Comments related to Oil and Natural Gas production in this thread.
191 thoughts to “Open Thread Petroleum, Sept 7, 2019”
Permian Basin horizontal Oil Rig count
Question Dennis: does anybody still drill vertical wells?
Frugal,
Yes, but most tight oil output comes from horizontal wells so I focus on that.
The Permian is layered with fields, the upper ones have been producing over 50 years with vertical wells. Before the price drop in 2014 and 15, they were drilling 800 to 900 vertical wells a month in the Permian. It has dropped to a little over 100, but could kick back up if prices rise. And, as shallow sands can attest to, there are a quite a number of shallower formations, like the Wilcox sands, all over Texas and other States. In general, their initial output is much lower, but they produce a lot longer.
GuyM
Yes they are still drilling vertical wells. Only enough to keep output roughly flat most of the tight oil wells being drilled are horizontal the vertical wells for the past 12 months in the Permian are primarily conventional wells.
From Rystad “US liquids production is forecast to surpass 24 million barrels per day over the next six years”. That’s 24 mbd – that’s not possible. Somebody needs to email Rystad and ask them what are their assumptions to get to 24 mbd.
EIA prediction longer term through 2025 for USL48 excl GOM is pretty reasonable and even STEO through 2020 is pretty close perhaps 200 kbpd too high in Dec 2019.
Elsewhere I have shown that the STEO in Jan 2018 underestimated Dec 2018 output by over 900 kbopd.
So yes the forecasts are far from perfect sometimes too low other times too high. AEO2019 reference scenario is reasonable up to 2028. After that it is not realistic at all decline will be steep by at least 2028 after 2025 peak of about 14.5 Mbpd.
Tony
That is C+C and NGL. Current level is about 17 Mbpd. I agree 25 is an overestimate but 20 Mbpd seems possible. Not too sure on NGL.
Tony,
I was mistaken, the June 2019 level is about 16.8 Mb/d for C+C+NGL, if we adjust for the lower energy content of NGL (about 70% of a barrel of average crude) the June 2019 output is 15.3 Mboe/d for US C+C+NGL (12.08 Mb/d of C+C output and 3.2 Mboe/d of NGL output.)
Tony,
If we use EIA data for C+C+NGL output at link below
The annual rate of increase for US C+C+NGL output from Sept 2016 to June 2019 has been 13.6% per year. If we assume this annual rate of increase slows to 6.16% per year from May 2019 to Dec 2025, then US C+C+ NGL output reaches 25 Mb/d by the end of 2025.
An alternative approach is to assume US C+C reaches 14.5 Mb/d by the end of 2025 and that NGL output doubles from 4800 kb/d to 9600 kb/d (annual growth rate of 11% for NGL) which would get output tp about 24000 kb/d. This ignores the fact that NGL has lower energy content (roughly 70% of a barrel of crude) so in barrels of oil equivalent the total would be 21,000 kboe/d rather than 24,000 kb/d.
In addition, such extrapolations tend to give poor predictions. It is doubtful that NGL output will continue to increase at an annual rate of 11% for the next 5.5 years. There has been a long term trend in US NGL output of 9.4%/year increases on average from Jan 2010 to July 2019, but it is doubtful that rate of increase will continue in my opinion. If we look at the most recent 12 months for NGL output the annual rate of increase has slowed to 6.4%.
Using that more realistic rate of increase and assuming C+C output of 14.5 Mb/d in 2025 and adjusting for the lower energy content of NGL (70% of a barrel of C+C) we get 19 Mboe/d for US C+C+NGL in 2025. That might be a reasonable estimate (possibly still on the optimistic side if the growth of NGL output slows further over the 2019 to 2025 period.)
GuyM
Yes there are a bunch of crazy forecasts out there.
EIA is pretty conservative by comparison. If you look back at crazy STEO forecasts you might find they were not bad.
GuyM,
Took a quick look at Aug 2018 STEO (about 12 months ago). At that time they expected US C+C output of 12.02 Mb/d at the end of 2019 and 11.7 Mb/d in June 2019. Seems they underestimated.
By Dec 2018 the estimate has increased to 12.29 Mb/d in Dec 2018, that seems like a pretty good estimate to me. Lately their estimates do seem a bit high in my opinion, but I have often believed that in the past and I was incorrect.
Mistake above, the Dec 2018 STEO has US C+C output at 12.29 Mb/d in Dec 2019 (I mistakenly typed 2018), which seems pretty reasonable. The most recent STEO estimates 12.95 Mb/d in Dec 2019 which I believe is probably 400 to 500 kb/d too high.
GuyM,
I find your argument that the completion rate might fall as majors take over the Permian compelling. I devised a scenario with a fairly high oil price assumption (Brent oil price rises to $90/b by 2027 from $56/b in August 2019). The completion rate falls gradually through Dec 2021 (from 1827 completions/month to 1744 completions/month), remains constant from Jan 2022 to Sept 2023, gradually rises from Oct 2023 to June 2024 (to 1753), declines gradually to April 2026 (1059), remains constant until 2027, rises until the end of 2027 (1073 completions per month), and sees a final decline in completion rate, reaching zero in Dec 2049. URR for US tight oil for this scenario is 82 Gb with a trailing 12 month (TTM) average peak output of 8570 kb/d, with a plateau in output between 8470 and 8570 kb/d for the TTM average from 2023 to 2028.
Obviously an assumption of lower oil prices would reduce the URR, by shortening the plateau and steepening the decline after the shortened plateau in output.
Also note that different completion rate assumptions could lead to higher or lower peak than assumed here with peak likely at any point from 2023 to 2028 depending upon assumed completion rates.
Thanks for the chart. I am not sure, just guessing. And I am not sure where they really are on first tier. Pioneer CEO says they are close to max. Second and third tier really suck. But, good enough for big energy. It’s a waiting game. Big energy does not have to move, the sick ones need to offer themselves up for sacrifice. The dead ones can wait. Big energy is not going to take on unnecessary liabilities.
GuyM,
Yes we are all guessing. I just think your guesses are quite good. The future will tell us if I am correct. The scenario is just confirmation that my interpretation (which may not be correct) of what you have been saying can easily occur with high oil prices and my typical economic and geological assumptions (which are backed up with well profile data from shaleprofile.com as well as completion data from the same source).
Chart below has well completion rate for scenario presented earlier.
Nice chart, I never dissociated Hz and vertical rigs, It’s interesting to see that Hz rigs count decreased somewhere in February 2019, while the Vertical rig count decreased earlier.
This is anyway not a plunge like in 2014-2015. But at that time, the plunge was mainly due to inefficient rigs that were still used due to the high prices of the 2010-2014, as you pointed.
The current decrease doesn’t seems enough to reduce the US production. In 2018, the Permian was able to add more than 1Mb/d of production (which was spectacular). Sure, it won’t be that high this year, but I think the idea that US oil production reached its second peak is premature.
If you read through today’s (Tuesday) RBN Energy posting, you will get a snapshot of what the effects that the new pipelines – Cactus II and EPIC – are having on Permian takeaway.
Specifically, a doubling to over 1 million bbld export out of Corpus Christi compared to a few weeks ago.
By the end of this calendar year, the Grey Oak pipe should be in operation.
Come early springtime, 2020, an increase of over 2 million bbld takeaway – yoy – from the Permian should be in place.
Price dependent, output is set to soar.
Rig count is still falling.
The opening time of the pipelines is known to everyone, so a drilling frenzy should have already started 2 months ago to be ready when the pipeline is up.
Eulenspeigel
EIA figures there are about 4,500 DUCs in the Permian and Eagle Ford combined (3,000/1,500 Perm/EF).
I realize many people are … selective … when it comes to using data from the EIA, but just throwing different scenarios around using, say, 2,000 wells already drilled but not frac’d and using production numbers ranging from 500 bbld to 1,000 bbld for 30 days running starts to show some pretty big increases in overall output.
Price, as always, is a huge determinant.
While I do not follow the Texas region too closely, I DO keep abreast of leading edge operational events.
People are going to be surprised by how advanced the completion practices are becoming in the unconventional hydrocarbon world.
The upside potential is very large, but the revenue streams continue to be a huge impediment.
Coffeguyzz,
If the completion rate increases, output will increase, even a constant completion rate results in a modest increase in output over the next 5 years or so. I agree much depends on oil prices and the financial health of the Texas tight oil producers (New Mexico as well for Permian basin output), that is difficult to predict. Doubt there will be much increase in Eagle Ford output, but Permian basin could see a 2 million barrel per day increase in output with higher completion rates, unclear if this will happen in the near term at current oil price level.
I think most of these DUCs are duds – there is no economic sense in drilling a well and not fracking it in the next 1 or 2 months.
It’s just sunken capital – it’s like renting a store at the mall and installing all the hardware, but not filling it with goods and opening it.
There have to be reasons why a DUC is a DUC for more than 2 months:
– Bad hole
– No money for calling the fracking team.
– I just like drilling 2 million $ wells
– Bad planning
– No fracking teams available (due to too strong grow)
– ???
Even when it is drilled to hold a lease (some contracts only need drilling, not producing…) there is no reason to frack it exactly now.
Output is slowly rising at the Permian at the moment, there are no signs to see this changing much.
Eulenspeigel
There are actually several reasons why wells are drilled and then not fractured right away.
As you may guess, money would be reasons #s1 through 5.
This entire “Drilled Uncompleted” category came into prominence about 4 years ago when oil prices crashed along with the DAPL fiasco in North Dakota.
(Actually, in Pennsylvania, going back almost a decade, wells were frequently drilled but not frac’d for years. Pipeline scarcity and leasing terms being the main reasons).
In ND, regulations called for wells to be turned inline within 365 days of, I believe, production casing being installed.
With the crash in prices, operators were looking at huge financial stress if the flush early months’ production revenues plummeted. ATW pricing in ND dipped below $20/bbl. at one point.
It was then that ND regulators doubled the timeframe to 2 years to turn inline with the expectations that pricing would rise.
The expected opening of DAPL provided further incentive to hold off completions.
Now, as to why drill in the first place if no frac’ing is immediately planned … again, several factors … but ‘dry hole’ not being one of them.
The planning/permitting process for each individual well can be quite lengthy.
In Texas and North Dakota, permits are usually granted within a month or less from first application. Pennsylvania regularly runs 6 to 9 months.
A huge amount of time and effort comes into play long before any permit is even requested.
Operators normally contract drilling rigs for periods of time wherein they pay less for longer contracts.
It is quite common to simply drill “x” number of wells and come back later to frac it/them as a way to – overall – save money.
This time next year, Cactus II, EPIC, and Grey Oak pipelines should be running all out with about 2 million barrels per day extra capacity.
To both fulfill shipping commitments and capture higher pricing, the number of Permian DUCs should drop significantly along with an increase of Permian output.
As always, realized revenues play a large, influencing role.
Tita,
Note that when we compare this to shaleprofile estimate of horizontal wells, it looks too high. Most of this is due to my “other lto” model (tight oil from plays other than ND Bakken, Eagle Ford, Permian, or Niobrara) which needs to be redone. Some of it might be tight oil from vertical wells (not tracked at shaleprofile), but that amount should be pretty small.
Weird inheritance. My wife’s grandfather bought 5 acres in New Mexico roughly 100 years ago, possibly hoping to grow grapes?? Somehow taxes continued to be paid and my wife inherited a slightly less than one acre share in Eddy County, New Mexico. Fortunately her cousin is a lawyer. It was leased, drilled. and pooled several years ago and the 5/6 th acre has produced income over $40,000 from several wells. The last monthly check from Matador was down, less than $500. We wonder what the future holds if anything.
A warmer climate, longer droughts, fewer wild animals and death. Your best days are behind you, enjoy.
Bingo!
We have a winner
Being 88, I probably won’t need to wait too long for death.
A tad bit pessimistic don’t you think HB, compared to the hopium you expound on the non oily side; perhaps we’ve hit peak optimism?
The richest free country in history voted to destroy it’s self. They wanted change, but hate gay marriage, people of color, women’s equality and the idea of feeling safe sending kids to school. God forbid they drive an efficient clean EV. You can lead a horse to water, but you can’t make it drink.
All of that strawman bunk you scribbled is pure ideology that only came about in the last few decades of a fantastically energy-augmented realm of existence, and is passingly tolerated only for as long as 22,000man*hours of effort in each barrel is economically obtainable. We live in a turbo-charged era of human existence, provided entirely by a one-time chemical endowment. Once that is gone, those contrived ideals you cherish -which do not comport with reality but exist in spite of it – will quickly give way to the resumption of hard manual labour comprising most of the day’s activities. Marriage will return to what it was, equality will re-balance to what it was (a biological division of responsibilities between man and women), and schools will probably become safe again. No more time spent indulging in lunatic victimology currently taught in our colleges or universities. The kiddies will have to toughen up and learn to work hard for a living. And boy, will they hate us for it.
So your children hate you for your selfishness, I’m sorry.
No, you’re not sorry for me or anything about me. Spare me and the rest of us your delusional strawman self-aggrandizing BS. Try reality for a change.
Perhaps take a second look at your own ideology and how that has been facilitated and ‘off-the-charts’ distorted by 22,000 man hours in every barrel.
Therein may be the start of an explanation for your current (and misguided) set of ideologies. It’s nice to escape to a fantasy now and again, but hey, reality eventually comes a’-knockin’.
It depends on where you live. In general, you would see a slightly warmer climate, a bit more rain, larger fruit, taller and greener trees and vegetation, Al Gore standing in knee deep water in Miami Beach explaining sea level is rising at 4 mm per year, and your neighbors driving a small pickup with a hybrid engine, because oil prices will definitely rise.
Try selling your happy talk to the surviving citizens of Barbados and Puerto Rico
Don’t know if this will matter.
Saudi Arabia’s King Salman replaced the country’s energy minister with one of his own sons Sunday, naming Prince Abdulaziz bin Salman to one of the most important positions in the country as oil prices remain stubbornly below what is needed to keep up with government spending.
Also on Sunday, the king issued a royal decree removing the current deputy minister of energy, Abdulaziz al-Abdulkarim. He did not name a new deputy energy minister.
Hi,
I have a question: all the increase in oil production in the last few years is light oil. Why isn’t there a problem with availability of diesel?
Thanks,
Michael
You still get diesel from light oil, but not as much as from heavier oil. For instance, from my wells in the EF, the API is 39. That can easily get mixed with others to get the normal amount of diesel. The higher the API goes, the less Diesel, but I have no idea what the percentages are. Someone else may be able to answer that. Also, they are currently exporting 3 mbpd of unknown mix. That was close to zero several years ago.
Here is a link that gives you an idea of distillation cut vs. crude. I always wondered whether you can get rid of the lights and still have greater than 200 deg C from shale oil that can be used in ships. There is quite a lot of >200 deg C material even from EF 46.6 API gravity material. Shale oil has very low sulfur.
1.1 mbpd diesel from animal fat and corn coming in 2021. So, the answer is that big oil expects less diesel from oil, but is going to kill a lot more hogs, and the corn crops will be safer. Ok, I am going to stop calling them big oil. The term is now big energy, they are way ahead of our guesses. Independents, see those headlights in your rear view window? Pull over, or get run over.
Hi Guym, I looked over the article you linked and it refers to a potential of 1.1 million gallons per day of biodiesel, not 1.1 million barrels. It also sounds pretty iffy.
Whoops my bad
Michael, while there is a glut of lighter distillates, the heavier ones are below their five-year average.
Still, whether you measure them as simple volumes or in terms of cover for future demand, OECD stockpiles are rising. Admittedly, much of the recent increase comes from natural gas liquids (light oils produced in large quantities from U.S. shale) which are used widely as petrochemical feedstocks. When you strip these out of the numbers, OECD inventories of crude oil plus the major fuel products – gasoline, middle distillates (diesel, heating oil and jet fuel) and fuel oil – are below their five-year average level.
I somewhat follow this item. Years ago Ron and I had a substantial discussion about Bakken vs Louisiana Light Sweet. Platts had some curious data then and it likely derived from a fairly large controversy at the time about ultra light fractions getting into rail cars from the Bakken, which were catching fire and blowing up and which had hearings in Congress going on that moment.
But overall it’s tricky for several reasons. Not the least of which is the date of assay.
First, the Krishnan dood above linked the Equinor assay page and it’s solid. There are others you can find online. Exxon has a big page:
The most eyebrow raising item on all of this is the Bakken’s history. The Director guy up in NoDak was very loud that Bakken oil had the same API as WTI. The WTI standard at the time (and for decades) was 39.6 and that was the published number for the Bakken. Then years passed and Bakken API crept upwards. The Equinor page above assays Bakken to be 43.3. That is in Aug of 2017. It has been rising since I have watched it, maybe starting 2012 or whatever.
Useful to also note that WTI, the yardstick, really is no longer a yardstick. It has changed, too. As oil flowing to Cushing from West Texas got blended in Cushing with Bakken liquid, the API number started to grow — and that was several years ago before the Permian LTO was flowing. Now that it is flowing, the API number gets even higher, and this has gotten the attention of NYMEX. Big questions of just what is being sold on NYMEX. Discussion here:
Amusing to note that Statoil’s page used to include WTI and it had risen to 42 something. There are comments in our database on this site pointing it out. Now it’s gone.
