In the discussion here I use the term net volume to refer to the volume of prospective rock that might be developed to produce tight oil. For each bench of a prospective tight oil play (Wolfcamp A would be one example of a bench) there is an area estimate (5733 thousand acres for Wolfcamp A of Delaware) and a success ratio (%) = 94.7, in the case of Wolfcamp A. Net acres are the total acres times the success ratio, for Wolfcamp A, 5429 thousand net acres. On average the Wolfcamp A of the Delaware basin is about 400 feet thick, so the net volume would be net acres times thickness or 2172 million acre-feet. An acre-foot is a volume that is one acre (44,000 square feet) by one foot thick or 44,000 cubic feet (or a box that is 1000 ft long by 44 feet wide by 1 foot high.)
Delaware Basin study by USGS estimates 32.2 million acres and 28.7 million net acres. and 242,000 net wells can be developed (net acres divided by acres per well, average of 118.7 acres per well.) The basin’s average bench is 450 feet thick on average (see EIA study.) Net volume is 12,900 million acre-feet.
Midland Basin study by USGS finds 21.2 million acres, 17.4 million net acres, and about 174,000 net wells (net acres divided by acres per well at an average of 122.3 acres per well.) The basin’s average bench is about 330 feet thick on average (based on IHS study linked below) and net volume 4400 million acre-feet.
Midland presentation from IHS Markit, estimates average thickness is 2000 feet, I use a more conservative 1550 foot thickness.
Spraberry trend study by USGS finds 8.5 million acres and 7.5 million net acre. Thickness averages about 175 feet for each bench, 52,900 net wells (net acres divided by acres per well at an average of 141.6 acres per well.) Net Volume is 1300 million acre-feet. Spraberry thickness estimate from page linked here.
Total Permian basin net volume is 18,600 million acre-feet (=12,900+4400+1300).
Eagle Ford USGS study finds 9.9 million acres, 8 million net acres, and 80,000 net wells (net acres divided by acres per well at average of 100.6 acres per well.) Thickness of benches is about 140 feet thick on average (from here). Net Volume is 1100 million acre-feet.
Bakken/Three Forks USGS study found 11.3 million acres, 10.4 million net acres, and 44,000 net wells (net acres divided by acres per well at average of 423.9 acres per well.) Average thickness of each bench(source here) is about 350 feet. Net volume is 3600 million acre-feet.
Combined net volume of Bakken/Three Forks and Eagle Ford is about 4700 million acre-feet vs 18600 acre-feet net volume for the Permian basin.
The TRR of Eagle Ford is about 14.5 Gb when cumulative output and reserves (6 Gb) are added to undiscovered TRR (UTRR) of 8.5 Gb. The TRR of the Bakken is about 11.6 Gb when 4.2 Gb of cumulative output and proved reserves at the end of 2012 are added to the 7.4 Gb assessment of UTRR in 2013.
Combined the TRR for the Eagle Ford and Bakken/Three Forks is 25 Gb and for the Permian Basin the TRR is 75 Gb when 5 Gb of reserves and cumulative output is added to the 70 Gb UTRR from the Delaware Basin (46 Gb), Midland Basin(20 Gb), and Spraberry (4 Gb) mean UTRR estimates from the USGS.
The larger volume of prospective geology in the Permian basin (18600 million acre-feet) compared to the combined volume of the Eagle Ford and Bakken/Three Forks prospective geology (4700 million acre-feet) a ratio of 3.96 to one, accounts in part for the larger technically recoverable resource (TRR) mean estimate by the USGS for the Permian basin. Differences in geology between plays also accounts for some of the difference as well as changes in oil development practices over the period of these USGS estimates from 2013 (Bakken) to 2018 (Delaware Basin section of Permian Basin). For example in 2013 the USGS assumed the average Bakken/Three Forks well spacing would be about 1900 feet, where the most recent USGS estimate for tight oil in November 2018 for the Delaware basin assumed a well spacing of about 600 feet for most wells.
