Mushalik – do you have any views on NGLs. There’s been quite a surge of production to fill some of the all liquids demand and US is the biggest producer but I’m not sure if the growth can be kept up. A lot depends on whether the new gas supplies (e.g. East Africa LNG) are wet/dry and I’ve seen no analysis on such things. I think US tight gas is fairly wet.
Won’t China’s tariffs on US LNG lower demand for US?
I doubt if production would decline though it would just go to a different market. There’s quit a lot of things that can happen. NGLs (even without the condensate) is about the same order as US, Russia and KSA for overall liquids supply and with the condensate it’s the largest but the liquids to gas ratio is completely different from field to field and the condensate to gas ratio changes with time so it’s difficult to predict (and less data than for oil even in the well reported producers).
Trump is going to have to bring out the big gun of SPR draw, his tweets did not have a lot of effect. That may be good for a month. Though, that may mainly effective in lowering WTI, and not so much Brent. I remember reading the last time, that refiners had some problems with it.
It looks like the traders want prices above $80 for Brent but can’t quite bring themselves to be the first.
Calls over $80 are higher than anything.
Traders only make good money when it goes up or down considerably. It’s not going down much, probably. Spot prices will probably prevent that. I think it is finally getting to the point, when spot prices have more sway than the Willy nilly decisions of what it should be by the traders.
Saw Brent get over $80 this morning, at least one time. Where is tweety bird?
This came instead (the oil price police is still holding it under $80):
OPEC and non-OPEC countries discussing possible production increase by another 500,000 bpd – Reuters
By Eren Sengezer
Citing three sources with direct knowledge of the matter, Reuters reported that OPEC and non-OPEC countries were discussing a possible production increase by 500,000 barrels per day.
Sources further added that OPEC and non-OPEC countries pumped less oil in August compared with July due to drop in Iranian crude supply.
Guess they will have to pull more out of storage. They can’t produce that much more.
Mr. Berman has a recent interview and slide deck linked at his site. I found what he had to say interesting with regards to oil price dynamics. I quite like his graphs/charts too.
the presentation was good. an article he wrote a couple weeks ago in response to the “next financial crises” article from NYT is a bit more cohesive and compact in terms of discussing his thesis. the presentation has much more data/charts though.
I like berman because he helps counter the “well duh supply and consumption are always equal” stuff we tend to get on the board. he also believes high oil prices contributed strongly to GFC.
Two cats,
Inventory can be considered a part of supply. Cannot consume what does not exist. I like Berman’s analysis as well.
Inventory increases and decreases and affects oil price.
Shallow Sand,
Continuing our discussion of decline rates from last weeks’s post…
I looked at decline rates for Permian wells from 2009 and 2010 from month 50 to month 90, with data sampled every 5 months to save time (50,55, … , 85, 90). The decline rate is about 13% per year. For Bakken 2009 and 2010 wells (later stage of development of play using horizontal fracked wells) over month 50 to month 90 we get about a 12.7% decline rate with same sampling. So at least through 2009 to 2010 the two plays have similar decline rates for months 50 to month 90.
For the Bakken we have older wells that give us some information about decline rates later in the life of the well (after month 90). For Bakken 2006 and 2007 wells (2008 has strange behavior with an increase in output late in the average wells life so I decided to exclude 2008) we have 237 wells, so a fairly small sample, but better than nothing. The annual decline rate from month 60 to month 115 is about 9.5%per year over that period, which suggests that a 9% decline rate may be reasonable based on the data we have.
We won’t know if the Permian Basin will match this for a few more years, based on the data we do have for the Permian we would not expect the terminal decline rate to be higher than 13%, and in my view an assumed 11% decline rate might be a reasonable guess.
It would be interesting to hear Fernando’s perspective, though usually he has said in the past he doesn’t know enough about these plays to even make an educated guess.
Charts below for data I have all pulled from Enno Peter’s shaleprofile.com (link below)
Chart for Bakken 2009 and 2010 average well decline from month 50 to 90.
Chart for 237 Bakken 2006 and 2007 average wells from month 60 to month 115 from first well output.
Average annual decline rate 9.5% over that 55 month period.
I have read by some that the new productivity is not increasing EUR, just merely getting it out quicker. I think that is more doomsday, than technical. Eventual decline rates are going to be a moving target, if this article has any significance, which I believe might be true. https://www.epmag.com/shifting-focus-optimized-production-1713356
Then you have EOG’s reported “success” in increasing EUR by 30 to 70% with enhanced Recovery in the Eagle Ford. Supposedly, just successful in the Eagle Ford because of containment. Although, other types of attempts are being tried by others in the other plays.
And decline rates will be affected by the shift from tier one to tier two as pointed out in Ron’s post, below.
Guym,
Probably true in the Bakken where average lateral length has not changed much since 2008, for the Permian basin much of the increase in new well EUR is due to increased lateral length so greater contact with the oil bearing zone of the play for each well increased overall EUR. It also means fewer total wells will be drilled as more acres consumed by each well.
Dennis.
We won’t know till we get there.
9% annual decline for a stripper well is pretty steep IMO.
Sprayberry has a lot of wells that are still economic at high oil prices despite producing under 10 BOPD.
Whether horizontals in the Permian will work at such low volumes remains to be seen.
Higher oil prices will help.
Shallow sand
I agree at low oil prices 10 bpd doesn’t work for horizontal wells.
Also agree 9% decline not great. 13% is worse.
We will see in a few years what the wells look like.
Dennis.
Do you know much about the construction of these horizontal wells? I admit I don’t.
There have been a few drilled in our area, at much shallower depths.
It seems that eventually the lateral casing collapses. I suppose maybe they were not constructed properly, as these date back 15+ years ago with regard to completion.
I assume the technology or geology is such that this is not a concern for the shale wells?
It seems like that is quite a load for the casing to bear under 10,000’ of rock, but I will admit that is just a guess on my part.
Shallow sand,
I would know less than you. I imagine the loads can be designed for from an engineering perspective.
Lighesout posted this link in the coal post but it belongs here.
While the majority of existing wells are located in geography with well performance of 1,000 b/d or more, the majority of remaining wells will likely be located in geography with well performance below 500 b/d.
The study shows that as operators move out of the core, average Bakken well performance could plummet.
Thanks Ron,
That piece is a good read.
There is also:
The North Dakota Pipeline Authority forecasts statewide production to gradually peak between 1.9 million b/d and 2.3 million b/d within about 15 years.
My expectation is that the peak in North Dakota Bakken/Three Forks output will be about 1.79 Mb/d in 2020 (vs 1.22 Mb/d in July 2018) for a scenario where oil prices peak at $113/b in 2017$ in 2027, remain flat until 2040 and then gradually decline. URR is 9 Gb by 2041 and 28,000 total wells are completed in the scenario. Well completion rate (new wells per month) shown on right axis of chart below peaks at 22o new wells per month in 2022 and falls to zero in December 2027.
Clearly I don’t know future well completion rates, but I expect higher oil prices might result in more drilling.
Alternative scenario for Bakken where well completion rate is limited to 155 new wells per month (the wells completed in July 2018 were 141 new wells based on Enno Peters assessment), peak in 2021 at 1.5 Mb/d, URR is 9 Gb and total wells completed about 28,000. Same oil price and other economic assumptions as previous scenario, only well completion rate is changed.
Dennis
I am glad you noticed that last paragraph in the Platts’ piece as I thought it was the single most important takeaway (as well as probably being accurate).
The overall negative tone in the article surprised me a bit as the Platts people have always seemed to be a pretty good source of info.
However, this instance could be a good opportunity for people to spend a few minutes, go to the source, and draw their own conclusions.
The referenced report is the September 14, 2018 NDIC Update from Justin Kringstad, Director of ND Pipeline Authority.
Screen #17 from the report may be the ‘money shot’ as a slightly more expanded view appears to show vastly higher numbers by simply dropping the bopd rate to 900 bopd or, more dramatically, to 800 bopd.
The ‘High Case’ scenario is on track to be more probable as the effectiveness of diverters has increased significantly these past 2 years.
Somewhat related, results from Liberty’s EOR pilot may be published soon.
Much interest focused upon the results.
I disagree that the high case scenario is more likely, as the higher productivity areas become fully drilled, the lower productivity areas will not be able to support high well densities. The low case looks far more likely to me and is more in line with the economics at reasonable oil price levels.
Also they use a model with $7 million well cost which probably excludes many real costs such as land cost, overhead, storage and gathering facilities and plugging cost at the end of a well’s life. The real full cycle cost is more like $9 million than $7 million. Investor presentations typically do “point forward” well costs and ignore sunk costs. A proper accounting to evaluate ROI considers the full cost of the investment including the current price the land could be sold for, the so called opportunity cost.
Interesting that you mention investor presentation, Dennis.
Mr. Kringstad is an employee of the ND state government, tasked with continuously modeling hydrocarbon activities within the state so as to better evaluate future tax revenues, infrastructure necessities, etc.
Now, you strike me as a numbers and graphs kind of guy, Dennis.
What say you regarding slide #18 from that report?
The chart projecting – at 1,200 completions/year and $61/bbl earl – OVER 60 years worth of drilling?
Asking for a friend…
Probably 1200 completions per year is too low an estimate, that’s 100 new wells completed per month, the high case estimate is very unrealistic given the productivity distribution, a realistic estimate is 40,000 total wells completed at most and about 13,000 wells have already been completed in ND Bakken/TF so that leaves 27,000 wells, at 1200/year, that’s 22.5 years of drilling when no economics is considered, a realistic economic assessment is as I show below with 33,000 total wells drilled, last well drilled in Feb 2035 if oil prices rise to $113.40 in 2017$ by Feb 2027 and remain at that level until 2040. So maybe 17 more years of drilling, with a gradual decline in completion rate after Jan 2033 due to poor economics as new well EUR falls as lower productivity areas are drilled.
Many of the state agencies make optimistic assumptions when developing their output profiles and use unrealistic well profiles.
The average 2017 Bakken/Three Forks well will have an EUR of about 400 kb0. It is too early to make a decent estimate of Bakken 2018 well EUR.
SEVENTEEN YEARS more drilling???
(Clasps hands to chest, pirouettes and does a face plant into da ground.)
Y’all might wanna screencap that comment, Dennis, and revisit it 5 years down the road.
GGZZ, All we are doing is documenting the atrocities. In 5 years, the scholarly citations will be numerous.
Documenting whatevuh, but 17 years remaining for drilling in the Bakken is way, way off the mark.
Despite my having very different views on many of these topics with most commentators here, this level of disconnect seems especially bizarre.
Heck, Kringstad’s report is calling for a peak in the Bak at about that timeframe – 15 years.
At about 2 MM bbld, no less.
You guys are the number crunchers.
Something is significantly awry, and I think the fulltime analysts outta ND get the nod.
“Heck, Kringstad’s report is calling for a peak in the Bak at about that timeframe – 15 years.
At about 2 MM bbld, no less.”
Really not that much different in the greater scheme of things.
You are not showing much of a cornucopia of riches either, wha’happen?
Every morning when I open my eyes, if I`m not seeing grass roots, Imma experiencing a cornucopia of riches.
Being a realist, I’d assert that you wouldn’t be seeing anything in that case.
Therein lies the diff.
Hi everybody,
I have been a reader of this blog for years now, and it´s time to take part in that discussion.
My problem is the number of “1280 spacing units (est.)” on slide 6. The questions is, how big is the Bakken Play from the north to the south and from the east to the west.
Start in the “Parshall” area (89w) and go to the border to Montana (104w), you get around 96 miles. Go from Billing and Stark (139n) to the border of Canada (164n) and you get around 156 miles. Some Areas in the north and the south-west are not too productive, so you get an average of around 120 productive miles from south to North (est.).
Multiply 120×96 and you get around 12000 “productive” sections, which means around 6000 “1280 spacing unit” and not all those units are economic. The numbers on slide 6 – almost 10000 spacing units – is weigh to high, even if acount or for some 640 spacing units that are beeing drilled.
That is the big mistake in that studie in my opinion.
Best regards
Toby
Toby
Welcome to the discussion.
Looking at that report (slide #5), they are using historical, production records showing output from 9,775 DSUs.
Of that number, almost 4,000 are dogs, less than 500 bopd from top producer in unit (probably the only producer if one wanted to crosscheck on the DMR Gis map).
Using the gross areas from Dunn, McKenzie, Williams, Mountrail, Divide and Burke counties gives about 11,000 square miles.
Less than 6,000 DSUs.
So, you sure seem accurate in wondering where all the ‘extra’ DSUs came from.
I’ll zap off an email to Mr. Kringstad tomorrow and ask him exactly that.
But – again – the DSUs that are in the report on slide #5 are from already producing wells, so they say.
Toby, there must also be a question of how they have come up with the high and (especially) low well densities as there nothing stated to justify the numbers and not much history to show what will work without interference in the poorer areas. Bakken is treated as a single tier from what I can see but pretty obviously the production declines markedly on the outskirts, and I think there’s already been some indication of well interference.
This shows the current production wells per DSU based on concentric rings from a nominal centre. Only one small area is above 8. If you assume 6 for the area to 50 km radius, 4 to 70, and 2 to 100 then there are 1500 more wells in the centre, then 2200 then 3800 (mostly crap on the periphery). Are my numbers any good? No but at least they fit in with current history and might not be any worse than the ones in the report. It includes Bakken and Three Forks so is conservative in some ways, not in others and doesn’t include abandoned wells.
George,
My low F95 TRR scenario ends up with about 7000 wells completed from Aug 2018 to Dec 2030, very much in line with your estimate here of roughly 7000 wells, though perhaps you might think that estimate is too optimistic. ERR, when a medium oil price scenario and an $8 million well cost assumption are applied is about 6.3 Gb, a little lower than proved reserves and cumulative production through Dec 2016 (about 6.8 Gb).
Coffeeguyzz,
It seems we have different North Dakota Government experts with very different production forecasts.
Compare slide 13 and 25 from the presentation linked above, the forecast on slide 13 must use a well profile that is not realistic.
Kringstad may be using a “typical well profile” that is far too high. Many of the “typical well profiles” given in older NDIC presentations are far from realistic. The “peak production estimate” given in slide 25 with about 1.5 to 1.6 Mb/d from 2025 to 2030 is at least somewhat realistic, but the long slope down assumes far too much output, than is realistic.
Scenario below attempt to match the Peak Output NDIC estimate of about 1.6 Mb/d in 2030, a high oil price scenario is used ($147/bo in 2017$ by 2027) and a low well cost of $6 million in 2017$ is assumed, 43,600 total wells drilled and ERR of 11.5 Gb by 2050, peak well completion rate is 320 new wells per month in the second half of 2029, new well EUR falls from 414 kb in July 2018 to 110 kb in Jan 2031 when the last well of the scenario is completed.
Dennis
This is just one of the many reasons that I do not hold future projections so fervently as being the Unvarnished Truth, aka, what to precisely expect.
Different views, varying input data points, on and on.
What caught my eye was slide #26 on your above link, the Gis map screenshot showing activity near the Red Rock field way over in Bottineau county.
Without digging into the specifics, it looks like the recent work from a smaller operator in shallower rock.
THIS is one of the bigger potentialities that I’ve mentioned in the past to watch out for.
Specifically, smaller operators in the US are tentavely pursuing exploration/development in shallower areas of known hydrocarbons using some of the hardware and processes that the Big Boys have been pioneering this past decade.
From old Appalachian Basin formations, the Clinton Sandstone, south eastern Colorado, tentative probing up in Michigan and Illinois …
These smaller operators may never produce the larger volumes of the prominent players, but – as can clearly be seen in that Gis screen shot – activity is well under way by these guys.
Coffeeguyzz,
At most these smaller operators may reduce the overall decline rate of US output a bit after 2023 when US LTO output is likely to peak, not going to be enough to stop the decline from larger producers as the more prospective areas become fully drilled.
If we ramp up hard to try to keep production flat we get a steep drop around 2030, even if we assume low well cost and high oil prices ($147/b in 2017$), small producers will not be able to stop a 1000 kb/d decline from 2030 to 2035 from the Bakken along with even bigger declines from the Permian basin. After 2030 the decline rates in the tight oil sector will be quite steep (though it might start sooner than this if the USGS mean estimates prove too optimistic.)
Reports on the net about yesterday’s Bakken 2.0 conference contain some eye opening claims that you might find perposterous, Dennis.
Ultimate recovery of 30 to 40 billion barrels
12 to 20 percent currently recovered from new wells
Possible 2 Mmbld rate in just a few years.
Interesting stuff.
Reporter named Springer wrote the articles that I read.
Cowboyistan.
Coffeeguyzz,
Only 40 Gb, why not 400 Gb? 🙂
You gave said before they won’t leave any oil behind.
Coffeguyzz,
The 2013 USGS estimate for the North Dakota Bakken Three Forks was a mean of 10 Gb, F95=8 Gb and F5=13 Gb for technically recoverable resources.
Continental has been claiming 30 Gb for many years. The average 2017 well has an EUR of about 400,000 barrels of oil, if we make the assumption that the average of all wells drilled in the Bakken/Three Forks will average 400,000 barrels each, then 75,000 wells gets us to 30 Gb and 100,000 wells gets us to 40 Gb.
Does it seem reasonable to you that the Bakken/Three Forks is being developed in a random way where oil companies just drill their wells anywhere in the formation?
Or would it seem more plausible that they drill and complete wells in the most prospective areas first, especially after the first few years when the tier one areas have been well defined?
I would submit that the latter case is more likely and that the tier one areas are being drilled preferentially, especially since 2014.
Clearly the assumption that the average well productivity will reach some maximum and remain at that EUR level for the remaining time that the play is developed is an absurd one.
Even more absurd would be an assumption that the new well EUR will continue to increase without limit.
I also note that the well cost estimate is about $8.5 million rather than the $7 million estimate given by the ND Pipeline Authority.
A more reasonable estimate with reasonable well cost, tax, royalty, transportation cost, OPEX, and oil price assumptions is at most 40,000 wells completed in the ND Bakken /Three Forks.
Average well productivity for all 40,000 wells is likely to be 250,000 barrels of oil over the life of the well.
The average well productivity will not remain constant, it started at about 150,000 barrels in 2005 increased to about 320,000 barrels by 2008, increased further to 400,000 barrels by 2017 and is likely to gradually decrease from Jan 2019 (a guess on my part it may be before or after that date) until the last well is drilled.
This is the normal life cycle of an oil play, always has been and always will be.
Coffeeguyzz,
The 30 to 40 Gb estimate is nothing new Continental has been claiming that since 2013, the NDIC agrees with the USGS F5 estimate of 13 Gb.
If one looks at the area where most of the completed wells are focused and the drilling densities to date, even 30,000 total wells completed may be a stretch, the NDIC estimate of 55,000 to 65,000 total wells completed only happens in a World with $200/b oil in 2017$ and well cost of $5 million. In other words, some other universe.
Aaannndd …
You may want to be a little cautious when making any comments regarding the extent and productivity of the Three Forks, which comprise a fair amount of this report.
There are too many unknowns.
The High Case scenario projects 10/6/4 wells throughout Tiers 1,2 and 3.
Based on some recent production, including a very good third bench TF well, upside potential is promising.
Canadians have been successfully targeting this formation for years north of the border.
The Three Forks is accounted for in my estimates, lower benches of the Three Forks do not look very productive.
Using well profile data to date from shale profile and the $7 million well cost and the assumed 1200 wells completed per year in the North Dakota estimates by the Pipeline Authority, along with the 2013 USGS mean estimate for TRR, I get a very different estimate for North Dakota Bakken/Three Forks output with peak in 2019/2020 at 1.36 Mb/d. URR is 9.6 Gb with 33,000 wells completed.
” … lower benches of the Three Forks do not look very productive”.
Where the heck are you getting data concerning TF2, TF3, and TF4, Dennis?
Some of the better wells out of North Dakota have come from TF2.
This is one reason the gas component is higher as the deeper, hotter formations contain more gas.
The operators have been very cautious in delineating productive TF 2/3/4 as it is more of a learning curve that they feel is not currently an optimal allocation of capital.
There is a fair amount of anticipation concerning the northerly step out as a very productive well was recently brought online near the Divide county line.
Coffeeguyzz,
Lower benches are TF3 and TF4, look at the report, the productivity of TF3 and TF4, most wells are under 500 bopd for peak month, there will not be the high density well spacing assumed in the “high case”.
Coffeeguyzz,
Keep in mind the years of drilling is based on 1200 wells per year drilled, that doesn’t get Bakken output close to 1.9 Mb/d (it would be more like a 1.3 Mb/d peak). To get to the 1.9 Mb/d peak about 600 new wells per month would need to be drilled at the peak and a reasonable scenario has about 83,500 total wells completed (the average of the high and low cases would be about 70,500 wells completed.)
If we ignore the economics at $7 million per well (an underestimate of full cycle cost) and just consider TRR, it would be about 13 Gb, near the F5 TRR estimate of the USGS. Peak is 1.86 Mb/d in 2025 for this very optimistic scenario. Note that the high case is 98,000 total wells drilled, but that case assumes 41,000 wells are completed with peak month output under 600 bopd, not very realistic, where the more realistic low case has about 26,000 fewer of these low productivity wells completed, so a more realistic scenario would have a maximum of 72,000 new wells completed (11,000 less than the scenario I created for very high TRR).
The chart below shows this highly unrealistic scenario.
Dennis
You have an awful lotta numbers in your comment that may or may not prove applicable in years to come.
Right now, on the ground procedures in North Dakota (and spreading throughout this entire unconventional industry), are enabling operators to access and recover far more hydrocarbon at lower cost.
I have noted on this blog numerous times that your inclination to view historical data and project forward, absent an understanding of ongoing developments, will continue to impact your predictions to the downside.
One of the bigger considerations with the Kringstad report may be the future potential of the Three Forks.
Dennis, if you look at the heat map from Kringstad relating to Tiers 1,2 and 3 – including the “Empty” Tiers #1 and2 – it should, hopefully, become clear that there is enormous upside potential to future TF development.
Furthermore, when smaller, scrappy outfits like Kraken Operating enter the arena, fringier areas might well be successfully targeted.
This, in fact, is what is presently unfolding.
If you spend a few moments just looking at slide #8, the size of it, the historically archaic practices that went into all those lightly shaded green and yellow dots … and fast forward to the rapid, precise drilling and highly productive new completion practices of today, one may grasp what is apt to take place in the coming decades.
As an aside, slide #23 may put to rest any uncertainties regarding Mr. Martenson’s unease regarding perceived discrepancies in well prodiction profiles.
Coffee, It seems that Kraken has recently cut it’s rigs from four to three. Does that seem right to you, and do you have any idea why.
dc
I no longer put too much time keeping an eye on the Bakken outside of regularly checking in on Bruce Oksol’s blog.
He has regularly commented on how effective Kraken’s wells seem to be, which is saying something as I believe most of their acreage is not considered top tier.
(They bought into the Bakken from a bigger operator’s divestment, I believe).
So, no, I do not know what those guys are up to.
ZZZ’s
“I have noted on this blog numerous times that your inclination to view historical data and project forward, absent an understanding of ongoing developments, will continue to impact your predictions to the downside.”
One of the great findings is how well a statistical/probabilistic analysis works on the Bakken. Just knowledge of number and a statistical view of the average allows us to come up with a close running tabulation of production. This was never possible in the past.
I love this; a guy from Minnesota, another from Maine, and one from San Francisco, of all places, arguing about the plight of the US shale oil industry. None of whom have EVER picked up a pipe wrench in their sheltered lives, or balanced a well’s checkbook, all of whom think they know the answers and can predict America’s hydrocarbon future. Two thru math and models, one because the shale oil industry simply SAYS so.
Ain’t the internet great ?!!
Nice to see your track record of being incorrect remains intact at the near 100% level, Mr. Roughneck.
This oh so sheltered life just picked up a pipe wrench last week to do some minor repairs.
And, not that it means squat when it comes to accurate information dissemination, this oh so sheltered life still has – and probably always will have – the world record for disassembling a Christmas tree flange at depth, 1,610 feet pressure, to be precise.
You, um, you HAVE seen Christmas trees out in the field, I reckon.
Mike invented the freakin X-mas tree! Everybody knows that.
Mike,
As I have said repeatedly, but you might have missed it, nobody can predict the future.
I create scenarios using a variety of assumptions of what the future would look like based on those assumptions.
A high well cost ($9 million in 2017$), low completion rate (100 new wells per month or 1200 new wells per year), and a medium oil price scenario ( a linear increase in 12 month average refinery gate oil price from $75/bo in June 2018 to $113/bo in 2017$ by Feb 2027) results in a relatively low peak in Bakken Output of 1.36 Mb/d in 2019. This seems too low a well completion rate to me as the most recent value was 139 wells in July 2018, an alternative scenario assumes well completion rate rises to 155 wells completed per month by 2020 and remains at this rate for 4 years before the completion rate decreases. All well cost and oil price assumptions are unchanged, peak is about 1.5 Mb/d in 2020/2021. For both of these scenarios URR is about 9 Gb, total wells completed (including the 13,000 ND Bakken/TF wells completed through July 2018) is 28,000 from Jan 1951 to Jan 2030.
Alternative “unrealistic scenarios” were created to see how many wells would be needed to reach the ND Pipeline Authority’s “Low Case” of 1.9 Mb/d in 2030 basically even unrealistic assumptions could not reach this level using a $6 million well cost in 2017$ (too low by at least $2 million) and a high oil price of $147/b in 2027 and remaining at that level until 2055 (in 2017$).
None of these are predictions in the sense that I cannot predict next month’s oil price or completion rate, never mind what they will be in 2030 or any year or month between. Past is known (to some degree) the future is not.
Where someone is from has little to do with whether they can analyze the data.
My opinion is that the 1.5 Mb/d peak in 2020 looks pretty reasonable if oil prices continue to rise (the medium oil price case assumes $85/bo in 2017$ at the end of 2020 at the refinery gate), note that the ERR is about 1 Gb less than the USGS F50 case for ND Bakken/TF TRR.
