[phaster]

Jan Arps is the most influential oilman you’ve never heard of.

In 1945, Arps, then a 33-year-old petroleum engineer for British-American Oil Producing Co., published a formula to predict how much crude a well will produce and when it will run dry. The Arps method has become one of the most widely used measures in the industry. Companies rely on it to predict the profitability of drilling, secure loans and report reserves to regulators. When Representative Ed Royce, a California Republican, said at a March 26 hearing in Washington that the U.S. should start exporting its oil to undermine Russian influence, his forecast of “increasing U.S. energy production” can be traced back to Arps.

The problem is the Arps equation has been twisted to apply to shale technology, which didn’t exist when Arps died in 1976. John Lee, a University of Houston engineering professor and an authority on estimating reserves, said billions of barrels of untapped shale oil in the U.S. are counted by companies relying on limited drilling history and tweaks to Arps’s formula that exaggerate future production. That casts doubt on how close the U.S. will get to energy independence, a goal that’s nearer than at any time since 1985, according to data from the U.S. Energy Information Administration.

“Things could turn out more pessimistic than people project,” said Lee. “The long-term production of some of those oil-rich wells may be overstated.”

Calculate Reserves

Lee’s criticisms have opened a rift in the industry about how to measure the stores of crude trapped within rock formations thousands of feet below the earth’s surface. In a newsletter published this year by Houston-based Ryder Scott Co., which helps drillers calculate reserves, Lee called for an industry conference to address what he said are inconsistent approaches. The Arps method is particularly open to abuse, he said.

U.S. oil production has increased 40 percent since the end of 2011 as drillers target layers of oil-bearing rock such as the Bakken shale in North Dakota, the Eagle Ford in Texas, and the Mississippi Lime in Kansas and Oklahoma, according to the EIA. The U.S. is on track to become the world’s largest oil producer by next year, according to the Paris-based International Energy Agency. A report from London-based consultants Wood Mackenzie said that by 2020 the Bakken’s output alone will be 1.7 million barrels a day, from 1.1 million now.

U.S. crude benchmark West Texas Intermediate fell 41 cents to $99.21 a barrel at 10:10 a.m London time in electronic trading on the New York Mercantile Exchange. It has risen 0.8 percent this year.

Inherently Uncertain

Predicting the future is an inherently uncertain business, and Arps’s method works as well as any other, said Scott Wilson, a senior vice president in Ryder Scott’s Denver office.

“No one method does it right every time,” Wilson said. “Arps is just a tool. If you blame Arps because a forecast turns out to be wrong, that’s like blaming the gun for shooting somebody. As far as Arps being old, the wheel was invented a long time ago too but it still comes in handy.”

Rising reserve estimates gives the U.S. a false sense of security, said Tad Patzek, chairman of the Department of Petroleum and Geosystems Engineering at the University of Texas at Austin.

“We have deceived ourselves into thinking that since we have an infinite resource, we don’t need to worry,” Patzek said. “We are stumbling like blind people into a future which is not as pretty as we think.”

The Arps formula is only as good as the assumptions a company puts into it, Patzek said. Estimates can be inflated when Arps is based on limited drilling history for data or on a few high-performing wells to predict performance across a wide swath of acreage. Forecasts can also be skewed higher by assuming slower production declines than Arps observed.

Reserves Cut

In November 2012, SandRidge Energy Inc. cut its reserve predictions to the equivalent of 422,000 barrels per well from 456,000. Five months later, the estimate was cut again, to 369,000 barrels, company records show. Oklahoma City-based SandRidge has since made an adjustment upward to 380,000 barrels per well.

The early, more optimistic forecasts were based on a small number of high-performing wells, which led the company to overestimate performance for its other acreage, said Duane Grubert, SandRidge’s executive vice president for investor relations and strategy. The company now has more than 1,100 wells and has improved its drilling. It is confident that current estimates are reliable, Grubert said.

