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Page added on April 3, 2014
Old Math Casts Doubt on Accuracy of Oil Reserve Estimates
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. (SD) 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. (SM), 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.
30 Comments on "Old Math Casts Doubt on Accuracy of Oil Reserve Estimates"
Davy, Hermann, MO on Thu, 3rd Apr 2014 11:10 am
ARTICLE SAID – Rising reserve estimates gives the U.S. a false sense of security. “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 pathological parasitic lobby of plenty and technological exuberance folks on Wall Street have jumped in bed with a Gold Rush mentality in the oil and gas fields in the US. A gold rush that is barely a drop in the bucket in relation to worldwide production. It just so happens to be significant now because of conventional depletion rates globally. The hang over from the party is being felt but the partiers are doing what hardcore partiers do start drinking the next day right after lunch. They do this by maintaining the propaganda all is well and the future is plenty. We were damn lucky as a country these energy producers came up with this production. We were damn lucky as a country our infrastructure and industry was in place for a huge ramp up. “BUT” Please in this situation don’t exaggerate something that can distort a vital area of our survival. Don’t exaggerate and allow the power and production markets to distort. In a different time it would not be critical but it is now. We are staring into an energy decent globally that will tear out the heart of the global economic system starting with the Ponzi scheme debt based finance system that is in an “INFLATED” debt bubble that is ready to burst. This time around the central banks will not have liquidity tools to buy up all the bad debt that will settle from this burst bubble. These bad debts will bring the system down to a much lower economic level. Let us hope it is a gradual process but as we have talked about here the decent is seldom gradual. When chaos enters the equation in a global system at the end of growth in diminishing returns with a population in overshoot to its carrying capacity with wealth inequality extreme the consequences are dire.
rollin on Thu, 3rd Apr 2014 11:19 am
So 20,000 wells gives the US a total of one year’s worth of oil.
If each well costs 11 million dollars that is $220 billion dollars.
A years worth of oil costs 760 billion dollars, so even after other costs there should be a huge profit at these reserve estimates.
So either these estimates are too high or these oil rigs are pumping gold.
As far as oil security goes though, we would need a couple dozen Bakken’s to continue with oil for a few more decades.
In other words, someone born today will not be using oil for transport as an adult. The whole thing is to make money now and leave the next generation stranded along the highway. Unless of course we get smart.
rockman on Thu, 3rd Apr 2014 11:43 am
Just so it’s clear to everyone there a bit of mixing apples and oranges here. There are two different reserves estimate being discussed here. First is the URR from EXISTING producing wells. Given the very non-linear decline of fractured reservoir wells this is a very difficult number to come up with. Equally important is the time span to recover any URR for any existing well. They mention a company reducing their decreasing URR for their wells. That’s fine but when they estimate X hundreds of thousands of bbls of recovery at what rate (which changes dramatically over time) are those X bbls produced? After all the price and availability of oil is a function of how fast it’s coming out of the ground and not how much all the wells ultimately produce. The time factor is much more important in estimating the profitability of a well than URR.
As far as estimating the URR from undrilled wells that’s has always been a very difficult GUESS based on limited geologic info (since the well hasn’t been drilled yet). Think about the hundreds of thousands of dry holes drilled in the last several decades. Everyone had a certain number of bbls/mcf estimated as recoverable. And every estimate was 100% incorrect…thus the dry holes. There are well established sweet spots and sour spots in the Eagle Ford and Bakken. And how were those determined? By drilling and producing wells. That’s the only way to prove the reserve potential of an undrilled area. IOW there’s no way to accurately predict what the undrilled regions of any of these plays will produce until they are drilled. Many areas with high potential prove to be rather poor. One company paid over $200 million just for the drilling rights on some EFS leases in Wilson County, Texas. Obviously they had projected big reserves. They drilled 8 very disappointing EFS and then sold the rest of the acreage for less than $0.10 on the dollar. Shell Oil paid $1 BILLION for a single ranch in S Texas to develop the EFS. And then drilled over $3 BILLION worth of wells. The result: Shell took a $2 BILLION write down last year and announced they were no longer going to pursue the shale plays ANYWHERE IN THE US. But it can work out the other way also. I’ve drilled wells on leases that many others have dismissed as worthless and made hundreds of $millions for companies.