Lower
I haven’t seen a probabilistic analysis of this just deterministic appraisals based on different assumed ultimate recoveries. The URRs may be probabilistic, and they are the key numbers, but industry has been generating P10 etc. estimates for these for many years so I don’t follow what is new.
George Kaplan,
For the Bakken, I agree not much is new, simply taking the average well profile and convolving with well completions, first popularized by Rune Likvern.
I have simply extend this analysis by assuming that new well EUR decreases in the future (with a guess of Jan 2019 as the start date), assume about 40,000 wells will be completed in the future (though this assumption varies from 30,000 to 50,000 and is of course unknown) and it is assumed that total URR is about equal to the USGS mean TRR before economic assumptions are applied and then economic assumptions for well cost OPEX, royalties, taxes, and transportation costs and oil prices are added to the analysis so that the discounted net cash flow over the life of the well is greater than or equal to the cost of the well. Future wells that do not meet this test, with the given economic assumptions are not completed.
Clearly we do not know future URR, when new well EUR will decrease, future oil prices, or future well completion rates, so different scenarios are presented with different, URR assumptions, total wells completed, oil prices and well completion rates.
I have not seen that many industry analyses where these assumptions are laid out clearly.
I am always willing to share my work with those who ask.
No one was really able to do this before (at least in the open) because no one ever had the numbers until the NoDak DMR provided such a comprehensive data set.
Convolving is a fancy name for multiplying time series for completions with a time series for assumed EUR per well and fitting to the constraint of URR. But all those three things are unknowns and simply your new assumptions or. choice of somebody else’s. A probability analysis would give some kind of distribution of possible outcomes and highlight the key variables (almost certainly the URR more that anything else). You are simply giving one (or a few) possible scenario(s) with no indication of it’s liklehood.
The statistical nature of a typical well allows the convolution approach to work very well if all one knows is the average and the number over time. Found that out early on and is an important piece of the extrapolations that Dennis is making.
George,
The historical well completion data is known and we can make a fairly good estimate of the well profile based on past data. The likelihood that might be assigned to well profiles, oil prices, future well costs, and well completion rates would be subjectively assigned and I don’t see much point in guessing at the probabilities (though occasionally I make such guesses). I could easily provide a low high and high TRR estimate based on USGS estimates and estimates by other experts such as David Hughes.
The USGS gives an F95, mean, and F5 estimate for undiscovered Bakken/Three Forks TRR, I typically use the mean which is around 10 Gb for TRR, F95 is about 8 Gb and F5 is about 13 Gb. That’s about as much probability that can be injected into the estimate. As to subjective probabilities for completion rates, oil prices, etc I will leave that to experts. I just look at what has happened in the past and make a subjective “reasonable” guess.
Note the very high TRR and ERR scenarios that peak around 1.85 Mb/dare consistent with the USGS F5 scenario.
A scenario consistent with the F95 scenario could also be created.
Such a scenario is presented below, with TRR of 8 Gb with 40,000 wells completed, using the medium oil price scenario (maximum of $113/bo in 2017$) and an assumed well cost of $8 million, the ERR is about 6.3 Gb with 20,000 total wells completed (7000 wells after July 2018).
I would guess there is at least a 95% probability that this scenario will be too low in terms of ERR. Through Dec 2016 about 2 Gb had been produced from the ND Bakken Three Forks and there were about 4856 Gb of crude proved reserves in the ND Bakken Three Forks at the end of 2016, so we would expect there should be a 90% or greater probability that 6.8 Gb will be produced from the ND Bakken/Three Forks.
Paul,
You, James Mason, and Rune Likvern were all doing this at around the same time, I just saw Rune Likvern’s work earlier than yours and Mason’s because I was reading the Oil Drum regularly at the time. Rune graciously shared some of his data with me and I started posting some stuff at my old blog.
The model has changed quite a bit over the years as I have gotten more data.
Coffeeguyzz,
I use the well profile of the average 2017 well to project forward as we don’t have enough data yet from 2018 wells to estimate the well profile. The average 2017 well has an estimated ultimate recovery (EUR) of 415 kb, based on actual data collected from the NDIC on well output from 1694 Bakken and Three Forks wells completed in 2016 and 2017.
One can hope that future wells perform much better but the history of the Bakken from 2008 to 2017 shows that by month 24 the well profile of newer wells falls to the level of older wells, over the first 24 months cumulative production of the average 2015 well was about 30 kb higher than the average 2008 well. At 20 months the average 2016 well had about 30 kb higher cumulative output than the average 2015 well. At 12 months the average 2017 well had about 30 kb higher cumulative output than the average 2016 well. So far the cumulative output of the 2018 and 2017 average wells are similar. The increase in the average EUR of Bakken/Three Forks wells is likely to end as sweet spots run out and will gradually decrease over time.
It is difficult to guess accurately when that will occur, my current estimate is Jan 2019, but we won’t really know if that guess is correct until 2021 when we have more data.
Coffeeguyzz,
The green dots are the areas where the rock is poor, doesn’t matter what technology is used those areas will never have high EUR.
Technology brings incremental improvements, it is not magic.
Coffeeguyzz,
If we then apply economic assumptions to the unrealistic TRR scenario with TRR=13 Gb and 83.5k wells completed under the assumption of a high oil price of $147/b in 2017$ reached in Jan 2027 and prices remaining at that level through 2060 and an unrealistically low real well cost of $6 million in 2017$, the number of wells completed is reduced to 43,600 total wells completed (about 40,000 wells in the very high TRR case are not profitable and so are not completed), the peak is about the same as the TRR case. Wells are only completed for 12 years until 2030.
Chart below.
A number that is below 500 is 0, and I think that is what will come out of a lot of the area they are considering.
Like the Eagle Ford, the result may be negative cash flow, for sure. There are certainly more than two categories of rock potential. Zero is one. Zero makes some lousy averages.
George,
Agree there probably wont be many wells completed with peak monthly output of 500 bopd or less unless oil is over 150 $/b.
They do it all the time in the Eagle Ford.
Guym,
Does the average well with peak monthly production of 500 bopd or less pay for the cost of the well in year 1?
Hell no, they are losers, overall. But, companies drill them all the time. Either to keep leases, add to production, or simply to justify their existence to OPM. And you can’t tell me that the same thing is not happening in the other shales. Mike is correct that the Austin Chalk fraud is still alive and well, and just moved to the shale. At least, in some cases. It’s easy to use old data, average decline rates, and project production over 20 to 30 years to show a future profit. It’s just not going to happen. They maybe could be profitable. At $120 oil price, but it hasn’t been at that price, yet. So, why are they drilling them? I’m not going to say who or where, because I hate law suits. However, the completion query on the RRC site will help you locate them in District one or two. If it shows an initial IP rate of less than 550, you can be assured it will be below 500 bpd high month production, unless it has a lot of production prior to the test. You can find stuff with far less IP rates than 500.
Guym,
Ok. There are lots of unprofitable wells that get completed, it’s a risky business and one doesn’t always know the result in advance. I would think that oil companies that drill a high proportion of such wells at oil prices of the last 3 years, will not remain in business for very long.
At one time, the aim was to make money. 🙂
That was completely true in the first few years, and the assumption was you would have a decline rate that would not approximate zero fast. They were expected to gush for twenty years or more, not five and then be too expensive to operate. The older companies and their initial efforts, I do not question. It the new kids who know better. I don’t have a crystal ball, but I can quess pretty well with as many wells that have been drilled, about what the IP rate will be at in an area. Not all the time, but a lot. The new players have the same info as I do.
As far as the 500 bpd wells being profitable? Rough guess, they would make 80k the first year. Total EUR of about 160k long term. May eventually cover most of the capex at $60 oil, but probably not all. It varies, but that’s a reasonable quess. At $120 oil price, you have a marginally profitable well. Eventually. That’s for Western Eagle Ford, I have no idea how Bakken works out.
Guym,
Are they still drilling in the lower output areas today? Seems not to be a smart move, but I am not in the business and as Mike has mentioned I do not carry a lot of pipe wrenches in my Prius. 🙂
Well, I’m confused. The article states avg daily output for Bakken wells at this:
“Of the nearly 8,000 existing Bakken wells, 49% are located in geology with a peak monthly performance of over 1,000 b/d, with 18% in geology with peaks over 1,500 b/d. Just 14% of existing wells are located within geography with peak monthly performance below 500 b/d.”
None of the URR recovery profiles I’ve ever seen, either from Art Berman or from Enno Peters (usually displayed by year of drilling as cohorts), have ever shown an average peak monthly output of over 500 barrels per day.
What gives? Does anybody know?
This is a huge discrepancy.
I am not sure of the production from Bakken wells, but from what I understand they produce as well, or better than the Eagle Ford. I do know something about the Eagle Ford. Peak monthly performance is almost always the first months production, or second month depending on the day of the month it is completed. A tier one or good tier two will have peak months production well over 30k barrels, which is over 1000 barrels a day.
Marathon and Continental especially are showing very strong wells in 2018 in the Bakken.
First full month production numbers are regularly above 40,000 bbld oil with a bunch above the 60k mark.
One the other day hit 90,000 barrels oil first month which is, I believe, a Bakken record.
The article is summing across 8,000 wells, not a few monsters drilled in 2018, and claiming that 49% + 18% = 67% are over 1,000 pbd.
I have exactly zero data from any cohort year that gets anywhere close to 1,000 bpd.
As far as I know all of that data comes from DrillingInfo at its source, which means it’s tied to the state coffers. Should be accurate. Something remains off here.
Chris, it is not a 1000 bpd average on a annual basis, but 1000 bpd on peak month. They may start off with a peak of 1000 bpd the first month, but by year end, they may be 200 bpd. So, if you see an annual production of 200k bpd, then that one was probably over a 1000 bpd at peak month, even though annual is closer to 550 bpd. These things have steep declines.
“Chris, it is not a 1000 bpd average on a annual basis, but 1000 bpd on peak month. ”
I get that, and all of my charts I am referring to plot out the daily oil production over time with monthly resolution.
I’d think that I’d have one charts somewhere that would show peak monthly flow rates at or near 1,000 bpd given that supposedly two-thirds of all wells had an IP of over 1,000 bpd.
But all of mine max out at around 350 bpd in the 12015 and earlier cohorts and at around 500 bpd for the 2016+
Again the charts are either plotting cumulative production against monthly production or monthly production over time (in months) with each month being averaged to a “daily production” value.
I’m sticking to this because *if* my charts are off by 100% I really need to know that. A lot of my thinking would change if they were.
Well, I’m pretty confident, as one of my wells was a high tier two and paid me for about a 1000 a month peak production. It’s on my pay stub. I look at about a three county area, regularly to look at IP rates on completions, and first month’s production off the RRC site. I regularly question Platts as to their estimates of the future, but never what they write about existing production. But, if you don’t want to believe them, that’s your choice.
Chris, I am sorry I have not called you back; I have been on a well from hell. Perhaps we can talk about this too.
I know you know this but I would not get caught up in all this data BS and though I have not seen your charts, don’t change anything! IP’s to IP180 days are manipulated at will via completion design, flowback management, etc., all for a host of phony reasons. The manner in which you can alter a well’s performance after frac energy is induced to the rock is remarkable. Unless you need lots of cash flow, which of course those guys all do, first month productivity is meaningless, IMO.
What matters is how soon, and IF those Bakken wells get to 425K-450K BO recovery (payout), and how many of those wells will exceed that sufficiently enough to help payback 95% of the other wells drilled that won’t come close to 450K BO.
I think this Platts article is not very well written and relies too much on numbers. People not in the oil business but analyzing the oil business, even people knowledgeable about oil, rely too much on data and really don’t know what to do with it. All those trees often keep one from seeing the forest. But the point of the article is clear to me: that sweet spots are getting no vacancy signs put on them and as those guys move off into flank areas… costs will go up, and productivity will go down, and down pretty significantly.
Agree. High month production does not tell the true picture. Initial IP rate can be completely deceiving. I have seen IP rates at over 2000 bpd peter out fairly quickly, and I have seen lower IP rates produce long term at a level unexpected. But, I believe for the drilling to be profitable, it needs to pay back capex quickly. To me, that means the first year. And should include the cost of the lease, even though that is not considered to be capex, normally. It is, however, part of the cost of that well. Transportation and discounts are higher in the Bakken, so it needs more production to cover that. I don’t know what the average production rate needs to be at over two years, but assume it is high, and different depending on the producer and what they paid for the land. If you got in early, and paid only about 2000 per acre lease bonus, the add on is only $160k per well at 80 acres. If you paid 30k per acre, tack on more than 2 million you need to get to cover that cost. And there is lease bonus wastage, too. To get that particular area, you had to pay for areas you can’t drill in, for one reason or another.
The first two years of production are the highest, after that, it’s a real crap shoot. But then, the whole thing is a crap shoot, so the better wells need to be much higher to cover the ones that won’t make it. Historically, most of the E&Ps have missed the mark.
I find that many wells are losers for the company that drilled them, and winners for a subsequent company.
Much of this has to do with oil prices during the first years.
Thousands of wells completed from late 2014 to mid 2017 likely won’t ever pay themselves out, but private firms who own them in the future may end up making a good return on investment.
We are operating about 50 wells that were drilled by a company in the early 1980s, that went BK in the late 1980s.
We bought them for what in hindsight was very cheap in the early 2000’s.
Worked for us, but not for them, and they operated the flush production.
$8 oil in 1986 and weak price recovery thereafter, along with debt did them in.
Sound familiar?
Mr. Martenson
The 2/3 of all wells having an IP over 1,000 bbld is an understandable misinterpretation due to the poor phrasing of the authors, IMHO.
Slide #5 of the presentation coupled with a careful rereading of Kringstad’s first bullet point opening the report would show that about 4,000 Bakken Formation wells (out of sbout 8,000), are located within 2,500 Drilling Spacing Units (DSUs) with at least one well having hit the 1,000 bopd threshold – peak month – within each of those DSUs.
Lower increments of 100 bopd are also displayed in addition to the same presentation being made for the 4 benches of the Three Forks formation.
This is essentially a heat map as to where and how much the wells have produced with forward projections of what to expect incorporating variable numbers of future drilling sites.
Coffeeguyzz,
It is evidence of a study that was poorly done.
The proper method would be to take all wells completed in the last 5 years and simply group them by their peak production.
We could also look at all data from 2008 to 2018 at 2 months from first production, which is 12,449 wells:
5% have 1000 bopd or higher output
10% have 800 bopd or higher output
21% have 600 bopd or higher output
39% have 400 bopd or higher output
65% have 200 bopd or higher output
78% have 100 bopd or higher output
average is 419 bopd and median is 363 bopd
From Enno Peter’s site we have the productivity rate distribution under advanced insights.
If we look at 2014 to 2018 at 2 months we find only 8% of wells completed have a peak month above 1000 bopd (of 5848 wells completed in those years)
16% of wells are 800 bopd or higher
29% of wells are 600 bopd or higher
47% of wells are 400 bopd or higher
68% of wells are 200 bopd or higher
average production rate is 480 bopd and median production rate is 421 bopd
All data is at 2 months from first output which is usually the peak production month, so this is a proxy for 30 day IP.
For the average 2014 to 2018 set of wells.
Note that percentages are cumulative so the 68% of wells with output 200 bopd or greater includes the wells 400 bopd or more, etc
For comparison if we look at only the 1475 2017 and 2018 wells completed that have produced for at least 2 months we find:
17% have 1000 bopd or higher output
28% have 800 bopd or higher output
45% have 600 bopd or higher output
61% have 400 bopd or higher output
72% have 200 bopd or higher output
mean is 621 bopd and median is 589 bopd
all data at 2 months to represent peak well output. Data is for North Dakota Bakken/Three Forks.
Hi Chris,
It is not 67%, the 18% is included in the 49%, this still seem too high though. Something does seem off in the data as only about 20% of 2017 and 2018 wells have output over 1000 bopd at 2 months based on Enno Peter’s data.
Chris,
This is a productivity distribution, so some wells have peak monthly production (usually month 2 to 4) of 1500, some are 1000-1500, etc.
This is not the average peak output of all wells in a given year or month.
Ah! Thank you Dennis for the reply above. Not only was the study poorly done, but the write-up was as well in providing the strong impression that half of wells were yielding 1,000 bpd.
The weasel-wording “…located in geology..” should have given it away for me. I read too quickly. That’s like saying that all of the people living near Zuckerberg “are located in a zip code that has a high 9 figure net worth.”
Also why did they pick 8,000 wells rather than the whole lot?
Reading your more careful break down it’s more fair to say that roughly half of all wells had an IP of 400 barrels or more, and that even taking the most recent two years (with sweet spot high-grading and ultra-long laterals, massive sand us, etc) we still find relatively modest IPs (with 45% > 600 bpd).
Better to be sure, but Art’s data says those higher IPs also come with faster decline rates.
At any rate, the good news is that I don’t have to suddenly re-adjust my entire thinking and toss out all the charts I’ve accumulated these past few years.
I’m always on the lookout for the information that will revoke or modify my understanding.
Thanks.
Hi Chris,
You should check out shaleprofile.com, it is very good. That is where I got the data.
What I have seen is that the newer wells do decline more rapidly over the first 24 months and then seem to follow the output path of the older (2008-2014 first production) wells from month 24. It is possible they may fall below this level in the future, but so far for the 2015 to 2018 wells there is no evidence of this.
Also in the Bakken there has been little change in the average length of the laterals, they have been about 10,000 feet since 2008. There has been an increase in the number of frac stages, the pounds of proppant used per well, etc. There has also been high grading by completing tier one wells almost exclusively since late 2015, average new well EUR was about 330 kb from 2008 to 2014 and has increased to 397 kb in 2017, it is too early (not enough data) to estimate the well profile of the average 2018 well, and to be honest the 2017 estimate is pretty rough, I essentially tacked the first 18 month estimate for the 2017 well to the 2016 well profile (2016 EUR is about 363 kb).
For the Permian Basin we have seen the lateral length increase from 2010 to 2017, along with more frac stages per foot of lateral and more proppant used, the increase in the length of lateral clearly will increase average well EUR ceteris paribus, but also will reduce the total number of wells that can be drilled in the play.
In simple terms, if we double the lateral length of the average well, then we halve the total number of potential wells that can be drilled in a given area.
Texas initial production out:
Oil 90,026, 556
Condensate 10,616, 871
Doesn’t look like an increase at first blush
Working with RRC to get my pending data for an estimate.
On Enno Peter’s blog why does it show no new spuds in EF but BakerHughes shows 78 rigs operating, or am I misreading something?
They are always late reporting drilling results to RRC, is all I can think off. They are drilling.
George,
If oil prices remain low you will be correct, at higher oil prices maybe not.
A gradual decrease in new well EUR from 370 kb in 2017 to 198 kb in 2034, with 15,000 wells completed after July 2018, in the scenario shown below where it is assumed that well completion rate decreases due to falling new well EUR. In this case total completed wells (including the 13,000 wells completed through July 2017) remains close to 28,000 wells and the URR through 2040 is slightly lower at 8.8 Gb. Peak output is 1.43 Mb/d in 2020.
Ok, as far as credible sources it is in a low orbit, but I found where Wall Street Journal just posted something similar, but it is behind a pay wall. When this stuff starts happening, Trumps tweets become less effective. What if it is running low, because Trump had SA up their shipments to the US to appease the EIA weekly? Backfire?
So, “where’s the beef”? Answer, wasta. Toto just pulled back the curtain?
SA’s eventual statement will be that, yes, we have 2.5 million in excess capacity, but it will take a while to develop. Then that will turn into we need it to maintain production. Gasp! There is no OZ! But, not before elections.
No doubt, they will somehow claim another 500k barrels a day are somehow imminent, but they haven’t even met the first million, yet. My favorite comment out of this is that the US, Russia, and SA have the ability to offset these losses. Well, maybe, but well after a year and a half. And the US will play heck trying to convert LTO to Arab Light.
Fairly soon, prices will rise, and we will begin to witness, first hand, which destruction has the most impact on oil prices? Demand destruction, or supply destruction?
Russia has peaked! Or at least that’s what one Russian who should know says.
Thanks for the links Eduard. Your third link: Will OPEC appease Donald Trump?, is very interesting. There is an Al Jazerra video here where three oil experts discuss whether or not OPEC will, or will not increase production to please the Donald. The general consensus is they will not.
One member of the panel, Mikhail Krutihin, Partner, RusEnergy Consulting Firm, Former Editor-in-Chief, The Russian Energy Newspaper, Former Editor, Russian Petroleum Investor Magazine, said Russia is at peak oil production right now and the decline in production will start next year. He said the decline will be caused by the deterioration of oil reserves. He said 70 percent of the oil remaining in Russia is very difficult to recover. He said that it is difficult to recover that oil at current prices. He also said that Russia will not increase oil production to please OPEC or Donald Trump. And he said, again, that Russian oil production will not increase but will decrease.
His segment begins at 6:50 into the video.
I noticed that too he actually said that. And his remark fits perfectly with the Russian production chart.
Saudis are trying to suggest that they have problems too, talking like ‘we are looking at more important aspects such as adequacy of supply’. And then to not let any misunderstanding he adds: ““The markets are adequately supplied.”. They rarely do that, they are pretty cocky about their production, and letting doubts on their “spare capacity” was usually out of the question. https://www.cnbc.com/2018/09/23/saudi-oil-minister-rejects-trump-claim-that-opec-is-raising-oil-prices.html
So all the eyes are on US, which means all the eyes are on Permian.
I am sure we are headed to some type of economic slowdown, and fairly soon. Yeah, oil prices can affect the economy, but not as much as the tariffs will. They are a pass through tax to the US consumer. Higher oil prices will hurt, so will the average consumer having to pay 15 to 25% more, every time they visit Walmart. Trump can’t be held responsible for higher oil prices, but he can for tariffs.
Andddd again. The deficit for FY2019 is going to be $1 trillion with a T. Economic slowdown is . . . one supposes, flat or negative GDP. $1T is getting injected into the economy from non capitalism next year. That’s 4.8% of $20.2T GDP. To go flat or negative you gotta lose that 4.8% and more. That would take something like an earthquake wiping out Seattle and San Francisco both entirely.
I say entirely because the broken window aspect of Keynes stuff would generate big GDP for repair expenses, and yes, that would be another $1T spent from the government (who would borrow it, probably from the Fed, to spend it).
So it’s really popular for folks to be calling for downturns right now, mostly because some number of years has passed. But the mechanism is hard to see with $1T deficits, and oil prices . . . hell, they just stimulate oil industry business offsetting any consumer recalibration (and let’s keep in mind spending on gasoline is itself consumer spending — if gasoline is all they can spend on, so what? They still spend the same amount into the “economy”)
The economy is overheated and needs new taxes to slow it down. It’s pretty nuts that the Republicans trashed public finances with their tax cut at this stage of the business cycle.
Lotsa talk above about Bakken. Have always frowned a bit at the perpetual counting of barrels without looking inside.
Small heads up —
Equinor has a new Bakken assay out dated Aug 2017 and quotes API 43.3. Remember when Lynn Helms told us the API was equal to WTI at 39?
Suspiciously, just months later Statoil quoted a new Bakken assay as 42.9. Their sulphur quote is 0.17%, up some from previous.
And so, as before, these assays are from a sample. Not all the geology is going to have the same API measurement for its liquid. About 6 yrs ago there was a lot of talk that refineries were objecting strongly to Bakken liquids because from train car to train car they could not maintain their same refining . . . settings.
Regardless of if they solved this, it means not all the liquid in those barrels is crude. API 43 is just too close to the 45 condensate threshold. The quoted barrel count is simply not legit. If you call it a flow of crude + condensate, then it’s legit. That’s not what we’re getting quoted.
It would be useful to know what % of flow is going north as diluent and what % is getting refined.
Yeah. Seriously doubt it will look anything like this. Global demand up over 4 mbpd by 2023 is the first giveaway. Which will come from….???
On another note, maybe Dennis can post Dean’s new estimate for Texas. I am having some delays with RRC on getting the pending file, but his changes have been in line with EIA, and my data. He shows about a 75k drop for July, which looks reasonable based on initial data. I doubt the pending file is increasing much, as it didn’t in June. Most of the increase in oil production seems to be coming from Washington DC, and not the Permian.
Lol, that is funny!!! There is no limit to their imagination. US will increase by 5.6 million barrels a day by 2013. Looks like we are slightly under their projection, Dennis. Texas Department of Transportation better get humping, and then there is new railways, and whatnot.
They just can’t seem to grasp decline rates. The first year declines are the worst, but when you add in previous years declines, a recent estimate in June was that 95% of current wells were to maintain production.
Guym,
Keep in mind that OPEC is talking total liquids, US NGL has been rising along with C+C, though in the past 18 months the trailing 12 month output of NGPL has only been 129 kb/d or 7 kb/d each month, so not that significant, US output might increase by 3.5 Mb/d for total liquids by 2022. Perhaps there will more NGL from elsewhere as Natural Gas output continues to increase.
I think if we focused on C+C demand increase and the fact that over the 1982 to 2017 period this has averaged about an 800 kb/d increase each year, that we would get better estimates. In addition, if output is short of consumption, inventory will continue to fall and eventually oil prices will rise as the tanks get 10 or 20% below the 5 year average stock level. Then after some period of lag (one to two years) people start to adjust their consumption of oil products to lower levels (by driving less, car pooling more, buying more efficient vehicles etc.) Also there might be an economic recession which tends to reduce consumption (though when that occurs is difficult to predict in advance.)
Lol, whether liquids or crude, it is still too high. It is interesting to note their projection for just crude. OPEC will peak in 2020, while non-OPEC peaks in 2023. So, their peak oil projection is 2023. Same as yours. I’m still saying 2018, but the difference is not significant, now. Peak oil will forever be one step ahead of peak demand.
