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US shale oil reaching 10 million barrels per day is fiction


Any financial advisor worth their salt will caution you that past performance is not a guarantee of the same in the future. And so it is with US shale oil. Recent EIA estimates claim potential production of up to 10 million barrels per day (BPD). That projection is pure fiction and in this article I will explain why.

Right off the bat, assuming annual declines of 2.0 Million BPD, wells having a 365-day average annual rate of 400 BPD requiring 5,000 wells and utilizing 330 rigs (with each well drilling 15 years per annum) would be needed just to offset declines. Should annual declines exceed 20% per new and vintage production, the number of rigs goes up proportionally.

Productivity of shale basins (a misnomer as the dominant facies consist of mixtures of sandstone, dolomite, limestone, siltstone, and clays) is determined by a number factors.

The first is the degree of catagenesis (i.e. the degree of cooking of the kerogens in the source rock). This determines the type of product at a given reservoir depth. Increasing depth usually grades from oil to wet gas, and then dry gas. The wet gas and dry gas regions have increasing pressures with dry gas reservoirs having pressure gradients up to of 1.6 times normal pressure. Pressure gradients in the wet gas window range form slightly over-pressured to 1.4 times normal pressure. The second is the rock facies and brittleness of the rock. Areas with high clay content are not frackable. Finally, porosity, permeability and product viscosity determine producibility. Wet gas regions are far and way the most profitable as they are capable of prolific production. They produce at higher values per BOE than dry gas or oil. Simply put, they have the best netbacks per BOE. This is the reason that wet gas areas see the most activity no matter the basin, be it Permian, Eagleford in the US or the Montney in Canada.

As we know, most plays (except the Bakken which is primarily an oil play) contain a mixture of all three products depending on depth. The Eagleford comprises of 22,700 square miles in twenty-three counties with 58%, 23% and 16% respectfully in the oil, wet gas, and dry gas regions. Twenty five percent of all Eagleford production is produced from only three counties; Karnes, Lasalle and Gonzales. To put this into perspective, Karnes county with only 754 square miles (3.3 % of the entire Eagleford foot print) produces 146,000 BPD. The total area in the wet gas window is in these three counties is about 1,400 square miles or 6% of the total foot print of the Eagleford. Both Gonzales (which adjacent to Karnes) and Lasalle counties are on depth trend with Karnes county.

At 75,000 square miles, the Permian is roughly three and a half times as large as the Eagleford. It has two main producing horizons; the Sprayberry (600 feet thick in several intervals) and the Wolfcamp (three hundred feet thick). The Permian has not been mapped in terms of product type, although we can assume that the same ratios apply, thus there could possibly be up two 15-20,000 square miles in the wet gas window. The caveat however is that 23% of all Eagleford oil production is produced from only 9% of the Eagleford footprint.

Much talk has been given towards the Permian and the plethora of intervals in each well. The geology of the Permian Basin is rich and complex, both horizontally and vertically. The basin has commercial accumulations of oil and gas in stacked layers, at depths ranging from 1,000 feet to more than 25,000 feet. At this point mapping of each product type (as is the case in the Eagleford) in the Permian has not been completed to my knowledge. A further complicating factor is the basement heat gradient, which is simply the temperature rise per unit of depth. In the case of the Montney, the producers who figured this out have the best (by far) land base, purchased at the lowest costs, before the herd mentality started. Should the basement heat gradient vary across the basin each product type could occur at different depths. Because of its large foot print, it is highly probable that the basement heat gradient varies across the Permian as it does in both the Eagleford and Montney.

Looking at the stacked intervals in the Permian, tracer logs that I am aware of, show that frack heights vary between 75 and 150 feet. This means that up to three wells could be needed to tap all intervals assuming a total thickness of 600 feet. A complicating factor arises if all the intervals do not have the same facies, product type and or are thick enough to be economic.

The EIA has estimated Ultimate Economical Recoverable Reserves of 11 to 33 Billion barrel in the Permian. Assuming an average type well across the basin has reserves of 600,000 barrels of oil per well, a total of 18,300 wells will be needed to recover 11 billion barrels. Assuming each rig drills only one interval, a total of 4,600 square miles will be consumed. Likewise, in the P50 case of 22 billion barrels, 9,200 square miles will be consumed. Based on the example of the Eagleford where production is centred on a few counties, the areal extent is likely between 4600 (6% of 75,000) and 9,200 (12.3%) square miles.