Anyway, Kerosene boils about 150C to 275C and Diesel is 200C to 350C. Comparison of yield (BY VOLUME, it’s not fair to do it by weight) says some things. Doesn’t say everything.
Important item. Geography matters. A given API from one place on Earth may not have the same diesel content as the same API from a different place on Earth. Have a look at Tapis in the Exxon assay. Look at its API.
Watcher
Your observation regarding the rising API number for Bakken output gets right to the heart of the suspicions (understandings?) of the effects of asphaltene precipitation impacting oil production in the LTO universe.
Generally, the more asphaltenes present, the lower the API reading.
As the formation pressure drops, the much-discussed “bubble point” kicks in where phase separation, aka smaller gas molecules separate from the hydrocarbon stream, and continue to the wellbore through the excruciatingly tiny frac’d pathways.
However, the remaining liquid hydrocarbons – consisting of various molecules including the large, thick (actually solids) asphaltene molecules – have their own separating process influenced by pressure depletion.
There is not only a growing appreciation of the deleterious effects of asphaltene precipitation, Bakken operators have already responded as can be seen on Enno’s site.
I refer you to the quarterly production profiles of 2018 and 2019 Bakken wells.
What you will see is a completely different profile due – in large part – to the operators not quickly flowing back the frac water shortly before turning the wells online.
The retained (underground) 200,000/250,000 barrels of water both pushes hydrocarbons to the wellbore along with preventing asphaltene precipitation and consequent pathway blockage.
If you’re blaming rising API on asphaltenes (somehow), because they are viscous (which lowers API), then removing them should decrease viscosity and raise API even more.
Yes, that is what is happening.
The larger, heavier molecules are unable to continue to make it through the tiny pathways as pressure depletion prompts them to separate from the liquid stream.
They then tend to clump together, further inhibiting production.
Without the heavies, lighter oil is produced … the rising Bakken API that you have been seeing.
I think it’s in part because europeans are using less diesel, but i’m not sure.
Here’s a podcast type interview with Adam Rozencwajg, founding partner of Goehring & Rozencwajg, an investment firm linked to natural resources such as mining, energy and agriculture. Perhaps some here will find it interesting, as I did.
Khafji is considered a northern extension of Saudi Safaniya field. Oil production from Safaniya could be secretly producing oil from Khafji which means that Saudi Arabia is benefiting from the 0 mbd production from Khafji.
“Saudi Arabia, OPEC’s de facto leader… has repeatedly called on Iraq and other less compliant countries to get with the program, but this has mostly fallen on deaf ears.”
I would not expect anything different. 🙂
At some point Saudis produce at Quota and let prices fall to punish those overproducing. Maybe they can’t afford to do that as they may need higher prices.
And maybe sustaining their own quota over a longer future is an issue and they would much rather get paid more for less and at the same time dont have to admit “we cant go higher and keep it there for many years as we are struggling with depletion and our reserves are exaggerated” ?
Baggen
Yes it is possible that KSA is producing all they can or all that they care to at current price level.
I don’t think KSA oil production depends much on price. If the price is high, they’ll produce all they can to make as much money as possible. If the price is low, they’ll produce all they can because they desperately need the income.
Frugal,
It seems their output depends very much on price in many cases. That may just be coincidence.
If the Saudi’s were strictly rational, they would cut their production in half, which would probably have the effect of more than doubling oil prices. So this would leave their oil income about the same as before and would reduce oil field depletion. Why aren’t they doing it?
Frugal,
Not sure if prices would double, but I don’t know how these decisions are made by KSA.
Some thoughts:
-they can’t halve production without damaging the fields
-it would encourage high-cost producers to invest and produce to make up the missing volume (resulting in half the income they have now)
-it might start a panic (if oil supplies actually do drop)
-it would make people think about future supply viability (everybody would talk like us!)
-It would piss off Trump
Reducing production is fraught with uncertainty and political risk.
Lloyd,
It is what OPEC/Russia at al are currently attempting. Not cutting output in half, but reducing output a bit to draw down stocks.
I have long suspected that the production fluctuations in response to price are more to do with inventory than production.
I always wondered about Saudi production and spare capacity. Why would Saudi crude inventory go down from 329 MM barrels in October 2015 to the current 188 MM barrels based on Jodi if Saudis had the spare capacity.
Krishnan,
In Oct 2015 there was a real glut of oil supply. Today the “glut” is mostly imagined by traders. Eventually they will catch on, give it another 6 months.
Dennis! We are not too far apart, again!
Yes I listen very carefully to what you say, often when I object, is is just a subtle difference of opinion (or I misread what you said). Generally we are on the same page. Either we are both wrong or both right for the most part. One slight difference is you fairly often say we have reached the peak. I agree we are close, but believe the peak is still 5 years off (or a range of 3 to 8 years). Of course I may be wrong, as has been true in many cases in the past.
Seems like we have reached peak oil for WTI in the $50s. If the world wants more oil, the price will need to go up at least $10-20. Permian rig count has been dropping steadily at this price, Saudis are uninterested in pumping more (if they’ve got it), no incentive to make a deal with Iran.
Does anyone know what the future potential of Guyana is?
Peak oil. That’s becoming more an more an elusive technical term. Valero is partnering with a co. to provide 1.1 mbpd of diesel in 2021 with fats and corn. Is that oil? Which will be cheaper?
Correction pointed out by dclonghorm; that’s one million gallons a day, not barrels.
= 0.026 mbpd?
Stephen Hren,
EXXON is still exploring. An article at OilPrice today said the company has announced reserves (I expect that should be “resources”) of 5 billion barrels of oil in the Starbroek block. There are other companies looking in offshore Guyana too.
Fernando Leanme might know.
Thanks Synapsid, sounds like it’s still a ways off but could amount to something mid decade
Dennis; I wouldn’t presume at this point to know more than a trader does. IMO, we are past peak even with shale accounted for.
The British navy ‘guards’ Iran oil flow. Economic security of th commonwealth is tied at the hip with oil price. As much as required for stability will be stolen?
I dunno. Tell that to the people who can’t afford a new electric vehicle and ask them. Most of the market. The largest part of the market is not tracked via dealer (used or new) car sales. Which are all thats reported. Been in the market as a retailer. The average truck or car we sold, was for $5000. Usually finance through some company charging three times the normal APR. These EV sales are so different from reality, it makes my mind cluttered. So when you read stated sales via the known market, it’s absolute B.S., full of sound, and signifying nothing.
GuyM,
Most cars get junked after 10 to 15 years, the fleet of cars is made up of cars that were at one time new. When I model this I look at new cars and assume cars are gradually retired at an average age of 15 years. So the percentage of new cars that are plugins gradually increases over time as prices of plugin vehicles falls as they ramp up and economies of scale and competition reduces prices. Once 100% of new car sales is plugins, then after 15 years the entire fleet is replaced, probably about a 25 to 30 year process. Of course newer personal vehicles less than 5 years old get most of the vehicle miles driven, so oil demand falls to half when perhaps 33% of the total fleet is plugin hybrids. If autonomous vehicles get approved in 10 years, then people may use their cars as robotaxis and average miles per year for those EVs may be 36,000 per year rather than 12,000 for the average vehicle, in that case each AV is like three EVs so a 3 times fewer are needed to replace the ICEV fleet. AVs might reach the approval stage by 2025, but more likely 2029. At that point car ownership may end for most people and everyone will just Uber (or most).
“Of course newer personal vehicles less than 5 years old get most of the vehicle miles driven, so oil demand falls to half when perhaps 33% of the total fleet is plugin hybrids.“
Dennis, not much reason to worry, so it seems. Unless…
“Sustainable development as techno and policy fix implies an unlikely scale of social engineering and suggests that there is consensus about what sustainability means. ‘Sustain what?’ as Andrew Revkin would ask… Are ‘sustainable’ economic and political institutions just ‘greenwashed’ versions of an industrial economy that produces crisis as it prefabricates consumable identities as Richard Kahn has argued? But if the pricing is right, the material substitutions found, the maximized energy and resource efficiency realized, then maybe we will escape limits in ‘a painless, rational process managed by economists and policy experts sitting in the control room of the fully modern, computerized society, coolly pulling levers and pushing buttons while ignoring democracy and home rule, village economies of scale, or any potentially engaged citizenry…
Does such cornucopian techno-optimism smuggle unwelcome values into ecological awareness? Under the aegis of efficiency and the growing economy, has the sustainable development discourse failed to challenge what some might call a cult of growth? Do we need to question the moral dimensions of modern technology on a larger scale? Is the 2030 Agenda for Sustainable Development adequately balancing human fulfillment with technological development?
Technologists have couched ecological crises as vast territories of growing technological and economic opportunity and natural resource and biosphere management–a shock doctrine for seizing the commons and commodifying them. To be clear, many sustainability champions are not immune to this challenge. Many of us tout the potential of offshore wind power. What of the urgent ‘need’ for Pennsylvania to increase solar PV’s share of the energy market? Are we setting up an economy that’s just less carbon-intensive and more efficient but still growing? If we are, then we should expect rebounds and the continued gross imbalance between industrialized people and the biosphere. And what’s to stop a carbon-neutral or renewable economy from being as unjust as the economy we have now? The technology won’t do it.”
Look at the cars driving on the highway. 10 to 15 years?
GuyM,
I would say for 99.5% of the cars I see it is 0 to 15 years. What do you see in Texas?
I’m not economically depressed, but I have a 2000 Nissan Frontier with 139k miles, which I intend to keep for a long time. But, there is more older cars than new. I travel all over the DFW area, and some areas have vehicles that far exceed 10 years. That’s where most of the population reside. Kinda hard to guess, but I would say your 99% is far, far off. You must live in a nice neighborhood. Most of the population don’t. I mean, geeze, I keep seeing Hyundai Excels running around, which is an absolute miracle. Worst car ever mass produced, it was cheapest for a reason. If Hyundai had not begun to buy their engines from another manufacturer for the Sonata, they would not be in business.
Dennis, I listen to you. You listen to me. That’s communication, I like it. But, the yen and the yang, is on the 914s. Everything else, can, and could be BS. We are three months behind reality. Who has been closer?
GuyM
Do you see a lot of cars older than yours? That would be 20 years. Note also your SUV has driven an average of 7300 miles per year. My guess is that you have a second newer car. My Dad drove my 97 Camry up to 2017 probably had 220k when he ggot rid of it. Maybe somebody is still driving it many cars reach the junkyard or just sit in the driveway after 20 years.
When you were in the business did you sell many 20 year old cars?
Nah, no money in 20 year old card. Trucks maybe.
Guym,
Found a source claiming that in 2018 there are 279 million registered light duty vehicles in the US.
If we do cumulative totals we find that 99% of vehicles on the road were purchased since October 2001, if the 279 million vehicle fleet estimate is correct for the US.
So about 99% of US registered vehicles are 19 years old or older. You are correct that my 15 year estimate was wrong. For cars from zero to 15 years old that is only 82% of the vehicle fleet, so we might need 20 years to replace the fleet rather than 15. It is still true that most miles are driven in newer cars, you can easily consider how many miles you drive in your newer vehicle vs your older vehicle. The only exception to this might be if you lease rather than buy, in that case sometimes people keep the miles down on the leased car, often around 12,000 per year.
GuyM,
I agree 914s are good, I also believe the “tight oil production estimates by play” are pretty good at page below.
Its too bad America can’t transition to EVs without getting bogged down in cult of founding CEO myths and subsidy for luxury brands. China meanwhile has EV co’s that actually make money (yay capitalism), something that has so far eluded Musk’s vanity project. Lots of EV ‘enthusiasts’ don’t want to, or can’t, talk about China, BYD for example; so they come off as Elon Musk Fan Bois, more than EV market trends analysts, which is kinda gross feeling. Plus BYD is just way more affordable. I believe BYD is doing public transit type electric buses in North America. Very proletariat, buses are. Not Musk’s style at all. Warren Buffet has his filthy fingers in BYD, as does Chrysler (I just still call it that). BYD made batteries for twenty years before they got into making EVs. I don’t know exactly what Musk did for the 20 years before he got into making EVs, but I suspect it involved too many Anthony Robbins videos.
Lots of companies get tax breaks from local governments, not just Tesla. Federal subsidies are available to every auto company that sells BEVs or plugin hybrid, based on battery size. The subsidies are limited after a manufacturer sells 200,000 vehicles and is gradually phased out over 24 months (100%, 75%, 50%, 25%, and then zero). Tesla is currently in the 25% phase which began July 1, 2019 and ends Dec 31, 2019.
Quite right Dennis, many co’s, besides Tesla, receive money from the taxpayers. Of all those that do, besides Pentagon contracts I suppose, I wonder how many are profitless year over year and, as well, also compensated their CEO almost $2.3 billion in 2018?
“According to The Times and Equilar, the Tesla CEO received stock options estimated to be worth nearly $2.3 billion in 2018.”
Amazon had no profits for many years. They get lots of tax subsidies from local governments, in fact local governments are trying to outbid each other for the tax giveaways they are willing to throw at Amazon.
These days its a river of profits for Amazon. 🙂
Does telsa get any federal subsidy?
I know that electric vehicles get a temporary subsidy on the first 200,000 units of model sales, but that goes to the purchaser, not the company.
And it has nothing to do with the name being telsa, it can be VW or FungShwai as well.
“Its too bad America can’t transition to EVs without getting bogged down in cult of founding CEO myths and subsidy for luxury brands.”
Yeh too bad, but only small number of people are actually bogged down by this.
Most people would/will be unbogged and move towards PHEV/EV when the price is comparable, and that becomes obvious to them.
All kinds of non-Tesla electric vehicles will be on the market in five years.
Wild cards are the price of oil and the price of batteries.
Almost everything else is in the favor of electrification.
Its great to not use petrol personally, so that it can be available for priority uses like farm equipment, emergency services, critical air flights, and long haul cargo for more decades to come.
full disclosure- I own a PHEV, and have been to the gas station three times this year. I have never used a public charge station. By and large, I get around on my own (power).
Yeh, only 32 miles. So this vehicle is prime for someone who does primarily short trips, but its total range when fully charged and gassed up is over 500 miles.
My preference would be to have a vehicle like this with a bigger battery, something like 80 miles.
Hickory,
I thought the question was battery range. Yes Chrysler claims 520 miles for your van. I agree more electric range would be nice. Not a lot of my trips would be covered with 32 miles, but 80 or 100 would probably cover a lot.
A vehicle like Chrysler Pacifa PHEV that got 80 miles on battery, rather 32 miles (as it does now), would be a huge winner. I believe the problem with making a vehicle like that currently would be the jump in price due to the bigger battery. Its ICE engine is a very good one. The overall integration between the two systems, and its control systems and performance is just outstanding.
“Norway has been hailed as a model for electric vehicles adoption with EV sales exceeding 57% of new car sales in June of this year…
…we can see that the annual cost of Norway’s EV support scheme already exceeds the annual cost of Maternity and Paternity leave pay (21.2B NOK) and also exceeds the annual Unemployment Benefit budget (14.2B NOK) and the Child Benefit budget (16.8B NOK). As a matter of fact, if Norway were to convert all its cars to EVs, the country EV budget would become the second largest government expenditure at 198B NOK, only behind the retirement pension budget at 223B NOK…
…Norwegian road traffic emissions statistics don’t capture a vehicle lifecycle emissions which are much higher at the outset for an EV due to the heavy CO2 emissions associated with battery production. This lifecycle gap in the data exaggerates the amount of CO2 emission reduction due to the displacement of emissions from where the car is driven to where it is produced. Another factor we need to consider is the continued improvement in fuel efficiency of newer ICE cars, which means as the ICE car fleet is renewed associated CO2 emissions are reduced naturally. Thus, when we take in consideration these factors, it is probable that the actual four-year reduction in Norwegian CO2 road emissions due to EVs is in the low single digits at best…
In light of the above, it is fair to say that Norway’s massive investment in EVs in eliminating a negligible amount of CO2 comes at a great financial cost. One reason for the muted impact of EVs on Norwegian gasoline and diesel consumption is that 64% of Norwegian households that own an EV also own an ICE car. Two cars households used ICE cars for 60% of their driving needs and EVs for 40%. The second car effect is apparent in the passenger car data: In 2014, Norway had 2.55M passenger cars (including 50K EVs and PHEVs) as compared to 2.76M passenger cars (Including 300K EVs and PHEVs) in 2018. This shows that the ICE fleet has remained constant and that EVs are supplementing ICE cars and not replacing them…
Another interesting feature of the Norwegian EV market is the split between the have and the have nots. The likelihood of purchasing an EV is 15 times higher for the richest 25% of Norwegian households as compared to the bottom 25%… The fact that 84% of the richest households own at least one additional ICE car against only 21% of the poorest households seems to indicate that without access to a second ICE car, owning an EV – despite all the incentives – is less appealing to the average person… In many ways, Norway’s EV support policy is a second car discount and living cost subsidy mechanism for the rich…
Norway has pursued its extreme EV support policy due to the seemingly mistaken belief that one can both fight climate change and maintain a car culture. Considering the limits of of today’s personal vehicle technology and the limitations of public finances, the simultaneous pursuit of these two conflicting objectives is perhaps a well-intentioned folly.”