I am way out of my comfort zone talking about resource plays, but, when I take your TRR for the 5 trends above (Midland, Delaware, Spraberry, Eagleford, Bakken-3Forks) and just divide that by the net acre-feet, all but the Eagleford are in the 3 to 5 range, while the Eagleford is 13. This would seem to be some measure of recovery efficiency, but I’m not sure. A couple questions about these intervals.
These are supposed to be source rocks, right? I suspect the Permian resource play units are source beds for intervening conventional reservoirs? Could that account for the low “recovery efficiency”? That is, these units have already expelled some hydrocarbons into conventional reservoirs. Maybe the same thing for the Bakken/3Forks? Aren’t there conventional reservoirs for which the Bakken-3Forks is the source? What’s different about the Eagleford? That brings up a question I’ve had for years. What happens to hydrocarbons in a petroleum system where there is no reservoir (technically this is not even a petroleum system).
SouthLaGeo,
Seems the way the USGS does these studies is to look at existing well data to guess at a probablility distribution for the the various benches in the Play and then they run a Monte Carlo simulation for their study of the potential resource. Typically they assume a lognormal probability distribution (I think, though perhaps it is something else). It is all a bit of a black box from my perspective, but I gave links to all the USGS resource estimates that applied to US tight oil from 2013 to 2018. To be honest your evaluation would be more insightful than mine as you are a geologist and I am not.
My main point was to show that the prospective volume in the Permian basin is large. My guess is that the Bakken/Three Forks mean estimate may be too low and the Eagle Ford is too high. My guess is that they should both be around 12 Gb for TRR, but the total of the two is roughly about right.
SouthLAGeo,
Petroleum migration without effective trap or seal results in tertiary migration – migration of petroleum to Earth’s surface.
In doing the math and I confess I’m a “babe in the woods” with all this, the TRR among all the basins cited above would be 171 GB. The estimated recoverable resource for Prudhoe Bay started around 10GB and has moved upward toward 15 GB; a factor of 11 less than cited above. Prudhoe Bay sent an average of 1.6 MBOD through the Alaskan pipeline to Valdez for 10 years. Would this mean that if all these basins would have been drilled ala Prudhoe Bay, Texas could have pumped 17.6 MBOD out of the ground over a 10 year period?
I guess, I’m trying to wrap my head around the dynamics and terms of what Dennis and others have presented here. Is this a reasonable hypothetical set of assumptions?
Peter
TRR is 74 Gb for Permian and about 25 Gb for Eagle Ford and Bakken.
Perhaps another 15 Gb for other US lto for about a 114 Gb total.
URR probably 80% of TRR at medium oil price level of 75 to 100 per barrel so roughly a 90 Gb URR.
Keep in mind speed of development can be faster for conventional reservoirs.
US tight oil will perhaps produce 10 Mb/d over a couple of years from 2023 to 2027. Most basins besides Permian are likely near or past peak output, at least
Bakken, Eagle Ford, and Niobrara, there may be some smaller plays that might reach new peaks at high oil prices. I lack the data on most other plays needed for a good estimate.
Hi Dennis,
I added the amounts from this paragraph: “Combined the TRR for the Eagle Ford and Bakken/Three Forks is 25 Gb and for the Permian Basin the TRR is 75 Gb when 5 Gb of reserves and cumulative output is added to the 70 Gb UTRR from the Delaware Basin (46 Gb), Midland Basin(20 Gb), and Spraberry (4 Gb) mean UTRR estimates from the USGS.”
25 – Eagle Ford and Bakken etc.
75 – Permian
46 – Delaware
20 – Midland
4 – Spraberry
170 – Total
That’s how I came up with the 170 TRR. I take it that the smaller fields may not be developed to anywhere near their respected stated TRR.
A goodly chunk has already been drained. No mention of porosity. No mention of water cut within the pores.
This kind of thing was done years ago. For individual shale wells. Computation of volume fracked. Nowhere near that number in ultimate recovery has been achieved.
Not really a permeability issue. It’s porosity, which is not required to be uniform across large distances.
Watcher,
For the Permian basin the estimates by the USGS were from 2016, and 2018 as I recall, the estimates from years ago were mostly for the Bakken/Three Forks (2013 and 2008), every play is different.