So, how high can the Permian go? Assuming net annual growth of 500,000 BPD with 375 rigs (5625 wells per year), the play would be exhausted in 3.25 years with production reaching 4 million barrels per day. This assumption is not plausible as the number of rigs will be based on updated play knowledge. Therefore, as the extent of the sweet spots become more defined the member of rigs will slowly decline should the lower case become evident or hold steady for a longer period. And the pace of development of course will depend on the price of oil. It’s likely that the pace of development will adjust as does the price of oil gas.

Weekly production estimates are published in the petroleum inventory report (which has recently been reduced as actuals provided by producers are obtained). Using actuals, the EIA reports have been over estimated by as much as 300,000 barrels per day recently. Month over month production saw June slightly lower than May.

In 2016, the EIA in a report to Congress estimated that by 2022 US shale oil production would reach 6 million barrels assuming a $50 WTI price and 10 million barrels per day assuming a price deck of $80 per barrel.

Estimating future production should be based on a play by play basis. The Bakken was initially thought to have the capacity to reach 2 million BPD. We now know that the Bakken is having difficulties achieving its peak production of 1.3 million BPD. Eagleford production peaked in 2015 at 1.65 million BPD. Many forecasts indicate that at best, production will climb slowly but may not reach the peak production levels. The Permian obviously is the wild card in the equation. Since 2011, with the advent of horizontal drilling, production in the Permian has grown by 46% per year, from 300,000 BPD to 2,300,00 BPD today. Using “Straitlineology” the Permian should be producing over seven million BPD by the end of 2020. This continuance of this level of increase growth is impossible to determine. But at some time the production will peak and then start a terminal decline as productivity slowly falls. Hint: Producers always drill the best first.

My best guess for peak shale oil production is 5.8 million BPD coinciding with peak Permian production of 3.5 Million BPD in 2020. During this timeframe, the Bakken should produce at a rate 1.0 million BPD, and the Eagleford at 1.3 million BPD. Factors that could derail this estimate are fewer wet gas areas in the Permian, lack of success in different intervals, increased service costs and of course lower than expected production from the Bakken and Eagleford.

On the other hand, should producers “discover” new wet gas areas in the Permian production could rise as high as 4.5 million BPD. This would raise total shale production to 6.8 million BPD. With higher prices (WTI at $50/barrel), the pace of development will increase and so will production rates. But as happened in 2014, price declines lead to a drop in activity and therefore production.

There is almost zero chance of US shale oil production of ten million BPD. The most likely range is between 5.8 and 6.8 million BPD if the Permian lives up to its initial promise. A further complication is that unconventional plays are not consistent through the full footprint of the basin. Only a fraction (10 to 15 % or less) should be considered as prime wet gas areas. The winners in this game will be those companies who have figured out the geology first and hold the best land at first mover prices. The losers will be those who believe that shale plays are homogenous throughout the basins and move into the plays later and pay to much for land that is not always the best.

Randy Evanchuk, P. Eng., has 35 years of experience in the patch. From 2007 until he retired in 2015, Mr. Evanchuk was involved in all phases of of unconventional resource development including;evaluation, economics, production and facilities. As as senior consultant with Murphy’s Holdings, he evaluated their Montney holding as well was as a member of evaluation team. Mr. Evanchuk was the Vice President of new ventures at Daylight Energy where his team was successful in acquiring a substantial Duvernay position. At Seven Generations Energy he was Executive Vice President looking after facilities, marketing, production operations and long range facility and marketing planning
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15 Comments on "US shale oil reaching 10 million barrels per day is fiction"

  1. dave thompson on Thu, 21st Sep 2017 7:07 am 

    No matter how much shale oil is produced, conventional oil that ran and still runs the world is what matters.

  2. dave thompson on Thu, 21st Sep 2017 8:02 am 

    This is one that will open your eyes a bit.

  3. Rocky Toad on Thu, 21st Sep 2017 8:03 am 

    This article is Zeno’s paradox retold. First principles arguments generate useful ideas, but do not separate demonstrable fact from fiction.

    Bad education explains why such logic dominates in comments threads and is not shot down immediately.

    If you do not understand what I am talking about, you illustrate the point nicely.

  4. dave thompson on Thu, 21st Sep 2017 8:25 am 

    This is a good explanation of why shale oil is not what it seems.

  5. joe on Thu, 21st Sep 2017 8:27 am 

    Lack of investment is the story being laid as the foundation of a price spike which of course is to ally artifical. They caused the Great Recession the last time they squeezed the masses when they literally sucked every last cent out of the working classes who promptly went bust and could no longer buy that overpriced oil or pay that overpriced subprime mortgage. The system is designed to boom and bust, so the next cycle will be no different. But before they enrich themselves again they need to flood the system with money, then get everyone into debt again, then they will simply spike the prices and rinse repeat…
    One of the watch outs is that some countries will be reducing the use of oil as personal transport fuel, instead (mostly in Europe) they wish to trade carbon emissions limits. The EU has a health and wealthy market for tradeable carbon emissions (
    So don’t be fooled by all this ‘save the earth ‘bullcrap the rich always get richer. Richard Branson will always drive a gas powered car, just not his employees….