“Nobody knew that until we actually ground-truthed the field by drilling it,” Grubert said. “What we came up was, hmm, that initial estimate was a little high.”

Future Production

SM Energy Co., a Denver-based producer, suffered a similar setback this year when its wells in the Eagle Ford shale in Texas fell short of forecasts. The company on Feb. 18 cut its prediction in one area to the equivalent of 475,000 barrels per well from 602,000. Estimating future production from early data is a challenge for the industry, said Brent Collins, a spokesman for SM Energy.

“This is especially true when you are trying to estimate an average from a limited number of wells,” Collins said.

Both SandRidge and SM Energy use variations of the Arps method, company records show.

Tapping shale formations differs from the drilling in Arps’ day, said Dean Rietz, an executive vice president in charge of reservoir simulation at Ryder Scott. The first commercial shale well was drilled in 2004, 59 years after Arps published his method.

Gas Pockets

In 1945, oil production meant drilling straight down to hit pockets of oil and gas that had become trapped after migrating upward from deep layers of rock. Today’s drilling targets those deep layers, boring through thousands of feet of the earth’s crust, then turning sideways to chew for a mile or more through layers that are harder and less porous than a granite countertop. The rock is shattered by a high-pressure jet of water, sand, and chemicals to create a network of small cracks to allow the oil and gas to escape. The largest fissures are narrower than the width of a paper clip. The smallest are thousands of times thinner than a human hair.

On a graph, these fractured wells appear to follow a different trajectory of decline than the conventional wells Arps studied, said Lee.

To replace the Arps calculation, researchers are testing new formulas with names worthy of indie bands: Stretched Exponential, which Lee helped develop; the Duong Method, devised by Anh Duong, principal reservoir engineer for ConocoPhillips; and Simple Scaling Theory, which the University of Texas’s Patzek worked on.

Rietz has made a well simulation model to predict production.

“Come back to me in 10 years, and I’ll tell you how reliable it was,” he said.

http://www.bloomberg.com/news/2014-04-03/old-math-casts-doubt-on-accuracy-of-oil-reserve-estimates.html

[phaster]

I am not going to read all that sh@#t without some analysis, comment, interpretation. What is Arps' point? What is it I am supposed to take away from the document? Is it that "Predicting the future is an inherently uncertain business"? No. Is it that "Rising reserve estimates gives the U.S. a false sense of security"? No. Is it that "company's overestimate performance to other acreage"? Perhaps.

I do believe this is the point: “Come back to me in 10 years, and I’ll tell you how reliable it was,” he said. You mean nobody knows what they are talking about? Yikes.

just thought I'd post the bloomberg article (and link w/ discussion) because it mentions a "model" I had not heard of before and thought it showed some insight how an "oil" company looked at the issue of oil reserves

[Pops]

An interesting article but to readers here I think not much of a surprise.

One thing I credit Magueri for, and that is opening my eyes to the fact that each tight well is a world all to itself and it extends only as far as the bore and longest fracture. It isn't a reservoir or "pool" of oil in a porous rock that trapped oil migrating from a source elsewhere. It's oil stuck in the source rock where it was formed because the rock is so tight it can't move.

A conventional reservoir is sorta like drinking a soda with 2 straws, the more you pump the more sugar you get; but a tight oil district is like eating a pie, it's only good in the middle, and you only get as much sugar as you can slice off.

So everyone got (gets) the wrong idea that there is big pool of oil down there that will go on giving like the elephants of old, just stick in a few straws and sit back watch the money roll in for the next 50-60 years. I'd guess that's also one of the reasons production has shot up faster than ever: there is no reason to limit production for fear of bypassing or leaving behind any of the oil, each "pool" is only as big as the extent of the frack so it's one and done and on to the next.

As usual I'm no expert so stand to be corrected.

[ROCKMAN]

Pops- One of the best descriptions of the distinction between conventional/unconventional reservoirs we've seen here IMHO. Bravo amigo!