I’m a career development geologist and not an explorationist per se. I always look at anyone’s undrilled reserves estimates with a very critical eye. But skepticism was ground into almost 40 years ago on my first project: developing an offshore field in the GOM. After drilling two successful wild cats the exploration group estimated 120 bcf and 25 million bo URR for the field. So I began drilling my “low risk” development wells off the new platform. After the first 5 wells turned out to be non-commercial the reserve estimate dropped from 120 bcf to 25 bcf and 25 million bo to 2million bo.
Yeah, I got your reserve estimates for you…RIGHT HERE! LOL.
buddavis on Thu, 3rd Apr 2014 1:12 pm
Been working in the oil patch for close to 20 years, 4th generation, on the exploration side. One of the first things I learned is Reserves are what you pull out of the ground. Putting a number on what is in the ground is a calculated risk and I have seen people get burned on both ends, as sellors and buyers.
Aaron on Thu, 3rd Apr 2014 1:15 pm
If even Bloomberg is acknowledging that there might be a problem, you know it’s time to take that last long-haul holiday.
paulo1 on Thu, 3rd Apr 2014 1:19 pm
@Rocky
So are there any reliable estimates beyond the rearview of, “we were right”, or “we were wrong”?
In the world of wood you cruise the timber and calculate volume of species and quality through measuring. The method is fixed. Then extrapolate. It is all about representative sampling. The market is the market and is the decision maker when or if the logging gets done. (These days). We used to have a quota system but that has been expediently shelved for company profits. There is usually a buyer before the first tree is dropped. If this isn’t the case you have the ‘someone lost their shirt’ routine. The wood will always have to be put up on the open market before it is exported out of BC (by law), but this is usually a sham and the buyer is already pre-determined.
How is this possible with oil? It is underground and test wells are expensive. What about all the new fancy 3d seismic and computer stuff?
Thanks…Paulo
rockman on Thu, 3rd Apr 2014 1:49 pm
Paulo – The tree analogy is a good one but only for wells that have been drilled. Now try this: estimate your timber yield for a patch of land you haven’t seen. It may be very similar to where you’ve planted before (profitable wells). Or it might it might be a bog where no tress will grow (dry holes). So OK…you have some fuzzy satellite photos to help you out. Sorta like the very high tech 3d seismic Devon’s staff of very experienced folks used to drill the last Deep Water GOM well I worked on for them. The 33,000’ deep and $245 million dry hole that didn’t find one gallon of oil. Personally I’ve drilled two “sure shot can’t miss” wells in my career. And both missed so I don’t drill sure things anymore. I stick with wells that have a reasonable chance of working. LOL.
shortonoil on Thu, 3rd Apr 2014 2:35 pm
The Arps type curve is a mathematical function that is based on the IP (initial production), D (initial decline rate), t (time), and a constant named “b”. “b” is the center of controversy. When:
b = 0 the formula is an exponential decay curve
b = 1 the formula is a logarithmic function
b > 1 the formula is a hyperbolic function
A hyperbolic curve has a tail that never approaches the X axis, that is; for a well it would produce an infinite quantity of petroleum. The shale industry has insisted that production from their wells is hyperbolic (go figure). Geologist Arthur Berman has been very critical of the industry for their use of the hyperbolic curve. Of course we agree with him, use of the hyperbolic function defies all common sense.
There are yet another aspects of shale condensate production. Condensate wells are a gas drive, and when the pressure in the well falls below the dew point the heavier fractions condensate out in the well where they are lost. Liquid production from the well stops at that point, or diminishes greatly and the well produces nothing but gas. That is, if condensate blockage doesn’t kill the well all together. Also, the energy content of the low molecular weight fractions produced from most shale condensate production is probably not sufficient to compensate for the energy needed to put the wells into production. When the energy needed to process these liquids into usable products is taken into consideration, there is little left, if any to be used by the general economy.