It is not clear that water cut is a very important metric for unconventional plays. I agree that porosity would be highly variable, this is likely true for all rocks over large areas or volumes.
The USGS mean TRR estimate for Wolfcamp, Spraberry and Bonespring subplays of the Permian Delaware and Midland sub-basins is about 74 Gb, for a reasonable oil price scenario and reasonable economic assumptions the economically recoverable resource (ERR) would be about 60 Gb, about 81% of the TRR, if the multitude of assumptions I make prove correct. That is unlikely, they may be too conservative (in which case ERR would be higher) or too optimistic (in which case the ERR would be lower). In the past my scenarios have tended to underestimate future output, the future might be the same or different, we will have to wait and see.
A km³ is a volume that is one km² (1,000,000 square meters) by one km thick or 1,000,000,000 cubic meters (or a box that is 1000 m long by 1000 m wide by 1000 m high. Works really well… You might try it. 😉
Yes, for a scientifiy person US measurements are kind of median age stuff. I always have to use a calculator for this stuff.
The thump of Mike Tyson per weight of President Nixon … would be not more strange. The metric system wasn’t invented without thoughts – before there was own measurement in every town.
And come on, Fahrenheit for example. 0 degree in a really cold winter night and 100 degrees the body temperature when the inventor was slightly ill. Nice try I would say.
Fahrenheit lived in Danzig, now Gdansk, Poland. 0F is about as cold as it ever gets there.
Verwimp,
Take it up with USGS.
They do their reports using Acres and feet. Perhaps you have noticed we typically use non-metric units such as barrels here.
This is fairly typical in US.
1 million acre feet is 1.2335 cubic kilometers or 1.2335 billion cubic meters.
Feel free to convert to metric.
Verwimp,
Do you have an update to your Bakken Model?
Here is an old model from July 2016, with the only change being updated data from NDIC added to chart (from July 2016 to Sept 2019).
The original model assumed a decrease in New well EUR starting in July 2017, in fact the average EUR increased over the 2016 to 2018 period with the shape of the well profile also changing so that initial output was significantly higher over the first 12 months of well output. Average number of wells added over the July 2016 to Sept 2019 period was 91 wells per month, low number of wells added in 2016 and 2017 and higher completion rate in 2018 and 2019. In any case the estimate in these scenarios proved too conservative.
Hi, Dennis, No I haven’t updated my model. I never did. I built the model early 2014 to ‘predict’ the december 2013 datapoint. All datapoints until december 2016, 36 datapoints in a row, were ‘predicted’ with very small errors (much to my own surprise). From january 2017 onwards things took a turn and reality walked completely the other way.
The entire shale revolution has un unprecedented scale, with historical consequences. The reduction of US oil imports with 6 million barrels per day, has given the opportunity to some developing countries (not to name China) to increase their imports and to grow their economies. That happened in less than 10 years! Without shale oil, the world would look completely different today. When this revolution really starts to fade out (eventually it will) we will whitness strange things.
(I do love the word acre-foot. It sounds very poetic. It’s a very apropriate unit for the content of a reservoir. It gives an intuitive feeling of the magnitude of a reservoir and it gives an idea of the surface of land that can be irrigated with the water in the reservoir, waiting for new rain. And then it starts raining some inches over those hundreds of square miles draining to the reservoir. Farmers with pocket calculators for the win. 😉 )
Thanks.
Do you remember the URR you used for your model?
It had only 2.77 Gigabarrels URR. Obviously an underestimation. Those days it gave me the best fit to match previous data.
Thanks
ND Bakken cumulative output through Sept 2019 is about 3.2 Gb.
Dennis
Is there some way of estimating what percentage of the volume contains recoverable oil. Can you estimate the volume that one well on average can access. If you can, then can you use the volume of oil that is recovered say over five to seven years from one average well and a bit of extrapolation to estimate the percentage of the volume that contains oil.
I hope this makes some sense.
Ovi, the problem is all wells are not the same. That’s why they call certain places in the reservoir “sweet spots”. So when they drain the sweet spots, the further and further they get from the sweet spots, the less oil per well they recover.