“I also typically drive my new cars more than the typical lease mileage.
…my wife didn’t like the Prius, she wanted something nicer, she likes her new Model 3 so it works for me…
Have you ever driven a Model 3, my wife loves hers (she lets me drive it on weekends)?” ~ Dennis Coyne
How many cars do you and your wife own (lease?), Dennis, and what kind of voluntary personal degrowth/simplicity/impoverishment forms are you folks pursuing and considering? What do you think you would you be willing to?
Offering to car-share and/or chauffeur the ‘Model 3’ (Tesla?) for the local neighborhood on the weekends?
What do you drive, if anything, weekdays, and what do you think your wealth is, relative to the average person living in the US? >25%?
Hi Caelan,
2 cars owned. Camry Hybrid is other car. Income above average.
Electric vehicles don’t sell in Spain, because the subsidy isn’t high enough. We do see hybrids, they get about 10% to 20% better mileage than my 5 speed diesel…but they cost a lot more. I believe I’ll buy a plug in hybrid in a few years, but I live in a beach town and usually drive short distances. A fully electric doesn’t make sense, because we have mountains, and it gets hot in summer. This explains why we don’t see electric taxis or buses.
With mountains they make lot’s of sense since you don’t use more energy than driving flat. You get most of the energy back driving down.
Current batteries have a heat problem – wait a few years until solid state batteries are out. They tend to love hot weather, so no more energy waste for cooling batteries. Toyota will present a car with them next year on Olympia, and a chinese company already started a test production line to optimize industrial production.
Double density and no more explosions are another goodie.
The price of pretty much everything is pretty much all the same trade now. Bonds are bid to ridiculous prices because everybody believes they will be able to unload them to central banks at a profit before maturity. Stocks are bid because if for any reason there was a sustained sell off. Central banks will step in.
Watch non-farm payroll data and inflation data in the US. If they continue to be soft oil will be bid because of expectations of the FED to do something about it. Bad data equals higher oil price now days. The worst the data becomes the better for oil price. While good data equals lower oil prices for longer.
Commodity currencies AUD and NZD look like they have finally made a bottom against the dollar. Which if it holds it’s a very positive sign for oil price. Because it means dollar weakness is coming. AUD and NZD bottomed out against the Euro about 4 weeks ago. AUD, NZD and might as add the CAD or canadian dollar in there as well have be losing ground to both the US dollar and the Euro for 5 years straight mainly do to dollar strength. That is why this potential turn in these currencies against the dollar is a very good sign for price of oil.
How do you deal with $24T debt if you allow rates to rise. You don’t. You got no inflation? Then the debt doesn’t erode. If it doesn’t erode you dare not let rates rise.
You got no inflation? Then why would the price of anything rise? In fact, the issue of not allowing rates to rise because of $24T extends to inflation. You can’t let that rise, either, or it would drive up rates — which $24T can’t permit, so inflation will be attacked, and not with the usual toolbox because $24T locks that. “Unconventional tools” will be required to push inflation down, while declaring that you need to have inflation.
The world ended in 2009. It’s all pretense since then, and any effort to make it not be ended is prevented by $24T. People need to begin all thought about circumstance with the $24T debt. Any expectations have to recognize how overwhelming that is. Fiscal stimulus (aka deficit) is now 5% of GDP ($1T). Just 1% rise of rates on $24T would take stimulus to $24T plus 240B. Where’s that $240B going to come from?
I get confused from your changing statements. I’m not trading oil, which you seem to do, but I can’t see how you can take positions and profit when you change your mind all the time.
“Bad data equals higher oil price now days.”
So now you believe the oil price will go up?
When you state that oil will go to $20 – do you think the economy will be super strong then?
RRC took away their completions, plugging and permits report. The only use I have of this site, now, is for individual wells.
Looks like they just reworked the site for updating, here is the graph for completions, even if it’s not 100% accurate month for month, because always some delay, as discussed – the tendency can be seen.
oil completions year to date reached 83 % of the 2018 numbers and drilling permits for oil/oil&gas are now at 85% of the 2018 level.
Thanks Envision,
In 2017 Texas C+C output rose at average annual rate of 688 kb/d, for year to date oil well completions 2019 is at 120% of the 2017 completion rate. In 2018 Texas C+C output increased by an average annual rate of 1043 kb/d and the 2019 completion rate is 83% of the 2018 rate year to date.
If the output increase is proportional to the completion rate this would imply in 2019 either 0.83 times 1043 or an annual rate of increase of 866 kb/d if the completion rate should remain at 83% of the 2018 completion rate for the entire year. We could also use the 2017 annual increase which implies 1.2*688 or an 825 kb/d increase in 2019 if this relative completion rate continues for all of 2019.
In both cases these estimates seem way too high. I think Texas will struggle to reach a 400 kb/d annual increase in output from Dec 2018 to Dec 2019.
Yeah, but I think with low price enviroment present today, they lowered completions and drill for the best rock with the longest useful lateral length, so actual 2019 production per well could be a bit higher then 2018.
Yeah, it’s reached about 200, and will struggle to get much higher into 2020. My guess. Permits for August are up, but nothing to write home about. August permit’s oil is definitely not going to be here until 2020. And, they did that in 2018, too.
GuyM,
They have plenty of permits for the stuff they want to drill and there are quite a few DUCs as well.
Envision,
Pretty sure oil prices are better than 2017, they have been high grading since 2015, that is nothing new.
Yeah, you keep talking about DUCs, and so does everyone else. But, they take an $80+ price to bring online, and the production is lousy to overall. They are tier two, at best, and most are tier three (less than 100k EUR). Otherwise, they would NOT be old time DUCs.
GuyM,
We don’t really know the age of the DUCs, there will always be some inventory of DUCs, as it takes time to complete the well after drilling has begun. I don’t really mention DUCs all that often. Approximately 10,000 more permits have been issued since 2015 than the number of wells reported as having been completed by the RRC in Texas.
Shale Profile has about 2500 Permian DUCs about a year ago (Sept 2018), this includes only horizontal oil wells, vertical wells are not included in the shaleprofile data.
Dennis,
It would be really interesting if the age of DUCs could be determined but ill take your word for it that such information is not available.
Personally i have just had this feeling that a lot of these DUCs are basically garbage and will more or less never be put into production unless oil price increases a lot.
I’m guessing that the companies that drilled those has a fairly good idea about the well and how it will produce if they spend the additional funds on it to bring it into production, if they know its crap they will probably not do it and try another hole instead.
Could the reason be that if you refuse to acknowledge that it was a dud, then you dont have to write it off and admit it was capital wasted? Instead you can keep it on the books for as long as you want as “capital invested/asset”.. and motivate that with “we are just waiting for the right time etc..”
Baggen,
An alternative explanation is that there is an inventory of DUCs that is needed to keep operations flowing smoothly. As the number of average completions increases the number of DUCs will increase as well, just the nature of the beast. So in 2016 the average number of horizontal oil well completions was about 188 per month and in 2018 the average completion rate was 427 wells per month, basically it looks like the oil companies like to see about a 5 to 6 month inventory of DUCs. There may be a few of these DUCs that are not worth completing, but we don’t really know how many.
Here is shale profile for Permian, DUCs.
In the early drilling, they drilled a lot of wells outside of the four county sweet spot in the Delaware. They brought some online, and were extremely disappointed. A lot of gas and condensate, not so much oil. When WTI gets near $80, you may see some DUCs come alive. At this price, they are all dead DUCs, except the ones currently drilled. There is no reasonable other explanation, as they are not short completion crews. Why would they waste cash! No different than the EF, just laid out differently. They will eventually come to the same conclusions in the Permian that they came to in the EF. In time.
When you plug a well, the whole thing remaining is now an expense, along with the plugging costs. Do you think these dingbats can afford to show that? No, they will sit on these “assets” hoping that oil goes to $150 or more. They certainly don’t want to treat them as expenses.
The horizontal drilling has a hidden cost. They may not be “dry holes”, but have some oil. Just not productive based on current oil prices. Vertical wells had one step. You had to get what was there, as you already laid out all the cost. On a horizontal, there are two steps. The second being the most expensive. All you have shown, is more proof of my explanation.
I have 6 more wells to be drilled Oct or Nov, some they may bring online, others may go into the balance sheet. Who knows? I keep saying, they know what they can expect, after drilling it. Pretty much fact. I have no drilling experience, but my family did. I’m just a worn out CPA, with forty years experience. Why do you think the majors are waiting? They don’t want to buy the miserable balance sheet by absorbing the company, they just want to buy good assets (more explicitly, the leases) when they go belly up. They will start out Chapt. 11s, and migrate into 7s. That didn’t happen last time, because there was still a lot of stupid money.
Shale will continue on. Just not as historically expected.
GuyM,
Not very clear when the “early drilling” in the Delaware occurred, but let’s say it was up to mid 2016 when DUCs fell to just under 1000 in the Permian basin (we will assume that all of these wells are “dead DUCs”, even though that is not very likely, in order to strengthen your argument). In Sept 2018 there were about 2400 DUCs (the fall off after that is an RRC and New Mexico reporting artifact, all the data is not in yet) so if we subtract 1000 that leaves 1400 DUCs which are still “alive”. Perhaps this number has fallen a bit due to rig count falling, but my guess is that by 2018 they had figured out where to drill.
Also note that even a 10% fall in the completion rate (annual rate) to match up with the 10% fall in rig count over the past year, doesn’t lead to a decline in output, just a slowdown in the rate of increase. Eventually oil prices rise and completion rate either levels off or increases. There are a lot of pipelines being built, this will lower transport costs as the midstream companies will want to fill those pipes. The lower transport cost helps the price at the wellhead.
Dennis,
Thanks for input, that sounds very possible and logical that duc inventory trends completion or runs in front of it.
If completions start to slow down then i guess it would ve drilling that decreases if this is the case and duc inventory is used more.
As you say, its a guess unless we could have age and make more educated guesses on dud duc %
Thanks envision. It took them about 4 days to update.
You will start seeing more and more articles like this one as we approach the oil scarcity of peak oil.
There is widespread disagreement about almost everything regarding the future of oil supply.
However, a world oil supply crunch may be coming in the next few years.
The long-term problem for shale oil isn’t just low prices – it’s low reserves.
Long Snip.
So, the conclusion is that there are too many variables to predict exactly what world oil production or what the oil price will be at any time in the future, but at the current and projected rate of shale oil production, all of the proved reserves of will be depleted by at least 2024. With US shale oil production out of the picture, there may be a significant shortfall in world oil production. Since most of the potential future world reserves still lie in offshore fields, it is most likely that offshore production would have to come back to take up the slack. Though, the lack of investment in this area in the last few years may make things a bit difficult here.
However, it is unlikely that shale oil production would stay elevated and suddenly stop in 2024. More likely, there will be a slowdown in production before that date and at least a pickup in offshore exploration & production activity beginning in the not-too-distant future. Indeed, the end of the shale revolution might already be in sight with a substantial decrease in new investment in the light of bankruptcies that are now occurring. The high level of debt has caused 28 frackers to file for bankruptcy this year, and the number is expected to rise when about $137 billion of debt will mature between 2020 and 2022. And any increase in the oil price from now on may not be able to fully compensate for the massive debt here.
Moreover, there is a good chance, for reasons that I’ve already stated, that offshore may not be able to respond quickly enough to fully compensate, at least in the short term, for a significant decrease in shale oil production; bringing with it, of course, an appreciation in the oil price.
A 5% recession (Trade War) would ensure a 5% decline in oil usage… bankrupcies faster?
It’s not a 1:1 relationship.
And do you even know what a 5% recession is in GDP growth? That is how it’s measured, after all. That would be a greater decline than 2008-2009. How do you get that with 5% of GDP fiscal stimulus ($1T deficit on $20T GDP) and the ECB doing QE, neither of which were happening in 2008-2009?
It will take a nuclear war on US soil or plague or something for those kind of numbers over entire years.
Ron,
You asked if I knew why Petroleum Supply Monthly was delayed. I came across the following from the EIA which offers an explanation.
A technical challenge occurred causing a delay in the publication of the Petroleum Supply Monthly (PSM). We are working diligently to ensure the resolution is thorough and meets EIA’s quality standards. We will provide an update as soon as available.
A technical challenge occurred? That don’t really tell me much. What is the definition of a “technical challenge”? Could it have anything to do with revisions in previous data? Anyway, by tomorrow, the delay will be 11 days. That’s a long time for a technical challenge.
Ron,
They changes the page, earlier their was a much more extensive discussion having to do with rail shipment data being messed up, but they claimed the totals were correct.
But, they are really “challenged” at this stage, Ron. Means none of their estimates are not proving close. I mean, if you choose 2050 as shale peak, yeah, your pretty much “challenged”. The only thing that’s real in EIA website is the monthlies 914, three month old drilling info data (which won’t show), and I don’t have a clue what else. I mean their STEO has to be constantly changed to reflect a minimal understanding to what the EIA monthly 914s from the companies are telling them.
GuyM,
The EIA’s AEO 2019 has the peak in tight oil output in 2031 at 10.28 Mb/d. Tight oil output falls to 8.4 Mb/d by 2050 in the reference scenario (most likely case).
Note that I would agree this is too optimistic, I expect a peak in 2021 to 2028 (best guess 2024/2025) at around 8.5 to 10 Mb/d, depending upon the rate that wells are completed. URR will be about 75 Gb, the EIA’s AEO reference case has tight oil output from 2006 to 2050 at 123 Gb, about 48 Gb too high.
See page linked below
I was wondering if anyone here has “solved” or could explain the cause of the dramatic rise in “unaccounted-for oil” in the U.S. inventory data.
Thanks for any insights. Doug
Doug,
It is a balancing item to make the numbers match, in short it means the data is screwed up, and nobody knows the answer for why the data doesn’t match up. One data set is too low (or too high) or the balancing data set is too high (or too low) or some combination. Unaccounted for oil is just an accounting line to make the numbers make sense, when they don’t.
Thanks, Dennis.
My question is not why they have that “plug factor”, but why has there been a massive increase in it the last several years. No one seems to have an answer.
I think Krishnan had the best explanation, we should ask him. It’s fairly complex.
Robert Merriam of EIA thought plant condensate (not crude) has been bought by refiners over lease condensate (crude by EIA definition). Both are derived from knocking out C5 and heavier from NG stream. Crash in NG price would have made plant condensate cheaper. There is not much difference between plant condensate and lease condensate in terms of composition.
Now it is also possible to isomerize these condensate to increase octane values for gasoline pool. KBR announced availability of such technology.
What I see is that plant condensate is masquerading as crude elevating adjustment factor. I also think that this will continue and gasoline production will increase by about 500 KBD.
We are still not there yet. We may be with supply, but nobody has a clue. From here through the next two quarters, prices will be determined by the magnitude of Trump tweets, or OPEC farts. Because, there is no intellect in markets.
Primary vision reported frac spreads at 9/6/2019 as 390. That’s down from an average of 462 in second quarter 2019, 450 in July and 416 in August. With oil production basically flat from Dec 18 to June 19, a 15% drop in spreads by September portends dropping production.
Of course we may have to wait until EIA August or September monthly’s come out at the end of October or November to see these reductions. I doubt the EIA weekly models will pick up a change in trend.
Russia crude production, including condensate, peaked at 11.05 mbd in Dec 2018. In May 2019, it was 10.71 mbd in May 2019. Was Dec 2018 an all time peak for Russia or will there be a new peak? https://www.eia.gov/beta/international/data/browser/
Data from Russian Energy Ministry
This graph looks to be in thousand tons per month. It would need to be adjusted to tons or bbbls per day to show trends. Notice the huge drops in Feb both years.
dclonghorn,
Using same data set, but dividing by days per month to get thousands of metric tonnes per day. Data at link below.
Thanks Dennis that’s a much more interesting graph although I’m not sure exactly what to make of it. The big increase before the Dec 18 Opec + cuts is evident as well as the bounce after the pipeline problems they had a few months back. I suppose in peak oil terms it might be an undulating plateau.
We can wait a year to see if Dec 2018 peak is exceeded but it appears that Russian oil production is on a peak plateau as shown by production since 2017. https://minenergo.gov.ru/en/activity/statistic
Seems to me they boost output before negotiations with OPEC for quotas.
A plateau is probably a good guess, I think they will maintain current output levels unless oil prices rise, when oil price goes up they may invest more and boost output.
Outstanding article, by Matt, detailing the Asia countries trend in oil production and consumption,
with huge geopolitical implications.
Guy- “So is the difference in our population vs theirs.”
I assume you are referring to the rapid growth in oil consumption of China and India, vs USA (and Europe)?
If so, yes, population growth is one aspect. They have grown much faster than we in past 3 decades.
And more importantly, they are both in the process of industrialization and increasing wealth of individuals, companies and local governments. This allows purchase of fuel to run equipment that was never available widely before. Imagine the changes in the USA from the 1920’s to 1990’s condensed in to 2-3 decades.
And also China consumes a considerable amount of energy in the production of exported goods. In effect, that fuel consumption and pollution is by and for the citizens of other countries who have contracted with China to produce the stuff for cheaper on their turf.
And its not just those two big countries. There are similar zones in many countries, like Korea, VietNam, Malaysia, Thailand, Philippines, etc.