And for the love of Dog, folks, let's understand what JJ was all about. His type of analysis is applied to a single well with a significant production history in the can: "J.J. Arps was an American geologist who published a mathematical relationship for the rate at which oil production from a single well declines over time. His paper made several references to existing methods and theory about decline analysis. This type of analysis has no value in predicting future production from any trend...just the future production from wells already drilled. And his formula works very poorly when it comes to fractured reservoirs given the complexity of the decline function. Which is why companies were using "curve fitting" to estimate URR. Another great advantage of curve fitting besides being butt simple: very easy to induce prejudice to create optimistic predictions. Sort of like judging the beauty of a piece of art: it's much in the eye of the beholder.

Notice: "...oil production from a single well...". I know that may sound simplistic and obvious today but he was tossing out this idea ALMOST 70 YEARS AGO. The science of reservoir engineering was just developing. Heck...it was only about 15 years earlier that oil companies began using geologists to hunt for oil.

[Tanada]

Over years of discussions I was initially shocked to discover most people think oil in the ground is in caves or pools that the experts drill into, like the lava chamber under a volcano or Carlsbad Caverns in New Mexico. I once thought the name of the rock would tell you how well it produced oil, Sandstone/Shale/Limestone/Coral Reef. I understood for the last couple decades that the oil is actually in rock that behaves like a sponge in conventional reservoirs but never even heard of the term Darcy and Milli-Darcy until I read Twilight in the Desert back around 2005 when it was recommended on here. I learned then that two sandstones will have different recovery rates depending on the geological processes they went through before the present. To make matters even more confusing you can produce oil from Conventional Reservoir rock by fracking to make those formations easier to produce, but the really tight formations like those under North Dakota and Eastern Ohio produce very little flow unless you frack them.

With all the dozens of confounding factors it is no wonder you need to be an expert petroleum geologist like Rockdoc123 and ROCKMAN and a few others who grace us with their knowledge and not a reporter, politician, or Joe6pack. Economists spend all their time thinking about money and how it flows and they claim a lot of things I think are made up on the spot, but money is an abstract representation of value. Petroleum is a real commodity that comes from real extraction and requires esoteric knowledge that the very large majority of end users do not understand much if at all. Most people never think about where their fuel comes from and how it is produced and processed. Those of us on here, lurkers and all, are a tiny slice of the world population.

[ROCKMAN]

T – And that leads me to explain the trick developed by the predecessors of me, rocdoc et al…folks who we owe much of our careers to. Geology is rightfully described as a “descriptive science” as opposed to the classic sciences. So to cut down on the word count we make up names for all the things and processes we see in nature. I can uses dozens of words to describe what a thalweg is. But I’ll write a report that explains how critical it is to locate the exact center of the thalweg to finalize a drilling location.

And here’s the genius part: you, Mr. Manager, have no freaking idea of what a thalweg is. So guess what: you have to pay a geologist to explain it. And then pay another one to explain the “turbidite” component of a DW GOM oil field. Etc, etc. That’s why we made up many thousands of code words to explain geology: you gotta pay us to translate the code to understand what the hell we’re talking about. Pure genius IMHO. LOL.

[westexas]

Pops,

A good example of what you are talking about is the East Texas Field. I think it's a reasonable assumption that the wells on the Eastern (structurally highest) side of the field were capable of producing, in the 1970's, virtually the same amount of oil that they could make in the 1930's. Of course, the RRC only allowed operators to produce their allowable, under the East Texas Field Rules, once the RRC was finally able to implement proration. (Of course, the wells on the Western, structurally lowest, side of the field watered out quickly.)

Contrast that with high decline rate tight/shale plays. My assumption is that at least 90% of the currently producing shale oil wells will be down to about 10 bpd or less, or will be plugged and abandoned, 10 years hence (some tight plays, like the "Wolfberry Play," might have somewhat better 10 year production levels).

Note that the gross underlying decline rate would be the rate of change in production if no new oil wells were put on line in the US from 2013 to 2014.

