only limited by its proximity to a market. To suggest that [i] the Duvernay plays may, or may not, be of interest to Canadian tar sands producers[/i] when many of the players now in the Duvenary are tar sands producers themselves, and diluent is an essential component for their production is an incredible statement. For example PetroChina, one of the principals in the Duvernay, owns and operates the MacKay River bitumen fields. The ongoing production from the tar sands is a much more significant factor in the status of PO than the Bakken will ever be!
As I said above: I employed the word MAY to counter the idea of using this blog as an investment forum. If you want to contribute useful info, great. If you want to hype some company or other — its not appropriate here.
Doug
If you want to hype some company or other
I wasn’t aware that that the Duvenary was a company. Here all along I’ve been thinking it as a geological formation. Silly me. Good thing I’ve got well informed people to set things straight. Next thing I’ll learn is that Ghawar is a pizza joint, API is used to rotate tires, and Darsie units are used in flower shops.
I wonder if condensate mobility is still the ratio of relative permeability to viscosity?????
Darcy is the spelling.
The problem with investor pointed data is it has an agenda.
No question in my mind that most of the guys getting on the Metro in the morning to ride to work at EIA’s offices don’t do that with the intention to lie. But regardless of that, we still get their weekly or monthly updates that are obviously from extrapolations and not models.
Similarly investor stuff probably can’t lie for legal reasons, but they will present data to close the deal because that is their job. So we somewhat don’t like investor pointed data.
Bring us investor pointed data that says misery looms the the investor better stay away from something. That gets much more credible.
errr extrapolations and not data.
Darcy is the spelling.
The problem with investor pointed data is it has an agenda.
“Darsie” is a girls nick name; guess you don’t spend much time in flower shops, and our data (extrapolations) is not investor pointed. We are a consulting engineering, and professional project management association, and we have clients all over the world. We are aware that petroleum is on the back side of the curve, and our interest is in how to best advise our clients on how to prosper/survive in that environment. One can pick up titbits from oil blogs, and on very rare occasions insights. It also helps us understand why so many people, not just bloggers, are basically working with broken models, and so much poor quality, and unverifiable information. Hope that appeases your paranoid mind about our financial complicity.
Now, does anyone here have any ideas as to why, that even with Gulf Coast storage 99% full, crude prices are still advancing upward?
http://www.thehillsgroup.org
I’ll stand corrected, BW. If you don’t have a history from The Oil Drum you don’t realize the kneejerk that is going to occur here from things that sound like hyping.
And yes, I do. The Russians are playing for keeps, and snipers in Libya and Nigeria are not expensive. If I were them, I’d drive the price up, too.
Also, might want to scan through some recent Ronpost comment threads. There is a lot of suspicion about the quality of the oil coming out of shale, and not in the traditional definition of quality. Not about sulphur, or even API.
About constituent components of it. There is some talk of diesel scarcity. In fact, beyond shale, there are quotes like “There is three times more diesel in Libyan oil than in KSA’s.”
BW Hill Wrote:
“Now, does anyone here have any ideas as to why, that even with Gulf Coast storage 99% full, crude prices are still advancing upward?”
Speculative reasons:
1. Last Weeks Jobs report came back positive as the number of new uemployment claims fell back to ~2007 levels. Market Speculators think the economy may be recovering causing a rebound in demand. Note last weeks sell off was contributed to this report because Investors think the Fed is going stop QE and start raising rates.
2. Ukraine Trouble. Russia is an major exporter and US/EU sanctions could lead to retailation by cutting Oil/NatGas Exports to Europe. This would force the EU to find other exporter and result in higher prices.
3. Trouble in Venezuela. Civil disobedence could result in Oil export disruptions. Demonstrations are turning to violence
4. Iran announced its entitled to enrich Uranium to 90% (Weapons grade). Fears this could lead to another gulf war.
http://www.powerlineblog.com/archives/2014/04/iran-claims-right-to-enrich-to-90-plans-new-nuclear-plants.php
Dood. You do realize this is not an investment blog? “We” and “our clients” is always worrisome.
Watcher said:
I’ll stand corrected, BW.
No apology needed. Pushing speculative oil stocks is sort of like selling “shit on a shingle”. Nasty job, but I guess someone has to do it, but it’s certainly not our thing!!
Thanks Tech Guy for your response, I’m sure that a lot of little issues are helping to keep prices elevated. But a lot of what’s at Cushing, and the Gulf Coast has to be condensate, and condensate is only marginally suited for producing transportation fuels. Even after running it through a splitter you only get about a 35% conversion. We’re watching for the point when a shortage of good old light sweet starts to run up finished product prices. I think that could start to happen this year, in spite of the weak economy. But overall the problem with oil is usually not an “if”, but a “when”. There are so many deep pocketed players in the industry, and contracts often so long term that things don’t move when you would expect .