Hickory
China consumes the majority of the oil.
Most oil consumption is unnecessary, used by people driving alone in cars.
Most people in Europe can get to work by public transport and Chinese dictatorship realizes they must provide alternatives to petrol cars.
Hugo, some people express hate of another people because they
recognize that previous advantages they held are no longer in play, and they
are afraid of competition from highly motivated and organized participants in the ‘game’.
You do have a heavy pattern of expressing great disdain for China.
2018 Oil consumption per capita (bbl/day per 1000 people)-
UK 25.7
China 7.0
India 2.6
You could post this link as a response to about 90% of comments from Cornucopians.
Cornucopians don’t care about peak oil. It is a non-issue for them.
For them:
Human ingenuity > laws of the universe.
A 3.1 Mb stock draw for crude plus products, 6.9 Mb for crude alone.
If we leave out propane and propylene and “other oils” (does not include gasoline, jet fuel, diesel, crude, or residual fuel) which total 2 Mb added to stocks, then the stock draw is 5.1 Mb for week ending September 6, 2019.
If we look at year ago stock levels and leave out the increases in propane/propylene and “other oils” (an increase of 48.7 Mb). Then Total stocks of Petroleum liquid fuels and crude (including SPR) were down by 4.7 Mb from one year ago.
Seems we have a glut of bottled gas and “other oils” (not including crude, gasoline, diesel, jet fuel, ethanol, and residual fuel.) The traders don’t seem to see this.
Well productivity is “tracking WAY below our model,” analysts Marshall Adkins and John Freeman wrote in the report. They note that U.S. oil production is up less than 100,000 bpd over the first seven months of 2019, compared to the 600,000-bpd increase over the same period in 2018.
The reason is that productivity improvements have suddenly come to an end. Since 2010, initial production rates for the first 30 days of production (IP-30) improved by 30 percent annually on average, according to Raymond James. That was largely the result of the “bigger hammer” approach, the bank said. In other words, drillers threw more of everything at the problem – more money, longer laterals, more sand, and more frac stages. Earlier this decade, IP-30 rates were growing by roughly 40 percent per year. But that slowed to 11 percent in 2017 and 15 percent last year.
However, in the first seven months of 2019, IP-30 rates are up only 2 percent, compared to the 10 percent prediction from Raymond James. Part of the reason is that there is simply a limit to “more, longer and bigger,” the analysts said. “We believe that this represents clear evidence that U.S. well productivity gains are beginning to reach maximum limits and may even roll over in the coming years as the industry struggles to offset well interference issues and rock quality deterioration.” Even 2018 figures may have been a “one-off” increase as the oil majors – Chevron and ExxonMobil – escalated activity.
“Recent Permian IP-90 well productivity trends are especially dire,” the analysts wrote. “While U.S.
IP-90s declined 2%, Permian IP-90s declined 10% relative to 2018.” Because the Permian is the largest source of shale production and the most important source of growth, whatever happens there will determinate the trajectory for U.S. production figures on the whole.
Its an interesting read!
Read it. Good read. I had it posted as one of the replies to Dennis, above. But, it is in some need for repetition (or, it’s own post) thanks!
And, it’s what I have been saying for about a year. That is, I read about it a year ago. Each shale has produced its own self limiter as far as early projections. You have to chase it in the Permian. Pioneer has upped their spacing to over 800 ft. For a comparison, that’s twice the spacing on our wells in the EF. Plus, the CEO reports the sweet spots for most everyone close to the end. Pioneer is in the Midland. EOG is in the Delaware, and reports 400ft spacing, but it looks like they are alternating formations.
And based upon your other post on completions, above, their 350k bpd increase projection for 2020, may be a tad high. They are beginning to catch up.
Double spacing than planned hints to half size of reserves than thought.
And half the time until all acres are used up – until they plan later to drill again in the middle, when the oil price is > 100$. Pressuring up the old dead wells with water and fracking a new one in the middle then.
My guess is they would get better results by drilling outside of the sweet spots when oil prices rise.
And the result is:
The LTO reserves are only half of the official values – which are calculated with the tight spacing. So not 73 Gb(EIA), but only 37.
Eulenspiegel,
If average lateral length is 7300 feet and wells are 100 acres then well spacing is 600 feet, this is the standard assumption of the USGS Delaware Wolfcamp study.
For all of the Permian basin the USGS has the TRR at about 74 Gb for their mean estimate (this includes the Midland, Spraberry, and Delaware studies). For reasonable oil price scenarios and economic assumptions the economically recoverable resources will be about 44 Gb for the Permian basin (about 5 Gb has been recovered to date so 39 Gb to go, if the USGS mean estimate and my economic and oil price assumptions prove correct).
For all of the US my economically recoverable resource estimate is about 74 Gb, with about 60% of the total from the Permian basin.
Also note that the EIA reference scenario for AEO 2019 has US tight oil at 123 Gb from 2006 to 2050 and has tight oil output at 8 Mb/d in 2050.
That estimate is not very good in my opinion and is higher than the USGS mean TRR for US tight oil (which is roughly 110 Gb).
It’s a normal of, at least, two miles now. At 800 ft spacing, that almost doubles your 100 acres. And there are sweet spots, and not so sweet spots. USGS is not producing anything that I know of. Heck, mine in the EF are at 12,000 feet. If they are as long as mine in the Permian, it would be 220 acres with 800 feet. And, I think they are, or longer.
Looked at the USGS report. Upper Wolfcamp has approximately 5 million acres, with the Midland being about half of that. Or, roughly 7,500,000. If 25% of that is sweet spot, then that’s really only about a year of sweet spot left. As says the CEO of Pioneer. Double that for the Spraberry. I’m not talking barrels, I’m talking land area. I used 500 completions per month.
GuyM,
In the Bonespring the laterals are longer about 10,000, USGS has 150 acres for those wells. Perhaps Pioneer has poor acreage, I believe you said EOG is doing 400 foot spacing, Pioneer 800, so perhaps the average is 600, not sure we have data on this. A 150 acre well with 10,000 foot lateral implies a spacing of 660 feet.
At least for the Bakken, the USGS estimate looks like it may prove pretty accurate, perhaps the TRR estimate is too optimistic for Permian basin, but generally the USGS mean estimates have been pretty conservative. At a maximum price of $90/b reached in 2026 and an eventual fall in oil price after 2035 (not a very steep drop), and if the USGS TRR mean estimate proves correct, then the ERR for the Permian basin will be about 44 Gb.
That’s 180 acres. And EOG is doing 400 ft spacing, alternating spacing, the equivalent to about 800 ft spacing per formation (bone springs, Wolfcamp. Pioneer is probably doing the same thing in the Midland with Spraberry, Wolfcamp.
I’m having real difficulty working this out past 6 years, based on spacing and available acreage per USGS. Which is far from being all sweet spots.
GuyM,
I focus on basin averages, that is what is reported in the piece I found. Just because one company claims their average lateral length will be 9800 ft doesn’t really tell us what will happen. They also claim an average EUR of 1.6 million BOE for their average well in 2019. If you believe that, I have a bridge to sell you. 🙂
As I suggested some plays such as Bonespring have longer laterals, Wolfcamp wells tend to be shorter, an average of 7200 feet. Note that most of the tier 1 wells are in the Wolfcamp.
Don’t try to sell me the bridge, until you can convince me we can drill enough wells on the limited area that exists. EOG spacing in the Delaware. But, as obvious, all lie on the EUR. Guess they have lousy acreage, too. Because if they combine Wolfcamp and Bone Springs wells, the average as listed is over 800 feet spacing, the lateral length is admittedly less, but still substantial acreage. My guess, it averages around 150 acres. Not per well, but some wasted space. http://investors.eogresources.com/Cache/1001255228.PDF?O=PDF&T=&Y=&D=&FID=1001255228&iid=4075407
Ok, so your conclusion is that pioneer and EOG are the lousiest producers in the Permian? EOG made good money, and pioneer came close, even after firing 25% of their workforce, and other adjustments. The other little piggies had none. Because, they drilled stupid cube wells, and ran their wells too close together. The benefit of the combined drilling in both formations, is they use the same platform for drilling and completion. What’s wasted is acreage over other costs. They must figure other cost is higher. Acreage is dead cost. And, we are still not considering that all of the acreage is not sweet spots. We can crunch historical numbers, but the reality rules the day.
To me, 150 to 180 spacing appears to be attractive now, but it will get worse. Trust me, I want to buy your bridge. At a discount.
GuyM,
Just checked shaleprofile.com. Enno claims in June 2019 the average lateral length in the Permian basin has increased to 9000 feet from 6000 feet in 2013, so if the increase were linear (I do not have data to confirm this) this suggests about a 500 foot increase in lateral length each year from 2013 to 2019. Since 2016 average productivity has been stagnant (not accounting for increased lateral length or proppant intensity.) This indicates a fall in productivity per hundred feet of lateral from 5120 bo/100 feet in 2016 to 4553 bo/100 feet in 2018, about a 5.5% annual decrease in productivity per foot of lateral from 2016 to 2018.
In short average well productivity in the Permian basin has only been maintained by increasing the average length of the laterals and increasing proppant density (this has doubled over the past 6 years).
GuyM,
Keep in mind that I do not expect the URR will be equal to the TRR. The TRR is 75 Gb for the Permian basin for the USGS mean estimate. For my $90/bo oil price scenario (maximum price is $90/bo from 2027 to 2035) my recent scenario has about 44 Gb of output from Permian basin.
Also the current average Permian well has an EUR of 387 kb vs 253 kb for the best wells modelled by the USGS at 100 acres, so a factor of 1.5 better. Let’s assume these wells are 150 acres and 9000 feet, that gives a spacing of 750 feet, pretty close to the 800 number that may be optimum.
Also note the $90/bo scenario has 133k wells drilled for the 44 Gb vs 350,000 wells to reach the USGS TRR, though those 350,000 wells would be smaller acres per well (100 vs 150), so we might have about 233,000 wells to reach the TRR (at 150 acres per well). So the comparison is 133k to 233k wells from ERR scenario to TRR scenario.
This points me to a possible error in my scenario, thanks. (I was erroneously using 350k wells, and should have been using 233k wells).
Based on estimates from shale profile the average well productivity for Permian basin wells has been pretty steady from 2016 to 2018, it is too early to estimate the productivity of 2019 wells.
EUR for 2016 is 384 kbo, 2017=386 kbo, and 2018=387 kbo, for the average 2017 well the gas EUR is about 300 kboe so overall EUR for 2017 wells including oil and gas is 686 kboe. Gas sales can help to offset LOE, also there is probably about 30 kb of NGL that can be extracted from the natural Gas, which is an additional revenue stream. Based on this data and assuming natural gas gets $2.50/MCF at the wellhead the breakeven oil price for the average 2017 well would be $48/bo at the wellhead for a well that costs $10 million. The well pays out in 63 months. A 10% annual discount rate is used for the discounted cash flow analysis.
Oh, they are going to win. They have the surface area. They have been the target of abuse. They will have oil remaining when others do not. Why would they be kindly disposed towards governments that have sanctioned them?
They will be willing to trade whatever they produce beyond their own consumption. But not for printed pieces of paper. For actions. Like unilateral disarmament.
Countries will refuse? They will shrug.
And who will they choose to sell to? Will they see China as an ally, or a threat?
There is always the save it for our grandkids option.
And no reason they can’t insist on Chinese disarmament, too.
Here in the USA, we do act as if oil is renewable or endless in supply. We act like Renat Muslimov speaks.
If we thought there were limits, we would have a plan to produce slowly at a longer sustained rate, trying to stretch out domestic production for as long as feasible.
We would purchase oil from abroad whenever the price was below a certain threshold, rather than consume our own resource as quick as possible.
But instead of long term planning, we rely on the market to direct the decisions of thousands of operators.
And as has been pointed out so many times- the oil market is extremely dysfunctional. The signals a producer gets from the market are extremely distorted in both time and magnitude.
Its a broken system, so we do act as if the Russian is correct.
Some people would counter that the market is a better determinant of industrial policy than any sort of central planning. I would generally agree, if the market was at least somewhat transparent, and timely, and if a product was truly renewable. Like corn for example.
“Some people would counter that the market is a better determinant of industrial policy than any sort of central planning.”
With the Pleistocene ape at their heart, perhaps they both suck.
My wife and I made two weekend round trips from Love Field to Boone’s Panhandle Ranch,in Boone’s jet, together with assorted Amarillo and Dallas friends. I had known Boone since 1945.
Table 5-4 is incorrect as the US states are not matched with the right production numbers. Eg Alaska produced 4.98 mbd in June as in chart below. Graph 5-7 shows both US crude weekly and monthly for 2019 and hasn’t increased much since Jan 2019.
They have mixed up Alaska and Texas
OPEC MOMR Table 5-6 shows OPEC forecast of tight oil plays with Permian being the largest contributor.
Lol, yeah that’s pretty messed up. They have Colo and the GOM switched too.
OPEC oil monthly report makes sense.
Non OPEC supply has increased by 2 million barrels per day.
Consumption has increased by 1 million barrels per day.
OPEC has therefore cut production by 1 million barrels per day to stop prices falling any further.
They also see very similar increases from 2019 to 2020.
My base scenario is that we will end up year with lower US production than that in Dec 2018. Next 3 months will be crucial.
There is only one thing: “The market can remain irrational longer than you can remain solvent.”
Peak oil is when the fat lady sings.
Propably when US shale is falling permanent because of depleted A and B+ locations, not a temporary dip because of low prices. As discussed here in the forum, 5 to 10 years in the future. Until then a lot more conventional giants will be in terminal decline, too.
With only B and C locations left they can drill what they want, they won’t keep the red queen on distance any more.
There could be some magic by bringing Iran and Venezuela back to market in full power – but would have to be timed. Venezuela back in the 30s would lengthen the top.
By then the Bazhenov formation could well be producing oil.
The Russians are gradually getting the technology to develop their shale fields and with higher prices in the coming years there is a good chance they will produce most of this resource.
They want to start lifting it commercial 2025(from article). And propably not in a wild frency like in the USA, but ramping up slow for replacing their aging cheap producing giants. So I think it mostly will hold russian production even for at least 20 years, +/- only a few million bpd.
No silver bullet, it’s a 20-70 billion barrel ressource. And the russians need 4 every year to stay even.
Additional, it’s in very cold climate region in Siberia. So without extra effort fracking is only possible in the summer months without risking ice cubes in every water hose. So no frency, but steady production more like in a normal field. By company fracking teams moving from site to site, building road and pipelines on their way in the most cost effency way. Perhaps they even build company railways for all the transport tasks.
Eulenspiegel,
It is pretty darn cold in North Dakota. They slow down a bit in winter, but for 9 months of the year that can go pretty much full bore, Russians think 0 C is warm weather. 🙂
Note that the resource is about 80 billion tonnes, that is 280 Gb, perhaps half is economically recoverable which would be 140 Gb. By the time this resource is ready to be developed oil prices will start to fall and it may never become economically viable. We will find out in 2025, I expect oil prices will start to fall no later than 2040, so if it is developed at all, probably no more than 25% of the TRR will be recovered, so perhaps 70 Gb would be a reasonable WAG.
Permian Basin horizontal Oil Rig count
Question Dennis: does anybody still drill vertical wells?
Frugal,
Yes, but most tight oil output comes from horizontal wells so I focus on that.
The Permian is layered with fields, the upper ones have been producing over 50 years with vertical wells. Before the price drop in 2014 and 15, they were drilling 800 to 900 vertical wells a month in the Permian. It has dropped to a little over 100, but could kick back up if prices rise. And, as shallow sands can attest to, there are a quite a number of shallower formations, like the Wilcox sands, all over Texas and other States. In general, their initial output is much lower, but they produce a lot longer.
GuyM
Yes they are still drilling vertical wells. Only enough to keep output roughly flat most of the tight oil wells being drilled are horizontal the vertical wells for the past 12 months in the Permian are primarily conventional wells.
In response to your last thread. I really have not kept up with the STEO since last year, because it looked like garbage. They really have lowered their expectations. But, the “myth” keeps being carried on with the likes of these jokers:
https://www.rystadenergy.com/newsevents/news/press-releases/US-oil-to-eclipse-Russia-and-Saudi-Arabia-combined-by-2025/
This guy is head of shale research at Rystad.
From Rystad “US liquids production is forecast to surpass 24 million barrels per day over the next six years”. That’s 24 mbd – that’s not possible. Somebody needs to email Rystad and ask them what are their assumptions to get to 24 mbd.
Who knows. Dennis’ predictions are realistic. EIA is not.
https://www.eia.gov/todayinenergy/detail.php?id=38852
GuyM
EIA prediction longer term through 2025 for USL48 excl GOM is pretty reasonable and even STEO through 2020 is pretty close perhaps 200 kbpd too high in Dec 2019.
Elsewhere I have shown that the STEO in Jan 2018 underestimated Dec 2018 output by over 900 kbopd.
So yes the forecasts are far from perfect sometimes too low other times too high. AEO2019 reference scenario is reasonable up to 2028. After that it is not realistic at all decline will be steep by at least 2028 after 2025 peak of about 14.5 Mbpd.