  6. Boat on Thu, 21st Sep 2017 11:05 am 

    dave thompson on Thu, 21st Sep 2017 8:02 am

    This is one that will open your eyes a bit.

    “Again, what the EIA calls “Crude oil” is actually Crude + Condensate (C+C), and based on EIA data, 22% of Lower 48 C+C production in 2015 exceeded 45 API gravity and about 40% of US Lower 48 C+C production exceeded the maximum API limit for WTI crude (42 API Gravity)”.

    That comment talks about EIA findings but no link to actual numbers.

    Here is a chart from the EIA that tells a much different story.

    22% of Lower 48 C+C production in 2015 exceeded 45 API gravity……This seems correct

    about 40% of US Lower 48 C+C production exceeded the maximum API limit for WTI crude (42 API Gravity)”……seems to be a crock of smoke and mirrors.

    wti is just one benchmark among many. 42 api is not condensate. This west texas guy is pulling a shortonoil, playing games with the non-chart readers.

  7. shortonoil on Thu, 21st Sep 2017 5:44 pm 

    42 API gravity is significant because every refinery in the world is designed to run 33 API crude. All crude must be blended to meet those specifications before it can be processed. Anything above 42 is a poor fuel producing raw material, and that is why Cushing specs require that WTI be equal to, or less than 42.

    Wet gas may be more profitable for the shale extractor, but only 7% of wet gas by volume condenses out to produce C7+ molecules. The molecular range needed to produce fuels. Most of the production from wet gas is only useable in the petrochemical industry for plastics, and other products. Its production is not a significant addition to the production of fuels, or the energy needed to power the economy.

  8. rockman on Thu, 21st Sep 2017 5:59 pm 

    Oil from the shales is OIL. It doesn’t matter what the API gravity might be or whether it’s classified as comventional or umcomventional. The condensate/light oils are CRITICAL to the US economy. US refineries process oil with a 32 API gravity. Very little of the oil produced in the US (or the world) is 32 API gravity from conventional completions. This also true for the often referenced WTI (West Texas Intermediate) that by definition has an gravity of 39.6 API: very little of the oil PRODUCED in the US can be classified as WTI.

    The vast majority oil processed by US refineries is BLENDED OIL which is typically heavy oil (less then 25 API) and condensate/light oil (40 API or lighter). Prior to the shale boom the US had to import a significant amount of condensate/light oil to BLEND with heavy oil supplies…both domestic and imported. Most know that the largest fuel storage facility in the world was built in Cushing, OK. Why did they need such a large STORAGE facility there? They didn’t: it was built out as the largest oil BLENDING FACILITY in the world. Billions of bbls of heavy oil imports were pipelines from Gulf Coast ports to Cushing to be blended with lighter oils.

    BTW if it weren’t for the export of 350,000 bbls per day of US condensate/light oil from the US to Alberta we would not have imported as much oil sands production. The Canadians only had 450,000 bbls/day of condensate/light oil to BLEND to make DILBIT (DILuted BITumin) with that heavy oil so it could be pumped via pipelines to the US. But even dilbit, with a 23 API, wasn’t suitable for US refineries. Which is why most Canadian dilbit was pipelined to Cushing where it was BLENDED with more condensate/light oil. And now with the huge supply of 32 API BLENDED oil in Cushing in addition to building a new pipeline (the southern leg of the Keystone XL Pipeline) an existing pipeline (Seaway) that had pumped heavy oil imports from the Gulf Coast to Cushing for BLENDING was reversed to carry the BLENDED Canadian oil to Texas refineries.

    Also hundreds of millions of bbls of Eagle Ford condensate/light oil was shipped from south Texas to refineries in eastern Canada to BLEND with their heavy oil supplies.

    Bottom lines: without the condensate/light oil supply the US refining industry would be crippled and unable to supply the products it has been delivering for decades.

    BTW just a reminder of the definition of “condensate”, at least in Texas, the biggest oil producing state. It IS NOT based on the API gravity nor whether from a conventional or unconventional completion. A 42 API oil from an unconventional completion might be classified as “oil” by the regulations of the Texas Rail Road Commission and a 38 API oil from a conventional completion is classified as “condensate”. The classification is based on whether that production exists in a liquid or gaseous phase IN THE RESERVOIR. This is not a minor technical issue but one with hundreds of $millions at play. I’ll skip the details.