Guym,
For tight oil they predict an increase of 4.3 Mb/d from 2017 to 2023, with 1.3 Mb/d from NGL.
For non-OPEC crude the peak is 2025 according to WOO 2018 with a 5.5 Mb/d increase from 2017 to 2025, or a 687 kb/d increase on average each year.
Interesting on their crude long term forecast they have a plateau at 80 Mb/d from 2025 to 2040 (slight increase of 1200 kb/d over a 15 year period or only 80 kb/d increase each year.
The World liquids output increase comes from NGL, processing gains, biofuels and other liquids (GTL and CTL maybe). Of the 5.7 Mb/d increase in total liquids, 3.8 Mb/d is from biofuels and NGL. In terms of boe this would only be 2.9 Mboe/d so the real increase in energy terms is about 4.3 Mboe/d when processing gains are deducted (those are a change in volume not a change in energy content), so over 15 years the average increase in liquids supply is 287 kboe/d. Liquids supply will be relatively limited if demand grows at historical levels (800 kb/d from 1982 to 2017). Crude oil output will be fairly flat from 2025 to 2040 at about 80+/-1 Mb/d. Seems they leave condensate out, possibly just for OPEC.
I looked at WOO and compared to EIA data, the “crude” in the WOO does not include condensate (about 6.5 Mb/d in 2017 if the OPEC estimate and EIA estimate is accurate.)
So if one assumes condensate output remains at 6.5 Mb/d until 2040, then C+C output would be about 87 Mb/d in 2040 and be roughly 86 to 87 Mb/d from 2025 to 2040. The flat condensate output estimate is just a WAG because OPEC does not break it out that way, but if my guess of a tight oil peak in 2025 is right and a lot of condensate comes from tight oil and shale gas, then we might expect a peak in condensate output in 2025 and a decline thereafter. So a more realistic scenario might be a rise in condensate from 6.5 to 7.5 Mb/d from 2017 to 2025 and then a decrease at a similar rate over the next 15 years perhaps to 5.5 Mb/d in 2040. In that scenario, the peak in C+C output would be around 2025 at roughly 87 Mb/d, based on the WOO 2018 and my assumptions about condensate output.
I think the real message is that OPEC won’t br able to meet rising demand so stop asking us.
I interpret the outcome as all members (perhaps excluding SA) pump more or less flat out. The cartel will not make any immediate additional increase but some of the spokespersons say “they needed to focus on reaching 100 percent compliance with production cuts agreed in June” (i.e. increase output).
(posted in the wrong thread)
Of course, they are using EIA’s lousy projection for US oil output against Trump. They are not planning on increasing output (as if they could), because the US will be increasing output by 2.4 million barrels. Iran is softened its stance, because SA stood up to Trump. Of course, the US will be about 2 million short of that projection, raising oil prices, which SA would be very happy with.
Saudi Arabia said that they’re meeting customer demand
2018-09-23 Algiers (Platts) Saudi Arabia intends to raise crude production in the coming months to meet mounting customer demand, energy minister Khalid al-Falih said Sunday,
September output from the kingdom is already higher than August’s level of about 10.4 million b/d, Falih said at a meeting of an OPEC/non-OPEC monitoring committee, though he did not provide a specific figure.
“October will be even higher,” he told reporters. But he stressed that Saudi Arabia’s production levels were dictated by customer demand, not to influence prices.
“We have seen higher demand in October,” Falih said. https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092318-saudi-arabia-plans-q4-output-boost-to-meet-mounting-demand-oil-minister
Saudi Arabia, the leader of OPEC, said Sunday that it will not increase crude oil output anytime soon, pushing back against President Trump’s calls for greater supply.
“The markets are adequately supplied,” Saudi Energy Minister Khalid al-Falih said, according to Reuters. “I don’t know of any refiner in the world who is looking for oil and is not able to get it.”
He added that Saudi Arabia could theoretically raise its output by as much as 1.5 million barrels per day.
Russia, Saudi Arabia’s largest oil-producing ally outside OPEC, agreed that it would not immediately increase its output either, the news outlet reported.
Falih added, “I do not influence prices.”
President Trump said last Thursday that OPEC should bring down oil prices, suggesting that the U.S.’s military assistance may be contingent on their cooperation.
Trump’s tweet:
Donald J. Trump
✔
@realDonaldTrump
We protect the countries of the Middle East, they would not be safe for very long without us, and yet they continue to push for higher and higher oil prices! We will remember. The OPEC monopoly must get prices down now!
And they, in turn, denominate sales in dollars, and buy US debt. He is a loose cannon. So loose, it could go anywhere. Russia has already sold most of their US debt. Next, will be China and SA.
China Cuts U.S. Treasury Holdings as Trade War Intensifies
Pretty subtle changes in message: extra capacity is now ‘theoretical’, no guarantee of meeting future demand, a step back from their position of not influencing prices, which is kind of the whole point of OPEC.
Brent is +$80 and going up fast at the moment so I think the traders are inferring the same messages.
The markets are adequately supplied, as Saudi Energy Minister says, but through a reduction in stored oil and diminishing spare capacity. That’s why the price of oil is pushing up. The lack of investments since the 2014 oil price crash guarantees that an increasing demand will not be met for several years.
Only two possible outcomes:
– An oil price shock that is almost guaranteed to trigger a new global crisis.
– A reduction in the demand growth that can only happen if several countries go into recession or stagnation. This could actually reduce oil price if big enough.
In both cases oil production will not increase by much. That’s the problem with Peak Oil. Whatever happens production doesn’t go up.
So far we are seeing signs of both. Oil storage and spare capacity are going down, and the flow of money in the global markets is reverting, leaving some countries like Turkey and Argentina high and dry.
Aren’t most countries other than USA looking a bit sad anyway? USA has boosted the stock market with tax cuts that have to some extent been recycled to stock buybacks and other ways to boost share price (rich get richer and poor get poorer). But a lot of other OECD countries and emerging markets are having growth figures revised downward.
Yeah, this is the whole storage thing. If you’re KSA and you have oil stored in the porous rock underground, why do you want to pump it up and put it in a tank on the surface? It’s already stored. Can you get a flow rate from a tank that is faster than the flow rates from the entire field? Can’t. Physically impossible. It would average out to exactly the flow rate into the tank, which is part of the flow rate from the field.
He’s right and you do realize he’s saying “supply and demand does not define the price of oil.” He has supplied all the requests by refiners. Why would the price move?
Central Banks can intervene to hold price of oil down if they so choose. Hell the FED admitted to having a massive VOL short not too long ago. Who’s to say they don’t short CL futures to keep a lid on oil price. We don’t have honest markets where true price discovery is allowed.
What we have is the illusion of free markets. That’s why forecasting price is so tricky. Don’t just assume prices will go up due to a lack of supply anymore. Price will be allowed to rise right up until the point where they feel it’s necessary to intervene.
Since 2008 all stock markets started to behave differently. Fundamentals went out the window it is now all about perception. Failing companies can see extraordinary rises in stock price if a bail out is presumed.
Central Banks can intervene to hold price of oil down if they so choose.
I guess you have no idea of the sheer size of the oil markets. Central banks and certain governments have the capacity to influence them by manipulating confidence, but if they decided to intervene them to hold the price the risk would be unacceptable.
Already Soros demonstrated that by taking the mighty British Pound out of the European Exchange Rate Mechanism in 1992. You might have not learned that lesson but central banks sure did.
Markets are angry beasts and it is not wise to poke them. If a stampede starts in the wrong direction there will be hell to pay.
Watcher, it’s sometimes quite entertaining but boy do you talk some uninformed rubbish.
Yeah. Tell me something — when you go to the store and want to buy something from a shelf, and the shelf has a price on it for the item — does that price change depending how many of the item is on that shelf?
2L bottle of pepsi is $1.78 at Walmart. It’s $1.78 if there are 5 bottles there or 1 bottle. It’s even $1.78 if the shelf is empty. Your demand didn’t change. Supply did. No price change.
I will venture to suggest, without data, but odds seem good, that throughout history the price of goods obtained in all transactions that have ever taken place . . . the vast majority of those transactions had a price not determined by supply and demand.
This would be the price of land a father offers to a son. It would be priced according to almost anything other than supply and demand. Might be free. So we could toss inheritance into the quantities of transactions.
It would be the price of every item ever acquired by conquest (which probably makes the case quantitatively in an overwhelmingly compelling manner without any other examples).
It would be the price of money itself, prevailing interest rates, set by Central Banks, with no interest at all in supply or demand. In fact, that item also quantitatively makes the case entirely.
Every government decree of price . . . all those transactions took place with no interest in supply and demand.
Why would you think supply and demand in some tiny minority of transactions happens to apply to oil? Why would oil be in that tiny minority?
I was talking about your knowledge, or lack thereof, concerning how oil companies work on a practical level. If you don’t know something you just seem to make up whatever explanation fits your set worldview. The “without data” comment is rather telling in the above though.
So you think purchase of literally trillions of MBS with no competitive pricing is a magnitude not reasonably larger than other transactions of history, and when added to acquisitions via conquest and inheritance, the absence of exact data suggests to you the whole of the matter is manufactured?
Come now, you know this is all very credible. You just don’t like what it means.
I don’t think any of that, not my field, just like API gravity, condensate definition, refining and operation of storage facilities obviously isn’t yours, but you don’t seem to let that be a hindrance.
George
Saw this today. West of Shetland is starting ro show a bit of promise.
I don’t have access there but I assume it’s about the Total gas find. Total need the gas to fill Shetland Gas plant because the Laggan Tormore fields have not produced as planned.
But more importantly, and dunno if asked before, but does anyone have any idea what the standard deviation is of API degrees for oil from different locations of a typical field?
As noted above, assays are showing API 43 ish for Bakken liquid. But those are from some sample. No reason to think the sample is high, low or at the mean of all API densities for all locations of a field.
And with condensate starting by definition (which has some attempts to redefine floating about) at 45, odds would seem pretty high that a standard deviation of just, say, 3, would define 30some% of the liquids from the Bakken as condensate and not crude. And if the sigma is even higher, then we have an explanation for the complaints by refiners years ago that the oil cars . . . car to car . . . had huge changes that forced them to change their refining procedures too often.
The overall point being, quoted production of liquids as crude may be pretty shaky. Why not include water?
Can’t produce what you don’t have. People are starting to figure out there is no 1M + bpd that can just be brought online when Iran gets sanctioned.
Ok, I think we are already firmly past stage one of the oil price rise. I said it would take the realization that OPEC can’t cover shortages by themselves, first, before they actually looked at the limitations of shale within the next year. EIA is reporting weekly production of the US at 11 million a day, which is about 300k over actual, probably. June monthlies by the EIA were at about 10.7, and Dean estimates a drop of 75k per Texas production which I should be able to confirm sometime today. The US will likely average production in the US at 10.55, rather than the 10.8 they are still hanging on to. With only 360k of new pipeline from now until the end of 2019, or first of 2020, the 11 million won’t be realized until that 360k is actually working. So, the average production in 2019 is going to be closer to 11.1 than EIA’s 11.7. There is one caveat to that, and that is if WTI gets much over $100 a barrel, there’s no telling what will happen, but even then 11.7 average is not probable.
Restated, OPEC plus non-OPEC can not cover current shortages by a long shot. And by OPEC continuing to use EIA’s uncorrected version of US oil production, they are telegraphing that the finger will be eventually pointed at the EIA when prices skyrocket.
It’s going to get interesting that’s or sure. I think about .3 increase in that 11.7 comes from an increase in the GoM and it’s more likely to be about -0.1 to 0.2, have you allowed for that?
Yeah, I am figuring zero for GOM as far as increase. An annual average estimate could have some variation depending on a lot of things. I’m just saying it will be closer to 11.1 than 11.7. An oil price spike could lead to more production in other shales than the Permian, but they are unlikely to increase a lot the first half, because it takes some time to get there.
Completion crews will still have plenty of work to do in 2019 in keeping the Permian maintained and in other shales.
North Dakota increase may offset some of the drop in Texas, other shale plays in Oklahoma, Colorado and Wyoming might also see increases so perhaps US output will be flat or at least L48 onshore, not sure about what to expect from GOM and Alaska, I think there’s usually summer maintenance in Alaska, not sure if GOM has been hit by any significant storms this summer.
Well, note I projected a 153k drop in Texas below, although that does not mean that’s what EIA will estimate. If so, it will be difficult to offset.
North Dakota output increased by 42 kb/d in July, so that drops it to 111 kb/d, if combined Oklahoma, Colorado, Wyoming, and New Mexico output also increased in July by 40 kb/d, the decrease would be reduced to 71 kb/d. Also note that the EIA estimates that US tight oil output increased by 131 kb/d in July, though that could be offset by decreases in conventional output, Alaskan output and GOM output.
Alaskan North Slope output dropped by about 60 kb/d in July, so if output elsewhere was flat that would be about a 70 kb/d increase in US C+C output. Not sure about GOM or US onshore conventional.
Chart below uses data from link above. The linear trend from Dec 2016 to August 2018 has a slope of 1279 kb/d (average annual rate of increase in US tight oil output over that 21 month period).
I think it is interesting to note the contrarian view, that a spike will precipitate a decrease in demand like in 2008. I mean, really, oil price was not the only factor that contributed to a decrease in demand, then. Remember? And a decrease in demand has not had any record of decreasing 2 million barrels vs an increase. Or, do they figure that US shale will continue to increase at a $50 oil price??? Reality disconnect.
Ok, I may have missed it, but do you have the “most of the world” inventory drops from last week, Energy News?
Another interesting tidbit I picked up from the OPEC meeting, was that SA maintains it has been increasing their inventory, but it is stored in the locations you pick up on world inventory.
Which, as of fairly recently, includes a signicant portion of SA inventories, according to SA after their meeting. Thank you.
They have moved from months of shipping time to a more closer to just in time inventory method. Which may account for much in the spike in July.
Where is Tweety Bird? Oil is over $80 now! Really, he can quit sweating it. With gasoline inventories this high, gas cant rise that much before Nov. 6.
How much if Iran manages to blow something up in the Straits of Hormuz?
I dunno, I would hope they would take a longer view of the whole mess, and come to the conclusion that it can’t last like this. But, then, you don’t know how much this whole fiasco affects local dissension.
Ok, I received the pending data file, and we are down. Reviewing June data, EIA was probably too high at 4410 for June. I had 4364, and second month’s total is 4344, which is the closest to actual, in my opinion. That is 66k less than EIA’s estimate.
For July I project 4257, which is 153k bpd less than EIA’s June estimate. As far as change goes and totals, Dean’s and mine are pretty close, within a thousand barrels.
I think what we are seeing is shut ins with small producer wells, that would probably not be covered in drilling info, nor ultimately in EIA estimates. Production is likely to fluctuate up and down, but won’t get much higher until after maybe December, when the results of the new pipeline expansion is felt. Drillinginfo and EIA are counting new production and assuming production from existing wells, and some of those are being shut in, and wouldn’t be included in the 914 reports.
I expect GOM to be up a bit, but will be offset by a smaller Alaska production. For July, I expect US total to be 10.500 to 10.550 million bpd. Weeklies over 450k to 500k for July. Next four months could fluctuate 150k.
Traders will eventually notice, but it will take some time.
Bank of America sees oil in the $95 range first quarter of 2019. But, they also see US oil production increasing 1.4 million in 2018, and 1 million in 2019. The US will be lucky to make half that prediction. How does that affect that $95 price prediction? You see how the EIA is affecting all these predictions. The keep believing the EIA that the Permian is continuing to increase, and will regardless of pipeline constraints. I have to believe that EIA knows what reality is now, and I am baffled by the continuing facade. Or, maybe I’ve gone off the deep end?
Many here like to make fun of Watcher.
So a little more than two years ago, traders took WTI below $30 and some said $10 and one said WTI would never be above $44 in his lifetime.
Now many are frantically calling for $100, $120 or higher.
Yes, the price of oil all has to do with supply and demand. Lol.
I have been following the oil price daily since 1997. Traders and their hype are the number one driver IMO.
And they aren’t even moving oil barrels, either. 90% of trading is paper, and not even oil. It’s just plain gambling. Gotta be frustrating to someone like you that’s in the business. They are more interested in indentifying whether prices are in an inverted doji, or whatnot. Fundamentals to them is what a bank or EIA is saying. For four years they have destroyed most investment in it, because they had their own interpretation of a fair oil price. It’s not even a full time vocation for them. It’s only one of their commodities. They spend a half hour on oil, and then turn to cotton, or hogs.
If traders set the price why has OPEC existed for so long. Why did the price crash after the 2008 financial crisis and then recover when SA cut production. Why did that cut then cause a boom that led to overproduction, record high inventories and another price crash which recovered partly because of another OPEC cut? Traders make money on daily noise, they’d all go bust if they went against the trend (I think one big one did before the recen crash when he bet big on permanent high prices).
My comments are somewhat sarcastic. But only somewhat.
The problem IMO is that the traders and all the paper barrels are greatly exaggerating the price movements.
One thing we don’t pay enough attention to is the effect the dollar’s value has on oil.
QE was a big factor in oil’s run after 2008 crash.
Would QE be considered supply/demand?
I just think it’s crazy to see traders hollering $100 plus, when two years ago it was lower forever.
Shallow sand,
It’s just oil market observers realizing they were wrong about how much tight oil can be produced and also not foreseeing the demise of Venezuelan output and the effect that lack of investment would have on future production, they also didn’t expect more sanctions on Iran.
Predicting the future is not an easy task. Though many of us expected that eventually oil prices would rise.
My current guess at future centered average 12 month Brent Oil prices in 2017$, 3 scenarios low has max price at $80/bo, med at
$113.4/bo, high at $146.7/bo all in 2017 constant US dollars.
Shallow sand,
In the short term, traders drive the price of oil, in the long term, it is supply and demand.
We cannot consume oil that is not produced, when there is a desire and the money behind that desire to consume more oil than is being produced at the current price level, oil prices will rise, it really is that simple in the long run.
Imagine for a moment a World where oil inventory was simply the amount needed to fill pipelines (essentially very close to zero).
Traders would be out of the loop. In the long run inventory is at some average level needed to make the system function and traders don’t mean squat.
The Short term stuff is just noise, unfortunately it kills small producers’ bottom line.
It is the reason the Texas Oil producers supported RRC production controls for so many years, it reduced volatility until Texas was no longer the swing producer. The Saudis and OPEC took over the reigns in 1975, but haven’t been doing a great job.
It might be better if a new OPPC (Organization of Petroleum Producing Countries) was formed with all major oil producing nations joining (US, Russia, KSA, and the next 17 largest C+C producers) and they set quotas for all major producing nations to attempt to match supply and demand and reduce oil price volatility.
Never gonna happen though.
Ok, but you have to admit when you put the WTI price, with worldwide demand and worldwide consumption on a graph, it looks pretty crazy.
Demand and supply keep churning up every year by 1-1.5 million BOPD. Not many exceptions to this.
The price action has been wild. Overall, we have benefitted, we used to think $30 was awesome. Now it will BK us.
I still contend much of the price swoon 2015-17 was overreaction to shale. Traders bought the BS that shale is “cheap to produce.”
Shale companies spewed a lot of BS. If it wasn’t for Elon Musk, I think they would win this decades corporate Pinocchio award when it comes to exaggerating fincancial success.
Shallow sand,
Agreed the short term price movements have indeed been wild. Note that an economist considers demand and consumption to be the same thing, it is the quantity of product that is purchased, for oil we usually think of this in barrels or tonnes (mass is really the better measure as it takes account of heavy and light barrels a little better and gives a more realistic estimate of the energy content of the oil produced).
On the increase in consumption consider the following chart.
Chart has monthly data from July 1982 to May 2018, the slope of the line is 800 which means on average each year there has been an 800kbopd annual increase in World C+C output over the past 36 years.
This increase is quite a bit lower than the 1200 kb/d often mentioned which might be total liquids increased output in recent years. The total liquids overstates energy output because much of it is processing gains (which is just a volume increase with no increase in energy in the product) and ethanol and NGL which have about 75% of the energy per barrel of the average C+C barrel.
The crude plus condensate is what is really needed for transportation which is the main component of oil demand, so the number to focus on is 800 kb/d, in my view.
Dennis, I was shocked at your chart. I thought, “that can’t be right”. I was used to looking at charts with a shorter time span. So I made one of my own. And yes, that’s exactly what it looked like.
But, I would bet my last dollar that this 800 kbd yearly increase will not continue. I now more convinced than ever that 2019 will be the peak. And if I had to guess where the 12 months average high would be, I would guess July 2018 through June 2019.
See my post above “Russia Has Peaked”. That is not my assessment but one Russian’s opinion, an expert in Russian oil production who would know. Also, I think OPEC has peaked, or nearly so. The only major producers who have not peaked, or nearly so, is the USA and Canada.
And you are correct, the price will rise. Unless of course, we have a really major recession, which is also possible. But if the world economy stays healthy the price will definitely be above $100 soon.
Hi Ron,
I do not expect it will continue beyond 2023 or so. Tight oil output in the US will likely peak around that time and output will either flatline or increase more slowly (100-200 kb/d per year) for a couple of years (maybe to 2025-2027), then there will be similar decline for a couple of years, then a gradually increasing decline rate to about 2% annual decline each year by 2040 or so.
I agree a recession will stop the rise in oil prices and might occur at any time, especially with trade wars disrupting the World economy. Seems Trump has never read any history in his lifetime.
Russia may have peaked, but at high oil prices we might see more output from some OPEC nations along with increased Canadian, US, and perhaps Brazilian output.
If you are correct that 2018 to 2019 is the peak, I expect that a plateau could be maintained (absent a recession) for 5 to 10 years, but my best guess is an increase in World output until 2023, plateau until 2027 and then decline (though there might be a 12 month centered average peak anywhere in the 2023 to 2027 period in my view).
I think you are just being overly conservative. The US and Canada might continue to increase production until 2023 but the rest of the world definitely will not. And the decline in the rest of the world will more than offset the increase in North America.
Brazil? I will post a comment on Brazil in a short time.
Why Canada? Fort Hills is pretty much finished, Hebron is still ramping up but it will hardly compensate for the decline in the rest of Atlantic Canada. There’s a bit from Christian Lake and a couple of other small SAGD projects but less than 100 kbpd total.
Hey, I think you may be correct. But the general consensus of opinion is that Canada still has a way to go before the peak. I was just hesitant go go against the general consensus of opinion.
Hi Ron,
The question becomes will the decreases in the World minus US and Canada be more than the increases in US and Canada.
We simply have different estimates of the future, in part because we have different estimates of World URR. I think there will be continued reserve growth as oil prices rise (and no I don’t think this will continue forever, it will gradually decrease to zero from now until 2050 or so). My estimate of World URR for C+C is about 3075 Gb (including 215 Gb of extra heavy oil and 60 Gb of LTO), not sure you have ever given an estimate of URR, but note that Jean Laherrere’s August 2018 URR estimate was about 2815 Gb of C+C, he also has a higher 3015 Gb estimate and historically his estimates have always tended to increase over time, especially for C+C less extra heavy oil. (2200 Gb to 2600 Gb over the last 6 years or so).
In a nutshell, a 1.4 Mb/d increase is forecast from 2017 to 2035 and a 1 Mb/d increase from 2017 to 2025..
It looks like there was a reduction in Saudi Arabia production some months of 2008 and 2009, for what one would think is an obvious reason — there was a presumed disappearance of consumption on the part of their customers.
The graphs say something like 2 million bpd kept underground in the absence of orders from customers for just a few weeks or months, who themselves were watching the carnage on Wall Street and presumed that THEIR customers were going to disappear.
A conversation here recently noted that actual consumption of oil in that time frame declined very little, but it was also noted that global GDP itself declined very little. It was the most apocalyptic financial event in the history of mankind, but it did not translate to economic activity erasure at anywhere near that magnitude.
So fairly quickly the refiners discovered their customers had not disappeared and they placed orders with the Saudis, who filled them.
What moved the price on that occasion? Money disappeared. Meaning it stayed in the pockets of people who otherwise would have been at the NYMEX, trading. After a few weeks it became clear that the Fed was going to save civilization, and with civilization saved the traders came back to work.
As for why OPEC existed so long — why has the FAO of the UN? Or the GECF? Obviously they don’t try to define price. Or if they did, they’re failing.
BTW Shallow, since I discovered Qatar’s SWF owns 10% of Rosneft, I also discovered they own a big chunk of the London Stock Exchange. Might be a good idea to find out who owns NYMEX. The SWFs of the world are taking ownership of more and more equity in all sorts of different things. In total they appear to own 25% of all of the common stock shares of every company on the planet Earth.
No reason why, as they take control of things like the London Stock Exchange they can’t also take control of prices. We’re talking about 10 guys — 10 asset managers from the largest SWFs. They are becoming the “market”.
CME Group owns NYMEX and that’s a duh.
CME Group’s primary shareholders list is a bit surprising, but no indication of SWFs having an influential role. The dominant holders are index ETFs fromVanguard and whoever . . . but that’s really surprising in that Vanguard’s Total Market ETF seems to own over 1%. How can that be? CME isn’t that much of the total stock market so how could even 1% be the right amount.
But anyway, unless SWFs have swaying positions among the firms running those ETFs, then they aren’t controlling prices. The next layer of investigation would be CME management.
A look at August’s crude oil production numbers. The official numbers released so far.
The total is up +265 kb/day month/month. But still down -136 kb/day from the average in 2017 https://pbs.twimg.com/media/Dn7ldBoW0AAh50w.jpg
Actually I think you were comparing Aug 2018 output to the 2017 average in your comment above, for US tight oil that comparison would be an increase of 1452 kb/d in Aug 2018 compared to average 2017 US tight oil output. So combining US tight oil output with your data from several countries we would have a C+C increase of 1316 kb/d in August 2018 compared to average 2017 output.