Tony
That is C+C and NGL. Current level is about 17 Mbpd. I agree 25 is an overestimate but 20 Mbpd seems possible. Not too sure on NGL.
Tony,
I was mistaken, the June 2019 level is about 16.8 Mb/d for C+C+NGL, if we adjust for the lower energy content of NGL (about 70% of a barrel of average crude) the June 2019 output is 15.3 Mboe/d for US C+C+NGL (12.08 Mb/d of C+C output and 3.2 Mboe/d of NGL output.)
Tony,
If we use EIA data for C+C+NGL output at link below
https://www.eia.gov/totalenergy/data/browser/index.php?tbl=T03.01#/?f=M&start=200001
The annual rate of increase for US C+C+NGL output from Sept 2016 to June 2019 has been 13.6% per year. If we assume this annual rate of increase slows to 6.16% per year from May 2019 to Dec 2025, then US C+C+ NGL output reaches 25 Mb/d by the end of 2025.
An alternative approach is to assume US C+C reaches 14.5 Mb/d by the end of 2025 and that NGL output doubles from 4800 kb/d to 9600 kb/d (annual growth rate of 11% for NGL) which would get output tp about 24000 kb/d. This ignores the fact that NGL has lower energy content (roughly 70% of a barrel of crude) so in barrels of oil equivalent the total would be 21,000 kboe/d rather than 24,000 kb/d.
In addition, such extrapolations tend to give poor predictions. It is doubtful that NGL output will continue to increase at an annual rate of 11% for the next 5.5 years. There has been a long term trend in US NGL output of 9.4%/year increases on average from Jan 2010 to July 2019, but it is doubtful that rate of increase will continue in my opinion. If we look at the most recent 12 months for NGL output the annual rate of increase has slowed to 6.4%.
Using that more realistic rate of increase and assuming C+C output of 14.5 Mb/d in 2025 and adjusting for the lower energy content of NGL (70% of a barrel of C+C) we get 19 Mboe/d for US C+C+NGL in 2025. That might be a reasonable estimate (possibly still on the optimistic side if the growth of NGL output slows further over the 2019 to 2025 period.)
GuyM
Yes there are a bunch of crazy forecasts out there.
EIA is pretty conservative by comparison. If you look back at crazy STEO forecasts you might find they were not bad.
GuyM,
Took a quick look at Aug 2018 STEO (about 12 months ago). At that time they expected US C+C output of 12.02 Mb/d at the end of 2019 and 11.7 Mb/d in June 2019. Seems they underestimated.
By Dec 2018 the estimate has increased to 12.29 Mb/d in Dec 2018, that seems like a pretty good estimate to me. Lately their estimates do seem a bit high in my opinion, but I have often believed that in the past and I was incorrect.
https://www.eia.gov/outlooks/steo/outlook.php#issues2018
Mistake above, the Dec 2018 STEO has US C+C output at 12.29 Mb/d in Dec 2019 (I mistakenly typed 2018), which seems pretty reasonable. The most recent STEO estimates 12.95 Mb/d in Dec 2019 which I believe is probably 400 to 500 kb/d too high.
GuyM,
I find your argument that the completion rate might fall as majors take over the Permian compelling. I devised a scenario with a fairly high oil price assumption (Brent oil price rises to $90/b by 2027 from $56/b in August 2019). The completion rate falls gradually through Dec 2021 (from 1827 completions/month to 1744 completions/month), remains constant from Jan 2022 to Sept 2023, gradually rises from Oct 2023 to June 2024 (to 1753), declines gradually to April 2026 (1059), remains constant until 2027, rises until the end of 2027 (1073 completions per month), and sees a final decline in completion rate, reaching zero in Dec 2049. URR for US tight oil for this scenario is 82 Gb with a trailing 12 month (TTM) average peak output of 8570 kb/d, with a plateau in output between 8470 and 8570 kb/d for the TTM average from 2023 to 2028.
Obviously an assumption of lower oil prices would reduce the URR, by shortening the plateau and steepening the decline after the shortened plateau in output.
Also note that different completion rate assumptions could lead to higher or lower peak than assumed here with peak likely at any point from 2023 to 2028 depending upon assumed completion rates.
Thanks for the chart. I am not sure, just guessing. And I am not sure where they really are on first tier. Pioneer CEO says they are close to max. Second and third tier really suck. But, good enough for big energy. It’s a waiting game. Big energy does not have to move, the sick ones need to offer themselves up for sacrifice. The dead ones can wait. Big energy is not going to take on unnecessary liabilities.
GuyM,
Yes we are all guessing. I just think your guesses are quite good. The future will tell us if I am correct. The scenario is just confirmation that my interpretation (which may not be correct) of what you have been saying can easily occur with high oil prices and my typical economic and geological assumptions (which are backed up with well profile data from shaleprofile.com as well as completion data from the same source).
Chart below has well completion rate for scenario presented earlier.
Nice chart, I never dissociated Hz and vertical rigs, It’s interesting to see that Hz rigs count decreased somewhere in February 2019, while the Vertical rig count decreased earlier.
This is anyway not a plunge like in 2014-2015. But at that time, the plunge was mainly due to inefficient rigs that were still used due to the high prices of the 2010-2014, as you pointed.
The current decrease doesn’t seems enough to reduce the US production. In 2018, the Permian was able to add more than 1Mb/d of production (which was spectacular). Sure, it won’t be that high this year, but I think the idea that US oil production reached its second peak is premature.
If you read through today’s (Tuesday) RBN Energy posting, you will get a snapshot of what the effects that the new pipelines – Cactus II and EPIC – are having on Permian takeaway.
Specifically, a doubling to over 1 million bbld export out of Corpus Christi compared to a few weeks ago.
By the end of this calendar year, the Grey Oak pipe should be in operation.
Come early springtime, 2020, an increase of over 2 million bbld takeaway – yoy – from the Permian should be in place.
Price dependent, output is set to soar.
Rig count is still falling.
The opening time of the pipelines is known to everyone, so a drilling frenzy should have already started 2 months ago to be ready when the pipeline is up.
Eulenspeigel
EIA figures there are about 4,500 DUCs in the Permian and Eagle Ford combined (3,000/1,500 Perm/EF).
I realize many people are … selective … when it comes to using data from the EIA, but just throwing different scenarios around using, say, 2,000 wells already drilled but not frac’d and using production numbers ranging from 500 bbld to 1,000 bbld for 30 days running starts to show some pretty big increases in overall output.
Price, as always, is a huge determinant.
While I do not follow the Texas region too closely, I DO keep abreast of leading edge operational events.
People are going to be surprised by how advanced the completion practices are becoming in the unconventional hydrocarbon world.
The upside potential is very large, but the revenue streams continue to be a huge impediment.
Coffeguyzz,
If the completion rate increases, output will increase, even a constant completion rate results in a modest increase in output over the next 5 years or so. I agree much depends on oil prices and the financial health of the Texas tight oil producers (New Mexico as well for Permian basin output), that is difficult to predict. Doubt there will be much increase in Eagle Ford output, but Permian basin could see a 2 million barrel per day increase in output with higher completion rates, unclear if this will happen in the near term at current oil price level.
I think most of these DUCs are duds – there is no economic sense in drilling a well and not fracking it in the next 1 or 2 months.
It’s just sunken capital – it’s like renting a store at the mall and installing all the hardware, but not filling it with goods and opening it.
There have to be reasons why a DUC is a DUC for more than 2 months:
– Bad hole
– No money for calling the fracking team.
– I just like drilling 2 million $ wells
– Bad planning
– No fracking teams available (due to too strong grow)
– ???
Even when it is drilled to hold a lease (some contracts only need drilling, not producing…) there is no reason to frack it exactly now.
Output is slowly rising at the Permian at the moment, there are no signs to see this changing much.
Eulenspeigel
There are actually several reasons why wells are drilled and then not fractured right away.
As you may guess, money would be reasons #s1 through 5.
This entire “Drilled Uncompleted” category came into prominence about 4 years ago when oil prices crashed along with the DAPL fiasco in North Dakota.
(Actually, in Pennsylvania, going back almost a decade, wells were frequently drilled but not frac’d for years. Pipeline scarcity and leasing terms being the main reasons).
In ND, regulations called for wells to be turned inline within 365 days of, I believe, production casing being installed.
With the crash in prices, operators were looking at huge financial stress if the flush early months’ production revenues plummeted. ATW pricing in ND dipped below $20/bbl. at one point.
It was then that ND regulators doubled the timeframe to 2 years to turn inline with the expectations that pricing would rise.
The expected opening of DAPL provided further incentive to hold off completions.
Now, as to why drill in the first place if no frac’ing is immediately planned … again, several factors … but ‘dry hole’ not being one of them.
The planning/permitting process for each individual well can be quite lengthy.
In Texas and North Dakota, permits are usually granted within a month or less from first application. Pennsylvania regularly runs 6 to 9 months.
A huge amount of time and effort comes into play long before any permit is even requested.
Operators normally contract drilling rigs for periods of time wherein they pay less for longer contracts.
It is quite common to simply drill “x” number of wells and come back later to frac it/them as a way to – overall – save money.
This time next year, Cactus II, EPIC, and Grey Oak pipelines should be running all out with about 2 million barrels per day extra capacity.
To both fulfill shipping commitments and capture higher pricing, the number of Permian DUCs should drop significantly along with an increase of Permian output.
As always, realized revenues play a large, influencing role.
Tita,
Note that when we compare this to shaleprofile estimate of horizontal wells, it looks too high. Most of this is due to my “other lto” model (tight oil from plays other than ND Bakken, Eagle Ford, Permian, or Niobrara) which needs to be redone. Some of it might be tight oil from vertical wells (not tracked at shaleprofile), but that amount should be pretty small.
Weird inheritance. My wife’s grandfather bought 5 acres in New Mexico roughly 100 years ago, possibly hoping to grow grapes?? Somehow taxes continued to be paid and my wife inherited a slightly less than one acre share in Eddy County, New Mexico. Fortunately her cousin is a lawyer. It was leased, drilled. and pooled several years ago and the 5/6 th acre has produced income over $40,000 from several wells. The last monthly check from Matador was down, less than $500. We wonder what the future holds if anything.
A warmer climate, longer droughts, fewer wild animals and death. Your best days are behind you, enjoy.
Bingo!
We have a winner
Being 88, I probably won’t need to wait too long for death.
A tad bit pessimistic don’t you think HB, compared to the hopium you expound on the non oily side; perhaps we’ve hit peak optimism?
The richest free country in history voted to destroy it’s self. They wanted change, but hate gay marriage, people of color, women’s equality and the idea of feeling safe sending kids to school. God forbid they drive an efficient clean EV. You can lead a horse to water, but you can’t make it drink.
All of that strawman bunk you scribbled is pure ideology that only came about in the last few decades of a fantastically energy-augmented realm of existence, and is passingly tolerated only for as long as 22,000man*hours of effort in each barrel is economically obtainable. We live in a turbo-charged era of human existence, provided entirely by a one-time chemical endowment. Once that is gone, those contrived ideals you cherish -which do not comport with reality but exist in spite of it – will quickly give way to the resumption of hard manual labour comprising most of the day’s activities. Marriage will return to what it was, equality will re-balance to what it was (a biological division of responsibilities between man and women), and schools will probably become safe again. No more time spent indulging in lunatic victimology currently taught in our colleges or universities. The kiddies will have to toughen up and learn to work hard for a living. And boy, will they hate us for it.
So your children hate you for your selfishness, I’m sorry.
No, you’re not sorry for me or anything about me. Spare me and the rest of us your delusional strawman self-aggrandizing BS. Try reality for a change.
Perhaps take a second look at your own ideology and how that has been facilitated and ‘off-the-charts’ distorted by 22,000 man hours in every barrel.
Therein may be the start of an explanation for your current (and misguided) set of ideologies. It’s nice to escape to a fantasy now and again, but hey, reality eventually comes a’-knockin’.
It depends on where you live. In general, you would see a slightly warmer climate, a bit more rain, larger fruit, taller and greener trees and vegetation, Al Gore standing in knee deep water in Miami Beach explaining sea level is rising at 4 mm per year, and your neighbors driving a small pickup with a hybrid engine, because oil prices will definitely rise.
Try selling your happy talk to the surviving citizens of Barbados and Puerto Rico
Don’t know if this will matter.
Saudi Arabia’s King Salman replaced the country’s energy minister with one of his own sons Sunday, naming Prince Abdulaziz bin Salman to one of the most important positions in the country as oil prices remain stubbornly below what is needed to keep up with government spending.
Also on Sunday, the king issued a royal decree removing the current deputy minister of energy, Abdulaziz al-Abdulkarim. He did not name a new deputy energy minister.
https://www.washingtonpost.com/world/middle_east/saudi-king-replaces-energy-minister-naming-one-of-his-sons/2019/09/07/04a74ea2-d1ce-11e9-a620-0a91656d7db6_story.html
The former energy minister made this statement: “I have no doubt in my mind that U.S. shale will peak, plateau and then decline like every other basin in history,” Al-Falih said at the time. “Until it does I think it’s prudent for those of us who have a lot at stake, and also for us who want to protect the global economy and provide visibility going forward, to keep adjusting to it.”
https://www.thestreet.com/investing/futures/saudi-arabia-ousts-energy-minister-al-falih-as-kingdom-re-thinks-oil-strategy-15080884
Hi,
I have a question: all the increase in oil production in the last few years is light oil. Why isn’t there a problem with availability of diesel?
Thanks,
Michael
You still get diesel from light oil, but not as much as from heavier oil. For instance, from my wells in the EF, the API is 39. That can easily get mixed with others to get the normal amount of diesel. The higher the API goes, the less Diesel, but I have no idea what the percentages are. Someone else may be able to answer that. Also, they are currently exporting 3 mbpd of unknown mix. That was close to zero several years ago.
Here is a link that gives you an idea of distillation cut vs. crude. I always wondered whether you can get rid of the lights and still have greater than 200 deg C from shale oil that can be used in ships. There is quite a lot of >200 deg C material even from EF 46.6 API gravity material. Shale oil has very low sulfur.
https://www.statoil.com/en/what-we-do/crude-oil-and-condensate-assays.html
https://www.chron.com/business/energy/amp/Valero-Darling-planning-major-renewable-diesel-14424412.php
1.1 mbpd diesel from animal fat and corn coming in 2021. So, the answer is that big oil expects less diesel from oil, but is going to kill a lot more hogs, and the corn crops will be safer. Ok, I am going to stop calling them big oil. The term is now big energy, they are way ahead of our guesses. Independents, see those headlights in your rear view window? Pull over, or get run over.
Hi Guym, I looked over the article you linked and it refers to a potential of 1.1 million gallons per day of biodiesel, not 1.1 million barrels. It also sounds pretty iffy.
Whoops my bad
Michael, while there is a glut of lighter distillates, the heavier ones are below their five-year average.
The World’s Oil Glut Is Much Worse Than It Looks
Still, whether you measure them as simple volumes or in terms of cover for future demand, OECD stockpiles are rising. Admittedly, much of the recent increase comes from natural gas liquids (light oils produced in large quantities from U.S. shale) which are used widely as petrochemical feedstocks. When you strip these out of the numbers, OECD inventories of crude oil plus the major fuel products – gasoline, middle distillates (diesel, heating oil and jet fuel) and fuel oil – are below their five-year average level.
I somewhat follow this item. Years ago Ron and I had a substantial discussion about Bakken vs Louisiana Light Sweet. Platts had some curious data then and it likely derived from a fairly large controversy at the time about ultra light fractions getting into rail cars from the Bakken, which were catching fire and blowing up and which had hearings in Congress going on that moment.
But overall it’s tricky for several reasons. Not the least of which is the date of assay.
First, the Krishnan dood above linked the Equinor assay page and it’s solid. There are others you can find online. Exxon has a big page:
https://corporate.exxonmobil.com/crude-oils/crude-trading/assays-available-for-download
Capline’s is huge and excruciating to navigate:
https://cappl.com/
The most eyebrow raising item on all of this is the Bakken’s history. The Director guy up in NoDak was very loud that Bakken oil had the same API as WTI. The WTI standard at the time (and for decades) was 39.6 and that was the published number for the Bakken. Then years passed and Bakken API crept upwards. The Equinor page above assays Bakken to be 43.3. That is in Aug of 2017. It has been rising since I have watched it, maybe starting 2012 or whatever.
Useful to also note that WTI, the yardstick, really is no longer a yardstick. It has changed, too. As oil flowing to Cushing from West Texas got blended in Cushing with Bakken liquid, the API number started to grow — and that was several years ago before the Permian LTO was flowing. Now that it is flowing, the API number gets even higher, and this has gotten the attention of NYMEX. Big questions of just what is being sold on NYMEX. Discussion here:
https://blogs.platts.com/2018/06/22/wti-vs-wti/
Amusing to note that Statoil’s page used to include WTI and it had risen to 42 something. There are comments in our database on this site pointing it out. Now it’s gone.
Anyway, Kerosene boils about 150C to 275C and Diesel is 200C to 350C. Comparison of yield (BY VOLUME, it’s not fair to do it by weight) says some things. Doesn’t say everything.