And if we assume a conservative* gross overall underlying decline rate from existing US Crude + Condensate (C+C) production of about 10%/year (which will almost certainly be increasing), then in order to maintain current US C+C production for 10 years, the industry would have to replace the productive equivalent of 100% of current US C+C production over the next 10 years.

*Note that Alaska has shown a net C+C decline rate of 6.5%/year from 2005 to 2013. This is net, after new wells were added. The gross underlying decline rate would be even higher, and this is for conventional crude oil production:

http://www.eia.gov/dnav/pet/hist/LeafHa ... RFPAK2&f=A

In round numbers, Alaskan C+C production dropped by 75% in 25 years, from 2.0 mbpd in 1988 to 0.5 mbpd in 2013 (a 25 year net annual decline rate of 5.5%/year). Of course, this primarily reflects the peak of production in the Prudhoe Bay Field, but the bottom line is that the industry would have needed to put on line another 1.5 mbpd of new production over the last 25 years, to maintain stable output from Alaska, or they would have needed to put on line the productive equivalent of 75% of the peak 1988 production level, in order to maintain flat production for 25 years. And this is with a much lower gross underlying decline rate than what we see in tight/shale plays.

[westexas]

On the natural gas side, according to the EIA, the observed simple percentage decline in Louisiana’s annual natural gas production from 2012 to 2013 was 20% (marketed production). This would be the net change in production, after new wells were added. The gross decline rate (from existing wells in 2012) would be even higher.

In my opinion, this 20% year over year net decline* in Louisiana’s natural gas production is massive confirmation that the Citi Research estimate of an overall gross underlying decline rate of 24%/year in US existing natural gas production is probably right on the money.

Based on the Citi estimate, all we have to do to maintain a dry (processed) gas production rate of 66 BCF/day for 10 years is to put on line the productive equivalent of all of the 2012 dry natural gas production from the Middle East--times three.

*Exponential decline rate was 22%/year from 2012 to 2013

[dcoyne78]

Hi all,

The questions about LTO (or shale oil) and whether Arps hyperbolics can be applied to estimate the future output from a multi stage fracked horizontal well makes me wonder how accurately the Bakken and Eagle Ford operators can be with their estimates of proved reserves.

For example from 2007 to 2012, the EIA reports that the proved reserves in North Dakota increased by about 3.2 Gb, most of which is likely to be Bakken reserves.

Should we believe these figures? I would love to hear Rockman's and/or Rocdoc's take on this. Thanks.

[ROCKMAN]

dc - After doing reserve analysis over the last 40 years there's only two ways to estimate ultimate recovery from any well. A) water drive reservoirs: accurately map the extent of the reservoir and then make accurate estimates of a myriad of factors. And B) For pressure depletion reservoirs (both conventional and unconventional like the shakes): plot the pressure decline curve on a log/normal grid. Take a straight edge, lay it on that line and intersect your assumed abandonment pressure and TA DA!...read the URR on the ordinate. Easy peazy. Except you need a considerable production period to make an accurate prediction. Which is exactly what you don't have for the first 2 to 3 years with a fractured reservoir. So what did companies do? Created the infamous "curve fitting" method: take the little bit of early production curve they have and try to match it to one of a wide series of theoretical curves. This is a very subjective methodology and very easy to apply a very negative/positive bias. Which is exactly why it's difficult to argue either way with anyone's answer: no math involved...all in the ye of the beholder.

But the good news: after 4 or 5 years it's easy to estimate the URR of a shale well. And that's because it has produced a significant percentage of it's URR at that point. Even better news: however inaccurate the prediction might be at that point in time it isn't very important because the production rate has declined so much it doesn't matter if the well is going to average 20 bopd or 40 bopd for the next few years because what's always important in a PO world is rate...not ultimate productive volume. Regardless whether a shale well recovers 150,000 bo or 450,000 bo after several years both wells will be producing an insignificant rate of oil. Which is why that company constantly reduced their URR estimate: difficult to fudge the curve fitting after a few years.