We have clients in the mining, and earth moving businesses, and the 350 gal/day that can run through a D9 didn’t even used to be an issue. Now that has to be taken into consideration. If you are moving 120 feet of overburden, and fuel prices jump 20%, or you can’t get fully supplied, there is one big problem. Whether you look at it from an economic, energy, or reserve point of view oil is becoming a bigger, and bigger factor in any project plan.
http://www.thehillsgroup.org/
Ron,
Meanwhile, back at the ranch.
“A long-awaited UN report on how to curb climate change says the world must rapidly move away from carbon-intensive fuels.”
http://www.bbc.com/news/science-environment-27008352
Doug
The only possibly way of the US to be energy independent is to control all of the earth’s oil fields and pipelines.
If the Bakken and all other formations in ND are producing 880,000 barrels per day, 100 Bakken plays would supply the world with the current demand of 88 million barrels per day.
2000 wells per year would be 60 thousand wells in 30 years.
Times 100 is 3000 years of drilling to complete enough wells to supply current world demand. You would need 4 million people drilling for oil for 30 years straight and then do it 100 times that many to complete 3000 years of well drilling.
1000 Bakken plays would take 300 years to drill and the production would be 880,000,000 barrels of oil per day. lol You would consume 440,000,000 bpd to extract 880,000,000 bpd. 250 million square miles of oil wells. 10,000 miles x 25000 miles of
oil shale formations. More than 1/3 of the earth’s crust in oil wells. They would circle the earth more than they do now.
Everybody would have their own gas station. lol
Pigs would fly.
Enthusiastic CEO’s from oil companies would sell it like it is a piece of cake to prospective investors.
Mrs. Hamm would get half and all of the mineral rights on Mars.
I am thinking about a possible way to apply Hubbert Linearization to US oil production in recent years. This is difficult, because HL requires that the current production to cumulative production ratio tends to fall as cumulative production rises. But the US current to cumulative ratio has been rising.
The US shale boom started to take off in 2008, when the US oil production was a little bit above 150 million barrels per month (approximately 5 million barrels per day). I treat 150 million barrels per month as “normal” production and call the difference between the actual production levels after 2008 and 150 million barrels per month as “excess” production and then conduct a HL analysis over the monthly “excess” production levels. By eliminating the “normal” production levels, the cumulative “excess” production could start from zero. This would allow the cumulative “excess” production to grow more rapidly than the current “excess” production and HL can be applied.
The graph below shows the result of this exercise. The circles show the historical current to cumulative ratios from January 2010 to January 2014. A downward trend started to emerge by 2012. After January 2014, I calculated the current to cumulative ratios based on EIA projections reported in the Short Term Energy Outlook. These are shown as solid black dots. Interestingly, the EIA projection from February 2014 to December 2015 implies a clear downward linear trend in the current to cumulative ratio. The linear trend (with a R-square ratio of 0.981) implies the ultimate cumulative “excess” production to be about 9.9 billion barrels (the cumulative “excess” production from January 2008 to January 2014 had been about 2.2 billion barrels).
For the last six months of 2015, the current to cumulative ratios based on the EIA projection have become more flattened. I applied a HL analysis to the last six months of 2015 only. The linear trend (with a R-square ratio of 0.970) implies the ultimate cumulative “excess” production to be 12.8 billion barrels.
The following graph compares the historical and projected US crude oil production from 2000 to 2025. The projected monthly oil production levels are based on the HL analysis shown in the above graph.
Projection 1 is based on trend 1 shown in the above graph. Under projection 1, US oil production is going to peak in January 2016, with a production level of 285 million barrels (about 9.2 million barrels per day).
Projection 2 is based on trend 2 shown in the above graph. Under projection 2, US oil production is going to peak in November 2016, with a production level of 298 million barrels (about 9.9 million barrels per day).
My (limited) understanding of Hubbert linearization relates to the use of a differential equation to make predictions about the peak production from CONVENTIONAL OIL reservoirs. US shale oil involves different hydraulics, dissimilar time-decay parameters, and distinctive geology (in other words, completely different dynamics).
Dennis Coyne solves this problem by using an empirical approach, which to my mind is valid — to a degree. I don’t have much confidence in his conclusions, given the host of variables outside his ken, but you know what he’s doing, why, and the limitations. Fair enough.
You appear to be applying Hubbert’s (and others) equations to a situation different from those for which they were developed. OK, I can live with that: if you can show reasons why you think this is valid. Of course you can’t be expected to plaster Ron’s Blog with pages of mathematical analysis but it is incumbent on you, in my opinion, to provide references to applicable science. If you’re just doing simple curve fitting exercises it is best to say so. And frankly, your conclusions totally confuse me.