Important item. Geography matters. A given API from one place on Earth may not have the same diesel content as the same API from a different place on Earth. Have a look at Tapis in the Exxon assay. Look at its API.
Watcher
Your observation regarding the rising API number for Bakken output gets right to the heart of the suspicions (understandings?) of the effects of asphaltene precipitation impacting oil production in the LTO universe.
Generally, the more asphaltenes present, the lower the API reading.
As the formation pressure drops, the much-discussed “bubble point” kicks in where phase separation, aka smaller gas molecules separate from the hydrocarbon stream, and continue to the wellbore through the excruciatingly tiny frac’d pathways.
However, the remaining liquid hydrocarbons – consisting of various molecules including the large, thick (actually solids) asphaltene molecules – have their own separating process influenced by pressure depletion.
There is not only a growing appreciation of the deleterious effects of asphaltene precipitation, Bakken operators have already responded as can be seen on Enno’s site.
I refer you to the quarterly production profiles of 2018 and 2019 Bakken wells.
What you will see is a completely different profile due – in large part – to the operators not quickly flowing back the frac water shortly before turning the wells online.
The retained (underground) 200,000/250,000 barrels of water both pushes hydrocarbons to the wellbore along with preventing asphaltene precipitation and consequent pathway blockage.
If you’re blaming rising API on asphaltenes (somehow), because they are viscous (which lowers API), then removing them should decrease viscosity and raise API even more.
Yes, that is what is happening.
The larger, heavier molecules are unable to continue to make it through the tiny pathways as pressure depletion prompts them to separate from the liquid stream.
They then tend to clump together, further inhibiting production.
Without the heavies, lighter oil is produced … the rising Bakken API that you have been seeing.
I think it’s in part because europeans are using less diesel, but i’m not sure.
Here’s a podcast type interview with Adam Rozencwajg, founding partner of Goehring & Rozencwajg, an investment firm linked to natural resources such as mining, energy and agriculture. Perhaps some here will find it interesting, as I did.
http://l2capital.com.br/en/podcast/16-adam-rozencwajg/
What’s really happening in the Saudi Kuwait Neutral Zone (NZ)?
It used to produce 0.38 mbd in 2014. Now, it produces 0 mbd. See Table 3 of IEA OMR.
https://www.iea.org/media/omrreports/tables/2019-08-09.pdf
https://www.iea.org/media/omrreports/tables/2015-12-11.pdf
There are two fields in the NZ: onshore Wafra and offshore Khafji.
http://www.arabtimesonline.com/news/new-terms-to-govern-joint-saudi-kuwait-khafji-oil-field/
Khafji is considered a northern extension of Saudi Safaniya field. Oil production from Safaniya could be secretly producing oil from Khafji which means that Saudi Arabia is benefiting from the 0 mbd production from Khafji.
There is still talk of resuming NZ production but no action yet. Saudi has a new energy minister so NZ production could be delayed again, perhaps to the benefit of increased Safaniya production.
https://news.kuwaittimes.net/website/can-kuwait-and-saudi-arabia-unlock-oil-production-in-the-neutral-zone/
Iraq hit record production figures in August with an output of 4.88 million barrels per day (bpd)
https://www.cnbc.com/2019/09/06/iraq-is-pumping-record-oil-disrupting-opecs-production-cutting-plans.html
From your link:
“Saudi Arabia, OPEC’s de facto leader… has repeatedly called on Iraq and other less compliant countries to get with the program, but this has mostly fallen on deaf ears.”
I would not expect anything different. 🙂
At some point Saudis produce at Quota and let prices fall to punish those overproducing. Maybe they can’t afford to do that as they may need higher prices.
And maybe sustaining their own quota over a longer future is an issue and they would much rather get paid more for less and at the same time dont have to admit “we cant go higher and keep it there for many years as we are struggling with depletion and our reserves are exaggerated” ?
Baggen
Yes it is possible that KSA is producing all they can or all that they care to at current price level.
I don’t think KSA oil production depends much on price. If the price is high, they’ll produce all they can to make as much money as possible. If the price is low, they’ll produce all they can because they desperately need the income.
Frugal,
It seems their output depends very much on price in many cases. That may just be coincidence.
If the Saudi’s were strictly rational, they would cut their production in half, which would probably have the effect of more than doubling oil prices. So this would leave their oil income about the same as before and would reduce oil field depletion. Why aren’t they doing it?
Frugal,
Not sure if prices would double, but I don’t know how these decisions are made by KSA.
Some thoughts:
-they can’t halve production without damaging the fields
-it would encourage high-cost producers to invest and produce to make up the missing volume (resulting in half the income they have now)
-it might start a panic (if oil supplies actually do drop)
-it would make people think about future supply viability (everybody would talk like us!)
-It would piss off Trump
Reducing production is fraught with uncertainty and political risk.
Lloyd,
It is what OPEC/Russia at al are currently attempting. Not cutting output in half, but reducing output a bit to draw down stocks.
I have long suspected that the production fluctuations in response to price are more to do with inventory than production.
I always wondered about Saudi production and spare capacity. Why would Saudi crude inventory go down from 329 MM barrels in October 2015 to the current 188 MM barrels based on Jodi if Saudis had the spare capacity.
Krishnan,
In Oct 2015 there was a real glut of oil supply. Today the “glut” is mostly imagined by traders. Eventually they will catch on, give it another 6 months.
Dennis! We are not too far apart, again!
Yes I listen very carefully to what you say, often when I object, is is just a subtle difference of opinion (or I misread what you said). Generally we are on the same page. Either we are both wrong or both right for the most part. One slight difference is you fairly often say we have reached the peak. I agree we are close, but believe the peak is still 5 years off (or a range of 3 to 8 years). Of course I may be wrong, as has been true in many cases in the past.
Seems like we have reached peak oil for WTI in the $50s. If the world wants more oil, the price will need to go up at least $10-20. Permian rig count has been dropping steadily at this price, Saudis are uninterested in pumping more (if they’ve got it), no incentive to make a deal with Iran.
Does anyone know what the future potential of Guyana is?
Peak oil. That’s becoming more an more an elusive technical term. Valero is partnering with a co. to provide 1.1 mbpd of diesel in 2021 with fats and corn. Is that oil? Which will be cheaper?
Correction pointed out by dclonghorm; that’s one million gallons a day, not barrels.
= 0.026 mbpd?
Stephen Hren,
EXXON is still exploring. An article at OilPrice today said the company has announced reserves (I expect that should be “resources”) of 5 billion barrels of oil in the Starbroek block. There are other companies looking in offshore Guyana too.
Fernando Leanme might know.
Thanks Synapsid, sounds like it’s still a ways off but could amount to something mid decade
Dennis; I wouldn’t presume at this point to know more than a trader does. IMO, we are past peak even with shale accounted for.
The British navy ‘guards’ Iran oil flow. Economic security of th commonwealth is tied at the hip with oil price. As much as required for stability will be stolen?
What do you guys who are actually IN the oil business think of this?
https://www.forbes.com/sites/mikescott/2019/09/02/economics-of-electric-vehicles-mean-oils-days-as-a-transport-fuel-are-numbered/#74243bcd5102
I dunno. Tell that to the people who can’t afford a new electric vehicle and ask them. Most of the market. The largest part of the market is not tracked via dealer (used or new) car sales. Which are all thats reported. Been in the market as a retailer. The average truck or car we sold, was for $5000. Usually finance through some company charging three times the normal APR. These EV sales are so different from reality, it makes my mind cluttered. So when you read stated sales via the known market, it’s absolute B.S., full of sound, and signifying nothing.
GuyM,
Most cars get junked after 10 to 15 years, the fleet of cars is made up of cars that were at one time new. When I model this I look at new cars and assume cars are gradually retired at an average age of 15 years. So the percentage of new cars that are plugins gradually increases over time as prices of plugin vehicles falls as they ramp up and economies of scale and competition reduces prices. Once 100% of new car sales is plugins, then after 15 years the entire fleet is replaced, probably about a 25 to 30 year process. Of course newer personal vehicles less than 5 years old get most of the vehicle miles driven, so oil demand falls to half when perhaps 33% of the total fleet is plugin hybrids. If autonomous vehicles get approved in 10 years, then people may use their cars as robotaxis and average miles per year for those EVs may be 36,000 per year rather than 12,000 for the average vehicle, in that case each AV is like three EVs so a 3 times fewer are needed to replace the ICEV fleet. AVs might reach the approval stage by 2025, but more likely 2029. At that point car ownership may end for most people and everyone will just Uber (or most).
“Of course newer personal vehicles less than 5 years old get most of the vehicle miles driven, so oil demand falls to half when perhaps 33% of the total fleet is plugin hybrids.“
Dennis, not much reason to worry, so it seems. Unless…
A reflection on David Orr’s critique of ‘technological sustainability’
Look at the cars driving on the highway. 10 to 15 years?
GuyM,
I would say for 99.5% of the cars I see it is 0 to 15 years. What do you see in Texas?
I’m not economically depressed, but I have a 2000 Nissan Frontier with 139k miles, which I intend to keep for a long time. But, there is more older cars than new. I travel all over the DFW area, and some areas have vehicles that far exceed 10 years. That’s where most of the population reside. Kinda hard to guess, but I would say your 99% is far, far off. You must live in a nice neighborhood. Most of the population don’t. I mean, geeze, I keep seeing Hyundai Excels running around, which is an absolute miracle. Worst car ever mass produced, it was cheapest for a reason. If Hyundai had not begun to buy their engines from another manufacturer for the Sonata, they would not be in business.
Dennis, I listen to you. You listen to me. That’s communication, I like it. But, the yen and the yang, is on the 914s. Everything else, can, and could be BS. We are three months behind reality. Who has been closer?
GuyM
Do you see a lot of cars older than yours? That would be 20 years. Note also your SUV has driven an average of 7300 miles per year. My guess is that you have a second newer car. My Dad drove my 97 Camry up to 2017 probably had 220k when he ggot rid of it. Maybe somebody is still driving it many cars reach the junkyard or just sit in the driveway after 20 years.
When you were in the business did you sell many 20 year old cars?
Nah, no money in 20 year old card. Trucks maybe.
Guym,
Found a source claiming that in 2018 there are 279 million registered light duty vehicles in the US.
Also found this data
https://fred.stlouisfed.org/series/LTOTALNSA
If we do cumulative totals we find that 99% of vehicles on the road were purchased since October 2001, if the 279 million vehicle fleet estimate is correct for the US.
So about 99% of US registered vehicles are 19 years old or older. You are correct that my 15 year estimate was wrong. For cars from zero to 15 years old that is only 82% of the vehicle fleet, so we might need 20 years to replace the fleet rather than 15. It is still true that most miles are driven in newer cars, you can easily consider how many miles you drive in your newer vehicle vs your older vehicle. The only exception to this might be if you lease rather than buy, in that case sometimes people keep the miles down on the leased car, often around 12,000 per year.
GuyM,
I agree 914s are good, I also believe the “tight oil production estimates by play” are pretty good at page below.
https://www.eia.gov/petroleum/data.php#crude
Its too bad America can’t transition to EVs without getting bogged down in cult of founding CEO myths and subsidy for luxury brands. China meanwhile has EV co’s that actually make money (yay capitalism), something that has so far eluded Musk’s vanity project. Lots of EV ‘enthusiasts’ don’t want to, or can’t, talk about China, BYD for example; so they come off as Elon Musk Fan Bois, more than EV market trends analysts, which is kinda gross feeling. Plus BYD is just way more affordable. I believe BYD is doing public transit type electric buses in North America. Very proletariat, buses are. Not Musk’s style at all. Warren Buffet has his filthy fingers in BYD, as does Chrysler (I just still call it that). BYD made batteries for twenty years before they got into making EVs. I don’t know exactly what Musk did for the 20 years before he got into making EVs, but I suspect it involved too many Anthony Robbins videos.
https://www.bloomberg.com/news/articles/2019-08-29/buffett-backed-byd-close-to-battery-supply-deal-with-vw-s-audi
https://seekingalpha.com/article/4289354-ev-company-news-month-august-2019
https://knowledge.wharton.upenn.edu/article/chinas-ev-market/
It helps to have lots of government backing and money.
https://qz.com/1579568/how-much-financial-help-does-china-give-ev-maker-byd/
Survivalist,
Lots of companies get tax breaks from local governments, not just Tesla. Federal subsidies are available to every auto company that sells BEVs or plugin hybrid, based on battery size. The subsidies are limited after a manufacturer sells 200,000 vehicles and is gradually phased out over 24 months (100%, 75%, 50%, 25%, and then zero). Tesla is currently in the 25% phase which began July 1, 2019 and ends Dec 31, 2019.
Quite right Dennis, many co’s, besides Tesla, receive money from the taxpayers. Of all those that do, besides Pentagon contracts I suppose, I wonder how many are profitless year over year and, as well, also compensated their CEO almost $2.3 billion in 2018?
“According to The Times and Equilar, the Tesla CEO received stock options estimated to be worth nearly $2.3 billion in 2018.”
https://www.businessinsider.com/elon-musk-tesla-compensation-explanation-2019-6
“If you have a reckless CEO who can’t be fired because it would hurt the company, then you don’t really have a company; you have a cult.”
https://newrepublic.com/article/151479/elon-musk-americas-toxic-cult-ceo
Amazon had no profits for many years. They get lots of tax subsidies from local governments, in fact local governments are trying to outbid each other for the tax giveaways they are willing to throw at Amazon.
These days its a river of profits for Amazon. 🙂
Does telsa get any federal subsidy?
I know that electric vehicles get a temporary subsidy on the first 200,000 units of model sales, but that goes to the purchaser, not the company.
And it has nothing to do with the name being telsa, it can be VW or FungShwai as well.
“Its too bad America can’t transition to EVs without getting bogged down in cult of founding CEO myths and subsidy for luxury brands.”
Yeh too bad, but only small number of people are actually bogged down by this.
Most people would/will be unbogged and move towards PHEV/EV when the price is comparable, and that becomes obvious to them.
All kinds of non-Tesla electric vehicles will be on the market in five years.
Wild cards are the price of oil and the price of batteries.
Almost everything else is in the favor of electrification.
Its great to not use petrol personally, so that it can be available for priority uses like farm equipment, emergency services, critical air flights, and long haul cargo for more decades to come.
full disclosure- I own a PHEV, and have been to the gas station three times this year. I have never used a public charge station. By and large, I get around on my own (power).
What is the battery range of your PHEV
Ovi,
I think he has said 32 miles.
https://www.chrysler.com/pacifica/hybrid.html
Yeh, only 32 miles. So this vehicle is prime for someone who does primarily short trips, but its total range when fully charged and gassed up is over 500 miles.
My preference would be to have a vehicle like this with a bigger battery, something like 80 miles.
Hickory,
I thought the question was battery range. Yes Chrysler claims 520 miles for your van. I agree more electric range would be nice. Not a lot of my trips would be covered with 32 miles, but 80 or 100 would probably cover a lot.
A vehicle like Chrysler Pacifa PHEV that got 80 miles on battery, rather 32 miles (as it does now), would be a huge winner. I believe the problem with making a vehicle like that currently would be the jump in price due to the bigger battery. Its ICE engine is a very good one. The overall integration between the two systems, and its control systems and performance is just outstanding.
Busting The Myth Of The World’s Hottest Electric Car Market
How many cars do you and your wife own (lease?), Dennis, and what kind of voluntary personal degrowth/simplicity/impoverishment forms are you folks pursuing and considering? What do you think you would you be willing to?
Offering to car-share and/or chauffeur the ‘Model 3’ (Tesla?) for the local neighborhood on the weekends?
What do you drive, if anything, weekdays, and what do you think your wealth is, relative to the average person living in the US? >25%?
Hi Caelan,
2 cars owned. Camry Hybrid is other car. Income above average.
Electric vehicles don’t sell in Spain, because the subsidy isn’t high enough. We do see hybrids, they get about 10% to 20% better mileage than my 5 speed diesel…but they cost a lot more. I believe I’ll buy a plug in hybrid in a few years, but I live in a beach town and usually drive short distances. A fully electric doesn’t make sense, because we have mountains, and it gets hot in summer. This explains why we don’t see electric taxis or buses.
With mountains they make lot’s of sense since you don’t use more energy than driving flat. You get most of the energy back driving down.
Current batteries have a heat problem – wait a few years until solid state batteries are out. They tend to love hot weather, so no more energy waste for cooling batteries. Toyota will present a car with them next year on Olympia, and a chinese company already started a test production line to optimize industrial production.
Double density and no more explosions are another goodie.
The price of pretty much everything is pretty much all the same trade now. Bonds are bid to ridiculous prices because everybody believes they will be able to unload them to central banks at a profit before maturity. Stocks are bid because if for any reason there was a sustained sell off. Central banks will step in.
Watch non-farm payroll data and inflation data in the US. If they continue to be soft oil will be bid because of expectations of the FED to do something about it. Bad data equals higher oil price now days. The worst the data becomes the better for oil price. While good data equals lower oil prices for longer.
Commodity currencies AUD and NZD look like they have finally made a bottom against the dollar. Which if it holds it’s a very positive sign for oil price. Because it means dollar weakness is coming. AUD and NZD bottomed out against the Euro about 4 weeks ago. AUD, NZD and might as add the CAD or canadian dollar in there as well have be losing ground to both the US dollar and the Euro for 5 years straight mainly do to dollar strength. That is why this potential turn in these currencies against the dollar is a very good sign for price of oil.