[dcoyne78]

Hi Rockman,

I don't know much, but I do realize that for the Bakken there is limited data, since 2008 about 7400 wells gave been drilled in the North Dakota(ND) Bakken.

Enno Peters (who posts over at Peak Oil Barrel) has pulled together the individual well data from the NDIC. If I average together all the wells with 12 months or more data I can create an average well profile that stretches out to 6 years (with fewer wells included as time increases (more wells at 12 months, fewer at 24 months, etc) if I plot natural log of output vs time I get a nice straight line with a URR (assuming exponential decline from year 7 forward) of about 300 kb at 22 years (output about 7 b/d at that point and I assume the well is adandoned). Most of the operators in the Bakken claim a typical well has an EUR of 500 kb.

The question is, would these companies book proved reserves in their annual reports based on the 500 kb per well number that is in their investor presentations or would they be more likely to use the more conservative approach which would suggest 300 kb, or possibly 350 kb (if they use a hyperbolic with a b of 1 or less).

Some have claimed that the EIA proved reserves are grossly exaggerated, I was always under the impression that proved reserves were pretty conservative.

Do you think the EIA's reported proved reserves for North Dakota in Dec 2012 of 3.8 Gb is too high? Should it be discounted by 60% (300 kb/500kb)? Just looking for an expert opinion. Thanks.

Also are proved plus probable reserves usually about 33% higher than proved reserves (as a rough rule of thumb.)?

Chart for Bakken log well profile attached

[ROCKMAN]

dc - "...would these companies book proved reserves in their annual reports based on the 500 kb per well number that is in their investor presentations or would they be more likely to use the more conservative approach which would suggest 300 kb...". In the last 40 years when there was a legitimate range of reserve estimates not once have I seen a pubco book the conservative number. But here’s the hook: as more data (future production) of wells previously book companies are required to update their reserve estimate. But the required timing of such updates is rather vague.

But this is also why you see companies drilling new wells as fast as possible: those new bigger “optimistic” reserve numbers tend to mask the effect of lower revised numbers for previous wells. As I said earlier after 4 or 5 years of production it’s very difficult for a pubco to book overly optimistic numbers for those wells: too much data. The curve fitting approached I mentioned is applied in the very early days of production. Your approach to look at the curve X years out will be much more valid.
Which also explains why if a company drills a well that doesn’t have impressive initial production and then won’t drill immediate offsets: because if they do and the original well is eventually downgraded those offset reserves will be downgraded also. Over the years I’ve seen many projects that were delayed because the booked reserves prior to development were higher then what a company expected the actual production to prove. Essentially boils down to lying by omission. Much more difficult for the SEC to get on your ass in such matters.

[dcoyne78]

Hi Rockman,

So reading between the lines, you do not think the proved reserve numbers are believable and would discount them by 60 %. Or maybe split the difference and take 70% of the proved reserves?

[ROCKMAN]

Not to duck the question but when someone presents me with a proven reserve number on just a single well I don't accept it. I'll look at all the data available and first decide it there's enough info there to justify the effort. Often I've seen situations where the unknowns prevent a reasonable estimation of "proved" reserves. If there's sufficient data I'll make an estimate of proved reserves but even then there will be some risk factors noted.

And now you ask my confidence level in someone's "proven reserves" of thousands or even tens of thousands of well when they don't provide details of the analysis of even one of those wells. In my world to be given the tag of "proved" demands a great deal of support. Obviously none of the estimated numbers tossed out are based on such rigorous analysis of the individual wells. But it is easy to make generalizations about entire trends because no one else has all the details to refute such generalizations. So no: from my perspective none of those numbers represent "proved reserves". They might represent reasonable estimates of recoverable reserves but that doesn't rate them the title of proven to me. "Proven" in my world is a very demanding hurdle to clear. But making estimates? I say everyone should have at. Eventually someone's estimate will be shown correct even though it might fall into the category of a blind pig finding an acorn. LOL. Eventually when someone wins the lottery it doesn't mean they were smarter then the many millions of folks who also bought tickets that week.