That has been the problem in Eagle Ford for well over a year now. The sweet spots are all drilled out and each new well will, on average, be further and further away from the sweet spot. And each new will, on average, produce less and less oil. That may be happening right now in the Bakken and will definitely start happening in the Permian very soon.
Ron,
Absolutely correct, there is always a distribution of wells, some with higher output and some with lower output and this well distribution will tend to change over time.
There are two competing factors, technological innovation will tend to increase the average EUR over time while the saturation of wells in the most prospective areas will tend to decrease the average new well EUR.
The Eagle Ford and Niobrara look like they may have peaked for average new well EUR in 2017, so far there has been no apparent decrease in new well EUR for the Bakken or Permian basin, but it may happen soon.
Operators can compensate for lower average new well EUR by completing more wells each month, but eventually they run out of new locations for wells.
For the Permian basin my best guess scenario is below, URR=59.6 Gb, total wells completed 192,000, average EUR=310 kb. Ron will no doubt believe this scenario is optimistic, perhaps outrageous, he has often thought this about my scenarios in the past and typically they have proved to have been too conservative.
We will have to wait a few years to see if history repeats, perhaps this time my scenario will indeed be too optimistic, I’d say there is about a 50% probability that will be the case.
Ron , if you compare wells of same lenght , bore dim. how will the data off decline rate off well flow in barrels each day , total estimated production during well lifetime and years of production average looks for Tiere 1 , Thiere 2 , Thiere 3 and 4 if such exsist. Guess here Thiere 1 means sweet spots. I guess in Permian the Area for Tiere 2 will be bigger than the sweet spots and they might drill longer in that Area before they chabged to Thiere 3 acre ? I believe break even price for thoose diferent categories wells will have high impact for future oil price.
Freddy,
Shaleprofile.com gives the ability to select individual production level categories. Tier 1 is defined as > 800 bd; Tier 2, 400-800bd; Tier 3, 200-400bd; and Tier 4, 100-200 bd. The following four charts show recent declines in Tiers 1 & 2 and increases in Tiers 3 & 4, for all Shaleprofile.com data on US shale oil.
This means that sweet spots are decreasing in number as former high production wells fall down into Tiers 3 & 4. Quoting Ron:
“Soooooo…. It just doesn’t matter what the price of oil goes to. Higher prices will not create more or sweeter sweet spots. Shale oil in the US is either now declining or soon will be.
So just get used to it.”
Thanks Tony, so it means a well can start as Tiere 1 well lets say 1000 bpd than after 6 months it might produce 600 acc. to decline curve and it is than categorized as Thiere 2 well? Guess than there are more than 5 levels. Guess if most sweet spots are used more wells will start below 800 bpd , considering same declinevrate and cost off well that will significant increase break even price. Since the pioneer Mark Papa in 2018 told they need 75 usd WTI to increase production without loan I exspect this soon might be 100 as result of reduced cashflow from wells drilled in lower quality rock and as everywhere there is inflation . I see Exxon will start a drilling orogram in GOM , good they have yhe huge discovery in Guam as there is no doubt they need a huge cash flow to fund both permian plans and build out what might be descovered in GOM . It might be 25 bill. dollars will not be suffisient, they also need to buy dividend. Not much dividend startibg with Tiere 3 wells in average even WTI reach 60 usd each barrel.
Tony
No you are not understanding Enno’s Charts.
What you have defined as tier 1, 2 etc is not correct.
Even a tier 1 well declines quickly. Use productivity distribution to judge tier 1, tier 2, by looking at 24 month cumulative output.
The chart you are using just gives daily output of all wells in different bins. Older wells have lower output whether tier 1 or tier 2.
Freddy and Tony
Enno Peters shows these different output levels but nowhere does he refer to them as tier 1, tier 2 etc.
Not a correct characterization.
Tier 2
Tier 3
Tier 4
Tony,
Note that these charts show current output for all producing wells rather than peak output. So in Jan 2018 about 13.4% of output was from wells with 100 b/d to 200 b/d of output and in July 2019 about 15.2%.
Most of the “lower output” wells (200 b/d or less) are simply wells that started production in 2017 or earlier.