Doug
Doug, you may choose to like my post or you may choose not.
Hubbert linearization was of course first proposed by Hubbert. But I am not aware that its application is limited to conventional oil ONLY. Certainly it has been used and can be used for the analysis of natural gas, coal, iron ore, copper, phosphate or any other resource that has a limited base.
As unconventional as shale oil is, I believe it is still a nonrenewable resource.
Like any other method, Hubbert Linearization certainly has its limitations. That has been said, I hope it offends no one by just showing what the currently available data indicate.
I was only asking for your scientific rationale, is there something amiss in that? Since I’ve never seen Hubbert Linearization applied beyond conventional oil reserve analysis it seems like a fair question, to me!
Doug
Doug, I like fair questions.
You may know that Jean Laherrere uses HL for oil, natural gas, as well as coal: http://www.esf.edu/Laherrere/cForecast.html
Others have used it for various mineral products. For pros and cons of HL, I would recommend the Royal Society paper by Steve Sorrell, “Using growth curves to forecast regional resource recovery.”
Shale oil, just like conventional oil, is a nonrenewable resource and will peak at some point. As it approaches the peak, its current production to cumulative production ratio will tend to fall. This is a mathmatical certainty and does not require any additional “scientific rationale”. Thus, by identifying the trend of falling current to cumulative production ratios, we can begin to accumulate information on when the production level is likely to peak.
HL helps to tell if the existing trend of current to cumulative production ratios continues, what will happen in the future. It does no more and no less and I am not claiming anything beyond it.
More precisely, if you look at the above two graphs more carefully, it’s not quite about the existing trend. To be precise, the above two graphs would help to tell if the trend PROJECTED BY EIA for Feb 2014 to Dece 2015 continues, what should happen in the future.
30/1/2014
Jean Laherrere uses Hubbert linearization to estimate Bakken shale oil peak in 2014
http://crudeoilpeak.info/jean-laherrere-uses-hubbert-linearization-to-estimate-bakken-shale-oil-peak-in-2014
HL may prove to be useful in considering tight oil production curves just as it has in projecting the production and peak of other mineral resources.
I have not extensively researched Hubberts work but I believe he intended it to be considered only as a tool to be used for conventional oil.
But if you want to get good results with it applying it to tight and or other unconventional oil you need to ignore the production and peak of conventional oil which is essentially a different animal-another animal altogether.
Mixing the data together is no good. That is like mixing apples and oranges. It is ok if you want to count pieces of fruit but if you want to know how many of each they must be separated.
What I am trying to say is that although unconventional oil is still oil it is so different in respect to actually producing it that it should be considered as a stand alone mineral.
That’s why I am looking at the “excess” production (the part of US oil production that is above the “normal” production in 2008) as a proxy for new production from shale oil.
Something else interesting is that according to what the NDIC has told the North Dakota legislature, assuming an oil price of $86.02/bbl, the average Bakken-Three Forks well “pays out” at 170,000 bbl of oil, or about 12 months of production. I’m basing that on slide 17 of the presentation here. Well, if the 170,000 bbl in 12 months calculation is correct, then most of the wells completed before 2013 should have reached that point by now and “payed out” as long as the actual prices were similar to the assumptions. Nevertheless, looking through the cumulative oil production totals per well shows that
104 Bakken-Three Forks wells completed in 2007
256 Bakken-Three Forks wells completed in 2008
282 Bakken-Three Forks wells completed in 2009
424 Bakken-Three Forks wells completed in 2010
845 Bakken-Three Forks wells completed in 2011
1,522 Bakken-Three Forks wells completed in 2012
have produced less than 170,000 bbl of oil through February 2014 and thus may or may not have reached “pay out.”
The cumulative oil production information in the NDIC database just keeps getting more and more interesting the more investigating I do.
Ya, I looked at that some time ago and I stepped back from it because IT IS NOT PIPELINED. Transport is not cheap. Expenses aren’t done after fracking is done. The trucks keep rolling. And if the price of oil goes up, so does the price of diesel.
Though there is a lot of work being done on getting more of the best wells in the Bakken connected to a pipeline for gathering purposes rather than having to rely on trucks. The latest estimates showed 44% of all wells in North Dakota using pipeline for gathering versus 56% using trucks. Now the number of trucks gathering oil has continued to increase since overall production has also increased, but the percentage of wells using pipelines for gathering has also been steadily inching up as each year more pipeline has been installed.
There is a lot of good data in the presentation at http://ndpipelines.files.wordpress.com/2012/04/ndpa-slides-april-1-20141.pdf. Attached below is one of the more pertinent slides.