[dcoyne78]

Hi Rockman,

I may not be being very clear. The EIA gives the proved reserves for the US and each state for each year end. So these "estimates are likely to be the totals reported in 10k reports for companies operating in the US, I would think they are pretty good, if some company reports 500 MMb of reserves in an annual report, would you suspect that the reserves are likely to be much less than this (say 300 MMb).

At the link below is the EIA proved reserve data for North Dakota.

http://www.eia.gov/dnav/pet/pet_crd_pres_dcu_SND_a.htm

The question is should we believe these numbers? If not, would taking say 80% of these numbers be safe or possibly treating them as 2P reserves (essentially discounting them by 25%).

It kind of sounds like you are very reluctant to call anything a proved reserve until its out of the ground and in the pipeline

[ROCKMAN]

dc - I've worked on numerous corporate acquisitions in my career and, to be crudely blunt, didn't give a sh*t what their 10k's said. In fact, never bothered to look at those numbers. I evaluated each well in detail. That was the basis of the negotiations. Likewise I've created 10k numbers using independent consultant companies, did my job and created reserves some of which had little chance of being produced and yet I got reputable third parties to sign off on my numbers. Which is why I did divestatures no one that evaluated my company gave a sh*t what our 10k said. I was very good at what I did and made good bonuses. And there were lots of hands who were better than me. LOL.

But let's cut to the chase: how important is the accuracy of those numbers to you? Have you noticed I seldom get drawn into those debates? They really don't represent an important metric to me. First, what we all know: how much oil is eventually recovered from the X trend has no bearing on how much oil will be produced on any future date. Consider just a single EFS well. "They" estimate is 400k bo. Fine...so how much oil will the well produce yearly throughout it's life? How much oil will that particular well produce on the 1,000th day after it begins producing? What...you can't answer? Why not...I just told you it would recover 400k bo. LOL.

So if you can't give the answer for just that one existing well how could you do it for a well yet drilled? So if you can't do it for neither the existing well nor one not drilled yet how could you or anyone else do it for the thousands of existing wells and the thousands yet drilled? And the point we all understand already: the Peak Oil Dynamic is first about the oil production rate and second about the price of oil. So the real question is how much oil will be produced on 1 January, 20XX from all the "proven" reserves we have now? And no one can even begin to make such a prediction accurately unless they can accurately predict the price of oil every day between now and 1 January, 20XX.

So what difference does it make if, at a constant assumed price, whether there's X billion bbls of proven oil reserves in the world? Or 2X billion bbls of proven oil? Or 0.5X bbls of proven oil? That prediction has little relevance to anyone. What folks want to know is what they'll have to pay for oil in the future. And even that projection isn't solely dependent on the production rate. Regardless of how much we're capable of producing, it will be of little concern to those who can't afford the price. Just as it is for so many economies today. IOW how happy are Americans because we're producing so much more oil today while they are paying 3X as much as they were 10 years ago? Or to put it on a personal level: would you rather be paying $1.90/gallon for gasoline as you were when we were producing 5 million bopd or paying $3.60/gallon when we're producing 8 million bopd? Remember we have much more proven oil reserves today then when we were paying less for fuel. Are you happy now? LOL.

So on that long winded basis why would I bother to debate the validity of anyone's reserve estimate? And it might sound odd but ExxonMobil doesn't care how much proven oil remains on the planet either. They care greatly how much proven reserves they own and how much proven reserves they'll be able to develop in the future. And neither of those two metrics depends on the global reserve base.

[dcoyne78]

Hi Rockman,

There is a pretty simple answer. Sanity check. All of these are estimates, none will be accurate to the barrel, nor could we forecast the price of oil to the nearest dollar next week.

We can make reasonable future forecasts at some future expected price level (or range of prices, because this is probably the hardest number to predict).