Norwegian Petroleum Directorate, crude oil & condensate production
August 2018: 1,532 kb/day down -23 from July
Down -86 from average 2017: 1,618
The rig count is a 3 month moving average (yellow line)
Chart: https://pbs.twimg.com/media/Dn8i0MSW0AA7D59.jpg
There was a lot of maintenance in August in the North Sea (Rystad Energy), chart: https://pbs.twimg.com/media/DmLJ8UEX4AAzOmK.jpg
Sept –> 2018-09-18 (Bloomberg) Norway: Goliat Gas Leak Leads to Evacuation of 502 People
Energy News,
Brazil down about 20 kb/d from 2017 Average, Norway -86 kb/d for a total of -106 kb/d, added to your other chart gives -242 kb/d, then adding the US tight oil increase of 1452 kb/d in August relative to the 2017 average, we have a 1210 kb/d increase in output compared with the 2017 average.
Hello, I usually add the EIA 914 survey number to the chart. Although as you know it’s a long wait for the August number.
What was the June number relative to the 2017 average? (I assume you have the data in a spreadsheet, if not forget it.) Guessing from the chart it looks like about an 800 kb/d increase in June relative to the 2017 average.
June 2018: 71,689 kb/day
The average for 2017 was: 70,647 kb/day
And so for this collection of countries production in June was higher by +1,042 kb/day than the average for 2017
Energy News,
Thank you. In June 2018, the EIA estimate for the World C+C is 884 kb/d higher output than the 2017 average, seems all of the increase is from the countries in your estimate and the rest of the World has declined by about 158 kb/d (assuming both estimates are correct). About 10,421 kb/d of World output was produced by the “rest of the World” (not covered in your estimate) and decline from those oil producers was at an annual rate of about 3% per year.
Still, the cheap money does not reach so far as to compensate for low oil prices 2014-2017 in “high risk” countries. Offshore is hit hardest, one reason being that infill drilling is expensive out on the seas. Exploration even more so. Heavy oil or other expensive oil not produced in western countries is second hardest hit by the glut. And for those not paying attention, this include some of the OPEC countries as well. I always thought we were going to be 2 mill b/d short this autumn and that it was not going to be an easy way to prevent it. Some support to the view that we will see a peak in oil prices at year end (stretching for who knows how long) is also seen in the MSM now.
What is happening is that global inventory declines until there is competition for the last produced barrel. India is added to the list it seems. https://oilprice.com/Latest-Energy-News/World-News/India-Looks-To-Cut-Crude-Imports-As-Oil-Prices-Rally.html. Along with China, Saudi Arabia, Kuwait and the US. Europe has always had limited storage capacity, and the opaque storages around the world saw severe draw down already in 2017. So inventory surpluses dwindle everywhere; not just in the OECD countries. And that it ends in a crash is just ultra typical, it has just to do with how human behaviour works. The contrarian view is getting ever more likely.
Crude Oil Production in Brazil is expected to be 2601.05 BBL/D/1K by the end of this quarter, according to Trading Economics global macro models and analysts expectations. Looking forward, we estimate Crude Oil Production in Brazil to stand at 2601.90 in 12 months time. In the long-term, the Brazil Crude Oil Production is projected to trend around 2601.91 BBL/D/1K in 2020, according to our econometric models.
Flat through 2020 no less.
Another Brazil Chart, same link as above. And they are predicting this level, 2,600 kbd, will hold through 2020.
I don’t get that, they have a load of FPSOs under construction, availabity of them and/or the drilling rigs would have to be awful for there not to be an increase (but actually that might be possible).
That’s Russia. I can believe that and if it’s true prices are going to go haywire and Putin might start looking like a nude emporer. But the comment was about Brazil. I wrote a draft post that Dennis might issue next month if there’s a slot but below is my guess at the new FPSOs (production black, construction blue and appraisal green).
Hey, all I was doing was quoting the experts.
Hi Ron,
I think George Kaplan’s analysis is the best around, in a future post he has an estimate for future Brazilian output that might be different from these other experts.
Dennis, I do not doubt his analysis or question his expertise. All I was doing was quoting what Tradingeconomics.com was saying. I cannot vouch for their expertise however.
Just a guess.
Looks very reasonable. To be certain about the tail is a guess game, and I always tend to think it will be pretty fat. But for Brazil to have enough resources to counter the peak is very difficult most likely.
I too suspect activity will pick up like this projection, and give increased production from 2021 and onwards (maybe later if we have an economic crisis – after a recovery this could be the picture after all). It is how offshore works, especially when far away from “safe havens” for cheap capital.
There will be other discoveries, probably quite a bit (Laherrere estimates 55 Gb) to fill out the tail.
George,
Did you model that decline after 2026 based on history from the North Sea?
Looks quite reasonable. Is the Santos decline steeper than Campos or is that an optical illusion?
No it’s bottom up based on other Brazil FPSOs and matching the 2P estimate.
George Kaplan,
Thanks.
Trump talking at the UN General Assembly today
2018-09-25 (Bloomberg) Trump says that OPEC Nations are `ripping off the world’ on oil prices – and reiterates he wants OPEC Nations to lower oil price
“Columbus was the first economist. He didn’t know where he was going. He deceived his men. & he travelled on government money.”
— Victor García, cited The Heretic’s Handbook of Quotations
At least he knows what is hitting him, and there are not many ways to prevent it.
“there are not many ways to prevent it”
Bullshit, Trump and his followers are the idiots who want to reduce the fuel economy standards in the future.
I have to admit you have a point there.
And as for the discussion of a policy to transition away from fossil fuels, it may belong in another thread. But, it is so much that can potentially be done that is being ignored for now a lot of places. I still think we have another 20 years or so to try to find a path. But I don’t think it is going to be as easy as 98% of people in the 20’s think today.
Such discussions are ok with me as they are related to future demand for petroleum, without which there will be very little supply, which is what this thread is about.
I agree we need about 20 years, maybe 30 and it will not be easy at all imo. Higher oil prices might move us in the right direction and the higher the oil price the faster the transition might occur.
Good policy would also help, but the auto companies that will survive will see the need to move in the proper direction without government interference.
In August 2018 the Tesla Model 3 was #18 for vehicles sold in the US (this includes pickup trucks, SUVs and Cars.) Not bad, and they are likely to continue climbing, probably reaching top 10 by Dec 2018.
Not a lot of competition in this price range (under 60k) until 2020 or later. They expect to start selling the base version (RWD and 210miles of range) in mid 2019, so far they can’t keep up with demand for the higher end 310 mile range vehicle which is 49k with RWD and no options.
The US SPR will release 11 million barrels of sour crude oil to be delivered from October 1, 2018 through November 30, 2018.
FEBRUARY 21, 2018 EIA: Assuming no other legislation over this period, the SPR could decline from 695 million barrels at the start of 2017 to about 410 million barrels at the start of 2028. https://www.eia.gov/todayinenergy/detail.php?id=35032
Energy News,
In your link from the EIA it says nothing about SPR sales in 2018.
What is the source for the statement below?
The US SPR will release 11 million barrels of sour crude oil to be delivered from October 1, 2018 through November 30, 2018.
So we have sales of 11 Mb over about a month, input to US refineries is about 542 million barrels per month so this sale of 11 Mb of oil from the SPR barely moves the needle, its about 2% of monthly crude input to US refineries, for a single month.
From Guym’s link:
The 11 million barrels will likely reduce supply disruptions ahead of the Iranian sanctions that are set to go into effect in November, experts said.
Do these “experts” know how tiny an amount of oil 11 Mb of oil is compared to total daily input to refineries? Its about 17 million barrels per day so if all the oil were sold in a day, rather than over 31 days, we could run the refineries for about 15.5 hours. (I assume the refineries run 24/7 as there is a lot of capital which might not be left idle.)
Last time, most was exported to China, anyway. Not likely to move the needle based on the quantity, unless the press makes it bigger, which is a likelihood. Last batch had some bad H2S problems, so I imagine they will just dump it cheap.
Yes a PR stunt before elections to show the Republicans are on the case with important Tweets from the Prez and all that 11 million barrels to keep gasoline prices low.
Hey the experts said it would really help, so it must be true. 🙂
I admit that I have been either side of the fence on this Democrat Republican thing. Last time I had any real interest was when William F Buckley was still in swing. He did significantly influence intellectual conservatism. An acceptable middle ground was important to identify. Now it’s Fox News at a high point. Sad. In the far past it gave us many good things that are taken as “liberal” now. Now, you for us or against us, on either end. Polarized. And the Republicans wind up with Harpo Marx who tweets instead of honking his horn. Yuck!!! Don’t look down now, Bill.
“Trump has the maturity of an eight year old boy with the insecurity of a teenage girl.”
I saw that on Bill Maher last weekend. Because it’s so true. Is what makes it funny and sad at the same time.
HB-
We are in late stage capitalism, so, for me, Trump is not that much off base from expected leadership.
What I find surprising is the constant lying–
Even a TV con man should be beyond that.
In theory, Riyadh can pump as much as 12.5 million barrels a day, compared to about 10.4 million last month, offsetting the loss of Iranian supply. Still, to reach that level, it needs time to drill more wells, and an SPR release could fill the gap until the Saudis are ready.
Elsewhere in that same piece they say as much as 30 million barrels can be released over a 60 day period so that’s about 0.5 Mb/d, to fill a 1 Mb/d gap, it would help a bit perhaps, but would be a short term fix for a couple of months.
Most people won’t be paying attention, anything that brings down gasoline prices will be seen as good by the masses, even if it is short term.
I had forgotten that the President has the power to release the SPR reserves (up to 30 Mb over any 60 day period) under the Law that created the reserve.
ps I think tradingeconomics predictions are just extensions of curve fitting they don’t any fundamental anlysis.
pps Was it you who came up with an analogy of a water skier for oil prices; i.e. the supply/demand balance is the boat pulling the skier in a certain direction but the skier can slalem left or right about buoys which represent the daily noise?
(Supposed to be a reply to Ron above but something got messed up)
George Kaplan,
What is your take on Brazilian future output?
I find your analysis about the best around.
Was it you who came up with an analogy of a water skier for oil prices;…
Yes, that was me. A skier can swing wide each side of the boat pulling him but eventually he is forced to follow the boat. The skier is traders swinging above and below the supply and demand trend. But eventually, they are forced to follow supply and demand.
What the traders are really trying to do is guess which way supply and demand will pull prices, up or down. When most traders guess low, the price will drop, when most traders guess high, the price will rise. But eventually, supply and demand will pull prices right back where they belong.
I’ve always found water skiing boring.
Gave it a good look, could jump start on one foot, etc.
But it is so far from the green room, that one could be on another planet.
Hickory,
Waiting for a boat from Tesla. 🙂
Beats riding around sightseeing on a boat, but yes not green at all, for the most part that’s true of human existence in the 21st century.
Ron,
I can ski on either side of the boat as long as the boat doesn’t get too close to shore or other hazards (rocks, islands, etc). Though I cant go any farther than the Rope is long, unless I let go, of course I no longer follow the boat at that point. 🙂
It is a cute analogy though, as long as the skier is comfortable enough to cross the wake and likes to turn, it works.
Shallow suggested dollar variance as an oil price influence. Items:
Dollar variance against a basket of currencies since 2010 max 27%
Dollar variance against Euro same timeframe 41%
Dollar variance against the pound same timeframe about 30%
haha Dollar variance against the Chinese yuan same timeframe <10% that's hilarious Imagine what they pay for their what, 7 mbpd imported oil vs England or Germany. They can print barrels.
For the people who continually question the upstream unconventional operators for financially mismanaging their companies, today’s RBN Energy site has another post in their ongoing analytical series monitoring the financial aspects of dozens of these outfits.
Breaking down the companies into 3 different groupings – oil focused, gas focused, and hybrid – RBN gives outstanding overview into what is going on with these organizations.
Recognizing that the corner has been turned, debt is being paid down, conservative capital investing is taking place is all apparent with the numbers presented in this article.
Coffeeguyzz,
I have shown an analysis of the Permian that suggests the debt can be paid down completely under reasonable price scenarios (my medium oil price scenario shown in a chart upthread) by 2025 and that cumulative net revenue from Jan 2010 to the future will reach $500 billion in 2017$, by 2036 at an assumed well cost of $9.5 million per well. Output of Permian tight oil for this scenario is on the right axis in kb/d. Cumulative net revenue in billions of 2017 $ is shown on left axis.
2018-09-26 (S&P Global Platts) Algiers — Libya’s crude oil production has hit a five-year high, bringing badly needed revenue to the violence-wracked country, but further gains will depend on stabilizing security and attracting foreign investment, the chairman of state-owned National Oil Corporation told S&P Global Platts.
Libya is pumping 1.28 million b/d, its most since August 2013, and still harbors ambitions of boosting output beyond 2 million b/d by 2022, Mustafa Sanalla said in an interview after attending Sunday’s OPEC/non-OPEC monitoring committee meeting in Algiers.
“If the security situation improves, our production outlook is very good,” he said. https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092618-interview-libyas-noc-hopes-talks-with-iocs-will-boost-oil-outlook-as-security-stays-fraught?
Oil prices making the news in Dubai, up +6 to 88.96
2018-09-26 (Dubai Mercantile) Marker Price on September 26, for November 2018 Oman Crude Oil Futures Contract OQD: US$ 88.96 Change: US$ +6.43 https://twitter.com/DubaiMercantile
Read that CME who now brings you WTI Cushing prices, will start their own WTI MEH price to compete in January. The more logical price for WTI, and it is trading $6 to $7 higher than WTI Cushing now for November. In my logic (dangerous), it should raise WTI in the future as there is only about a $3 transportation cost, or less, to get Cushing to MEH. Right now traders have a totally confused interpretation of WTI Cushing. Means my little dab from the Eagle Ford is probably being bought this morning at 77.5 less transportation costs. https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092418-cme-to-launch-wti-houston-crude-futures-setting-up-battle-with-ice
And if E&Ps in the Permian had a strong enough, or smart enough, group think to cut back production just a little, they would make far more in the long run. There would still be a transportation cost of $3 or less to get it to MEH, but it still could be trading at over WTI Cushing prices, I think.
Inventories up over one million, but obviously due to operating at 90% capacity vs 96. Exports edging back up. The great takeaway in this weekly is that Washington DC produced an additional one hundred thousand barrels. We couldn’t possibly be at 11.1 until sometime in the second half of 2019. We have to be half a million barrels over actual, now. When this fit hits the shan, Tump will just fire Perry for being a bad apprentice.
I am guessing US production is at around 10.550 for July, Dennis is “less pessimistic” and estimates it at around 10.7. Bound to be somewhere in between, but if we use his estimate, oil would have had to increase by 400k barrels in less than two months. Anyone buy that?
Guym,
The weekly output estimates are useless, I actually don’t have an estimate for US output, beyond the most recently reported EIA monthly estimates, Alaskan output was down, tight oil output was up, that’s all I know for now. I am a bit more optimistic than you about rising output in the last 5 months of the year, it will slow down compared to the first 7 months due to lack of pipeline and rail capacity in the Permian basin, but with rising oil prices some DUCs may be completed in North Dakota, Oklahoma, Montana, Colorado, and Wyoming, heck maybe even in the Eagle Ford play. So we might see another 300 to 400 kb/d increase in the last 5 months of 2018. I would say a 1000 to 1100 kb/d increase from Dec 2017 to Dec 2018 for US C+C output is a reasonable guess.
I would say 800k, and that would be due to the Cushing pipeline expansion due after Nov 1. Another 100k from Other. Not much more until after the first quarter. It takes time to switch gears.
Guym,
You could be right, especially if higher oil prices have little effect on supply in the short term. I am guessing the 2 year trend in US C+C output continues, you are guessing it will not. We will see.
Note that the 2 year trend for tight oil is similar to US C+C with both increasing at an annual rate slightly over 1100 kb/d each year. We have tight oil data through August 2018 so in another 4 months we will know if tight oil output has increased enough to reach 1000 kb/d, so far the tight oil increase has been 789 kb/d for the first 8 months of the year, another 211 kb/d over 4 months gets us to 1000 kb/d.
Your using those numbers from EIA on tight oil output. They are probably mostly from drilling info which is their estimate. I think Texas production is proving that those numbers do not project shut ins, which are obviously (to me) happening. Projections won’t estimate shutins. They estimate as if those wells continue to produce, or I can’t think of any other way they could do it.
It is my guess, and the next few months should confirm, deny, or change. It’s a new ball game, and we are listening to the results with a huge time delay.
Guym,
I think drilling info gets its data from the various state agencies. Note that the data is not from the drilling productivity report.
It is always possible that any estimate is incorrect and of course trends often change in ways that are difficult to predict.
As I said, you may well be correct, we’ll know better in Feb 2019 or perhaps in Sept 2019.
Yeah, and I just found out that extra 360k of new pipeline ain’t gonna happen. I am victim again of faulty reporting. The pipeline will have a total of 360k, when the new expansion of 90k barrels come online the end of October. So, we will only have 90k new pipeline capacity. If we have 800k of new oil in the US by the end of the year, we’d be lucky. Nothing new on the Permian until the end of next year that I know of. You can use historical numbers to estimate, in this circumstance, I wouldn’t.
Drilling info gets its numbers from the RRC, yes. But it uses the old numbers and new completions to estimate the most recent two months. Anything past June, now, would have to be estimates. I am pretty confident on using the pending data files from RRC, and in July production went down, and EIA’s June numbers were too high by at least 50k. Which makes July output around 150k less than what they reported for June. It may go up again in August, but I think our average can be found from the past three months plus the 90 that’s coming.
Guym,
From Dec 2017 to June 2018 the increase in tight oil output has been 572 kb/d, with a 217 kb/d increase from June to August. Perhaps the drilling info estimates for July and August are too high, hard to know at this point.
Well, the EIA numbers for July are due pretty quickly. Be interesting to see what they come up with.
Get into your time machine and travel a couple (maybe less) years into the future. Oil prices are terrible, oil supply is frightening. Yet, we are continuing to export oil from the Permian and elsewhere. Yeah, it’s at an API that’s pretty useless for most refineries, but in the minds of the public and sort of minds of the elected officials it is still just oil, and we are wasting it selling it to other countries. I can see the oil export ban being reinstituted. After all, that is what precipitated the first one (oil shortage). At that point, where to produce oil will be on what type, rather than all on how much.
Before you say that can’t happen, look at the current administration, or what we had as an alternative, and think a little harder.
It would also change dramatically, projections on US output.
There is nothing that compares to a desert area aroma after a good rain. I lived in Arizona for a couple of years, and it was flat amazing after a rain. The flash floods were not so great, but the smell was.
I have no idea what to make of India, and their plans. One week, they will not be following sanctions, and the next, the will. It reverses every week. Last week, I read they are going to draw on their reserves, and this week they are going to grow reserves. It is probably not India, but the reporting on India.
It’s going to be more difficult to know what is happening because India hasn’t updated it’s oil inventory data on JODI for a few months.
And China has stopped reporting it’s inventory data through their Xinhua news agency
It sounds like refiners are saying that they will comply with sanctions in November but they hope for waivers.
Whereas it’s governments that are saying that they will setup alternative payment systems.
Oil market has already climbed back over today’s losses. It’s beginning to look like the battery bunny. And they are not realizing yet, that all OPEC losses could be covered, and we would still be over a million short.
Another explanation for the up and down movement in the Permian production rather than shut ins is the still long delay between completions and the huge decline rates. But, overall, I don’t think it is growing at the rate expected. There is, no doubt, a lot of possible explanations for the slowdown. Including constraints other than pipelines. I read the roads are really becoming a problem in the local Midland newspaper.
Shell GM says roads are bigger problem in Permian growth than pipelines.
Some kind of wild west road movie.
This kind of driving, 80-100 hours a week with a truck isn’t possible anymore in burocratic old Europe. With electronic tamper proof tachographs, the driver inserts his licence card and the clock runs. When he exceeds 40 hours driving time a week, he’ll be in deep trouble, up to loosing his truck license. Speeding can be detected even weeks later with this system, so don’t do anything to alarm the police.
Reduced truck accidents by a lot here. In Permian, they would have to hire 2 drivers for a truck.
Guym,
I imagine the roads will improve over time, the pipeline constraints will take some pressure off, completions might drop about 28% which will take some pressure off the roads, but they need to be widened by the time pipeline capacity comes online in late 2019.
Guym,
No doubt there will be a slow down in the completion rate, due to pipeline constraints in the Permian, I would expect they would have no difficulty keeping output flat at the level the oil can be moved by pipeline and rail to refineries or export terminals, so I doubt output will decrease. Other areas such as Eagle Ford, Bakken, SCOOP/STACK, and Niobrara don’t have the same constraints, higher oil prices might increase the completion rates of DUCs in those plays.
Note that according to Enno Peter’s data, the completion rate for horizontal tight oil wells in the Permian basin averaged 334 per month from Sept 2017 to March 2018, so the EIA estimate for completions in June may be too high. Also based on my model only about 285 completions per month are needed to keep Permian output flat at Aug 2018 levels estimated by the EIA. I simulate what output would look like through July 2019 if 285 wells were completed each month from Sept 2018 to July 2019, output remains relatively flat if average well productivity remains flat.
The EIA’s legacy decline estimated by the Drilling Productivity report is not very accurate and suggests 412 new wells per month are needed to keep output from falling, when in fact the number is only 285 new wells per month.
Nice presentation regarding climate research-
https://graphics.reuters.com/CLIMATECHANGE-GREENLAND-CHALLENGES/010080EH0V0/index.html
Oops- didn’t realize this was petro thread.
18/9/2018
What happened to crude oil production after the first peak in 2005?
http://crudeoilpeak.info/what-happened-to-crude-oil-production-after-the-first-peak-in-2005
Mushalik – do you have any views on NGLs. There’s been quite a surge of production to fill some of the all liquids demand and US is the biggest producer but I’m not sure if the growth can be kept up. A lot depends on whether the new gas supplies (e.g. East Africa LNG) are wet/dry and I’ve seen no analysis on such things. I think US tight gas is fairly wet.
Won’t China’s tariffs on US LNG lower demand for US?
I doubt if production would decline though it would just go to a different market. There’s quit a lot of things that can happen. NGLs (even without the condensate) is about the same order as US, Russia and KSA for overall liquids supply and with the condensate it’s the largest but the liquids to gas ratio is completely different from field to field and the condensate to gas ratio changes with time so it’s difficult to predict (and less data than for oil even in the well reported producers).
Trump is going to have to bring out the big gun of SPR draw, his tweets did not have a lot of effect. That may be good for a month. Though, that may mainly effective in lowering WTI, and not so much Brent. I remember reading the last time, that refiners had some problems with it.
It looks like the traders want prices above $80 for Brent but can’t quite bring themselves to be the first.
Calls over $80 are higher than anything.
Traders only make good money when it goes up or down considerably. It’s not going down much, probably. Spot prices will probably prevent that. I think it is finally getting to the point, when spot prices have more sway than the Willy nilly decisions of what it should be by the traders.
Saw Brent get over $80 this morning, at least one time. Where is tweety bird?
This came instead (the oil price police is still holding it under $80):
OPEC and non-OPEC countries discussing possible production increase by another 500,000 bpd – Reuters
By Eren Sengezer
Citing three sources with direct knowledge of the matter, Reuters reported that OPEC and non-OPEC countries were discussing a possible production increase by 500,000 barrels per day.
Sources further added that OPEC and non-OPEC countries pumped less oil in August compared with July due to drop in Iranian crude supply.
Guess they will have to pull more out of storage. They can’t produce that much more.
Mr. Berman has a recent interview and slide deck linked at his site. I found what he had to say interesting with regards to oil price dynamics. I quite like his graphs/charts too.
http://www.artberman.com
the presentation was good. an article he wrote a couple weeks ago in response to the “next financial crises” article from NYT is a bit more cohesive and compact in terms of discussing his thesis. the presentation has much more data/charts though.
https://www.artberman.com/shale-plays-will-not-cause-the-next-financial-crisis/
I like berman because he helps counter the “well duh supply and consumption are always equal” stuff we tend to get on the board. he also believes high oil prices contributed strongly to GFC.
Two cats,
Inventory can be considered a part of supply. Cannot consume what does not exist. I like Berman’s analysis as well.
Inventory increases and decreases and affects oil price.
Shallow Sand,
Continuing our discussion of decline rates from last weeks’s post…
I looked at decline rates for Permian wells from 2009 and 2010 from month 50 to month 90, with data sampled every 5 months to save time (50,55, … , 85, 90). The decline rate is about 13% per year. For Bakken 2009 and 2010 wells (later stage of development of play using horizontal fracked wells) over month 50 to month 90 we get about a 12.7% decline rate with same sampling. So at least through 2009 to 2010 the two plays have similar decline rates for months 50 to month 90.
For the Bakken we have older wells that give us some information about decline rates later in the life of the well (after month 90). For Bakken 2006 and 2007 wells (2008 has strange behavior with an increase in output late in the average wells life so I decided to exclude 2008) we have 237 wells, so a fairly small sample, but better than nothing. The annual decline rate from month 60 to month 115 is about 9.5%per year over that period, which suggests that a 9% decline rate may be reasonable based on the data we have.
We won’t know if the Permian Basin will match this for a few more years, based on the data we do have for the Permian we would not expect the terminal decline rate to be higher than 13%, and in my view an assumed 11% decline rate might be a reasonable guess.
It would be interesting to hear Fernando’s perspective, though usually he has said in the past he doesn’t know enough about these plays to even make an educated guess.
Charts below for data I have all pulled from Enno Peter’s shaleprofile.com (link below)
https://shaleprofile.com/
As always, thank you Enno!
Chart for Bakken 2009 and 2010 average well decline from month 50 to 90.
Chart for 237 Bakken 2006 and 2007 average wells from month 60 to month 115 from first well output.
Average annual decline rate 9.5% over that 55 month period.