The claims by the industry that shale will bring energy independence to the nation are in conflict with reality, and border on the absurd. “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.”
You Think???
http://www.thehillsgroup.org
bobinget on Thu, 3rd Apr 2014 3:05 pm
Experienced Real Estate sales people know to never celebrate until that check clears.
Thanks again Rockman for your clear ‘insider’ intel.
Makati1 on Thu, 3rd Apr 2014 3:42 pm
…just watchin’ the black swans circling overhead …
Davy, Hermann, MO on Thu, 3rd Apr 2014 3:56 pm
Snap goes the Whip…great observation as usual Short!
J-Gav on Thu, 3rd Apr 2014 4:08 pm
Xhort – Thanks for your mention of Art Berman’s really quite scathing critique of the predominant “everything’s just peachy in fracking land” position. Everyone should be aware of his arguments.
shortonoil on Thu, 3rd Apr 2014 4:41 pm
Of the few dozen condensate wells for which we have reliable numbers (third party) the mean of the RR (recoverable resource) on URR has averaged about 7%, with a low of 3% and a high of 16%. Conventional wells in the US have averaged about 35% over the last 50 years. Using URR for evaluating recoverable resource of condensate fields is likely to produce unreliable estimates. Of course the shale industry has a vested interest in not supply the most likely numbers, but the best.
In all fairness the tendency to over estimate reserves is not unique to the petroleum industry. One mining company that I worked with in Canada insisted they had 135 years of reserve. Our analysis put it at 7 years. 4 years later they went out of business.
Guess we were both wrong!
“Xhort – Thanks for your mention of Art Berman’s really quite scathing critique of the predominant “everything’s just peachy in fracking land” position. Everyone should be aware of his arguments.”
Berman has done some exceptional work in shale. For a geologist there is often a tremendous amount of pressure to supply rosy scenarios. Berman has stood by his professional evaluations. He is a credit to his science.
http://www.thehillsgroup.org
.
paulo1 on Thu, 3rd Apr 2014 5:41 pm
Thanks Rockman
As a non oil guy I always thought the seismic offered up more information than I guess it does.
Paulo
Mark Ziegler on Thu, 3rd Apr 2014 6:14 pm
So, if the US has 100 years or 200 years worth of natural gas, why do they keep drilling? There is way too much and countries overseas can do the same thing.
isgota on Thu, 3rd Apr 2014 9:02 pm
A hyperbolic curve has a tail that never approaches the X axis, that is; for a well it would produce an infinite quantity of petroleum.
Sorry but actually hyperbolic curves of oil depletion approach the X axis:
http://www.petrocenter.com/reservoir/DCA_theory.htm
And just like an exponential decay curve, the cumulative production of crude (area below the curve for a zero to infinite improper integral) is not infinite for hyperbolic depletion curves.
So that sentence is not proof LTO depletion curves aren’t hyperbolic.
Nony on Thu, 3rd Apr 2014 9:09 pm
Ryder Scott? Who’s even heard of that firm? I’m sure the bloggers in the peak oil world know more and have more on the line in getting the numbers right. Or Art Berman…after all he’s been so prescient with his 2009 claims about shale gas.