You seem to have a problem with precision, at least in the blog world.

So if someone is going to take the EIA's Annual Energy Outlook reference oil prices and attempt to give a rough idea of the rate of production over the next 30 years, they need some idea of reserves, if 1200 Gb have been produced and there are another 1000 Gb of proved plus probable reserves, but my forecast suggests 2000 Gb will be produced over the next 30 years, then either another 1000 Gb will be discovered (including reserve growth) or my forecast is wrong. This is why it matters.

We cannot produce oil that we cannot "find", where found means it is both technically recoverable and profitable at future oil prices.

You have often said that oil companies care very much about reserves. Within an oil company they probably have a pretty good estimate of their reserves (the best estimate would be their proved plus probable.) To find the World total we would just add up all the companies 2P reserves. This is impossible world wide, but within the US for public oil companies it would be possible.

It would be interesting to get Rocdoc's perspective on this.

Let's try this. North Dakota in 2012 reported about 3.8 Gb of proved reserves at the end of 2012, and based on NDIC data about 2.3 Gb of oil was produced from 1951 to Dec 2012 in North Dakota. The sum of these two is about 6.3 Gb. If the yearly average price of oil remains over $95/barrel in 2013$ for the next 20 years and you were a betting man, would you bet that the cumulative production of oil in North Dakota would be over or under 6.3 Gb by Dec 2043?

Why does this matter? Sanity check for future forecasts from now to 2040 for the North Dakota Bakken/Three Forks. Jean Laherrere thinks the URR of the North Dakota Bakken will be between 2.5 and 4 Gb, I think the 2P reserves plus oil produced in the Bakken was at least 3.7 Gb at the end of 2012, so a 4 Gb estimate implies no more than 0.3 Gb will be added to North Dakota's 2P reserves in the future.

A second bet would be assuming the average annual oil price in 2013$ remains above $90 for 10 years (until August 2024) would you expect North Dakota's added reserves to be over or under 0.3 Gb over the next 10 years?

I think 2 Gb is a pretty safe bet for added reserves over the next 10 years if annual average oil prices remain over $80/barrel in 2013$.

[ROCKMAN]

dc - "If the yearly average price of oil remains over $95/barrel in 2013$ for the next 20 years and you were a betting man, would you bet that the cumulative production of oil in North Dakota would be over or under 6.3 Gb by Dec 2043?

I'll match your question with two more that would aid my answer: First, about 10 years ago what did the IEA forecast the oil price in 2014? So do expect their current forecast to be as accurate as the one they made 10 years ago? Second question: if in fact oil prices stay at $95/bbl how many more Balkan locations are there to drill? After all, if there aren't enough locations to drill until 2040 those reserves won't be developed. Which gets back to the implant I've expressed before...the assumptions: first the oil price and second the recovery per well. But let's assume both numbers are correct. So now calculate how many wells need to be drilled. Now put a pin on the map showing where each one of those wells will be drilled. So...do you run out of map before you use all the pins. As simplistic as it sounds it's still true: it doesn't matter what price and recovery numbers are predicted. If there aren't enough locations to drill then the reserves won't be realized.

And once you've proved how many actual locations might be drilled you need to develop a drilling time line. With that you can estimate the daily production for the Bakken every day until 2040. And after all that's what will have an effect on the POD...not the URR from the Bakken or any other trend.

I'm not asking for extreme accuracy in those predictions. Just show me why I should expect better accuracy then predictions made just 10 years ago. After all the current predictions carry forward 26 years. I'll settle for being just 50% accurate. But we need to see the proof now...many of us won't be here in 26 years. LOL.

[Pops]

So do expect their current forecast to be as accurate as the one they made 10 years ago?

Ya know, I think there must have been a change in the way EIA makes estimates since they are now forecasting a peak/plateau in LTO in 2016 or thereabouts. If you can take Kopits word the future of production is no longer driven by demand but by supply as the constraint is on that side now.