I have read by some that the new productivity is not increasing EUR, just merely getting it out quicker. I think that is more doomsday, than technical. Eventual decline rates are going to be a moving target, if this article has any significance, which I believe might be true.
https://www.epmag.com/shifting-focus-optimized-production-1713356
Then you have EOG’s reported “success” in increasing EUR by 30 to 70% with enhanced Recovery in the Eagle Ford. Supposedly, just successful in the Eagle Ford because of containment. Although, other types of attempts are being tried by others in the other plays.
And decline rates will be affected by the shift from tier one to tier two as pointed out in Ron’s post, below.
Guym,
Probably true in the Bakken where average lateral length has not changed much since 2008, for the Permian basin much of the increase in new well EUR is due to increased lateral length so greater contact with the oil bearing zone of the play for each well increased overall EUR. It also means fewer total wells will be drilled as more acres consumed by each well.
Dennis.
We won’t know till we get there.
9% annual decline for a stripper well is pretty steep IMO.
Sprayberry has a lot of wells that are still economic at high oil prices despite producing under 10 BOPD.
Whether horizontals in the Permian will work at such low volumes remains to be seen.
Higher oil prices will help.
Shallow sand
I agree at low oil prices 10 bpd doesn’t work for horizontal wells.
Also agree 9% decline not great. 13% is worse.
We will see in a few years what the wells look like.
Dennis.
Do you know much about the construction of these horizontal wells? I admit I don’t.
There have been a few drilled in our area, at much shallower depths.
It seems that eventually the lateral casing collapses. I suppose maybe they were not constructed properly, as these date back 15+ years ago with regard to completion.
I assume the technology or geology is such that this is not a concern for the shale wells?
It seems like that is quite a load for the casing to bear under 10,000’ of rock, but I will admit that is just a guess on my part.
Shallow sand,
I would know less than you. I imagine the loads can be designed for from an engineering perspective.
Lighesout posted this link in the coal post but it belongs here.
Bakken operators facing shift to less prolific geography: study
While the majority of existing wells are located in geography with well performance of 1,000 b/d or more, the majority of remaining wells will likely be located in geography with well performance below 500 b/d.
The study shows that as operators move out of the core, average Bakken well performance could plummet.
Thanks Ron,
That piece is a good read.
There is also:
The North Dakota Pipeline Authority forecasts statewide production to gradually peak between 1.9 million b/d and 2.3 million b/d within about 15 years.
My expectation is that the peak in North Dakota Bakken/Three Forks output will be about 1.79 Mb/d in 2020 (vs 1.22 Mb/d in July 2018) for a scenario where oil prices peak at $113/b in 2017$ in 2027, remain flat until 2040 and then gradually decline. URR is 9 Gb by 2041 and 28,000 total wells are completed in the scenario. Well completion rate (new wells per month) shown on right axis of chart below peaks at 22o new wells per month in 2022 and falls to zero in December 2027.
Clearly I don’t know future well completion rates, but I expect higher oil prices might result in more drilling.
Alternative scenario for Bakken where well completion rate is limited to 155 new wells per month (the wells completed in July 2018 were 141 new wells based on Enno Peters assessment), peak in 2021 at 1.5 Mb/d, URR is 9 Gb and total wells completed about 28,000. Same oil price and other economic assumptions as previous scenario, only well completion rate is changed.
Dennis
I am glad you noticed that last paragraph in the Platts’ piece as I thought it was the single most important takeaway (as well as probably being accurate).
The overall negative tone in the article surprised me a bit as the Platts people have always seemed to be a pretty good source of info.
However, this instance could be a good opportunity for people to spend a few minutes, go to the source, and draw their own conclusions.
The referenced report is the September 14, 2018 NDIC Update from Justin Kringstad, Director of ND Pipeline Authority.
Screen #17 from the report may be the ‘money shot’ as a slightly more expanded view appears to show vastly higher numbers by simply dropping the bopd rate to 900 bopd or, more dramatically, to 800 bopd.
The ‘High Case’ scenario is on track to be more probable as the effectiveness of diverters has increased significantly these past 2 years.
Somewhat related, results from Liberty’s EOR pilot may be published soon.
Much interest focused upon the results.
That report can be found at link below
https://ndpipelines.files.wordpress.com/2018/09/kringstad-ndic-slides-sep-14-2018-full-page.pdf
I disagree that the high case scenario is more likely, as the higher productivity areas become fully drilled, the lower productivity areas will not be able to support high well densities. The low case looks far more likely to me and is more in line with the economics at reasonable oil price levels.
Also they use a model with $7 million well cost which probably excludes many real costs such as land cost, overhead, storage and gathering facilities and plugging cost at the end of a well’s life. The real full cycle cost is more like $9 million than $7 million. Investor presentations typically do “point forward” well costs and ignore sunk costs. A proper accounting to evaluate ROI considers the full cost of the investment including the current price the land could be sold for, the so called opportunity cost.
Interesting that you mention investor presentation, Dennis.
Mr. Kringstad is an employee of the ND state government, tasked with continuously modeling hydrocarbon activities within the state so as to better evaluate future tax revenues, infrastructure necessities, etc.
Now, you strike me as a numbers and graphs kind of guy, Dennis.
What say you regarding slide #18 from that report?
The chart projecting – at 1,200 completions/year and $61/bbl earl – OVER 60 years worth of drilling?
Asking for a friend…
Probably 1200 completions per year is too low an estimate, that’s 100 new wells completed per month, the high case estimate is very unrealistic given the productivity distribution, a realistic estimate is 40,000 total wells completed at most and about 13,000 wells have already been completed in ND Bakken/TF so that leaves 27,000 wells, at 1200/year, that’s 22.5 years of drilling when no economics is considered, a realistic economic assessment is as I show below with 33,000 total wells drilled, last well drilled in Feb 2035 if oil prices rise to $113.40 in 2017$ by Feb 2027 and remain at that level until 2040. So maybe 17 more years of drilling, with a gradual decline in completion rate after Jan 2033 due to poor economics as new well EUR falls as lower productivity areas are drilled.
Many of the state agencies make optimistic assumptions when developing their output profiles and use unrealistic well profiles.
The average 2017 Bakken/Three Forks well will have an EUR of about 400 kb0. It is too early to make a decent estimate of Bakken 2018 well EUR.
SEVENTEEN YEARS more drilling???
(Clasps hands to chest, pirouettes and does a face plant into da ground.)
Y’all might wanna screencap that comment, Dennis, and revisit it 5 years down the road.
GGZZ, All we are doing is documenting the atrocities. In 5 years, the scholarly citations will be numerous.
Documenting whatevuh, but 17 years remaining for drilling in the Bakken is way, way off the mark.
Despite my having very different views on many of these topics with most commentators here, this level of disconnect seems especially bizarre.
Heck, Kringstad’s report is calling for a peak in the Bak at about that timeframe – 15 years.
At about 2 MM bbld, no less.
You guys are the number crunchers.
Something is significantly awry, and I think the fulltime analysts outta ND get the nod.
Really not that much different in the greater scheme of things.
You are not showing much of a cornucopia of riches either, wha’happen?
Every morning when I open my eyes, if I`m not seeing grass roots, Imma experiencing a cornucopia of riches.
Being a realist, I’d assert that you wouldn’t be seeing anything in that case.
Therein lies the diff.
Hi everybody,
I have been a reader of this blog for years now, and it´s time to take part in that discussion.
My problem is the number of “1280 spacing units (est.)” on slide 6. The questions is, how big is the Bakken Play from the north to the south and from the east to the west.
Start in the “Parshall” area (89w) and go to the border to Montana (104w), you get around 96 miles. Go from Billing and Stark (139n) to the border of Canada (164n) and you get around 156 miles. Some Areas in the north and the south-west are not too productive, so you get an average of around 120 productive miles from south to North (est.).
Multiply 120×96 and you get around 12000 “productive” sections, which means around 6000 “1280 spacing unit” and not all those units are economic. The numbers on slide 6 – almost 10000 spacing units – is weigh to high, even if acount or for some 640 spacing units that are beeing drilled.
That is the big mistake in that studie in my opinion.
Best regards
Toby
Toby
Welcome to the discussion.
Looking at that report (slide #5), they are using historical, production records showing output from 9,775 DSUs.
Of that number, almost 4,000 are dogs, less than 500 bopd from top producer in unit (probably the only producer if one wanted to crosscheck on the DMR Gis map).
Using the gross areas from Dunn, McKenzie, Williams, Mountrail, Divide and Burke counties gives about 11,000 square miles.
Less than 6,000 DSUs.
So, you sure seem accurate in wondering where all the ‘extra’ DSUs came from.
I’ll zap off an email to Mr. Kringstad tomorrow and ask him exactly that.
But – again – the DSUs that are in the report on slide #5 are from already producing wells, so they say.
Toby, there must also be a question of how they have come up with the high and (especially) low well densities as there nothing stated to justify the numbers and not much history to show what will work without interference in the poorer areas. Bakken is treated as a single tier from what I can see but pretty obviously the production declines markedly on the outskirts, and I think there’s already been some indication of well interference.
This shows the current production wells per DSU based on concentric rings from a nominal centre. Only one small area is above 8. If you assume 6 for the area to 50 km radius, 4 to 70, and 2 to 100 then there are 1500 more wells in the centre, then 2200 then 3800 (mostly crap on the periphery). Are my numbers any good? No but at least they fit in with current history and might not be any worse than the ones in the report. It includes Bakken and Three Forks so is conservative in some ways, not in others and doesn’t include abandoned wells.
George,
My low F95 TRR scenario ends up with about 7000 wells completed from Aug 2018 to Dec 2030, very much in line with your estimate here of roughly 7000 wells, though perhaps you might think that estimate is too optimistic. ERR, when a medium oil price scenario and an $8 million well cost assumption are applied is about 6.3 Gb, a little lower than proved reserves and cumulative production through Dec 2016 (about 6.8 Gb).
Coffeeguyzz,
It seems we have different North Dakota Government experts with very different production forecasts.
See
https://www.dmr.nd.gov/oilgas/presentations/WBPC052418_2400.pdf
Compare slide 13 and 25 from the presentation linked above, the forecast on slide 13 must use a well profile that is not realistic.
Kringstad may be using a “typical well profile” that is far too high. Many of the “typical well profiles” given in older NDIC presentations are far from realistic. The “peak production estimate” given in slide 25 with about 1.5 to 1.6 Mb/d from 2025 to 2030 is at least somewhat realistic, but the long slope down assumes far too much output, than is realistic.
Scenario below attempt to match the Peak Output NDIC estimate of about 1.6 Mb/d in 2030, a high oil price scenario is used ($147/bo in 2017$ by 2027) and a low well cost of $6 million in 2017$ is assumed, 43,600 total wells drilled and ERR of 11.5 Gb by 2050, peak well completion rate is 320 new wells per month in the second half of 2029, new well EUR falls from 414 kb in July 2018 to 110 kb in Jan 2031 when the last well of the scenario is completed.
Dennis
This is just one of the many reasons that I do not hold future projections so fervently as being the Unvarnished Truth, aka, what to precisely expect.
Different views, varying input data points, on and on.
What caught my eye was slide #26 on your above link, the Gis map screenshot showing activity near the Red Rock field way over in Bottineau county.
Without digging into the specifics, it looks like the recent work from a smaller operator in shallower rock.
THIS is one of the bigger potentialities that I’ve mentioned in the past to watch out for.
Specifically, smaller operators in the US are tentavely pursuing exploration/development in shallower areas of known hydrocarbons using some of the hardware and processes that the Big Boys have been pioneering this past decade.
From old Appalachian Basin formations, the Clinton Sandstone, south eastern Colorado, tentative probing up in Michigan and Illinois …
These smaller operators may never produce the larger volumes of the prominent players, but – as can clearly be seen in that Gis screen shot – activity is well under way by these guys.
Coffeeguyzz,
At most these smaller operators may reduce the overall decline rate of US output a bit after 2023 when US LTO output is likely to peak, not going to be enough to stop the decline from larger producers as the more prospective areas become fully drilled.
If we ramp up hard to try to keep production flat we get a steep drop around 2030, even if we assume low well cost and high oil prices ($147/b in 2017$), small producers will not be able to stop a 1000 kb/d decline from 2030 to 2035 from the Bakken along with even bigger declines from the Permian basin. After 2030 the decline rates in the tight oil sector will be quite steep (though it might start sooner than this if the USGS mean estimates prove too optimistic.)
Reports on the net about yesterday’s Bakken 2.0 conference contain some eye opening claims that you might find perposterous, Dennis.
Ultimate recovery of 30 to 40 billion barrels
12 to 20 percent currently recovered from new wells
Possible 2 Mmbld rate in just a few years.
Interesting stuff.
Reporter named Springer wrote the articles that I read.
Cowboyistan.
Coffeeguyzz,
Only 40 Gb, why not 400 Gb? 🙂
You gave said before they won’t leave any oil behind.
Coffeguyzz,
The 2013 USGS estimate for the North Dakota Bakken Three Forks was a mean of 10 Gb, F95=8 Gb and F5=13 Gb for technically recoverable resources.
Continental has been claiming 30 Gb for many years. The average 2017 well has an EUR of about 400,000 barrels of oil, if we make the assumption that the average of all wells drilled in the Bakken/Three Forks will average 400,000 barrels each, then 75,000 wells gets us to 30 Gb and 100,000 wells gets us to 40 Gb.
Does it seem reasonable to you that the Bakken/Three Forks is being developed in a random way where oil companies just drill their wells anywhere in the formation?
Or would it seem more plausible that they drill and complete wells in the most prospective areas first, especially after the first few years when the tier one areas have been well defined?
I would submit that the latter case is more likely and that the tier one areas are being drilled preferentially, especially since 2014.
Clearly the assumption that the average well productivity will reach some maximum and remain at that EUR level for the remaining time that the play is developed is an absurd one.
Even more absurd would be an assumption that the new well EUR will continue to increase without limit.
I also note that the well cost estimate is about $8.5 million rather than the $7 million estimate given by the ND Pipeline Authority.
A more reasonable estimate with reasonable well cost, tax, royalty, transportation cost, OPEX, and oil price assumptions is at most 40,000 wells completed in the ND Bakken /Three Forks.
Average well productivity for all 40,000 wells is likely to be 250,000 barrels of oil over the life of the well.
The average well productivity will not remain constant, it started at about 150,000 barrels in 2005 increased to about 320,000 barrels by 2008, increased further to 400,000 barrels by 2017 and is likely to gradually decrease from Jan 2019 (a guess on my part it may be before or after that date) until the last well is drilled.
This is the normal life cycle of an oil play, always has been and always will be.
Coffeeguyzz,
The 30 to 40 Gb estimate is nothing new Continental has been claiming that since 2013, the NDIC agrees with the USGS F5 estimate of 13 Gb.
If one looks at the area where most of the completed wells are focused and the drilling densities to date, even 30,000 total wells completed may be a stretch, the NDIC estimate of 55,000 to 65,000 total wells completed only happens in a World with $200/b oil in 2017$ and well cost of $5 million. In other words, some other universe.
Aaannndd …
You may want to be a little cautious when making any comments regarding the extent and productivity of the Three Forks, which comprise a fair amount of this report.
There are too many unknowns.
The High Case scenario projects 10/6/4 wells throughout Tiers 1,2 and 3.
Based on some recent production, including a very good third bench TF well, upside potential is promising.
Canadians have been successfully targeting this formation for years north of the border.
The Three Forks is accounted for in my estimates, lower benches of the Three Forks do not look very productive.
Using well profile data to date from shale profile and the $7 million well cost and the assumed 1200 wells completed per year in the North Dakota estimates by the Pipeline Authority, along with the 2013 USGS mean estimate for TRR, I get a very different estimate for North Dakota Bakken/Three Forks output with peak in 2019/2020 at 1.36 Mb/d. URR is 9.6 Gb with 33,000 wells completed.
” … lower benches of the Three Forks do not look very productive”.
Where the heck are you getting data concerning TF2, TF3, and TF4, Dennis?
Some of the better wells out of North Dakota have come from TF2.
This is one reason the gas component is higher as the deeper, hotter formations contain more gas.
The operators have been very cautious in delineating productive TF 2/3/4 as it is more of a learning curve that they feel is not currently an optimal allocation of capital.
There is a fair amount of anticipation concerning the northerly step out as a very productive well was recently brought online near the Divide county line.
Coffeeguyzz,
Lower benches are TF3 and TF4, look at the report, the productivity of TF3 and TF4, most wells are under 500 bopd for peak month, there will not be the high density well spacing assumed in the “high case”.
Coffeeguyzz,
Keep in mind the years of drilling is based on 1200 wells per year drilled, that doesn’t get Bakken output close to 1.9 Mb/d (it would be more like a 1.3 Mb/d peak). To get to the 1.9 Mb/d peak about 600 new wells per month would need to be drilled at the peak and a reasonable scenario has about 83,500 total wells completed (the average of the high and low cases would be about 70,500 wells completed.)
If we ignore the economics at $7 million per well (an underestimate of full cycle cost) and just consider TRR, it would be about 13 Gb, near the F5 TRR estimate of the USGS. Peak is 1.86 Mb/d in 2025 for this very optimistic scenario. Note that the high case is 98,000 total wells drilled, but that case assumes 41,000 wells are completed with peak month output under 600 bopd, not very realistic, where the more realistic low case has about 26,000 fewer of these low productivity wells completed, so a more realistic scenario would have a maximum of 72,000 new wells completed (11,000 less than the scenario I created for very high TRR).
The chart below shows this highly unrealistic scenario.
Dennis
You have an awful lotta numbers in your comment that may or may not prove applicable in years to come.
Right now, on the ground procedures in North Dakota (and spreading throughout this entire unconventional industry), are enabling operators to access and recover far more hydrocarbon at lower cost.
I have noted on this blog numerous times that your inclination to view historical data and project forward, absent an understanding of ongoing developments, will continue to impact your predictions to the downside.
One of the bigger considerations with the Kringstad report may be the future potential of the Three Forks.
Dennis, if you look at the heat map from Kringstad relating to Tiers 1,2 and 3 – including the “Empty” Tiers #1 and2 – it should, hopefully, become clear that there is enormous upside potential to future TF development.
Furthermore, when smaller, scrappy outfits like Kraken Operating enter the arena, fringier areas might well be successfully targeted.
This, in fact, is what is presently unfolding.
If you spend a few moments just looking at slide #8, the size of it, the historically archaic practices that went into all those lightly shaded green and yellow dots … and fast forward to the rapid, precise drilling and highly productive new completion practices of today, one may grasp what is apt to take place in the coming decades.
As an aside, slide #23 may put to rest any uncertainties regarding Mr. Martenson’s unease regarding perceived discrepancies in well prodiction profiles.
Coffee, It seems that Kraken has recently cut it’s rigs from four to three. Does that seem right to you, and do you have any idea why.
dc
I no longer put too much time keeping an eye on the Bakken outside of regularly checking in on Bruce Oksol’s blog.
He has regularly commented on how effective Kraken’s wells seem to be, which is saying something as I believe most of their acreage is not considered top tier.
(They bought into the Bakken from a bigger operator’s divestment, I believe).
So, no, I do not know what those guys are up to.
ZZZ’s
One of the great findings is how well a statistical/probabilistic analysis works on the Bakken. Just knowledge of number and a statistical view of the average allows us to come up with a close running tabulation of production. This was never possible in the past.
I love this; a guy from Minnesota, another from Maine, and one from San Francisco, of all places, arguing about the plight of the US shale oil industry. None of whom have EVER picked up a pipe wrench in their sheltered lives, or balanced a well’s checkbook, all of whom think they know the answers and can predict America’s hydrocarbon future. Two thru math and models, one because the shale oil industry simply SAYS so.
Ain’t the internet great ?!!
Nice to see your track record of being incorrect remains intact at the near 100% level, Mr. Roughneck.
This oh so sheltered life just picked up a pipe wrench last week to do some minor repairs.
And, not that it means squat when it comes to accurate information dissemination, this oh so sheltered life still has – and probably always will have – the world record for disassembling a Christmas tree flange at depth, 1,610 feet pressure, to be precise.
You, um, you HAVE seen Christmas trees out in the field, I reckon.
Mike invented the freakin X-mas tree! Everybody knows that.
Mike,
As I have said repeatedly, but you might have missed it, nobody can predict the future.
I create scenarios using a variety of assumptions of what the future would look like based on those assumptions.
A high well cost ($9 million in 2017$), low completion rate (100 new wells per month or 1200 new wells per year), and a medium oil price scenario ( a linear increase in 12 month average refinery gate oil price from $75/bo in June 2018 to $113/bo in 2017$ by Feb 2027) results in a relatively low peak in Bakken Output of 1.36 Mb/d in 2019. This seems too low a well completion rate to me as the most recent value was 139 wells in July 2018, an alternative scenario assumes well completion rate rises to 155 wells completed per month by 2020 and remains at this rate for 4 years before the completion rate decreases. All well cost and oil price assumptions are unchanged, peak is about 1.5 Mb/d in 2020/2021. For both of these scenarios URR is about 9 Gb, total wells completed (including the 13,000 ND Bakken/TF wells completed through July 2018) is 28,000 from Jan 1951 to Jan 2030.
Alternative “unrealistic scenarios” were created to see how many wells would be needed to reach the ND Pipeline Authority’s “Low Case” of 1.9 Mb/d in 2030 basically even unrealistic assumptions could not reach this level using a $6 million well cost in 2017$ (too low by at least $2 million) and a high oil price of $147/b in 2027 and remaining at that level until 2055 (in 2017$).
None of these are predictions in the sense that I cannot predict next month’s oil price or completion rate, never mind what they will be in 2030 or any year or month between. Past is known (to some degree) the future is not.
Where someone is from has little to do with whether they can analyze the data.
My opinion is that the 1.5 Mb/d peak in 2020 looks pretty reasonable if oil prices continue to rise (the medium oil price case assumes $85/bo in 2017$ at the end of 2020 at the refinery gate), note that the ERR is about 1 Gb less than the USGS F50 case for ND Bakken/TF TRR.
Lower
I haven’t seen a probabilistic analysis of this just deterministic appraisals based on different assumed ultimate recoveries. The URRs may be probabilistic, and they are the key numbers, but industry has been generating P10 etc. estimates for these for many years so I don’t follow what is new.
George Kaplan,
For the Bakken, I agree not much is new, simply taking the average well profile and convolving with well completions, first popularized by Rune Likvern.
See for example posts at the page below.
http://www.theoildrum.com/tag/red_queen_0
I have simply extend this analysis by assuming that new well EUR decreases in the future (with a guess of Jan 2019 as the start date), assume about 40,000 wells will be completed in the future (though this assumption varies from 30,000 to 50,000 and is of course unknown) and it is assumed that total URR is about equal to the USGS mean TRR before economic assumptions are applied and then economic assumptions for well cost OPEX, royalties, taxes, and transportation costs and oil prices are added to the analysis so that the discounted net cash flow over the life of the well is greater than or equal to the cost of the well. Future wells that do not meet this test, with the given economic assumptions are not completed.
Clearly we do not know future URR, when new well EUR will decrease, future oil prices, or future well completion rates, so different scenarios are presented with different, URR assumptions, total wells completed, oil prices and well completion rates.
I have not seen that many industry analyses where these assumptions are laid out clearly.
I am always willing to share my work with those who ask.
Dennis, That’s it exactly — doing that kind of convolution analysis at around the same time or before Rune presented at TOD
http://theoilconundrum.blogspot.com/2012/05/bakken-growth.html
No one was really able to do this before (at least in the open) because no one ever had the numbers until the NoDak DMR provided such a comprehensive data set.
Convolving is a fancy name for multiplying time series for completions with a time series for assumed EUR per well and fitting to the constraint of URR. But all those three things are unknowns and simply your new assumptions or. choice of somebody else’s. A probability analysis would give some kind of distribution of possible outcomes and highlight the key variables (almost certainly the URR more that anything else). You are simply giving one (or a few) possible scenario(s) with no indication of it’s liklehood.
The statistical nature of a typical well allows the convolution approach to work very well if all one knows is the average and the number over time. Found that out early on and is an important piece of the extrapolations that Dennis is making.
George,
The historical well completion data is known and we can make a fairly good estimate of the well profile based on past data. The likelihood that might be assigned to well profiles, oil prices, future well costs, and well completion rates would be subjectively assigned and I don’t see much point in guessing at the probabilities (though occasionally I make such guesses). I could easily provide a low high and high TRR estimate based on USGS estimates and estimates by other experts such as David Hughes.
The USGS gives an F95, mean, and F5 estimate for undiscovered Bakken/Three Forks TRR, I typically use the mean which is around 10 Gb for TRR, F95 is about 8 Gb and F5 is about 13 Gb. That’s about as much probability that can be injected into the estimate. As to subjective probabilities for completion rates, oil prices, etc I will leave that to experts. I just look at what has happened in the past and make a subjective “reasonable” guess.
Note the very high TRR and ERR scenarios that peak around 1.85 Mb/dare consistent with the USGS F5 scenario.
A scenario consistent with the F95 scenario could also be created.
Such a scenario is presented below, with TRR of 8 Gb with 40,000 wells completed, using the medium oil price scenario (maximum of $113/bo in 2017$) and an assumed well cost of $8 million, the ERR is about 6.3 Gb with 20,000 total wells completed (7000 wells after July 2018).
I would guess there is at least a 95% probability that this scenario will be too low in terms of ERR. Through Dec 2016 about 2 Gb had been produced from the ND Bakken Three Forks and there were about 4856 Gb of crude proved reserves in the ND Bakken Three Forks at the end of 2016, so we would expect there should be a 90% or greater probability that 6.8 Gb will be produced from the ND Bakken/Three Forks.
Paul,
You, James Mason, and Rune Likvern were all doing this at around the same time, I just saw Rune Likvern’s work earlier than yours and Mason’s because I was reading the Oil Drum regularly at the time. Rune graciously shared some of his data with me and I started posting some stuff at my old blog.