How do you deal with $24T debt if you allow rates to rise. You don’t. You got no inflation? Then the debt doesn’t erode. If it doesn’t erode you dare not let rates rise.
You got no inflation? Then why would the price of anything rise? In fact, the issue of not allowing rates to rise because of $24T extends to inflation. You can’t let that rise, either, or it would drive up rates — which $24T can’t permit, so inflation will be attacked, and not with the usual toolbox because $24T locks that. “Unconventional tools” will be required to push inflation down, while declaring that you need to have inflation.
The world ended in 2009. It’s all pretense since then, and any effort to make it not be ended is prevented by $24T. People need to begin all thought about circumstance with the $24T debt. Any expectations have to recognize how overwhelming that is. Fiscal stimulus (aka deficit) is now 5% of GDP ($1T). Just 1% rise of rates on $24T would take stimulus to $24T plus 240B. Where’s that $240B going to come from?
I get confused from your changing statements. I’m not trading oil, which you seem to do, but I can’t see how you can take positions and profit when you change your mind all the time.
“Bad data equals higher oil price now days.”
So now you believe the oil price will go up?
When you state that oil will go to $20 – do you think the economy will be super strong then?
RRC took away their completions, plugging and permits report. The only use I have of this site, now, is for individual wells.
Looks like they just reworked the site for updating, here is the graph for completions, even if it’s not 100% accurate month for month, because always some delay, as discussed – the tendency can be seen.
oil completions year to date reached 83 % of the 2018 numbers and drilling permits for oil/oil&gas are now at 85% of the 2018 level.
Thanks Envision,
In 2017 Texas C+C output rose at average annual rate of 688 kb/d, for year to date oil well completions 2019 is at 120% of the 2017 completion rate. In 2018 Texas C+C output increased by an average annual rate of 1043 kb/d and the 2019 completion rate is 83% of the 2018 rate year to date.
If the output increase is proportional to the completion rate this would imply in 2019 either 0.83 times 1043 or an annual rate of increase of 866 kb/d if the completion rate should remain at 83% of the 2018 completion rate for the entire year. We could also use the 2017 annual increase which implies 1.2*688 or an 825 kb/d increase in 2019 if this relative completion rate continues for all of 2019.
In both cases these estimates seem way too high. I think Texas will struggle to reach a 400 kb/d annual increase in output from Dec 2018 to Dec 2019.
Yeah, but I think with low price enviroment present today, they lowered completions and drill for the best rock with the longest useful lateral length, so actual 2019 production per well could be a bit higher then 2018.
Yeah, it’s reached about 200, and will struggle to get much higher into 2020. My guess. Permits for August are up, but nothing to write home about. August permit’s oil is definitely not going to be here until 2020. And, they did that in 2018, too.
GuyM,
They have plenty of permits for the stuff they want to drill and there are quite a few DUCs as well.
Envision,
Pretty sure oil prices are better than 2017, they have been high grading since 2015, that is nothing new.
Yeah, you keep talking about DUCs, and so does everyone else. But, they take an $80+ price to bring online, and the production is lousy to overall. They are tier two, at best, and most are tier three (less than 100k EUR). Otherwise, they would NOT be old time DUCs.
GuyM,
We don’t really know the age of the DUCs, there will always be some inventory of DUCs, as it takes time to complete the well after drilling has begun. I don’t really mention DUCs all that often. Approximately 10,000 more permits have been issued since 2015 than the number of wells reported as having been completed by the RRC in Texas.
Shale Profile has about 2500 Permian DUCs about a year ago (Sept 2018), this includes only horizontal oil wells, vertical wells are not included in the shaleprofile data.
Dennis,
It would be really interesting if the age of DUCs could be determined but ill take your word for it that such information is not available.
Personally i have just had this feeling that a lot of these DUCs are basically garbage and will more or less never be put into production unless oil price increases a lot.
I’m guessing that the companies that drilled those has a fairly good idea about the well and how it will produce if they spend the additional funds on it to bring it into production, if they know its crap they will probably not do it and try another hole instead.
Could the reason be that if you refuse to acknowledge that it was a dud, then you dont have to write it off and admit it was capital wasted? Instead you can keep it on the books for as long as you want as “capital invested/asset”.. and motivate that with “we are just waiting for the right time etc..”
Baggen,
An alternative explanation is that there is an inventory of DUCs that is needed to keep operations flowing smoothly. As the number of average completions increases the number of DUCs will increase as well, just the nature of the beast. So in 2016 the average number of horizontal oil well completions was about 188 per month and in 2018 the average completion rate was 427 wells per month, basically it looks like the oil companies like to see about a 5 to 6 month inventory of DUCs. There may be a few of these DUCs that are not worth completing, but we don’t really know how many.
Here is shale profile for Permian, DUCs.
In the early drilling, they drilled a lot of wells outside of the four county sweet spot in the Delaware. They brought some online, and were extremely disappointed. A lot of gas and condensate, not so much oil. When WTI gets near $80, you may see some DUCs come alive. At this price, they are all dead DUCs, except the ones currently drilled. There is no reasonable other explanation, as they are not short completion crews. Why would they waste cash! No different than the EF, just laid out differently. They will eventually come to the same conclusions in the Permian that they came to in the EF. In time.
When you plug a well, the whole thing remaining is now an expense, along with the plugging costs. Do you think these dingbats can afford to show that? No, they will sit on these “assets” hoping that oil goes to $150 or more. They certainly don’t want to treat them as expenses.
The horizontal drilling has a hidden cost. They may not be “dry holes”, but have some oil. Just not productive based on current oil prices. Vertical wells had one step. You had to get what was there, as you already laid out all the cost. On a horizontal, there are two steps. The second being the most expensive. All you have shown, is more proof of my explanation.
I have 6 more wells to be drilled Oct or Nov, some they may bring online, others may go into the balance sheet. Who knows? I keep saying, they know what they can expect, after drilling it. Pretty much fact. I have no drilling experience, but my family did. I’m just a worn out CPA, with forty years experience. Why do you think the majors are waiting? They don’t want to buy the miserable balance sheet by absorbing the company, they just want to buy good assets (more explicitly, the leases) when they go belly up. They will start out Chapt. 11s, and migrate into 7s. That didn’t happen last time, because there was still a lot of stupid money.
On top of that, we have some questions on productivity.
https://oilprice.com/Energy/Crude-Oil/Weakening-Shale-Productivity-VERY-Bullish-For-Oil-Prices.html
Circa Eagle Ford 2014.
The DUCs are a myth.
Shale will continue on. Just not as historically expected.
GuyM,
Not very clear when the “early drilling” in the Delaware occurred, but let’s say it was up to mid 2016 when DUCs fell to just under 1000 in the Permian basin (we will assume that all of these wells are “dead DUCs”, even though that is not very likely, in order to strengthen your argument). In Sept 2018 there were about 2400 DUCs (the fall off after that is an RRC and New Mexico reporting artifact, all the data is not in yet) so if we subtract 1000 that leaves 1400 DUCs which are still “alive”. Perhaps this number has fallen a bit due to rig count falling, but my guess is that by 2018 they had figured out where to drill.
Also note that even a 10% fall in the completion rate (annual rate) to match up with the 10% fall in rig count over the past year, doesn’t lead to a decline in output, just a slowdown in the rate of increase. Eventually oil prices rise and completion rate either levels off or increases. There are a lot of pipelines being built, this will lower transport costs as the midstream companies will want to fill those pipes. The lower transport cost helps the price at the wellhead.
Dennis,
Thanks for input, that sounds very possible and logical that duc inventory trends completion or runs in front of it.
If completions start to slow down then i guess it would ve drilling that decreases if this is the case and duc inventory is used more.
As you say, its a guess unless we could have age and make more educated guesses on dud duc %
Thanks envision. It took them about 4 days to update.
You will start seeing more and more articles like this one as we approach the oil scarcity of peak oil.
There Is An Oil Supply Glut Now, But The Party Won’t Last Forever
There is widespread disagreement about almost everything regarding the future of oil supply.
However, a world oil supply crunch may be coming in the next few years.
The long-term problem for shale oil isn’t just low prices – it’s low reserves.
Long Snip.
So, the conclusion is that there are too many variables to predict exactly what world oil production or what the oil price will be at any time in the future, but at the current and projected rate of shale oil production, all of the proved reserves of will be depleted by at least 2024. With US shale oil production out of the picture, there may be a significant shortfall in world oil production. Since most of the potential future world reserves still lie in offshore fields, it is most likely that offshore production would have to come back to take up the slack. Though, the lack of investment in this area in the last few years may make things a bit difficult here.
However, it is unlikely that shale oil production would stay elevated and suddenly stop in 2024. More likely, there will be a slowdown in production before that date and at least a pickup in offshore exploration & production activity beginning in the not-too-distant future. Indeed, the end of the shale revolution might already be in sight with a substantial decrease in new investment in the light of bankruptcies that are now occurring. The high level of debt has caused 28 frackers to file for bankruptcy this year, and the number is expected to rise when about $137 billion of debt will mature between 2020 and 2022. And any increase in the oil price from now on may not be able to fully compensate for the massive debt here.
Moreover, there is a good chance, for reasons that I’ve already stated, that offshore may not be able to respond quickly enough to fully compensate, at least in the short term, for a significant decrease in shale oil production; bringing with it, of course, an appreciation in the oil price.
A 5% recession (Trade War) would ensure a 5% decline in oil usage… bankrupcies faster?
It’s not a 1:1 relationship.
And do you even know what a 5% recession is in GDP growth? That is how it’s measured, after all. That would be a greater decline than 2008-2009. How do you get that with 5% of GDP fiscal stimulus ($1T deficit on $20T GDP) and the ECB doing QE, neither of which were happening in 2008-2009?
It will take a nuclear war on US soil or plague or something for those kind of numbers over entire years.
Ron,
You asked if I knew why Petroleum Supply Monthly was delayed. I came across the following from the EIA which offers an explanation.
https://www.eia.gov/petroleum/supply/monthly/releasenote.php
A technical challenge occurred causing a delay in the publication of the Petroleum Supply Monthly (PSM). We are working diligently to ensure the resolution is thorough and meets EIA’s quality standards. We will provide an update as soon as available.
A technical challenge occurred? That don’t really tell me much. What is the definition of a “technical challenge”? Could it have anything to do with revisions in previous data? Anyway, by tomorrow, the delay will be 11 days. That’s a long time for a technical challenge.
Ron,
They changes the page, earlier their was a much more extensive discussion having to do with rail shipment data being messed up, but they claimed the totals were correct.
Link below has data.
https://www.eia.gov/petroleum/production/
Click on excel link for table 1 at right.
But, they are really “challenged” at this stage, Ron. Means none of their estimates are not proving close. I mean, if you choose 2050 as shale peak, yeah, your pretty much “challenged”. The only thing that’s real in EIA website is the monthlies 914, three month old drilling info data (which won’t show), and I don’t have a clue what else. I mean their STEO has to be constantly changed to reflect a minimal understanding to what the EIA monthly 914s from the companies are telling them.
GuyM,
The EIA’s AEO 2019 has the peak in tight oil output in 2031 at 10.28 Mb/d. Tight oil output falls to 8.4 Mb/d by 2050 in the reference scenario (most likely case).
Note that I would agree this is too optimistic, I expect a peak in 2021 to 2028 (best guess 2024/2025) at around 8.5 to 10 Mb/d, depending upon the rate that wells are completed. URR will be about 75 Gb, the EIA’s AEO reference case has tight oil output from 2006 to 2050 at 123 Gb, about 48 Gb too high.
See page linked below
https://www.eia.gov/outlooks/aeo/data/browser/#/?id=14-AEO2019®ion=0-0&cases=ref2019&start=2017&end=2050&f=A&linechart=ref2019-d111618a.10-14-AEO2019&ctype=linechart&sourcekey=0
Hi,
I was wondering if anyone here has “solved” or could explain the cause of the dramatic rise in “unaccounted-for oil” in the U.S. inventory data.
Thanks for any insights. Doug
Doug,
It is a balancing item to make the numbers match, in short it means the data is screwed up, and nobody knows the answer for why the data doesn’t match up. One data set is too low (or too high) or the balancing data set is too high (or too low) or some combination. Unaccounted for oil is just an accounting line to make the numbers make sense, when they don’t.
Thanks, Dennis.
My question is not why they have that “plug factor”, but why has there been a massive increase in it the last several years. No one seems to have an answer.
I think Krishnan had the best explanation, we should ask him. It’s fairly complex.
Robert Merriam of EIA thought plant condensate (not crude) has been bought by refiners over lease condensate (crude by EIA definition). Both are derived from knocking out C5 and heavier from NG stream. Crash in NG price would have made plant condensate cheaper. There is not much difference between plant condensate and lease condensate in terms of composition.
Now it is also possible to isomerize these condensate to increase octane values for gasoline pool. KBR announced availability of such technology.
What I see is that plant condensate is masquerading as crude elevating adjustment factor. I also think that this will continue and gasoline production will increase by about 500 KBD.
We are still not there yet. We may be with supply, but nobody has a clue. From here through the next two quarters, prices will be determined by the magnitude of Trump tweets, or OPEC farts. Because, there is no intellect in markets.
Primary vision reported frac spreads at 9/6/2019 as 390. That’s down from an average of 462 in second quarter 2019, 450 in July and 416 in August. With oil production basically flat from Dec 18 to June 19, a 15% drop in spreads by September portends dropping production.
Of course we may have to wait until EIA August or September monthly’s come out at the end of October or November to see these reductions. I doubt the EIA weekly models will pick up a change in trend.
Russia crude production, including condensate, peaked at 11.05 mbd in Dec 2018. In May 2019, it was 10.71 mbd in May 2019. Was Dec 2018 an all time peak for Russia or will there be a new peak?
https://www.eia.gov/beta/international/data/browser/
Data from Russian Energy Ministry
This graph looks to be in thousand tons per month. It would need to be adjusted to tons or bbbls per day to show trends. Notice the huge drops in Feb both years.
dclonghorn,
Using same data set, but dividing by days per month to get thousands of metric tonnes per day. Data at link below.
https://minenergo.gov.ru/en/activity/statistic
Thanks Dennis that’s a much more interesting graph although I’m not sure exactly what to make of it. The big increase before the Dec 18 Opec + cuts is evident as well as the bounce after the pipeline problems they had a few months back. I suppose in peak oil terms it might be an undulating plateau.
Dennis,
Last month’s IEA OMR also showed a peak of just over 11.4 mbd in Dec 2018, falling to just under 11.2 mbd in Jul 2019.
https://www.iea.org/media/omrreports/fullissues/2019-08-09.pdf
Rosneft last quarterly report showed its Russian liquids production dropping from 4.74 mbd in 2019Q1 to 4.62 mbd in 2019Q2. Their reasons were Transneft pipeline constraints and OPEC+ obligation agreement.
https://www.rosneft.com/upload/site2/document_cons_report/MDA_ENG_2Q2019.pdf
We can wait a year to see if Dec 2018 peak is exceeded but it appears that Russian oil production is on a peak plateau as shown by production since 2017.
https://minenergo.gov.ru/en/activity/statistic
Seems to me they boost output before negotiations with OPEC for quotas.
A plateau is probably a good guess, I think they will maintain current output levels unless oil prices rise, when oil price goes up they may invest more and boost output.
Outstanding article, by Matt, detailing the Asia countries trend in oil production and consumption,
with huge geopolitical implications.
http://crudeoilpeak.info/peak-oil-in-asia-where-will-the-oil-come-from-for-the-asian-century
The consumption trend shown in figure 12 is mind boggling. I wonder how many more years China and India’s oil use can continue to increase like that?
http://crudeoilpeak.info/wp-content/uploads/Asia_oil_consumption_1965-2018.jpg
So is the difference in our population vs theirs.
Guy- “So is the difference in our population vs theirs.”
I assume you are referring to the rapid growth in oil consumption of China and India, vs USA (and Europe)?
If so, yes, population growth is one aspect. They have grown much faster than we in past 3 decades.
And more importantly, they are both in the process of industrialization and increasing wealth of individuals, companies and local governments. This allows purchase of fuel to run equipment that was never available widely before. Imagine the changes in the USA from the 1920’s to 1990’s condensed in to 2-3 decades.
And also China consumes a considerable amount of energy in the production of exported goods. In effect, that fuel consumption and pollution is by and for the citizens of other countries who have contracted with China to produce the stuff for cheaper on their turf.
And its not just those two big countries. There are similar zones in many countries, like Korea, VietNam, Malaysia, Thailand, Philippines, etc.
Hickory
China consumes the majority of the oil.
Most oil consumption is unnecessary, used by people driving alone in cars.
Most people in Europe can get to work by public transport and Chinese dictatorship realizes they must provide alternatives to petrol cars.
http://www.globalconstructionreview.com/sectors/why-china-can-build-high-speed-rail34socheaply7365/
Hugo, some people express hate of another people because they
recognize that previous advantages they held are no longer in play, and they
are afraid of competition from highly motivated and organized participants in the ‘game’.