😉
eugene on Thu, 3rd Apr 2014 9:17 pm
Endless discussions about bullsh– and mirrors. Get a grip. Do some basic research yourself.
shortonoil on Thu, 3rd Apr 2014 9:36 pm
“Sorry but actually hyperbolic curves of oil depletion approach the X axis: ”
The Arbs function is: P = Po/(1+bDT)^1/b
P = production
Po = initial production (a constant)
D = decline rate (a constant)
T = time (increasing)
b > 1 for a hyperbolic function (a constant)
Any number to the 1/b is greater than zero (0) if b > 1. The Arbs hyperbolic function approaches zero (0) at infinity. A well produces forever, according to the shale industry, or until you get there.
http://www.thehillsgroup.org
Nony on Thu, 3rd Apr 2014 9:52 pm
Except they routinely use a two-stage model with hyperbolic followed by exponential. Then again…have fun getting back to beating up a straw man. I’ll have fun looking at all the crazy predictions that the doomers made 10 years ago and haven’t admitted they messed up on.
rockman on Thu, 3rd Apr 2014 10:10 pm
Paulo – This might sound odd after what I said about the $billion lost drilling on modern 3d seismic: exploration success has never been greater now then ever before. Even just using old 2d seismic in the mid 80’s I hit 23 out of 25 wells going after small stratigraphic trapped NG reservoir. Historically the success rate in this trend was 1 in 5…at best.
I’ve made the point before bout how much easier it is to FIND oil/NG reservoirs. And so much more efficient: I can generate a series of maps using 3d seismic with a desk top computer system in one month that would take 5 geophysicists 6 months to duplicate with 2d seismic. And my maps would be more accurate.
The problem isn’t the quality of our current exploration tech. It’s the lack of viable prospects. As a result we use the tech to drill risky prospects because that’s mostly hit we have left. Which is why the shales are THE play today for the pubcos: rarely do they drill a “dry hole” which isn’t the same as not drilling money losing wells.
Nony on Thu, 3rd Apr 2014 10:18 pm
Maybe we should call in Stuart Saniford and Matt Simmons to do the reserves calculations for us. They must be better than that fly by night Ryder Scott firm. After all, peakers did such a great job predicting the cliff/nosedive/twilight in the desert (saying Saudia Arabia was running out of oil).
Nony on Thu, 3rd Apr 2014 10:19 pm
Or maybe Gail. She makes a lot of posts with charts and stuff.
isgota on Thu, 3rd Apr 2014 10:23 pm
The Arbs function is: P = Po/(1+bDT)^1/b
P = production
Po = initial production (a constant)
D = decline rate (a constant)
T = time (increasing)
b > 1 for a hyperbolic function (a constant)
Any number to the 1/b is greater than zero (0) if b > 1. The Arbs hyperbolic function approaches zero (0) at infinity. A well produces forever, according to the shale industry, or until you get there.
That’s exactly the function described in the link I posted before (except it consider b < 1 for hyperbolic).
But guess what, the exponential decay curve, so popular in Peak Oil models, it also produces forever.
The only value P(t)=Po exp(-D*t) -> 0 is in t -> infinite, all the others are positive.
Yet, its total area that represents the total oil produced by the well, is not infinite.
From the link before:
Q(t)=(Po-P(t))/D when t -> infinite is
Q(inf) -> Po/D
paulo1 on Fri, 4th Apr 2014 12:11 am
re:
“The problem isn’t the quality of our current exploration tech. It’s the lack of viable prospects. As a result we use the tech to drill risky prospects because that’s mostly hit we have left.”
Got it. “Here’s is to luck of the find”, as he sips his glass of wine. Now I understand. If we had 3d seismic years ago we wouldn’t have any oil left to speak of. And if we didn’t have it now, we would be in the same fix.
Paulo
rockman on Fri, 4th Apr 2014 1:57 am
Paulo – Actually that sorta happened out on the GOM shelf (0′ to 600′ water depth) with respect to NG since the mid 70’s. And that was just using good 2d seismic. Geologists draw maps which show likely traps where oil/NG MIGHT collect. But in some trends, like the GOM, you can sometimes actually see the NG on the seismic data. The common term is “bight spot”… tech term: amplitude anomaly. It increased the success rate several fold and why we continued to develop so much for a while. But guess what: the GOM shelf is relatively dead now because we were shooting fish in the barrel for over 20 years…and now there aren’t many fish left. Especially the big ones. That onshore play where I hit 23 out of 25…that was using 2d seismic bright spots. The operators in those trends had not worked in the offshore when this tech was discovered. I had. For a while I was the fox in the chicken coop. But in a few years many caught on. And guess what: just like the offshore there aren’t many onshore bright spot left to drill: we shot most of those fish by now. The only fish of any quantity we have left are the shales and the Deep Water. And like all the other trends drilled from the beginning of the oil patch some day there won’t be many of those fish left regardless of the price of oil/NG.