My first post at link below
http://oilpeakclimate.blogspot.com/2012/10/using-dispersive-diffusion-model-for.html
The model has changed quite a bit over the years as I have gotten more data.
Coffeeguyzz,
I use the well profile of the average 2017 well to project forward as we don’t have enough data yet from 2018 wells to estimate the well profile. The average 2017 well has an estimated ultimate recovery (EUR) of 415 kb, based on actual data collected from the NDIC on well output from 1694 Bakken and Three Forks wells completed in 2016 and 2017.
One can hope that future wells perform much better but the history of the Bakken from 2008 to 2017 shows that by month 24 the well profile of newer wells falls to the level of older wells, over the first 24 months cumulative production of the average 2015 well was about 30 kb higher than the average 2008 well. At 20 months the average 2016 well had about 30 kb higher cumulative output than the average 2015 well. At 12 months the average 2017 well had about 30 kb higher cumulative output than the average 2016 well. So far the cumulative output of the 2018 and 2017 average wells are similar. The increase in the average EUR of Bakken/Three Forks wells is likely to end as sweet spots run out and will gradually decrease over time.
It is difficult to guess accurately when that will occur, my current estimate is Jan 2019, but we won’t really know if that guess is correct until 2021 when we have more data.
Coffeeguyzz,
The green dots are the areas where the rock is poor, doesn’t matter what technology is used those areas will never have high EUR.
Technology brings incremental improvements, it is not magic.
Coffeeguyzz,
If we then apply economic assumptions to the unrealistic TRR scenario with TRR=13 Gb and 83.5k wells completed under the assumption of a high oil price of $147/b in 2017$ reached in Jan 2027 and prices remaining at that level through 2060 and an unrealistically low real well cost of $6 million in 2017$, the number of wells completed is reduced to 43,600 total wells completed (about 40,000 wells in the very high TRR case are not profitable and so are not completed), the peak is about the same as the TRR case. Wells are only completed for 12 years until 2030.
Chart below.
A number that is below 500 is 0, and I think that is what will come out of a lot of the area they are considering.
Like the Eagle Ford, the result may be negative cash flow, for sure. There are certainly more than two categories of rock potential. Zero is one. Zero makes some lousy averages.
George,
Agree there probably wont be many wells completed with peak monthly output of 500 bopd or less unless oil is over 150 $/b.
They do it all the time in the Eagle Ford.
Guym,
Does the average well with peak monthly production of 500 bopd or less pay for the cost of the well in year 1?
Hell no, they are losers, overall. But, companies drill them all the time. Either to keep leases, add to production, or simply to justify their existence to OPM. And you can’t tell me that the same thing is not happening in the other shales. Mike is correct that the Austin Chalk fraud is still alive and well, and just moved to the shale. At least, in some cases. It’s easy to use old data, average decline rates, and project production over 20 to 30 years to show a future profit. It’s just not going to happen. They maybe could be profitable. At $120 oil price, but it hasn’t been at that price, yet. So, why are they drilling them? I’m not going to say who or where, because I hate law suits. However, the completion query on the RRC site will help you locate them in District one or two. If it shows an initial IP rate of less than 550, you can be assured it will be below 500 bpd high month production, unless it has a lot of production prior to the test. You can find stuff with far less IP rates than 500.
Guym,
Ok. There are lots of unprofitable wells that get completed, it’s a risky business and one doesn’t always know the result in advance. I would think that oil companies that drill a high proportion of such wells at oil prices of the last 3 years, will not remain in business for very long.
At one time, the aim was to make money. 🙂
That was completely true in the first few years, and the assumption was you would have a decline rate that would not approximate zero fast. They were expected to gush for twenty years or more, not five and then be too expensive to operate. The older companies and their initial efforts, I do not question. It the new kids who know better. I don’t have a crystal ball, but I can quess pretty well with as many wells that have been drilled, about what the IP rate will be at in an area. Not all the time, but a lot. The new players have the same info as I do.
As far as the 500 bpd wells being profitable? Rough guess, they would make 80k the first year. Total EUR of about 160k long term. May eventually cover most of the capex at $60 oil, but probably not all. It varies, but that’s a reasonable quess. At $120 oil price, you have a marginally profitable well. Eventually. That’s for Western Eagle Ford, I have no idea how Bakken works out.
Guym,
Are they still drilling in the lower output areas today? Seems not to be a smart move, but I am not in the business and as Mike has mentioned I do not carry a lot of pipe wrenches in my Prius. 🙂
Well, I’m confused. The article states avg daily output for Bakken wells at this:
“Of the nearly 8,000 existing Bakken wells, 49% are located in geology with a peak monthly performance of over 1,000 b/d, with 18% in geology with peaks over 1,500 b/d. Just 14% of existing wells are located within geography with peak monthly performance below 500 b/d.”
None of the URR recovery profiles I’ve ever seen, either from Art Berman or from Enno Peters (usually displayed by year of drilling as cohorts), have ever shown an average peak monthly output of over 500 barrels per day.
What gives? Does anybody know?
This is a huge discrepancy.
I am not sure of the production from Bakken wells, but from what I understand they produce as well, or better than the Eagle Ford. I do know something about the Eagle Ford. Peak monthly performance is almost always the first months production, or second month depending on the day of the month it is completed. A tier one or good tier two will have peak months production well over 30k barrels, which is over 1000 barrels a day.
Marathon and Continental especially are showing very strong wells in 2018 in the Bakken.
First full month production numbers are regularly above 40,000 bbld oil with a bunch above the 60k mark.
One the other day hit 90,000 barrels oil first month which is, I believe, a Bakken record.
The article is summing across 8,000 wells, not a few monsters drilled in 2018, and claiming that 49% + 18% = 67% are over 1,000 pbd.
I have exactly zero data from any cohort year that gets anywhere close to 1,000 bpd.
As far as I know all of that data comes from DrillingInfo at its source, which means it’s tied to the state coffers. Should be accurate. Something remains off here.
Chris, it is not a 1000 bpd average on a annual basis, but 1000 bpd on peak month. They may start off with a peak of 1000 bpd the first month, but by year end, they may be 200 bpd. So, if you see an annual production of 200k bpd, then that one was probably over a 1000 bpd at peak month, even though annual is closer to 550 bpd. These things have steep declines.
“Chris, it is not a 1000 bpd average on a annual basis, but 1000 bpd on peak month. ”
I get that, and all of my charts I am referring to plot out the daily oil production over time with monthly resolution.
I’d think that I’d have one charts somewhere that would show peak monthly flow rates at or near 1,000 bpd given that supposedly two-thirds of all wells had an IP of over 1,000 bpd.
But all of mine max out at around 350 bpd in the 12015 and earlier cohorts and at around 500 bpd for the 2016+
Again the charts are either plotting cumulative production against monthly production or monthly production over time (in months) with each month being averaged to a “daily production” value.
I’m sticking to this because *if* my charts are off by 100% I really need to know that. A lot of my thinking would change if they were.
Well, I’m pretty confident, as one of my wells was a high tier two and paid me for about a 1000 a month peak production. It’s on my pay stub. I look at about a three county area, regularly to look at IP rates on completions, and first month’s production off the RRC site. I regularly question Platts as to their estimates of the future, but never what they write about existing production. But, if you don’t want to believe them, that’s your choice.
Chris, I am sorry I have not called you back; I have been on a well from hell. Perhaps we can talk about this too.
I know you know this but I would not get caught up in all this data BS and though I have not seen your charts, don’t change anything! IP’s to IP180 days are manipulated at will via completion design, flowback management, etc., all for a host of phony reasons. The manner in which you can alter a well’s performance after frac energy is induced to the rock is remarkable. Unless you need lots of cash flow, which of course those guys all do, first month productivity is meaningless, IMO.
What matters is how soon, and IF those Bakken wells get to 425K-450K BO recovery (payout), and how many of those wells will exceed that sufficiently enough to help payback 95% of the other wells drilled that won’t come close to 450K BO.
I think this Platts article is not very well written and relies too much on numbers. People not in the oil business but analyzing the oil business, even people knowledgeable about oil, rely too much on data and really don’t know what to do with it. All those trees often keep one from seeing the forest. But the point of the article is clear to me: that sweet spots are getting no vacancy signs put on them and as those guys move off into flank areas… costs will go up, and productivity will go down, and down pretty significantly.
Agree. High month production does not tell the true picture. Initial IP rate can be completely deceiving. I have seen IP rates at over 2000 bpd peter out fairly quickly, and I have seen lower IP rates produce long term at a level unexpected. But, I believe for the drilling to be profitable, it needs to pay back capex quickly. To me, that means the first year. And should include the cost of the lease, even though that is not considered to be capex, normally. It is, however, part of the cost of that well. Transportation and discounts are higher in the Bakken, so it needs more production to cover that. I don’t know what the average production rate needs to be at over two years, but assume it is high, and different depending on the producer and what they paid for the land. If you got in early, and paid only about 2000 per acre lease bonus, the add on is only $160k per well at 80 acres. If you paid 30k per acre, tack on more than 2 million you need to get to cover that cost. And there is lease bonus wastage, too. To get that particular area, you had to pay for areas you can’t drill in, for one reason or another.
The first two years of production are the highest, after that, it’s a real crap shoot. But then, the whole thing is a crap shoot, so the better wells need to be much higher to cover the ones that won’t make it. Historically, most of the E&Ps have missed the mark.
I find that many wells are losers for the company that drilled them, and winners for a subsequent company.
Much of this has to do with oil prices during the first years.
Thousands of wells completed from late 2014 to mid 2017 likely won’t ever pay themselves out, but private firms who own them in the future may end up making a good return on investment.
We are operating about 50 wells that were drilled by a company in the early 1980s, that went BK in the late 1980s.
We bought them for what in hindsight was very cheap in the early 2000’s.
Worked for us, but not for them, and they operated the flush production.
$8 oil in 1986 and weak price recovery thereafter, along with debt did them in.
Sound familiar?
Mr. Martenson
The 2/3 of all wells having an IP over 1,000 bbld is an understandable misinterpretation due to the poor phrasing of the authors, IMHO.
Slide #5 of the presentation coupled with a careful rereading of Kringstad’s first bullet point opening the report would show that about 4,000 Bakken Formation wells (out of sbout 8,000), are located within 2,500 Drilling Spacing Units (DSUs) with at least one well having hit the 1,000 bopd threshold – peak month – within each of those DSUs.
Lower increments of 100 bopd are also displayed in addition to the same presentation being made for the 4 benches of the Three Forks formation.
This is essentially a heat map as to where and how much the wells have produced with forward projections of what to expect incorporating variable numbers of future drilling sites.
Coffeeguyzz,
It is evidence of a study that was poorly done.
The proper method would be to take all wells completed in the last 5 years and simply group them by their peak production.
We could also look at all data from 2008 to 2018 at 2 months from first production, which is 12,449 wells:
5% have 1000 bopd or higher output
10% have 800 bopd or higher output
21% have 600 bopd or higher output
39% have 400 bopd or higher output
65% have 200 bopd or higher output
78% have 100 bopd or higher output
average is 419 bopd and median is 363 bopd
From Enno Peter’s site we have the productivity rate distribution under advanced insights.
If we look at 2014 to 2018 at 2 months we find only 8% of wells completed have a peak month above 1000 bopd (of 5848 wells completed in those years)
16% of wells are 800 bopd or higher
29% of wells are 600 bopd or higher
47% of wells are 400 bopd or higher
68% of wells are 200 bopd or higher
average production rate is 480 bopd and median production rate is 421 bopd
All data is at 2 months from first output which is usually the peak production month, so this is a proxy for 30 day IP.
For the average 2014 to 2018 set of wells.
Note that percentages are cumulative so the 68% of wells with output 200 bopd or greater includes the wells 400 bopd or more, etc
For comparison if we look at only the 1475 2017 and 2018 wells completed that have produced for at least 2 months we find:
17% have 1000 bopd or higher output
28% have 800 bopd or higher output
45% have 600 bopd or higher output
61% have 400 bopd or higher output
72% have 200 bopd or higher output
mean is 621 bopd and median is 589 bopd
all data at 2 months to represent peak well output. Data is for North Dakota Bakken/Three Forks.
Hi Chris,
It is not 67%, the 18% is included in the 49%, this still seem too high though. Something does seem off in the data as only about 20% of 2017 and 2018 wells have output over 1000 bopd at 2 months based on Enno Peter’s data.
Chris,
This is a productivity distribution, so some wells have peak monthly production (usually month 2 to 4) of 1500, some are 1000-1500, etc.
This is not the average peak output of all wells in a given year or month.
Ah! Thank you Dennis for the reply above. Not only was the study poorly done, but the write-up was as well in providing the strong impression that half of wells were yielding 1,000 bpd.
The weasel-wording “…located in geology..” should have given it away for me. I read too quickly. That’s like saying that all of the people living near Zuckerberg “are located in a zip code that has a high 9 figure net worth.”
Also why did they pick 8,000 wells rather than the whole lot?
Reading your more careful break down it’s more fair to say that roughly half of all wells had an IP of 400 barrels or more, and that even taking the most recent two years (with sweet spot high-grading and ultra-long laterals, massive sand us, etc) we still find relatively modest IPs (with 45% > 600 bpd).
Better to be sure, but Art’s data says those higher IPs also come with faster decline rates.
At any rate, the good news is that I don’t have to suddenly re-adjust my entire thinking and toss out all the charts I’ve accumulated these past few years.
I’m always on the lookout for the information that will revoke or modify my understanding.
Thanks.
Hi Chris,
You should check out shaleprofile.com, it is very good. That is where I got the data.
What I have seen is that the newer wells do decline more rapidly over the first 24 months and then seem to follow the output path of the older (2008-2014 first production) wells from month 24. It is possible they may fall below this level in the future, but so far for the 2015 to 2018 wells there is no evidence of this.
Also in the Bakken there has been little change in the average length of the laterals, they have been about 10,000 feet since 2008. There has been an increase in the number of frac stages, the pounds of proppant used per well, etc. There has also been high grading by completing tier one wells almost exclusively since late 2015, average new well EUR was about 330 kb from 2008 to 2014 and has increased to 397 kb in 2017, it is too early (not enough data) to estimate the well profile of the average 2018 well, and to be honest the 2017 estimate is pretty rough, I essentially tacked the first 18 month estimate for the 2017 well to the 2016 well profile (2016 EUR is about 363 kb).
For the Permian Basin we have seen the lateral length increase from 2010 to 2017, along with more frac stages per foot of lateral and more proppant used, the increase in the length of lateral clearly will increase average well EUR ceteris paribus, but also will reduce the total number of wells that can be drilled in the play.
In simple terms, if we double the lateral length of the average well, then we halve the total number of potential wells that can be drilled in a given area.
Texas initial production out:
Oil 90,026, 556
Condensate 10,616, 871
Doesn’t look like an increase at first blush
Working with RRC to get my pending data for an estimate.
On Enno Peter’s blog why does it show no new spuds in EF but BakerHughes shows 78 rigs operating, or am I misreading something?
They are always late reporting drilling results to RRC, is all I can think off. They are drilling.
George,
If oil prices remain low you will be correct, at higher oil prices maybe not.
A gradual decrease in new well EUR from 370 kb in 2017 to 198 kb in 2034, with 15,000 wells completed after July 2018, in the scenario shown below where it is assumed that well completion rate decreases due to falling new well EUR. In this case total completed wells (including the 13,000 wells completed through July 2017) remains close to 28,000 wells and the URR through 2040 is slightly lower at 8.8 Gb. Peak output is 1.43 Mb/d in 2020.
Baker Hughes weekly US rig count
Oil -1 to 866
Natural gas 0 to 186
Permian +5 to 488
Cana Woodford -6 to 60
Table: https://pbs.twimg.com/media/Dnoi8WhWsAIQv-Z.jpg
http://phx.corporate-ir.net/phoenix.zhtml?c=79687&p=irol-reportsother
What’s with Canada? A 29 rig drop? That’s over 10%.
That is strange. Canada is seasonal but their low rig count is in the summer. In September they should be building rigs, not dropping them.
Here’s a chart, if that’s any help (chart showing just the rigs reported as drilling for oil)
oil rigs down -13 rigs
gas rigs down -16 rigs
Ok, then it is not strange when you look at oil rigs only. They are almost back to last year’s level. Thanks
https://sputniknews.com/amp/business/201809221068248823-oil-prices-spike-saudi-iran/
Ok, as far as credible sources it is in a low orbit, but I found where Wall Street Journal just posted something similar, but it is behind a pay wall. When this stuff starts happening, Trumps tweets become less effective. What if it is running low, because Trump had SA up their shipments to the US to appease the EIA weekly? Backfire?
And as a repeat to the last post, this indicates SA is increasing capex simply to maintain production.
https://aawsat.com/english/home/article/1393241/aramco-increases-production-offshore-fields?amp
So, “where’s the beef”? Answer, wasta. Toto just pulled back the curtain?
SA’s eventual statement will be that, yes, we have 2.5 million in excess capacity, but it will take a while to develop. Then that will turn into we need it to maintain production. Gasp! There is no OZ! But, not before elections.
More likely a gradual unfolding of the truth. Gimme a break, Iraq is falling apart and getting no new capex:
http://www.arabnews.com/node/1372831
Meanwhile the dazed and confused try to cover the meetings of the great and mighty OZ.
https://www.bloomberg.com/news/articles/2018-09-21/bulls-gain-conviction-in-oil-rally-as-opec-ministers-gather
No doubt, they will somehow claim another 500k barrels a day are somehow imminent, but they haven’t even met the first million, yet. My favorite comment out of this is that the US, Russia, and SA have the ability to offset these losses. Well, maybe, but well after a year and a half. And the US will play heck trying to convert LTO to Arab Light.
Fairly soon, prices will rise, and we will begin to witness, first hand, which destruction has the most impact on oil prices? Demand destruction, or supply destruction?
You are right seems there is some meat in this rumor, may other sources are covering this:
https://twitter.com/steve_sedgwick/status/1043798432358576128/photo/1
And more:
https://www.bloombergquint.com/opinion/2018/09/23/opec-like-a-dying-star-is-about-to-go-supernova
https://www.aljazeera.com/programmes/insidestory/2018/09/opec-appease-donald-trump-180922175718803.html
https://www.youtube.com/watch?v=NKxa9XpT9h8
Russia has peaked! Or at least that’s what one Russian who should know says.
Thanks for the links Eduard. Your third link: Will OPEC appease Donald Trump?, is very interesting. There is an Al Jazerra video here where three oil experts discuss whether or not OPEC will, or will not increase production to please the Donald. The general consensus is they will not.
One member of the panel, Mikhail Krutihin, Partner, RusEnergy Consulting Firm, Former Editor-in-Chief, The Russian Energy Newspaper, Former Editor, Russian Petroleum Investor Magazine, said Russia is at peak oil production right now and the decline in production will start next year. He said the decline will be caused by the deterioration of oil reserves. He said 70 percent of the oil remaining in Russia is very difficult to recover. He said that it is difficult to recover that oil at current prices. He also said that Russia will not increase oil production to please OPEC or Donald Trump. And he said, again, that Russian oil production will not increase but will decrease.
His segment begins at 6:50 into the video.
I noticed that too he actually said that. And his remark fits perfectly with the Russian production chart.
Even the Energy Minister is avoiding to talk about spare capacity talks about couple of thousands barrel instead, and aging fields:
https://www.bloomberg.com/news/videos/2018-09-24/russia-s-energy-minister-on-spare-capacity-video
Saudis are trying to suggest that they have problems too, talking like ‘we are looking at more important aspects such as adequacy of supply’. And then to not let any misunderstanding he adds: ““The markets are adequately supplied.”. They rarely do that, they are pretty cocky about their production, and letting doubts on their “spare capacity” was usually out of the question.
https://www.cnbc.com/2018/09/23/saudi-oil-minister-rejects-trump-claim-that-opec-is-raising-oil-prices.html
So all the eyes are on US, which means all the eyes are on Permian.
I am sure we are headed to some type of economic slowdown, and fairly soon. Yeah, oil prices can affect the economy, but not as much as the tariffs will. They are a pass through tax to the US consumer. Higher oil prices will hurt, so will the average consumer having to pay 15 to 25% more, every time they visit Walmart. Trump can’t be held responsible for higher oil prices, but he can for tariffs.
Andddd again. The deficit for FY2019 is going to be $1 trillion with a T. Economic slowdown is . . . one supposes, flat or negative GDP. $1T is getting injected into the economy from non capitalism next year. That’s 4.8% of $20.2T GDP. To go flat or negative you gotta lose that 4.8% and more. That would take something like an earthquake wiping out Seattle and San Francisco both entirely.
I say entirely because the broken window aspect of Keynes stuff would generate big GDP for repair expenses, and yes, that would be another $1T spent from the government (who would borrow it, probably from the Fed, to spend it).
So it’s really popular for folks to be calling for downturns right now, mostly because some number of years has passed. But the mechanism is hard to see with $1T deficits, and oil prices . . . hell, they just stimulate oil industry business offsetting any consumer recalibration (and let’s keep in mind spending on gasoline is itself consumer spending — if gasoline is all they can spend on, so what? They still spend the same amount into the “economy”)
The economy is overheated and needs new taxes to slow it down. It’s pretty nuts that the Republicans trashed public finances with their tax cut at this stage of the business cycle.
Lotsa talk above about Bakken. Have always frowned a bit at the perpetual counting of barrels without looking inside.
Small heads up —
Equinor has a new Bakken assay out dated Aug 2017 and quotes API 43.3. Remember when Lynn Helms told us the API was equal to WTI at 39?
Suspiciously, just months later Statoil quoted a new Bakken assay as 42.9. Their sulphur quote is 0.17%, up some from previous.
And so, as before, these assays are from a sample. Not all the geology is going to have the same API measurement for its liquid. About 6 yrs ago there was a lot of talk that refineries were objecting strongly to Bakken liquids because from train car to train car they could not maintain their same refining . . . settings.
Regardless of if they solved this, it means not all the liquid in those barrels is crude. API 43 is just too close to the 45 condensate threshold. The quoted barrel count is simply not legit. If you call it a flow of crude + condensate, then it’s legit. That’s not what we’re getting quoted.
It would be useful to know what % of flow is going north as diluent and what % is getting refined.
https://www.oilandgasinvestor.com/texas-oil-pipeline-start-november-easing-bottleneck-1716521
Nov 1, 2018 is when the Permian will increase oil pipeline capacity. Should be at 360k more by the first quarter of 2019. Last gasp until very late next year when production can go up 2 million more, or maybe not.
https://www.mrt.com/business/oil/amp/Permian-pipeline-constraints-could-delay-1-4-13195019.php
OPEC’s World Oil Outlook (2018) released today
https://woo.opec.org/
Canada https://woo.opec.org/chapter.html?chapterNr=4&chartID=103
Yeah. Seriously doubt it will look anything like this. Global demand up over 4 mbpd by 2023 is the first giveaway. Which will come from….???
On another note, maybe Dennis can post Dean’s new estimate for Texas. I am having some delays with RRC on getting the pending file, but his changes have been in line with EIA, and my data. He shows about a 75k drop for July, which looks reasonable based on initial data. I doubt the pending file is increasing much, as it didn’t in June. Most of the increase in oil production seems to be coming from Washington DC, and not the Permian.
Dean has tweeted his Texas RRC C+C chart: https://pbs.twimg.com/media/Dny2F9lXoAAV5T0.png
Thanks, EN
Argus article on OPEC’s WOO 2018 (free)
2018-09-23 (Argus Media) Growth in global oil demand over the next five years will be more than offset by rising non-Opec production, particularly from the US, Opec said in its latest World Oil Outlook (WOO) today.
Demand will grow by an annual 1.2mn b/d to reach an average 104.5mn b/d in 2023, with demand growing fastest from India.
https://www2.argusmedia.com/en/news/1759382-nonopec-to-more-than-sate-demand-growth-by-2023-opec?backToResults=true
Lol, that is funny!!! There is no limit to their imagination. US will increase by 5.6 million barrels a day by 2013. Looks like we are slightly under their projection, Dennis. Texas Department of Transportation better get humping, and then there is new railways, and whatnot.
They just can’t seem to grasp decline rates. The first year declines are the worst, but when you add in previous years declines, a recent estimate in June was that 95% of current wells were to maintain production.
Guym,
Keep in mind that OPEC is talking total liquids, US NGL has been rising along with C+C, though in the past 18 months the trailing 12 month output of NGPL has only been 129 kb/d or 7 kb/d each month, so not that significant, US output might increase by 3.5 Mb/d for total liquids by 2022. Perhaps there will more NGL from elsewhere as Natural Gas output continues to increase.
I think if we focused on C+C demand increase and the fact that over the 1982 to 2017 period this has averaged about an 800 kb/d increase each year, that we would get better estimates. In addition, if output is short of consumption, inventory will continue to fall and eventually oil prices will rise as the tanks get 10 or 20% below the 5 year average stock level. Then after some period of lag (one to two years) people start to adjust their consumption of oil products to lower levels (by driving less, car pooling more, buying more efficient vehicles etc.) Also there might be an economic recession which tends to reduce consumption (though when that occurs is difficult to predict in advance.)
Lol, whether liquids or crude, it is still too high. It is interesting to note their projection for just crude. OPEC will peak in 2020, while non-OPEC peaks in 2023. So, their peak oil projection is 2023. Same as yours. I’m still saying 2018, but the difference is not significant, now. Peak oil will forever be one step ahead of peak demand.
Guym,
For tight oil they predict an increase of 4.3 Mb/d from 2017 to 2023, with 1.3 Mb/d from NGL.
For non-OPEC crude the peak is 2025 according to WOO 2018 with a 5.5 Mb/d increase from 2017 to 2025, or a 687 kb/d increase on average each year.