Tony one way to consider tier 1 to tier 3 wells is to look at productivity under advanced insight tab.
Chart below looks at Bakken ND, Permian and Eagle Ford for 2008 to 2017 for cumulative 24 month output, 62% of wells are lower than average, which suggests that a Maximum entropy probability distribution may be a good approximation.
Ovi,
Yes that is what the USGS does when it estimates TRR.
One barrel is 0.158987 m3.
For Permian basin the net volume of prospective rock is 22,900 cubic kilometers.
The TRR is 11.8 billion m3 or 11.8 cubic kilometers.
So the percentage of oil in the prospective net volume is 11.8/22,900=0.05%.
Not the question you asked.
Let’s say the prospective net volume of the Permian basin is 23,000 cubic km. Let us also assume 3000 m lateral length and 300 m well spacing for the average well, the average thickness of the prospective Permian “benches” is about 130 meters. so the average well accesses a volume of rock equal to 3000*300*130=117 million m3 or 0.117 cubic km.
This implies about 23000/0.117=196,600 total wells to access the total TRR of 74 Gb (mean USGS estimate) with an average EUR of 74 Gb/196,600 wells=376 kb.
For my models I assume about 254,000 total wells to access the total mean TRR which implies an average EUR of 74 Gb/254,000 wells=291 kb.
I had not done the volume calculation on the wells in the past. The 376 kb EUR estimate for the average well seems too high, but this may simply be due to poor estimates for well spacing, a tighter average well spacing to 250 meters rather than 300 meters, increases the total number of wells to 235,900 and reduces average EUR to 314 kb. In any case I am guessing at future well spacing, clearly this is unknown.
I still may not have answered your question adequately.
So much depends on future price.
If it is high, they will have dense wells to squeeze out as much oil for their area as possible. Later in the cycle there will be tries of refracking and drilling new child wells between old ones.
And with low prices spacing will get even wider to get as much oil per well as possible, once the industry has to earn it’s own money.
It’s like a small-medium size conventional field: High prices means water flooding, CO2 flooding, gas injections, crazy infill drilling all the fancy stuff possible.
Low prices means just drill it and pump, perhaps a little bit of water flooding. It’s no Ghawar, so no crazy stuff.
So price is the most important parameter for recovery.
And when price is oszillating things get even more complicated.
Eulenspiegel,
I agree. I have assumed a 10 million well cost (full cycle), LOE of $13/b0, natural gas sales used to offset LOE (price of $1.50/MCF at wellhead in 2018$), annual discount rate of 10%, annual interest rate of 7.5%, royalties and taxes of 28.5%, transport cost of $5/bo and all costs are in real dollars (2018$), discount rate and interest rate are nominal with 2.5 % annual inflation rate assumed ( so real discount rate is 7.5% and real interest rate is 5%).
Brent oil price in 2018$ assumed for the scenario above in chart below.
Clearly oil prices will be more volatile than this, but predicting that volatility would not be possible, think of this as a 24 month centered average oil price.
To me it seems a pretty conservative scenario, though it is possible prices might start to fall by 2040, which would result in lower output in the tail, if that proves correct.
Dennis
If lateral length is 3000 m, how can you have 300 m spacing. Also no mention of main well length.
Just trying to understand the logic
Ovi,
lateral is the horizontal section of the well, the spacing is the distance between laterals. So consider an area that is 3000 meters long and 3000 meters wide, there would be 10 wells placed in such an area, the first well 150 m from one side, then 450, 750, … , 2550, 2850 m from one side.
Not sure what you mean by “main well length”, do you mean the vertical section of the well? That would be what ever length is needed to get to the pay zone.
picture below shows wells in Bakken from Hughes Shale Reality Check 2019 page 12. This would be a view from an aerial drone (or satellite) looking down at the oil field. The straight white lines (the longer part) are the horizontal laterals (along vertical axis) the spacing would be the distance left to right between those horizontal laterals.
https://www.postcarbon.org/publications/shale-reality-check-2019/
Think of a box 3000 m long, 300 m wide and 130 m tall. Now take 10 of these boxes and place them side by side in a square that is 3000 m by 3000 m.