It was my understanding the added pipes are mostly to create nodes. The trucks are to have shorter trips to nodes, but not fewer of them. The pickup at the well is still on wheels.
These wells are essentially dead in 2-3 years. They flow water. They flow NGL. They have to be serviced somewhat for separation and I suspect this is not automated. Why build a pipe to each well? OTOH, maybe that’s what CLR’s choking down output is to be about. Extend life at a lower level, justify pipelines and fire truckers.
Another item. I got $5 says the guys who threw together shale EROEI estimates did not have any idea 1 million pounds of water and 3+ million pounds of proppant (often shipped from China) was being trucked out in 2000 trips for every single well.
Did you look at the presentation? There certainly are individual wells connected to a gathering pipeline. That much is also apparent from the “scars” of pipeline laying that connect some well pads to one another in Google Earth or other photos on the internet.
Some of the crude-by-rail terminals obtain their oil primarily or even exclusively by pipelines connected to individual well pads. The EOG terminal was mentioned in prior comments. Not only did EOG build a crude-by-rail terminal close to where most of their wells are, they also connected the terminal to those wells with pipe. Enbridge also owns a rail terminal in the Bakken, and Plains All American owns two. These are both pipeline companies. You better believe they have pushed to have oil delivered to their terminals via pipe. In Enbridge’s case, I believe they have been successful in having their crude-by-rail terminal obtain all oil via pipeline. Although in that case, another compelling reason to have this configuration is that the terminal is in Berthold, well outside of the mature portion of the Bakken (I assume there was cheaper land available there, not to mention an Enbridge pipeline to Minnesota already went through the area). To deliver crude to this terminal via truck, one would generally be looking at at least a 40 mile one-way trip from any of the wells. Delivering the oil by pipe had to be the more sensible option.
I did.
Have a look at this:
https://www.youtube.com/watch?v=Tfnb7oof2Rw
I didn’t say that all the rail terminals obtain their oil partially or fully by pipeline.
Something worth noting is the Bakken Oil Express (BOE) facility in the video is the largest crude-by-rail terminal in the Bakken. Currently 200,000 bpd can be exported from there, which is over twice the capacity of all but one other rail facility. The next largest terminal is the 120,000 bpd Crestwood facility in Epping (side note: the Epping facility has had a revolving door of owners in just the couple years or so since being built; there are probably several good storylines there regarding the financial aspects of this boom).
Anyway, work is being done to eliminate the line of trucks at the BOE facility, or, probably more appropriately, shift the problem closer to where the majority of the wells are (BOE is located in Dickinson in the southern periphery of the Bakken). Earlier this year, a 165,000 bpd pipeline was approved to run from a truck unloading facility in Killdeer to the rail terminal, about 40 miles away (see http://www.psc.nd.gov/docs/newsroom/1-3-bakken-oil-express-pipeline-permit.pdf). At capacity, that is equivalent to several hundred truckloads.
Also as bad as the line of trucks in the video was, things could have been worse as that facility has been gathering oil from the Four Bears Pipeline since 2012. That pipeline has 105,000 bpd of capacity, but is connected to both the rail terminal and the larger Butte Pipeline in Baker, Montana.
It’s possible we’re not in any disagreement. I looked at the data and it laid out the piecharts, showing that the majority in major counties are sending oil by truck to . . .something.
My understanding was, from a similar briefing by a pipeline guy last year, that the goal was to shorten truck trips. Add nodes where they can offload to a pipeline which sends the oil to a railhead, or a Williston Basin exiting much larger pipeline.
But my semi focus is the traffic jam at a well being drilled, and then after it’s, drilled for the first year of operation. As noted Waaaaaay above, first year wells seem to be 50% of production. If you’re laying pipelines to collect oil from wells in the 3rd year, that won’t be much oil.
The briefing from last year did say pipelines are going in, but as the presentation you displayed shows, there is no reduction in truck trips. Ya, it’s because wells are drilled, but it’s the first year that matters so . . . it sort of makes my point?
I have no disagreement with any of this comment. I would just point out, though, that the well pads that have been connected to local pipelines have had that done with the expectation that with infill drilling, the well pad will eventually have 8, 14, 16, or what have you, active wells. So while the first well on that pad may have needed production to be trucked away in the first year or two, subsequent wells may not. Pipeline capacities will play a role here, but with the decline rates being what they are, on the whole I imagine within a relatively short time all production on a pad with multiple wells will fit into a local pipeline.
The people bankrolling the infrastructure aren’t seeing a problem with this, but then they are anticipating the Harold Hamms of the world are correct and the wells will last for 40+ years and produce 600,000+ BOE.