Interesting on their crude long term forecast they have a plateau at 80 Mb/d from 2025 to 2040 (slight increase of 1200 kb/d over a 15 year period or only 80 kb/d increase each year.
The World liquids output increase comes from NGL, processing gains, biofuels and other liquids (GTL and CTL maybe). Of the 5.7 Mb/d increase in total liquids, 3.8 Mb/d is from biofuels and NGL. In terms of boe this would only be 2.9 Mboe/d so the real increase in energy terms is about 4.3 Mboe/d when processing gains are deducted (those are a change in volume not a change in energy content), so over 15 years the average increase in liquids supply is 287 kboe/d. Liquids supply will be relatively limited if demand grows at historical levels (800 kb/d from 1982 to 2017). Crude oil output will be fairly flat from 2025 to 2040 at about 80+/-1 Mb/d. Seems they leave condensate out, possibly just for OPEC.
I looked at WOO and compared to EIA data, the “crude” in the WOO does not include condensate (about 6.5 Mb/d in 2017 if the OPEC estimate and EIA estimate is accurate.)
So if one assumes condensate output remains at 6.5 Mb/d until 2040, then C+C output would be about 87 Mb/d in 2040 and be roughly 86 to 87 Mb/d from 2025 to 2040. The flat condensate output estimate is just a WAG because OPEC does not break it out that way, but if my guess of a tight oil peak in 2025 is right and a lot of condensate comes from tight oil and shale gas, then we might expect a peak in condensate output in 2025 and a decline thereafter. So a more realistic scenario might be a rise in condensate from 6.5 to 7.5 Mb/d from 2017 to 2025 and then a decrease at a similar rate over the next 15 years perhaps to 5.5 Mb/d in 2040. In that scenario, the peak in C+C output would be around 2025 at roughly 87 Mb/d, based on the WOO 2018 and my assumptions about condensate output.
I think the real message is that OPEC won’t br able to meet rising demand so stop asking us.
OPEC meeting: https://www.reuters.com/article/us-oil-opec/opec-russia-rebuff-trumps-call-for-immediate-boost-to-oil-output-idUSKCN1M30DK?il=0
I interpret the outcome as all members (perhaps excluding SA) pump more or less flat out. The cartel will not make any immediate additional increase but some of the spokespersons say “they needed to focus on reaching 100 percent compliance with production cuts agreed in June” (i.e. increase output).
(posted in the wrong thread)
Of course, they are using EIA’s lousy projection for US oil output against Trump. They are not planning on increasing output (as if they could), because the US will be increasing output by 2.4 million barrels. Iran is softened its stance, because SA stood up to Trump. Of course, the US will be about 2 million short of that projection, raising oil prices, which SA would be very happy with.
Saudi Arabia said that they’re meeting customer demand
2018-09-23 Algiers (Platts) Saudi Arabia intends to raise crude production in the coming months to meet mounting customer demand, energy minister Khalid al-Falih said Sunday,
September output from the kingdom is already higher than August’s level of about 10.4 million b/d, Falih said at a meeting of an OPEC/non-OPEC monitoring committee, though he did not provide a specific figure.
“October will be even higher,” he told reporters. But he stressed that Saudi Arabia’s production levels were dictated by customer demand, not to influence prices.
“We have seen higher demand in October,” Falih said.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092318-saudi-arabia-plans-q4-output-boost-to-meet-mounting-demand-oil-minister
OPEC dismisses Trump demand for higher oil production
Saudi Arabia, the leader of OPEC, said Sunday that it will not increase crude oil output anytime soon, pushing back against President Trump’s calls for greater supply.
“The markets are adequately supplied,” Saudi Energy Minister Khalid al-Falih said, according to Reuters. “I don’t know of any refiner in the world who is looking for oil and is not able to get it.”
He added that Saudi Arabia could theoretically raise its output by as much as 1.5 million barrels per day.
Russia, Saudi Arabia’s largest oil-producing ally outside OPEC, agreed that it would not immediately increase its output either, the news outlet reported.
Falih added, “I do not influence prices.”
President Trump said last Thursday that OPEC should bring down oil prices, suggesting that the U.S.’s military assistance may be contingent on their cooperation.
Trump’s tweet:
Donald J. Trump
✔
@realDonaldTrump
We protect the countries of the Middle East, they would not be safe for very long without us, and yet they continue to push for higher and higher oil prices! We will remember. The OPEC monopoly must get prices down now!
And they, in turn, denominate sales in dollars, and buy US debt. He is a loose cannon. So loose, it could go anywhere. Russia has already sold most of their US debt. Next, will be China and SA.
China Cuts U.S. Treasury Holdings as Trade War Intensifies
https://www.bloomberg.com/news/articles/2018-09-18/china-cuts-u-s-treasury-holdings-as-trade-war-starts-heating-up
Pretty subtle changes in message: extra capacity is now ‘theoretical’, no guarantee of meeting future demand, a step back from their position of not influencing prices, which is kind of the whole point of OPEC.
Brent is +$80 and going up fast at the moment so I think the traders are inferring the same messages.
The markets are adequately supplied, as Saudi Energy Minister says, but through a reduction in stored oil and diminishing spare capacity. That’s why the price of oil is pushing up. The lack of investments since the 2014 oil price crash guarantees that an increasing demand will not be met for several years.
Only two possible outcomes:
– An oil price shock that is almost guaranteed to trigger a new global crisis.
– A reduction in the demand growth that can only happen if several countries go into recession or stagnation. This could actually reduce oil price if big enough.
In both cases oil production will not increase by much. That’s the problem with Peak Oil. Whatever happens production doesn’t go up.
So far we are seeing signs of both. Oil storage and spare capacity are going down, and the flow of money in the global markets is reverting, leaving some countries like Turkey and Argentina high and dry.
Aren’t most countries other than USA looking a bit sad anyway? USA has boosted the stock market with tax cuts that have to some extent been recycled to stock buybacks and other ways to boost share price (rich get richer and poor get poorer). But a lot of other OECD countries and emerging markets are having growth figures revised downward.
Yeah, this is the whole storage thing. If you’re KSA and you have oil stored in the porous rock underground, why do you want to pump it up and put it in a tank on the surface? It’s already stored. Can you get a flow rate from a tank that is faster than the flow rates from the entire field? Can’t. Physically impossible. It would average out to exactly the flow rate into the tank, which is part of the flow rate from the field.
He’s right and you do realize he’s saying “supply and demand does not define the price of oil.” He has supplied all the requests by refiners. Why would the price move?
Central Banks can intervene to hold price of oil down if they so choose. Hell the FED admitted to having a massive VOL short not too long ago. Who’s to say they don’t short CL futures to keep a lid on oil price. We don’t have honest markets where true price discovery is allowed.
What we have is the illusion of free markets. That’s why forecasting price is so tricky. Don’t just assume prices will go up due to a lack of supply anymore. Price will be allowed to rise right up until the point where they feel it’s necessary to intervene.
Since 2008 all stock markets started to behave differently. Fundamentals went out the window it is now all about perception. Failing companies can see extraordinary rises in stock price if a bail out is presumed.
I guess you have no idea of the sheer size of the oil markets. Central banks and certain governments have the capacity to influence them by manipulating confidence, but if they decided to intervene them to hold the price the risk would be unacceptable.
Already Soros demonstrated that by taking the mighty British Pound out of the European Exchange Rate Mechanism in 1992. You might have not learned that lesson but central banks sure did.
Markets are angry beasts and it is not wise to poke them. If a stampede starts in the wrong direction there will be hell to pay.
Watcher, it’s sometimes quite entertaining but boy do you talk some uninformed rubbish.
Yeah. Tell me something — when you go to the store and want to buy something from a shelf, and the shelf has a price on it for the item — does that price change depending how many of the item is on that shelf?
2L bottle of pepsi is $1.78 at Walmart. It’s $1.78 if there are 5 bottles there or 1 bottle. It’s even $1.78 if the shelf is empty. Your demand didn’t change. Supply did. No price change.
I will venture to suggest, without data, but odds seem good, that throughout history the price of goods obtained in all transactions that have ever taken place . . . the vast majority of those transactions had a price not determined by supply and demand.
This would be the price of land a father offers to a son. It would be priced according to almost anything other than supply and demand. Might be free. So we could toss inheritance into the quantities of transactions.
It would be the price of every item ever acquired by conquest (which probably makes the case quantitatively in an overwhelmingly compelling manner without any other examples).
It would be the price of money itself, prevailing interest rates, set by Central Banks, with no interest at all in supply or demand. In fact, that item also quantitatively makes the case entirely.
Every government decree of price . . . all those transactions took place with no interest in supply and demand.
Why would you think supply and demand in some tiny minority of transactions happens to apply to oil? Why would oil be in that tiny minority?
I was talking about your knowledge, or lack thereof, concerning how oil companies work on a practical level. If you don’t know something you just seem to make up whatever explanation fits your set worldview. The “without data” comment is rather telling in the above though.
So you think purchase of literally trillions of MBS with no competitive pricing is a magnitude not reasonably larger than other transactions of history, and when added to acquisitions via conquest and inheritance, the absence of exact data suggests to you the whole of the matter is manufactured?
Come now, you know this is all very credible. You just don’t like what it means.
I don’t think any of that, not my field, just like API gravity, condensate definition, refining and operation of storage facilities obviously isn’t yours, but you don’t seem to let that be a hindrance.
George
Saw this today. West of Shetland is starting ro show a bit of promise.
https://www.londonstockexchange.com/exchange/news/market-news/market-news-detail/TTA/13801465.html
I don’t have access there but I assume it’s about the Total gas find. Total need the gas to fill Shetland Gas plant because the Laggan Tormore fields have not produced as planned.
But more importantly, and dunno if asked before, but does anyone have any idea what the standard deviation is of API degrees for oil from different locations of a typical field?
As noted above, assays are showing API 43 ish for Bakken liquid. But those are from some sample. No reason to think the sample is high, low or at the mean of all API densities for all locations of a field.
And with condensate starting by definition (which has some attempts to redefine floating about) at 45, odds would seem pretty high that a standard deviation of just, say, 3, would define 30some% of the liquids from the Bakken as condensate and not crude. And if the sigma is even higher, then we have an explanation for the complaints by refiners years ago that the oil cars . . . car to car . . . had huge changes that forced them to change their refining procedures too often.
The overall point being, quoted production of liquids as crude may be pretty shaky. Why not include water?
Can’t produce what you don’t have. People are starting to figure out there is no 1M + bpd that can just be brought online when Iran gets sanctioned.
https://www.cnbc.com/2018/09/24/oil-markets-us-crude-inventories-looming-us-sanctions-on-iran-in-focus.html
Ok, I think we are already firmly past stage one of the oil price rise. I said it would take the realization that OPEC can’t cover shortages by themselves, first, before they actually looked at the limitations of shale within the next year. EIA is reporting weekly production of the US at 11 million a day, which is about 300k over actual, probably. June monthlies by the EIA were at about 10.7, and Dean estimates a drop of 75k per Texas production which I should be able to confirm sometime today. The US will likely average production in the US at 10.55, rather than the 10.8 they are still hanging on to. With only 360k of new pipeline from now until the end of 2019, or first of 2020, the 11 million won’t be realized until that 360k is actually working. So, the average production in 2019 is going to be closer to 11.1 than EIA’s 11.7. There is one caveat to that, and that is if WTI gets much over $100 a barrel, there’s no telling what will happen, but even then 11.7 average is not probable.
Restated, OPEC plus non-OPEC can not cover current shortages by a long shot. And by OPEC continuing to use EIA’s uncorrected version of US oil production, they are telegraphing that the finger will be eventually pointed at the EIA when prices skyrocket.
It’s going to get interesting that’s or sure. I think about .3 increase in that 11.7 comes from an increase in the GoM and it’s more likely to be about -0.1 to 0.2, have you allowed for that?
Yeah, I am figuring zero for GOM as far as increase. An annual average estimate could have some variation depending on a lot of things. I’m just saying it will be closer to 11.1 than 11.7. An oil price spike could lead to more production in other shales than the Permian, but they are unlikely to increase a lot the first half, because it takes some time to get there.
Completion crews will still have plenty of work to do in 2019 in keeping the Permian maintained and in other shales.
North Dakota increase may offset some of the drop in Texas, other shale plays in Oklahoma, Colorado and Wyoming might also see increases so perhaps US output will be flat or at least L48 onshore, not sure about what to expect from GOM and Alaska, I think there’s usually summer maintenance in Alaska, not sure if GOM has been hit by any significant storms this summer.
Well, note I projected a 153k drop in Texas below, although that does not mean that’s what EIA will estimate. If so, it will be difficult to offset.
North Dakota output increased by 42 kb/d in July, so that drops it to 111 kb/d, if combined Oklahoma, Colorado, Wyoming, and New Mexico output also increased in July by 40 kb/d, the decrease would be reduced to 71 kb/d. Also note that the EIA estimates that US tight oil output increased by 131 kb/d in July, though that could be offset by decreases in conventional output, Alaskan output and GOM output.
Alaskan North Slope output dropped by about 60 kb/d in July, so if output elsewhere was flat that would be about a 70 kb/d increase in US C+C output. Not sure about GOM or US onshore conventional.
Guym,
EIA has US Tight Oil Output increasing see
https://www.eia.gov/energyexplained/data/U.S.%20tight%20oil%20production.xlsx
Chart below uses data from link above. The linear trend from Dec 2016 to August 2018 has a slope of 1279 kb/d (average annual rate of increase in US tight oil output over that 21 month period).
https://www.bloomberg.com/amp/news/articles/2018-09-24/major-traders-see-return-of-100-oil-due-to-u-s-iran-sanctions
I think it is interesting to note the contrarian view, that a spike will precipitate a decrease in demand like in 2008. I mean, really, oil price was not the only factor that contributed to a decrease in demand, then. Remember? And a decrease in demand has not had any record of decreasing 2 million barrels vs an increase. Or, do they figure that US shale will continue to increase at a $50 oil price??? Reality disconnect.
Ok, I may have missed it, but do you have the “most of the world” inventory drops from last week, Energy News?
Another interesting tidbit I picked up from the OPEC meeting, was that SA maintains it has been increasing their inventory, but it is stored in the locations you pick up on world inventory.
Inventories, sum of available weekly data, to Sept 14th
https://pbs.twimg.com/media/DnmC_j4UYAEgj6e.jpg
Which, as of fairly recently, includes a signicant portion of SA inventories, according to SA after their meeting. Thank you.
They have moved from months of shipping time to a more closer to just in time inventory method. Which may account for much in the spike in July.
Where is Tweety Bird? Oil is over $80 now! Really, he can quit sweating it. With gasoline inventories this high, gas cant rise that much before Nov. 6.
https://oilprice.com/Energy/Oil-Prices/JP-Morgan-Expect-Brent-Oil-To-Reach-90-On-Iran-Sanctions.html
Slowly, price projections move up.
How much if Iran manages to blow something up in the Straits of Hormuz?
I dunno, I would hope they would take a longer view of the whole mess, and come to the conclusion that it can’t last like this. But, then, you don’t know how much this whole fiasco affects local dissension.
Ok, I received the pending data file, and we are down. Reviewing June data, EIA was probably too high at 4410 for June. I had 4364, and second month’s total is 4344, which is the closest to actual, in my opinion. That is 66k less than EIA’s estimate.
For July I project 4257, which is 153k bpd less than EIA’s June estimate. As far as change goes and totals, Dean’s and mine are pretty close, within a thousand barrels.
I think what we are seeing is shut ins with small producer wells, that would probably not be covered in drilling info, nor ultimately in EIA estimates. Production is likely to fluctuate up and down, but won’t get much higher until after maybe December, when the results of the new pipeline expansion is felt. Drillinginfo and EIA are counting new production and assuming production from existing wells, and some of those are being shut in, and wouldn’t be included in the 914 reports.
I expect GOM to be up a bit, but will be offset by a smaller Alaska production. For July, I expect US total to be 10.500 to 10.550 million bpd. Weeklies over 450k to 500k for July. Next four months could fluctuate 150k.
Traders will eventually notice, but it will take some time.
https://oilprice.com/Energy/Oil-Prices/100-Oil-Is-A-Distinct-Possibility.html
Bank of America sees oil in the $95 range first quarter of 2019. But, they also see US oil production increasing 1.4 million in 2018, and 1 million in 2019. The US will be lucky to make half that prediction. How does that affect that $95 price prediction? You see how the EIA is affecting all these predictions. The keep believing the EIA that the Permian is continuing to increase, and will regardless of pipeline constraints. I have to believe that EIA knows what reality is now, and I am baffled by the continuing facade. Or, maybe I’ve gone off the deep end?
Many here like to make fun of Watcher.
So a little more than two years ago, traders took WTI below $30 and some said $10 and one said WTI would never be above $44 in his lifetime.
Now many are frantically calling for $100, $120 or higher.
Yes, the price of oil all has to do with supply and demand. Lol.
I have been following the oil price daily since 1997. Traders and their hype are the number one driver IMO.
And they aren’t even moving oil barrels, either. 90% of trading is paper, and not even oil. It’s just plain gambling. Gotta be frustrating to someone like you that’s in the business. They are more interested in indentifying whether prices are in an inverted doji, or whatnot. Fundamentals to them is what a bank or EIA is saying. For four years they have destroyed most investment in it, because they had their own interpretation of a fair oil price. It’s not even a full time vocation for them. It’s only one of their commodities. They spend a half hour on oil, and then turn to cotton, or hogs.
If traders set the price why has OPEC existed for so long. Why did the price crash after the 2008 financial crisis and then recover when SA cut production. Why did that cut then cause a boom that led to overproduction, record high inventories and another price crash which recovered partly because of another OPEC cut? Traders make money on daily noise, they’d all go bust if they went against the trend (I think one big one did before the recen crash when he bet big on permanent high prices).
My comments are somewhat sarcastic. But only somewhat.
The problem IMO is that the traders and all the paper barrels are greatly exaggerating the price movements.
One thing we don’t pay enough attention to is the effect the dollar’s value has on oil.
QE was a big factor in oil’s run after 2008 crash.
Would QE be considered supply/demand?
I just think it’s crazy to see traders hollering $100 plus, when two years ago it was lower forever.
Shallow sand,
It’s just oil market observers realizing they were wrong about how much tight oil can be produced and also not foreseeing the demise of Venezuelan output and the effect that lack of investment would have on future production, they also didn’t expect more sanctions on Iran.
Predicting the future is not an easy task. Though many of us expected that eventually oil prices would rise.
My current guess at future centered average 12 month Brent Oil prices in 2017$, 3 scenarios low has max price at $80/bo, med at
$113.4/bo, high at $146.7/bo all in 2017 constant US dollars.
Shallow sand,
In the short term, traders drive the price of oil, in the long term, it is supply and demand.
We cannot consume oil that is not produced, when there is a desire and the money behind that desire to consume more oil than is being produced at the current price level, oil prices will rise, it really is that simple in the long run.
Imagine for a moment a World where oil inventory was simply the amount needed to fill pipelines (essentially very close to zero).
Traders would be out of the loop. In the long run inventory is at some average level needed to make the system function and traders don’t mean squat.
The Short term stuff is just noise, unfortunately it kills small producers’ bottom line.
It is the reason the Texas Oil producers supported RRC production controls for so many years, it reduced volatility until Texas was no longer the swing producer. The Saudis and OPEC took over the reigns in 1975, but haven’t been doing a great job.
It might be better if a new OPPC (Organization of Petroleum Producing Countries) was formed with all major oil producing nations joining (US, Russia, KSA, and the next 17 largest C+C producers) and they set quotas for all major producing nations to attempt to match supply and demand and reduce oil price volatility.
Never gonna happen though.
Ok, but you have to admit when you put the WTI price, with worldwide demand and worldwide consumption on a graph, it looks pretty crazy.
Demand and supply keep churning up every year by 1-1.5 million BOPD. Not many exceptions to this.
The price action has been wild. Overall, we have benefitted, we used to think $30 was awesome. Now it will BK us.
I still contend much of the price swoon 2015-17 was overreaction to shale. Traders bought the BS that shale is “cheap to produce.”
Shale companies spewed a lot of BS. If it wasn’t for Elon Musk, I think they would win this decades corporate Pinocchio award when it comes to exaggerating fincancial success.
Shallow sand,
Agreed the short term price movements have indeed been wild. Note that an economist considers demand and consumption to be the same thing, it is the quantity of product that is purchased, for oil we usually think of this in barrels or tonnes (mass is really the better measure as it takes account of heavy and light barrels a little better and gives a more realistic estimate of the energy content of the oil produced).
On the increase in consumption consider the following chart.
I used data from the page below for World C+C Output from the EIA.
https://www.eia.gov/totalenergy/data/monthly/
Chart has monthly data from July 1982 to May 2018, the slope of the line is 800 which means on average each year there has been an 800kbopd annual increase in World C+C output over the past 36 years.
This increase is quite a bit lower than the 1200 kb/d often mentioned which might be total liquids increased output in recent years. The total liquids overstates energy output because much of it is processing gains (which is just a volume increase with no increase in energy in the product) and ethanol and NGL which have about 75% of the energy per barrel of the average C+C barrel.
The crude plus condensate is what is really needed for transportation which is the main component of oil demand, so the number to focus on is 800 kb/d, in my view.
Dennis, I was shocked at your chart. I thought, “that can’t be right”. I was used to looking at charts with a shorter time span. So I made one of my own. And yes, that’s exactly what it looked like.
But, I would bet my last dollar that this 800 kbd yearly increase will not continue. I now more convinced than ever that 2019 will be the peak. And if I had to guess where the 12 months average high would be, I would guess July 2018 through June 2019.
See my post above “Russia Has Peaked”. That is not my assessment but one Russian’s opinion, an expert in Russian oil production who would know. Also, I think OPEC has peaked, or nearly so. The only major producers who have not peaked, or nearly so, is the USA and Canada.
And you are correct, the price will rise. Unless of course, we have a really major recession, which is also possible. But if the world economy stays healthy the price will definitely be above $100 soon.
Hi Ron,
I do not expect it will continue beyond 2023 or so. Tight oil output in the US will likely peak around that time and output will either flatline or increase more slowly (100-200 kb/d per year) for a couple of years (maybe to 2025-2027), then there will be similar decline for a couple of years, then a gradually increasing decline rate to about 2% annual decline each year by 2040 or so.
I agree a recession will stop the rise in oil prices and might occur at any time, especially with trade wars disrupting the World economy. Seems Trump has never read any history in his lifetime.
Russia may have peaked, but at high oil prices we might see more output from some OPEC nations along with increased Canadian, US, and perhaps Brazilian output.
If you are correct that 2018 to 2019 is the peak, I expect that a plateau could be maintained (absent a recession) for 5 to 10 years, but my best guess is an increase in World output until 2023, plateau until 2027 and then decline (though there might be a 12 month centered average peak anywhere in the 2023 to 2027 period in my view).
I think you are just being overly conservative. The US and Canada might continue to increase production until 2023 but the rest of the world definitely will not. And the decline in the rest of the world will more than offset the increase in North America.
Brazil? I will post a comment on Brazil in a short time.
Why Canada? Fort Hills is pretty much finished, Hebron is still ramping up but it will hardly compensate for the decline in the rest of Atlantic Canada. There’s a bit from Christian Lake and a couple of other small SAGD projects but less than 100 kbpd total.
Hey, I think you may be correct. But the general consensus of opinion is that Canada still has a way to go before the peak. I was just hesitant go go against the general consensus of opinion.
Hi Ron,
The question becomes will the decreases in the World minus US and Canada be more than the increases in US and Canada.
We simply have different estimates of the future, in part because we have different estimates of World URR. I think there will be continued reserve growth as oil prices rise (and no I don’t think this will continue forever, it will gradually decrease to zero from now until 2050 or so). My estimate of World URR for C+C is about 3075 Gb (including 215 Gb of extra heavy oil and 60 Gb of LTO), not sure you have ever given an estimate of URR, but note that Jean Laherrere’s August 2018 URR estimate was about 2815 Gb of C+C, he also has a higher 3015 Gb estimate and historically his estimates have always tended to increase over time, especially for C+C less extra heavy oil. (2200 Gb to 2600 Gb over the last 6 years or so).
Hi George Kaplan,
Have you read CAPP’s forecast?
https://www.capp.ca/publications-and-statistics/crude-oil-forecast
In a nutshell, a 1.4 Mb/d increase is forecast from 2017 to 2035 and a 1 Mb/d increase from 2017 to 2025..
It looks like there was a reduction in Saudi Arabia production some months of 2008 and 2009, for what one would think is an obvious reason — there was a presumed disappearance of consumption on the part of their customers.
The graphs say something like 2 million bpd kept underground in the absence of orders from customers for just a few weeks or months, who themselves were watching the carnage on Wall Street and presumed that THEIR customers were going to disappear.
A conversation here recently noted that actual consumption of oil in that time frame declined very little, but it was also noted that global GDP itself declined very little. It was the most apocalyptic financial event in the history of mankind, but it did not translate to economic activity erasure at anywhere near that magnitude.
So fairly quickly the refiners discovered their customers had not disappeared and they placed orders with the Saudis, who filled them.
What moved the price on that occasion? Money disappeared. Meaning it stayed in the pockets of people who otherwise would have been at the NYMEX, trading. After a few weeks it became clear that the Fed was going to save civilization, and with civilization saved the traders came back to work.
As for why OPEC existed so long — why has the FAO of the UN? Or the GECF? Obviously they don’t try to define price. Or if they did, they’re failing.
BTW Shallow, since I discovered Qatar’s SWF owns 10% of Rosneft, I also discovered they own a big chunk of the London Stock Exchange. Might be a good idea to find out who owns NYMEX. The SWFs of the world are taking ownership of more and more equity in all sorts of different things. In total they appear to own 25% of all of the common stock shares of every company on the planet Earth.
No reason why, as they take control of things like the London Stock Exchange they can’t also take control of prices. We’re talking about 10 guys — 10 asset managers from the largest SWFs. They are becoming the “market”.