  9. Boat on Thu, 21st Sep 2017 7:40 pm 


    A 42 API oil from an unconventional completion might be classified as “oil” by the regulations of the Texas Rail Road Commission and a 38 API oil from a conventional completion is classified as “condensate”. The classification is based on whether that production exists in a liquid or gaseous phase IN THE RESERVOIR.

    Interesting bit of information. Dozens and dozens of articles, including the EIA, peg condensate at 45 api but any oil in a reservoir would need to be liquid, I would assume. You know of any links that explain crude that approaches liquid state from different locations? I bet temp plays a role.

  10. shortonoil on Thu, 21st Sep 2017 7:58 pm 

    “Oil from the shales is OIL.”

    Categorically incorrect. Oils can vary from pentane (C5H12) API 92.70 to very heavy asphaltenes with molecular weights in the thousands. Their utility also varies accordingly from petrochemical feedstock to production of petroleum coke. The most profitable of crude to process are those that lends themselves to the production of transportation fuels. Those include crude that are high in the molecular structures needed to produce fuels; the C7+ family of hydrocarbons. Most of those reside in crude of the 30 to 45 API range. Light crude is less able to produce fuels and thus sells at a considerable discount. Shale usually sells for $10 to $15 per barrel less than conventional because of its concentration of lighter fractions, its greater inconsistency, and higher gas content.

    The quality of a crude is dependent on its formation characteristics. Higher temperatures and pressures during its formation period result in lighter fractions. Most conventional crude is found at the 4000 foot depth region because that is where the temperature, and pressure were optimal for the formation of higher quality oil. Heavier crude is usually found in shallower deposits where it volatiles have been able to boil away. LTOs are found at greater depths and pressures. LTOs have lower energy content because of their higher concentration of lighter fractions. The energy content of an oil is directly proportional to its API rating.

  11. green_achers on Thu, 21st Sep 2017 10:20 pm 

    I wonder what he means by “15 years per annum (sic).” The rest of the article was almost as incoherent, but I suspect it has more to do with low skills in the English language than with his technical knowledge. Though who can tell?

  12. Anonymous on Thu, 21st Sep 2017 10:51 pm 


    Production is strongly influenced by price. Had we stuck with $100 oil, we would likely already be at 10 MM bpd shale oil by year end. We were adding 1+ MM bpd per year and 3 more years would have elapsed with that. For a simple thing, just consider what would happen if we had stayed at 1600 oil rigs, running.

    Shale is very sensitive to price, but this winter with prices at $57 (strip into 60+), we were actually growing at 1 MM bpd/year (for about 4 months). Since then price droped into the 40s and growth flatlined. So what happens will depend on World price, which is hard to predict.

    short: that “all refineries” comment is a silly comment. Different refineries are optomized for different feedstreams. In the US, we have refineries with more complicated structures (cokers, etc.) that can run lower APIs. And even here, they run the lower API, not because they prefer it but because it is cheaper (and they can handle it).

  13. Dale Chenery on Sun, 24th Sep 2017 10:47 pm 

    What does the gibberish statement “with each well drilling 15 years per annum” mean? I’m assuming that it should be “with each rig drilling 15 wells/year”, but that is a huge leap from what is presented.

  14. GregT on Sun, 24th Sep 2017 10:56 pm 


    “Production is strongly influenced by price. Had we stuck with $100 oil, we would likely already be at 10 MM bpd shale oil by year end.”

    If oil had of “stuck” at $100, the 10 trillion dollar US alone attempt at recovery from the Global Financial Crisis would have been far more apparent than it already has been.

    And Nony, keep ignoring the environment, while pretending that $50/bbl oil is still affordable to the worlds’ economies. Everything is going to work out just fine.

    Tell yourself.

  15. Davy on Mon, 25th Sep 2017 6:55 am 

    “And Nony, keep ignoring the environment, while pretending that $50/bbl oil is still affordable to the worlds’ economies. Everything is going to work out just fine.”

    Nony is an excellent contribute to this board and he offer relevant info and he keeps it focused. You on the other hand pollute the conversation with “keep ignoring the environment”. You ignore the environment all the time but that is ok because it is you and your double standards. We need to keep subject feeds clean of stupid interjections about this or that per agendas. There are plenty of articles on the environment here. You extremist have nearly succeeded in running off most of the oil related expertise here. You dumbasses are trying to run Rock off now. Get a grip what your extremism does. It makes a rich environment of ideas into a monoculture of opinions.

    tell yourself

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