I guess the well spacing depend of rock quality and is mostely set to prevent frack hits , pressure gradients to neighbur wells. If rock are more britle , longer fraction if fracking pressure remains the same and the result might be more frack hits. Think also frack hits will increase if Area starting to be fully utelized?.
Freddy,
Yes well spacing that is too close can lead to frack hits. Not sure if they have determined the optimum spacing to minimize cost per barrel extracted, if it is known it may be kept secret as it would give the company that has determined this an advantage. In the USGS report they give a 100 acre estimate for Wolfcamp well spacing. If we assume average lateral length is 7000 feet, that would suggest about 628 foot well spacing (about 188 meters for a 2100 meter lateral), 100 acres is about 396,000 m2.
I have read that some operators are moving to wider spacing, unclear what the optimum is.
Found the following presentation which seems excellent, would be great to get any Petroleum engineers to weigh in, bottom line, it is complicated. There is no one size fits all.
https://www.spegcs.org/media/files/files/2375f5d5/SPE-GCS_WSG_May_2018_-_Optimize_Well_Spacing_and_Well_Completion_with_Latest_Modeling_Technologies.pdf
Dennis
The people on the front lines of this stuff are steering away from the term ‘frac hits’ and using a more general term ‘Fracture Induced Events’.
Main reason being that effects on offset wells range from micro seismic recordings, pressure pulses, fluid transfer, proppant intrusion to name just a few.
This topic of completions specifically, unconventional development broadly, is receiving global research attention as countries around the world continue to evaluate their own future potentialities.
India just threw in the towel as the clay content in their hydrocarbon bearing shales is too high, while Pakistan is vigorously plunging ahead with a dozen wells in a pilot program.
The EOR work in the Bakken by Liberty and now Hess could be a major development in better understanding more complete hydrocarbon recovery in plays worldwide.
Check out the presentation, if you have not already seen it, interesting stuff. Complex.
very interesting presentation , I guess this is a teoretical modell with some input from real data obtained from site. Think also thoose natural fractions might have some impact. Perhaps this modell will be more accurate as more data wells in a Area is drilled and fracked as I think geology is not the same. Very interesting, thanks for shearing.
Freddy
You’re welcome.
Yes this is a complex model used by companies for optimization requires a lot of data.
Dennis
That is an excellent presentation – almost 2 years old – that captures quite a bit of the complexity involved.
If you really want to get into the weeds with this stuff, there are several works – even somewhat simplistic videos – available online.
Some recent ones focus on Extreme Limited Entry, the whole array of Diversion products and techniques, on and on.
Complex, highly dynamic process somewhat like a drunken monkey trying to screw a greased football (grid iron ball for the non Yanks) while wearing roller skates.
Coffeeguyzz,
The presentation was from 18 months ago (May 2018) at an SPE conference by a PhD Petroleum Engineer, so fairly cutting edge at the time. No doubt there have been further advances since May 2018, this is what I found that was free with a quick search, I am not a fan of videos.
Dennis
Yes, presented at the May conference, but compiled in February, as the first page shows.
Excellent snapshot with the underlying principles still valid.
Coffeeguyzz
You are correct Feb 2018 is the date on the presentation. Nearly 2 years old.
Thought you all would find this interesting
https://www.bloomberg.com/news/articles/2019-11-27/texas-scoffs-at-paris-oil-predictions-as-shale-patch-feels-pain
Thanks Karen
Good article.
The EIA inventory report is out. Total production is up another 100 kb/d to 12,900 kb/d. The lower 48 is also up by 100 kb/d to 12,400 kb/d. See chart. The October EIA monthly production at 12,100 kb/d is from the November MER. Just wondering if it just averages the weekly numbers until better info is collected. The STEO production for the L48 for November is 12.54kb/d. Looks a bit high for November, when compared to the weekly data.
300 kpd plus in just one month is a good boom. Annually round about a grow rate of 4 mbd, a new Ghawar each year.
Makes one wonder if we are in the age of Fake News.
Ovi
The best estimate is the EIA monthly estimate.