CME Group owns NYMEX and that’s a duh.
CME Group’s primary shareholders list is a bit surprising, but no indication of SWFs having an influential role. The dominant holders are index ETFs fromVanguard and whoever . . . but that’s really surprising in that Vanguard’s Total Market ETF seems to own over 1%. How can that be? CME isn’t that much of the total stock market so how could even 1% be the right amount.
But anyway, unless SWFs have swaying positions among the firms running those ETFs, then they aren’t controlling prices. The next layer of investigation would be CME management.
A look at August’s crude oil production numbers. The official numbers released so far.
The total is up +265 kb/day month/month. But still down -136 kb/day from the average in 2017
https://pbs.twimg.com/media/Dn7ldBoW0AAh50w.jpg
Columbia – Ministerio de Minas y Agencia Nacional de Hidrocarburos
https://pbs.twimg.com/media/Dn7mkrdX0AEk_oD.jpg
Petroleos Mexicanos crude & condensates production
August 2018 1,816 kb/day
2017 avergage 1,949 kb/day
https://pbs.twimg.com/media/Dn7lwTYXoAUrIWA.jpg
Mexico looks like some big acceleration in nitrogen breakthrough the last two months so decline rate could be accelerating.
Energy News,
Average US tight oil output for the first 8 months of 2018 is 1097 kb/d higher than the 2017 average tight oil output.
See
https://www.eia.gov/energyexplained/data/U.S.%20tight%20oil%20production.xlsx
Energy News,
Actually I think you were comparing Aug 2018 output to the 2017 average in your comment above, for US tight oil that comparison would be an increase of 1452 kb/d in Aug 2018 compared to average 2017 US tight oil output. So combining US tight oil output with your data from several countries we would have a C+C increase of 1316 kb/d in August 2018 compared to average 2017 output.
2018-09-25 Brazil, Petrobras August output decreased compared to the previous month, the reduction was mainly due to the concentration of scheduled stoppages for maintenance
Chart: https://pbs.twimg.com/media/Dn8fy22VAAAm1mr.jpg
Petrobras news release: http://www.investidorpetrobras.com.br/en/press-releases/oil-and-natural-gas-production-august-1
Norwegian Petroleum Directorate, crude oil & condensate production
August 2018: 1,532 kb/day down -23 from July
Down -86 from average 2017: 1,618
The rig count is a 3 month moving average (yellow line)
Chart: https://pbs.twimg.com/media/Dn8i0MSW0AA7D59.jpg
There was a lot of maintenance in August in the North Sea (Rystad Energy), chart: https://pbs.twimg.com/media/DmLJ8UEX4AAzOmK.jpg
Sept –> 2018-09-18 (Bloomberg) Norway: Goliat Gas Leak Leads to Evacuation of 502 People
Energy News,
Brazil down about 20 kb/d from 2017 Average, Norway -86 kb/d for a total of -106 kb/d, added to your other chart gives -242 kb/d, then adding the US tight oil increase of 1452 kb/d in August relative to the 2017 average, we have a 1210 kb/d increase in output compared with the 2017 average.
Hello, I usually add the EIA 914 survey number to the chart. Although as you know it’s a long wait for the August number.
I have a June one
https://pbs.twimg.com/media/Dn-Hc_AXsAAk54U.jpg
What was the June number relative to the 2017 average? (I assume you have the data in a spreadsheet, if not forget it.) Guessing from the chart it looks like about an 800 kb/d increase in June relative to the 2017 average.
June 2018: 71,689 kb/day
The average for 2017 was: 70,647 kb/day
And so for this collection of countries production in June was higher by +1,042 kb/day than the average for 2017
Energy News,
Thank you. In June 2018, the EIA estimate for the World C+C is 884 kb/d higher output than the 2017 average, seems all of the increase is from the countries in your estimate and the rest of the World has declined by about 158 kb/d (assuming both estimates are correct). About 10,421 kb/d of World output was produced by the “rest of the World” (not covered in your estimate) and decline from those oil producers was at an annual rate of about 3% per year.
Still, the cheap money does not reach so far as to compensate for low oil prices 2014-2017 in “high risk” countries. Offshore is hit hardest, one reason being that infill drilling is expensive out on the seas. Exploration even more so. Heavy oil or other expensive oil not produced in western countries is second hardest hit by the glut. And for those not paying attention, this include some of the OPEC countries as well. I always thought we were going to be 2 mill b/d short this autumn and that it was not going to be an easy way to prevent it. Some support to the view that we will see a peak in oil prices at year end (stretching for who knows how long) is also seen in the MSM now.
What is happening is that global inventory declines until there is competition for the last produced barrel. India is added to the list it seems. https://oilprice.com/Latest-Energy-News/World-News/India-Looks-To-Cut-Crude-Imports-As-Oil-Prices-Rally.html. Along with China, Saudi Arabia, Kuwait and the US. Europe has always had limited storage capacity, and the opaque storages around the world saw severe draw down already in 2017. So inventory surpluses dwindle everywhere; not just in the OECD countries. And that it ends in a crash is just ultra typical, it has just to do with how human behaviour works. The contrarian view is getting ever more likely.
Brazil
Nope, Brazil has peaked or very nearly so.
Brazil Crude Oil Production – Forecast
Crude Oil Production in Brazil is expected to be 2601.05 BBL/D/1K by the end of this quarter, according to Trading Economics global macro models and analysts expectations. Looking forward, we estimate Crude Oil Production in Brazil to stand at 2601.90 in 12 months time. In the long-term, the Brazil Crude Oil Production is projected to trend around 2601.91 BBL/D/1K in 2020, according to our econometric models.
Flat through 2020 no less.
Another Brazil Chart, same link as above. And they are predicting this level, 2,600 kbd, will hold through 2020.
I don’t get that, they have a load of FPSOs under construction, availabity of them and/or the drilling rigs would have to be awful for there not to be an increase (but actually that might be possible).
That’s Russia. I can believe that and if it’s true prices are going to go haywire and Putin might start looking like a nude emporer. But the comment was about Brazil. I wrote a draft post that Dennis might issue next month if there’s a slot but below is my guess at the new FPSOs (production black, construction blue and appraisal green).
Hey, all I was doing was quoting the experts.
Hi Ron,
I think George Kaplan’s analysis is the best around, in a future post he has an estimate for future Brazilian output that might be different from these other experts.
Dennis, I do not doubt his analysis or question his expertise. All I was doing was quoting what Tradingeconomics.com was saying. I cannot vouch for their expertise however.
Just a guess.
Looks very reasonable. To be certain about the tail is a guess game, and I always tend to think it will be pretty fat. But for Brazil to have enough resources to counter the peak is very difficult most likely.
I too suspect activity will pick up like this projection, and give increased production from 2021 and onwards (maybe later if we have an economic crisis – after a recovery this could be the picture after all). It is how offshore works, especially when far away from “safe havens” for cheap capital.
There will be other discoveries, probably quite a bit (Laherrere estimates 55 Gb) to fill out the tail.
George,
Did you model that decline after 2026 based on history from the North Sea?
Looks quite reasonable. Is the Santos decline steeper than Campos or is that an optical illusion?
No it’s bottom up based on other Brazil FPSOs and matching the 2P estimate.
George Kaplan,
Thanks.
Trump talking at the UN General Assembly today
2018-09-25 (Bloomberg) Trump says that OPEC Nations are `ripping off the world’ on oil prices – and reiterates he wants OPEC Nations to lower oil price
“Columbus was the first economist. He didn’t know where he was going. He deceived his men. & he travelled on government money.”
— Victor García, cited The Heretic’s Handbook of Quotations
At least he knows what is hitting him, and there are not many ways to prevent it.
“there are not many ways to prevent it”
Bullshit, Trump and his followers are the idiots who want to reduce the fuel economy standards in the future.
I have to admit you have a point there.
And as for the discussion of a policy to transition away from fossil fuels, it may belong in another thread. But, it is so much that can potentially be done that is being ignored for now a lot of places. I still think we have another 20 years or so to try to find a path. But I don’t think it is going to be as easy as 98% of people in the 20’s think today.
Such discussions are ok with me as they are related to future demand for petroleum, without which there will be very little supply, which is what this thread is about.
I agree we need about 20 years, maybe 30 and it will not be easy at all imo. Higher oil prices might move us in the right direction and the higher the oil price the faster the transition might occur.
Good policy would also help, but the auto companies that will survive will see the need to move in the proper direction without government interference.
https://www.goodcarbadcar.net/2018/09/august-2018-the-best-selling-vehicles-in-america-every-vehicle-ranked/
From link above.
In August 2018 the Tesla Model 3 was #18 for vehicles sold in the US (this includes pickup trucks, SUVs and Cars.) Not bad, and they are likely to continue climbing, probably reaching top 10 by Dec 2018.
Not a lot of competition in this price range (under 60k) until 2020 or later. They expect to start selling the base version (RWD and 210miles of range) in mid 2019, so far they can’t keep up with demand for the higher end 310 mile range vehicle which is 49k with RWD and no options.
The US SPR will release 11 million barrels of sour crude oil to be delivered from October 1, 2018 through November 30, 2018.
FEBRUARY 21, 2018 EIA: Assuming no other legislation over this period, the SPR could decline from 695 million barrels at the start of 2017 to about 410 million barrels at the start of 2028.
https://www.eia.gov/todayinenergy/detail.php?id=35032
Energy News,
In your link from the EIA it says nothing about SPR sales in 2018.
What is the source for the statement below?
The US SPR will release 11 million barrels of sour crude oil to be delivered from October 1, 2018 through November 30, 2018.
Link to Oct SPR sales. Contracts awarded.
http://www.kallanishenergy.com/2018/09/12/doe-awards-contracts-to-oil-companies-for-strategic-petroleum-reserves/
Guym,
I just needed to do a search, there is also this from the DOE:
https://www.energy.gov/fe/articles/strategic-petroleum-reserves-announces-notice-sale-crude-oil
So we have sales of 11 Mb over about a month, input to US refineries is about 542 million barrels per month so this sale of 11 Mb of oil from the SPR barely moves the needle, its about 2% of monthly crude input to US refineries, for a single month.
From Guym’s link:
The 11 million barrels will likely reduce supply disruptions ahead of the Iranian sanctions that are set to go into effect in November, experts said.
Do these “experts” know how tiny an amount of oil 11 Mb of oil is compared to total daily input to refineries? Its about 17 million barrels per day so if all the oil were sold in a day, rather than over 31 days, we could run the refineries for about 15.5 hours. (I assume the refineries run 24/7 as there is a lot of capital which might not be left idle.)
Last time, most was exported to China, anyway. Not likely to move the needle based on the quantity, unless the press makes it bigger, which is a likelihood. Last batch had some bad H2S problems, so I imagine they will just dump it cheap.
Yes a PR stunt before elections to show the Republicans are on the case with important Tweets from the Prez and all that 11 million barrels to keep gasoline prices low.
Hey the experts said it would really help, so it must be true. 🙂
I admit that I have been either side of the fence on this Democrat Republican thing. Last time I had any real interest was when William F Buckley was still in swing. He did significantly influence intellectual conservatism. An acceptable middle ground was important to identify. Now it’s Fox News at a high point. Sad. In the far past it gave us many good things that are taken as “liberal” now. Now, you for us or against us, on either end. Polarized. And the Republicans wind up with Harpo Marx who tweets instead of honking his horn. Yuck!!! Don’t look down now, Bill.
“Trump has the maturity of an eight year old boy with the insecurity of a teenage girl.”
I saw that on Bill Maher last weekend. Because it’s so true. Is what makes it funny and sad at the same time.
HB-
We are in late stage capitalism, so, for me, Trump is not that much off base from expected leadership.
What I find surprising is the constant lying–
Even a TV con man should be beyond that.
These guys don’t even know how to search. They are obviously oil experts.
https://www.bloomberg.com/amp/news/articles/2018-09-25/as-twitter-fails-trump-s-next-avenue-is-strategic-oil-reserve
Guym,
From that piece:
In theory, Riyadh can pump as much as 12.5 million barrels a day, compared to about 10.4 million last month, offsetting the loss of Iranian supply. Still, to reach that level, it needs time to drill more wells, and an SPR release could fill the gap until the Saudis are ready.
Elsewhere in that same piece they say as much as 30 million barrels can be released over a 60 day period so that’s about 0.5 Mb/d, to fill a 1 Mb/d gap, it would help a bit perhaps, but would be a short term fix for a couple of months.
Most people won’t be paying attention, anything that brings down gasoline prices will be seen as good by the masses, even if it is short term.
I had forgotten that the President has the power to release the SPR reserves (up to 30 Mb over any 60 day period) under the Law that created the reserve.
ps I think tradingeconomics predictions are just extensions of curve fitting they don’t any fundamental anlysis.
pps Was it you who came up with an analogy of a water skier for oil prices; i.e. the supply/demand balance is the boat pulling the skier in a certain direction but the skier can slalem left or right about buoys which represent the daily noise?
(Supposed to be a reply to Ron above but something got messed up)
George Kaplan,
What is your take on Brazilian future output?
I find your analysis about the best around.
Was it you who came up with an analogy of a water skier for oil prices;…
Yes, that was me. A skier can swing wide each side of the boat pulling him but eventually he is forced to follow the boat. The skier is traders swinging above and below the supply and demand trend. But eventually, they are forced to follow supply and demand.
What the traders are really trying to do is guess which way supply and demand will pull prices, up or down. When most traders guess low, the price will drop, when most traders guess high, the price will rise. But eventually, supply and demand will pull prices right back where they belong.
I’ve always found water skiing boring.
Gave it a good look, could jump start on one foot, etc.
But it is so far from the green room, that one could be on another planet.
Hickory,
Waiting for a boat from Tesla. 🙂
Beats riding around sightseeing on a boat, but yes not green at all, for the most part that’s true of human existence in the 21st century.
Ron,
I can ski on either side of the boat as long as the boat doesn’t get too close to shore or other hazards (rocks, islands, etc). Though I cant go any farther than the Rope is long, unless I let go, of course I no longer follow the boat at that point. 🙂
It is a cute analogy though, as long as the skier is comfortable enough to cross the wake and likes to turn, it works.
Shallow suggested dollar variance as an oil price influence. Items:
Dollar variance against a basket of currencies since 2010 max 27%
Dollar variance against Euro same timeframe 41%
Dollar variance against the pound same timeframe about 30%
haha Dollar variance against the Chinese yuan same timeframe <10% that's hilarious Imagine what they pay for their what, 7 mbpd imported oil vs England or Germany. They can print barrels.
For the people who continually question the upstream unconventional operators for financially mismanaging their companies, today’s RBN Energy site has another post in their ongoing analytical series monitoring the financial aspects of dozens of these outfits.
Breaking down the companies into 3 different groupings – oil focused, gas focused, and hybrid – RBN gives outstanding overview into what is going on with these organizations.
Recognizing that the corner has been turned, debt is being paid down, conservative capital investing is taking place is all apparent with the numbers presented in this article.
Coffeeguyzz,
I have shown an analysis of the Permian that suggests the debt can be paid down completely under reasonable price scenarios (my medium oil price scenario shown in a chart upthread) by 2025 and that cumulative net revenue from Jan 2010 to the future will reach $500 billion in 2017$, by 2036 at an assumed well cost of $9.5 million per well. Output of Permian tight oil for this scenario is on the right axis in kb/d. Cumulative net revenue in billions of 2017 $ is shown on left axis.
2018-09-26 (S&P Global Platts) Algiers — Libya’s crude oil production has hit a five-year high, bringing badly needed revenue to the violence-wracked country, but further gains will depend on stabilizing security and attracting foreign investment, the chairman of state-owned National Oil Corporation told S&P Global Platts.
Libya is pumping 1.28 million b/d, its most since August 2013, and still harbors ambitions of boosting output beyond 2 million b/d by 2022, Mustafa Sanalla said in an interview after attending Sunday’s OPEC/non-OPEC monitoring committee meeting in Algiers.
“If the security situation improves, our production outlook is very good,” he said.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092618-interview-libyas-noc-hopes-talks-with-iocs-will-boost-oil-outlook-as-security-stays-fraught?
Oil prices making the news in Dubai, up +6 to 88.96
2018-09-26 (Dubai Mercantile) Marker Price on September 26, for November 2018 Oman Crude Oil Futures Contract OQD: US$ 88.96 Change: US$ +6.43
https://twitter.com/DubaiMercantile
Read that CME who now brings you WTI Cushing prices, will start their own WTI MEH price to compete in January. The more logical price for WTI, and it is trading $6 to $7 higher than WTI Cushing now for November. In my logic (dangerous), it should raise WTI in the future as there is only about a $3 transportation cost, or less, to get Cushing to MEH. Right now traders have a totally confused interpretation of WTI Cushing. Means my little dab from the Eagle Ford is probably being bought this morning at 77.5 less transportation costs.
https://www.spglobal.com/platts/en/market-insights/latest-news/oil/092418-cme-to-launch-wti-houston-crude-futures-setting-up-battle-with-ice
And if E&Ps in the Permian had a strong enough, or smart enough, group think to cut back production just a little, they would make far more in the long run. There would still be a transportation cost of $3 or less to get it to MEH, but it still could be trading at over WTI Cushing prices, I think.
https://beforeitsnews.com/v3/science-and-technology/2018/2934915.html
Inventories up over one million, but obviously due to operating at 90% capacity vs 96. Exports edging back up. The great takeaway in this weekly is that Washington DC produced an additional one hundred thousand barrels. We couldn’t possibly be at 11.1 until sometime in the second half of 2019. We have to be half a million barrels over actual, now. When this fit hits the shan, Tump will just fire Perry for being a bad apprentice.
I am guessing US production is at around 10.550 for July, Dennis is “less pessimistic” and estimates it at around 10.7. Bound to be somewhere in between, but if we use his estimate, oil would have had to increase by 400k barrels in less than two months. Anyone buy that?
Guym,
The weekly output estimates are useless, I actually don’t have an estimate for US output, beyond the most recently reported EIA monthly estimates, Alaskan output was down, tight oil output was up, that’s all I know for now. I am a bit more optimistic than you about rising output in the last 5 months of the year, it will slow down compared to the first 7 months due to lack of pipeline and rail capacity in the Permian basin, but with rising oil prices some DUCs may be completed in North Dakota, Oklahoma, Montana, Colorado, and Wyoming, heck maybe even in the Eagle Ford play. So we might see another 300 to 400 kb/d increase in the last 5 months of 2018. I would say a 1000 to 1100 kb/d increase from Dec 2017 to Dec 2018 for US C+C output is a reasonable guess.
I would say 800k, and that would be due to the Cushing pipeline expansion due after Nov 1. Another 100k from Other. Not much more until after the first quarter. It takes time to switch gears.
Guym,
You could be right, especially if higher oil prices have little effect on supply in the short term. I am guessing the 2 year trend in US C+C output continues, you are guessing it will not. We will see.
Note that the 2 year trend for tight oil is similar to US C+C with both increasing at an annual rate slightly over 1100 kb/d each year. We have tight oil data through August 2018 so in another 4 months we will know if tight oil output has increased enough to reach 1000 kb/d, so far the tight oil increase has been 789 kb/d for the first 8 months of the year, another 211 kb/d over 4 months gets us to 1000 kb/d.
Your using those numbers from EIA on tight oil output. They are probably mostly from drilling info which is their estimate. I think Texas production is proving that those numbers do not project shut ins, which are obviously (to me) happening. Projections won’t estimate shutins. They estimate as if those wells continue to produce, or I can’t think of any other way they could do it.
It is my guess, and the next few months should confirm, deny, or change. It’s a new ball game, and we are listening to the results with a huge time delay.
Guym,
I think drilling info gets its data from the various state agencies. Note that the data is not from the drilling productivity report.
See
https://www.eia.gov/energyexplained/images/charts/u.s.tight_oil_production.jpg
and
https://www.eia.gov/energyexplained/data/U.S.%20tight%20oil%20production.xlsx
It is always possible that any estimate is incorrect and of course trends often change in ways that are difficult to predict.
As I said, you may well be correct, we’ll know better in Feb 2019 or perhaps in Sept 2019.
Yeah, and I just found out that extra 360k of new pipeline ain’t gonna happen. I am victim again of faulty reporting. The pipeline will have a total of 360k, when the new expansion of 90k barrels come online the end of October. So, we will only have 90k new pipeline capacity. If we have 800k of new oil in the US by the end of the year, we’d be lucky. Nothing new on the Permian until the end of next year that I know of. You can use historical numbers to estimate, in this circumstance, I wouldn’t.
Drilling info gets its numbers from the RRC, yes. But it uses the old numbers and new completions to estimate the most recent two months. Anything past June, now, would have to be estimates. I am pretty confident on using the pending data files from RRC, and in July production went down, and EIA’s June numbers were too high by at least 50k. Which makes July output around 150k less than what they reported for June. It may go up again in August, but I think our average can be found from the past three months plus the 90 that’s coming.
Guym,
From Dec 2017 to June 2018 the increase in tight oil output has been 572 kb/d, with a 217 kb/d increase from June to August. Perhaps the drilling info estimates for July and August are too high, hard to know at this point.
Well, the EIA numbers for July are due pretty quickly. Be interesting to see what they come up with.
Get into your time machine and travel a couple (maybe less) years into the future. Oil prices are terrible, oil supply is frightening. Yet, we are continuing to export oil from the Permian and elsewhere. Yeah, it’s at an API that’s pretty useless for most refineries, but in the minds of the public and sort of minds of the elected officials it is still just oil, and we are wasting it selling it to other countries. I can see the oil export ban being reinstituted. After all, that is what precipitated the first one (oil shortage). At that point, where to produce oil will be on what type, rather than all on how much.
Before you say that can’t happen, look at the current administration, or what we had as an alternative, and think a little harder.
It would also change dramatically, projections on US output.
https://oilprice.com/Energy/Energy-General/The-US-Will-Ensure-A-Well-Supplied-Oil-Market.html
Ok, Washington DC can handle any oil shortage. Lol. They produce a lot of oil out of a pretty small area.
I was just having a quick look at Saskatchewan’s crude oil production
And yearly drilling statistics: https://pbs.twimg.com/media/DoCvx83XUAAf1Vj.jpg
Colourful photos of sky and storms above Odessa Texas
2016-09-17 Odessa, Storms rolling through earlier today
https://pbs.twimg.com/media/CsiQ80uUIAAJMLx.jpg
2016-09-21 https://pbs.twimg.com/media/Cs4M5EzVYAAM8yB.jpg
From this lady here: Twitter account https://twitter.com/MShortes
There is nothing that compares to a desert area aroma after a good rain. I lived in Arizona for a couple of years, and it was flat amazing after a rain. The flash floods were not so great, but the smell was.
https://www.mrt.com/business/energy/article/Plains-working-to-open-pipeline-expansion-out-of-13256090.php
I have no idea what to make of India, and their plans. One week, they will not be following sanctions, and the next, the will. It reverses every week. Last week, I read they are going to draw on their reserves, and this week they are going to grow reserves. It is probably not India, but the reporting on India.
It’s going to be more difficult to know what is happening because India hasn’t updated it’s oil inventory data on JODI for a few months.
And China has stopped reporting it’s inventory data through their Xinhua news agency
It sounds like refiners are saying that they will comply with sanctions in November but they hope for waivers.
Whereas it’s governments that are saying that they will setup alternative payment systems.
Oil market has already climbed back over today’s losses. It’s beginning to look like the battery bunny. And they are not realizing yet, that all OPEC losses could be covered, and we would still be over a million short.
https://oilprice.com/Energy/Crude-Oil/The-Productivity-Problem-In-The-Permian.amp.html
Another explanation for the up and down movement in the Permian production rather than shut ins is the still long delay between completions and the huge decline rates. But, overall, I don’t think it is growing at the rate expected. There is, no doubt, a lot of possible explanations for the slowdown. Including constraints other than pipelines. I read the roads are really becoming a problem in the local Midland newspaper.
https://www.bloomberg.com/amp/news/articles/2018-09-18/roads-not-pipelines-seen-as-biggest-permian-peril-to-growth
Shell GM says roads are bigger problem in Permian growth than pipelines.
Some kind of wild west road movie.
This kind of driving, 80-100 hours a week with a truck isn’t possible anymore in burocratic old Europe. With electronic tamper proof tachographs, the driver inserts his licence card and the clock runs. When he exceeds 40 hours driving time a week, he’ll be in deep trouble, up to loosing his truck license. Speeding can be detected even weeks later with this system, so don’t do anything to alarm the police.
Reduced truck accidents by a lot here. In Permian, they would have to hire 2 drivers for a truck.
Guym,
I imagine the roads will improve over time, the pipeline constraints will take some pressure off, completions might drop about 28% which will take some pressure off the roads, but they need to be widened by the time pipeline capacity comes online in late 2019.
Guym,
No doubt there will be a slow down in the completion rate, due to pipeline constraints in the Permian, I would expect they would have no difficulty keeping output flat at the level the oil can be moved by pipeline and rail to refineries or export terminals, so I doubt output will decrease. Other areas such as Eagle Ford, Bakken, SCOOP/STACK, and Niobrara don’t have the same constraints, higher oil prices might increase the completion rates of DUCs in those plays.
Note that according to Enno Peter’s data, the completion rate for horizontal tight oil wells in the Permian basin averaged 334 per month from Sept 2017 to March 2018, so the EIA estimate for completions in June may be too high. Also based on my model only about 285 completions per month are needed to keep Permian output flat at Aug 2018 levels estimated by the EIA. I simulate what output would look like through July 2019 if 285 wells were completed each month from Sept 2018 to July 2019, output remains relatively flat if average well productivity remains flat.
The EIA’s legacy decline estimated by the Drilling Productivity report is not very accurate and suggests 412 new wells per month are needed to keep output from falling, when in fact the number is only 285 new wells per month.