You do have a heavy pattern of expressing great disdain for China.
2018 Oil consumption per capita (bbl/day per 1000 people)-
UK 25.7
China 7.0
India 2.6
You could post this link as a response to about 90% of comments from Cornucopians.
Cornucopians don’t care about peak oil. It is a non-issue for them.
For them:
Human ingenuity > laws of the universe.
Seems inventories in US conti ue to drop..
https://www.google.com/url?sa=i&source=web&cd=&ved=2ahUKEwjmsOejmMfkAhUL7aYKHT5NDNAQzPwBegQIARAC&url=https%3A%2F%2Fwww.marketwatch.com%2Fstory%2Foil-prices-rise-as-api-data-reportedly-show-us-crude-supplies-down-by-more-than-7-million-barrels-2019-09-10&psig=AOvVaw3ucxSnRwSCu4x23_rGafVK&ust=1568237016930791
EIA Weekly Petroleum Status
http://ir.eia.gov/wpsr/overview.pdf
A 3.1 Mb stock draw for crude plus products, 6.9 Mb for crude alone.
If we leave out propane and propylene and “other oils” (does not include gasoline, jet fuel, diesel, crude, or residual fuel) which total 2 Mb added to stocks, then the stock draw is 5.1 Mb for week ending September 6, 2019.
If we look at year ago stock levels and leave out the increases in propane/propylene and “other oils” (an increase of 48.7 Mb). Then Total stocks of Petroleum liquid fuels and crude (including SPR) were down by 4.7 Mb from one year ago.
Seems we have a glut of bottled gas and “other oils” (not including crude, gasoline, diesel, jet fuel, ethanol, and residual fuel.) The traders don’t seem to see this.
Nick Cunningham at Oilprice has an article on decreasing shale productivity. It appears based on a report by Raymond James.
https://oilprice.com/Energy/Crude-Oil/Weakening-Shale-Productivity-VERY-Bullish-For-Oil-Prices.html
Well productivity is “tracking WAY below our model,” analysts Marshall Adkins and John Freeman wrote in the report. They note that U.S. oil production is up less than 100,000 bpd over the first seven months of 2019, compared to the 600,000-bpd increase over the same period in 2018.
The reason is that productivity improvements have suddenly come to an end. Since 2010, initial production rates for the first 30 days of production (IP-30) improved by 30 percent annually on average, according to Raymond James. That was largely the result of the “bigger hammer” approach, the bank said. In other words, drillers threw more of everything at the problem – more money, longer laterals, more sand, and more frac stages. Earlier this decade, IP-30 rates were growing by roughly 40 percent per year. But that slowed to 11 percent in 2017 and 15 percent last year.
However, in the first seven months of 2019, IP-30 rates are up only 2 percent, compared to the 10 percent prediction from Raymond James. Part of the reason is that there is simply a limit to “more, longer and bigger,” the analysts said. “We believe that this represents clear evidence that U.S. well productivity gains are beginning to reach maximum limits and may even roll over in the coming years as the industry struggles to offset well interference issues and rock quality deterioration.” Even 2018 figures may have been a “one-off” increase as the oil majors – Chevron and ExxonMobil – escalated activity.
“Recent Permian IP-90 well productivity trends are especially dire,” the analysts wrote. “While U.S.
IP-90s declined 2%, Permian IP-90s declined 10% relative to 2018.” Because the Permian is the largest source of shale production and the most important source of growth, whatever happens there will determinate the trajectory for U.S. production figures on the whole.
Its an interesting read!
Read it. Good read. I had it posted as one of the replies to Dennis, above. But, it is in some need for repetition (or, it’s own post) thanks!
And, it’s what I have been saying for about a year. That is, I read about it a year ago. Each shale has produced its own self limiter as far as early projections. You have to chase it in the Permian. Pioneer has upped their spacing to over 800 ft. For a comparison, that’s twice the spacing on our wells in the EF. Plus, the CEO reports the sweet spots for most everyone close to the end. Pioneer is in the Midland. EOG is in the Delaware, and reports 400ft spacing, but it looks like they are alternating formations.
And based upon your other post on completions, above, their 350k bpd increase projection for 2020, may be a tad high. They are beginning to catch up.
Double spacing than planned hints to half size of reserves than thought.
And half the time until all acres are used up – until they plan later to drill again in the middle, when the oil price is > 100$. Pressuring up the old dead wells with water and fracking a new one in the middle then.
My guess is they would get better results by drilling outside of the sweet spots when oil prices rise.
And the result is:
The LTO reserves are only half of the official values – which are calculated with the tight spacing. So not 73 Gb(EIA), but only 37.
Eulenspiegel,
If average lateral length is 7300 feet and wells are 100 acres then well spacing is 600 feet, this is the standard assumption of the USGS Delaware Wolfcamp study.
For all of the Permian basin the USGS has the TRR at about 74 Gb for their mean estimate (this includes the Midland, Spraberry, and Delaware studies). For reasonable oil price scenarios and economic assumptions the economically recoverable resources will be about 44 Gb for the Permian basin (about 5 Gb has been recovered to date so 39 Gb to go, if the USGS mean estimate and my economic and oil price assumptions prove correct).
For all of the US my economically recoverable resource estimate is about 74 Gb, with about 60% of the total from the Permian basin.
Also note that the EIA reference scenario for AEO 2019 has US tight oil at 123 Gb from 2006 to 2050 and has tight oil output at 8 Mb/d in 2050.
That estimate is not very good in my opinion and is higher than the USGS mean TRR for US tight oil (which is roughly 110 Gb).
It’s a normal of, at least, two miles now. At 800 ft spacing, that almost doubles your 100 acres. And there are sweet spots, and not so sweet spots. USGS is not producing anything that I know of. Heck, mine in the EF are at 12,000 feet. If they are as long as mine in the Permian, it would be 220 acres with 800 feet. And, I think they are, or longer.
Looked at the USGS report. Upper Wolfcamp has approximately 5 million acres, with the Midland being about half of that. Or, roughly 7,500,000. If 25% of that is sweet spot, then that’s really only about a year of sweet spot left. As says the CEO of Pioneer. Double that for the Spraberry. I’m not talking barrels, I’m talking land area. I used 500 completions per month.
GuyM,
In the Bonespring the laterals are longer about 10,000, USGS has 150 acres for those wells. Perhaps Pioneer has poor acreage, I believe you said EOG is doing 400 foot spacing, Pioneer 800, so perhaps the average is 600, not sure we have data on this. A 150 acre well with 10,000 foot lateral implies a spacing of 660 feet.
At least for the Bakken, the USGS estimate looks like it may prove pretty accurate, perhaps the TRR estimate is too optimistic for Permian basin, but generally the USGS mean estimates have been pretty conservative. At a maximum price of $90/b reached in 2026 and an eventual fall in oil price after 2035 (not a very steep drop), and if the USGS TRR mean estimate proves correct, then the ERR for the Permian basin will be about 44 Gb.
GuyM
Found the following
https://adi-analytics.com/2019/03/25/current-trends-in-u-s-shale-plays-part-1-permian-basin/
Exhibit 1 shows that the average lateral length of a horizontal well drilled in Permian has increased from 5,200 feet in 2012 to 7,200 feet in 2018.
Chart below, if it’s too small click on it and you will get a larger view.
Pioneer has increased for 2019, another 800 feet, making it 9800 ft. They all are, unless they lack the acreage, from what I can tell.
https://www.rigzone.com/news/pioneers_2019_permian_production_growth_on_track-09-aug-2019-159531-article/?amp
That’s 180 acres. And EOG is doing 400 ft spacing, alternating spacing, the equivalent to about 800 ft spacing per formation (bone springs, Wolfcamp. Pioneer is probably doing the same thing in the Midland with Spraberry, Wolfcamp.
I’m having real difficulty working this out past 6 years, based on spacing and available acreage per USGS. Which is far from being all sweet spots.
GuyM,
I focus on basin averages, that is what is reported in the piece I found. Just because one company claims their average lateral length will be 9800 ft doesn’t really tell us what will happen. They also claim an average EUR of 1.6 million BOE for their average well in 2019. If you believe that, I have a bridge to sell you. 🙂
As I suggested some plays such as Bonespring have longer laterals, Wolfcamp wells tend to be shorter, an average of 7200 feet. Note that most of the tier 1 wells are in the Wolfcamp.
Don’t try to sell me the bridge, until you can convince me we can drill enough wells on the limited area that exists. EOG spacing in the Delaware. But, as obvious, all lie on the EUR. Guess they have lousy acreage, too. Because if they combine Wolfcamp and Bone Springs wells, the average as listed is over 800 feet spacing, the lateral length is admittedly less, but still substantial acreage. My guess, it averages around 150 acres. Not per well, but some wasted space.
http://investors.eogresources.com/Cache/1001255228.PDF?O=PDF&T=&Y=&D=&FID=1001255228&iid=4075407
Ok, so your conclusion is that pioneer and EOG are the lousiest producers in the Permian? EOG made good money, and pioneer came close, even after firing 25% of their workforce, and other adjustments. The other little piggies had none. Because, they drilled stupid cube wells, and ran their wells too close together. The benefit of the combined drilling in both formations, is they use the same platform for drilling and completion. What’s wasted is acreage over other costs. They must figure other cost is higher. Acreage is dead cost. And, we are still not considering that all of the acreage is not sweet spots. We can crunch historical numbers, but the reality rules the day.
To me, 150 to 180 spacing appears to be attractive now, but it will get worse. Trust me, I want to buy your bridge. At a discount.
GuyM,
Just checked shaleprofile.com. Enno claims in June 2019 the average lateral length in the Permian basin has increased to 9000 feet from 6000 feet in 2013, so if the increase were linear (I do not have data to confirm this) this suggests about a 500 foot increase in lateral length each year from 2013 to 2019. Since 2016 average productivity has been stagnant (not accounting for increased lateral length or proppant intensity.) This indicates a fall in productivity per hundred feet of lateral from 5120 bo/100 feet in 2016 to 4553 bo/100 feet in 2018, about a 5.5% annual decrease in productivity per foot of lateral from 2016 to 2018.
In short average well productivity in the Permian basin has only been maintained by increasing the average length of the laterals and increasing proppant density (this has doubled over the past 6 years).
GuyM,
Keep in mind that I do not expect the URR will be equal to the TRR. The TRR is 75 Gb for the Permian basin for the USGS mean estimate. For my $90/bo oil price scenario (maximum price is $90/bo from 2027 to 2035) my recent scenario has about 44 Gb of output from Permian basin.
Also the current average Permian well has an EUR of 387 kb vs 253 kb for the best wells modelled by the USGS at 100 acres, so a factor of 1.5 better. Let’s assume these wells are 150 acres and 9000 feet, that gives a spacing of 750 feet, pretty close to the 800 number that may be optimum.
Also note the $90/bo scenario has 133k wells drilled for the 44 Gb vs 350,000 wells to reach the USGS TRR, though those 350,000 wells would be smaller acres per well (100 vs 150), so we might have about 233,000 wells to reach the TRR (at 150 acres per well). So the comparison is 133k to 233k wells from ERR scenario to TRR scenario.
This points me to a possible error in my scenario, thanks. (I was erroneously using 350k wells, and should have been using 233k wells).
Based on estimates from shale profile the average well productivity for Permian basin wells has been pretty steady from 2016 to 2018, it is too early to estimate the productivity of 2019 wells.
EUR for 2016 is 384 kbo, 2017=386 kbo, and 2018=387 kbo, for the average 2017 well the gas EUR is about 300 kboe so overall EUR for 2017 wells including oil and gas is 686 kboe. Gas sales can help to offset LOE, also there is probably about 30 kb of NGL that can be extracted from the natural Gas, which is an additional revenue stream. Based on this data and assuming natural gas gets $2.50/MCF at the wellhead the breakeven oil price for the average 2017 well would be $48/bo at the wellhead for a well that costs $10 million. The well pays out in 63 months. A 10% annual discount rate is used for the discounted cash flow analysis.
https://peakoil.com/geology/renat-muslimov-oil-in-fact-is-endless-it-is-a-renewable-energy-source
Replenishing sedimentary rock, etc.
Lol. Then I guess Russia can pump forever.
Oh, they are going to win. They have the surface area. They have been the target of abuse. They will have oil remaining when others do not. Why would they be kindly disposed towards governments that have sanctioned them?
They will be willing to trade whatever they produce beyond their own consumption. But not for printed pieces of paper. For actions. Like unilateral disarmament.
Countries will refuse? They will shrug.
And who will they choose to sell to? Will they see China as an ally, or a threat?
There is always the save it for our grandkids option.
And no reason they can’t insist on Chinese disarmament, too.
Here in the USA, we do act as if oil is renewable or endless in supply. We act like Renat Muslimov speaks.
If we thought there were limits, we would have a plan to produce slowly at a longer sustained rate, trying to stretch out domestic production for as long as feasible.
We would purchase oil from abroad whenever the price was below a certain threshold, rather than consume our own resource as quick as possible.
But instead of long term planning, we rely on the market to direct the decisions of thousands of operators.
And as has been pointed out so many times- the oil market is extremely dysfunctional. The signals a producer gets from the market are extremely distorted in both time and magnitude.
Its a broken system, so we do act as if the Russian is correct.
Some people would counter that the market is a better determinant of industrial policy than any sort of central planning. I would generally agree, if the market was at least somewhat transparent, and timely, and if a product was truly renewable. Like corn for example.
“Some people would counter that the market is a better determinant of industrial policy than any sort of central planning.”
With the Pleistocene ape at their heart, perhaps they both suck.
T. Boone Pickens has passed on.
https://www.nytimes.com/2019/09/11/business/boone-pickens-dead.html
https://oilprice.com/Latest-Energy-News/World-News/Oil-Legend-Boone-Pickens-Passes-Away-At-91.html
My wife and I made two weekend round trips from Love Field to Boone’s Panhandle Ranch,in Boone’s jet, together with assorted Amarillo and Dallas friends. I had known Boone since 1945.
https://www.facebook.com/photo.php?fbid=1505594846907&set=a.1399109144831&type=3&theater
OPEC Sep 11 MOMR is out
https://momr.opec.org/pdf-download/
Table 5-4 is incorrect as the US states are not matched with the right production numbers. Eg Alaska produced 4.98 mbd in June as in chart below. Graph 5-7 shows both US crude weekly and monthly for 2019 and hasn’t increased much since Jan 2019.
They have mixed up Alaska and Texas
OPEC MOMR Table 5-6 shows OPEC forecast of tight oil plays with Permian being the largest contributor.
Lol, yeah that’s pretty messed up. They have Colo and the GOM switched too.
OPEC oil monthly report makes sense.
Non OPEC supply has increased by 2 million barrels per day.
Consumption has increased by 1 million barrels per day.
OPEC has therefore cut production by 1 million barrels per day to stop prices falling any further.
They also see very similar increases from 2019 to 2020.
No Peak oil just yet
On 30th of September we will get full picture of changes:
https://www.eia.gov/petroleum/production/
This will be a game changer for the rest of the year.
My base scenario is that we will end up year with lower US production than that in Dec 2018. Next 3 months will be crucial.
There is only one thing: “The market can remain irrational longer than you can remain solvent.”
Peak oil is when the fat lady sings.
Propably when US shale is falling permanent because of depleted A and B+ locations, not a temporary dip because of low prices. As discussed here in the forum, 5 to 10 years in the future. Until then a lot more conventional giants will be in terminal decline, too.
With only B and C locations left they can drill what they want, they won’t keep the red queen on distance any more.
There could be some magic by bringing Iran and Venezuela back to market in full power – but would have to be timed. Venezuela back in the 30s would lengthen the top.
By then the Bazhenov formation could well be producing oil.
The Russians are gradually getting the technology to develop their shale fields and with higher prices in the coming years there is a good chance they will produce most of this resource.
https://www.reuters.com/article/us-russia-oil-shale-gazpromneft/gazprom-neft-says-bazhenov-shale-oil-output-to-reach-viability-by-2022-2023-idUSKCN1TI0MQ
They want to start lifting it commercial 2025(from article). And propably not in a wild frency like in the USA, but ramping up slow for replacing their aging cheap producing giants. So I think it mostly will hold russian production even for at least 20 years, +/- only a few million bpd.
No silver bullet, it’s a 20-70 billion barrel ressource. And the russians need 4 every year to stay even.
Additional, it’s in very cold climate region in Siberia. So without extra effort fracking is only possible in the summer months without risking ice cubes in every water hose. So no frency, but steady production more like in a normal field. By company fracking teams moving from site to site, building road and pipelines on their way in the most cost effency way. Perhaps they even build company railways for all the transport tasks.
Eulenspiegel,
It is pretty darn cold in North Dakota. They slow down a bit in winter, but for 9 months of the year that can go pretty much full bore, Russians think 0 C is warm weather. 🙂
Note that the resource is about 80 billion tonnes, that is 280 Gb, perhaps half is economically recoverable which would be 140 Gb. By the time this resource is ready to be developed oil prices will start to fall and it may never become economically viable. We will find out in 2025, I expect oil prices will start to fall no later than 2040, so if it is developed at all, probably no more than 25% of the TRR will be recovered, so perhaps 70 Gb would be a reasonable WAG.