shortonoil on Fri, 4th Apr 2014 1:39 pm
“But guess what, the exponential decay curve, so popular in Peak Oil models, it also produces forever.”
Between 1960 and 2005 the EIA’s cumulative production followed a logistic function (almost exactly). Hubbert (and many others) have used a logistic function, and in our study we show why the accumulative production curve follows a logistic function. It is the same phenomena (and for the same reason, energy) that bacterial growth, and decline in a petri dish follows a logistic function. Although that curve may be a shewed logistic function which has no explicit CDF or PDF. That is, there is no existing mathematical equation to describe it. All calculations must be done numerically. The use of an exponential decay curve is incorrect!
The Arbs function applied to shale production is flawed for other reasons than the misinterpretation of the its “b” constant. Most shale production is in the form of condensate. The Bakken, and a small part of the Eagle Ford are the exceptions. Condensate is a gas in the reservoir. Its temperature/pressure is high enough to generate a single phase fluid. As the pressure falls (these are gas drive wells) it hits the dew point, and the heavier fractions condense out in the well where they are lost. Liquid production at that point essentially stops, and only gas (methane, ethane, propane) are produced (if condensate blockage doesn’t kill the well altogether).
The production curve has hit a discontinuity, and the form of the curve becomes irrelevant. In non-permeable structures like shale, liquid production ceases in most cases in one to five years. The shale industry has misrepresented their potential by an assortment of mathematical tricks, gimmicks, and a general lack of knowledge about the subject by the public and investment community. Their overall impact on the economy is actually minimal, at best.
http://www.thehillsgroup.org
.
Kenz300 on Fri, 4th Apr 2014 4:45 pm
The fossil fuel industry will say anything and do anything to keep their hold on energy production and limit alternatives.
They will fight, kick and scream to keep their massive profits rolling in.
They have their heads stuck in the past……… safer, cheaper and cleaner alternatives are growing in use every year.
rockman on Fri, 4th Apr 2014 5:16 pm
Ken – I am THE fossil fuel industry and I don’t have to do sh*t to keep hold of energy production because I am energy production. I also don’t have to do sh*t to limit alternatives. the energy consuming public makes that decision and they have spoken.
And my head isn’t stuck in the past…it’s stuck in the present. I develop fossil fuels. I’m not in the alt construction biz…never has been…never will be. And for a simple reason: that ain’t the biz I’m in.
Nony on Fri, 4th Apr 2014 8:52 pm
It’s interesting seeing what areas the oil business has been able to move into. They really don’t seem to have much history of moving successfully into other energies. Exxon failed at nuclear in the 70s. BP was a bunch of “beyond petroleum” silliness…and then they showed with Macondo, they weren’t concentrating enough on safety and good engineering practices in their core business. I’m unaware of any that seem to have really done much in coal or coal gasification. Or hard rock mining.
One area that they have gotten into is the deployed military support (at least the oil service companies). Uses their ability in logistics, rapid movement across geographies, even a bit the geopolitics and security (and a willingness to play in that sort of arena that say a GE or Dow or more traditional manufacturing companies lack).
They do seem to dabble in chemicals to different extents. And you can see the analogy of a refinery and a chemical plant (in some cases even the justification for hard-piped vertical integration). But even there, seems some hesitancy to move that far from the heavy metal commodity businesses. And they go through fads of selling of their chemical businesses (or even their refineries). Some real differences of culture and business style from the upstream and downstream. And an open question if it really has a value to be vertically integrated (exploration and refining and even retail).