Everything else is a guess.
The tight oil production estimate by play is also pretty good.
DPR, weekly, and STEO are not very good, imho they are best ignored.
Are you clear now on the well volume?
Dennis
What was confusing me was well spacing. My impression was that a well had one long main hole, say 3000m long with a diameter of 1/3 of a metre. Off this main hole, there would be a number of lateral holes of say 1000m long and 0.1 m diameter that fed the main hole. Something like a leaf pattern, main stem with side stems. This is the impression I got from reading Twilight in the Desert. What you are showing is a different but similar concept. Thanks for explaining.
Ovi, what you are describing, almost but not quite, is a multiple reservoir contact well. Known as MRC wells. Saudi has some of them but they are not as common as just an ordinary horizontal well with only one wellbore. The wellbore and all the branches of a MRC well are always the same diameter because they are all drilled with the same diameter bit.
A fracked well is never an MRC well. It only has one wellbore. The rock around the wellbore is fractured with intense pressure from the equipment above. The furthest point is fractured first. Then the wellbore is plugged at that point and another fracture takes place. Many fractures take place in this way. Then when all the fractures are done, all the plugs are drilled out and the well is put into service.
That is interesting Ron, as I have read after fracking they add water,gel solution and propant to keep fraction open as long as possible. In a sand stone reservoir there is normaly over pressure or water, gaz can be injected to make the oil flow. In shale I guess the oil is situated between layers of hard rock. Is the Areas where the oil is situated overpresure , is it vacum in the production pipe how do they get the oil to the surface, is it flowing of it self?
In shale I guess the oil is situated between layers of hard rock.
No, that is not quite right. The oil is in the shale rock, not between the layers. All sedimentary rock has pores. These pores either contain oil or water. Most, of course, contain water but some contain oil or a combination of oil and water. the pores in shale are very small or tight. In normal oil bearing rock the water pressure from below pushes the oil up to the “reservoir rock” where it is trapped.
But in some shale, the pores are so small and tight the oil cannot escape. That’s why they call it “tight oil”. But if you blast the rock apart, or fracture it, the oil can escape.
There is, not always but usually, pressure from below that forces the oil out into the wellbore. But most often the oil still needs an artificial lift to get it to the surface.
Hope this helps.
Ron
Most tight oil wells start with no artificial lift. As the pressure falls as oil and natural gas are removed eventually many wells go to artificial lift towards the tail end of output.
That varies from well to well.
Thanks Ron
See my answer to Dennis below. Between you and him I now understand the context in which lateral is used. I mistakenly took the MRC pattern and assumed it was being used to extract LTO. The multiple holes being drilled look very efficient. The other piece of info that confused me was the use of direction rigs vs horizontal rigs. I thought that the directional rigs were used to drill the lateral well bores from the main well bore.
Ovi
Fairly sure most tight oil wells are drilled with so called horizontal rigs.
Dennis
Recalling an article I read a while back and a clearer understanding of the word lateral, I think that directional rigs let one rig drill three wellbores from on location before having to move. Think of a three pronged fork. The drill head would do one horizontal well. Then another one, 300 meters to the left or right by heading down at an angle and then horizontal and parallel to the first one 300 meters over. This saves the driller time since they do not have to dismantle and move the rig.
Upon reflection, I think this is what my takeaway was from the article. It will be interesting to hear from some experts on this site on the use and role of directional rigs.
Ovi
For KSA that is a correct description.
For shale plays we have a vertical section to get to proper depth then a curved section to get to roughly horizontal and then a horizontal lateral at 5000 to 10000 feet. The 3000 meter estimate is the lateral length and the 300 m spacing is the distance between horizontal laterals which are roughly parallel.
Thanks Dennis
I now understand the context in which lateral is used when discussing LTO extraction. It is used the describe the change in direction from vertical to horizontal. As I mentioned above, and Ron confirmed, my thinking was influenced by my understanding of Saudi MRC wells.
There are times when understanding the correct meaning of terminology is critical. See my answer to Ron above that further explains my source of confusion.
That was impressive growth, wonder if the if monthly decline of DUCs increase with such impressive growth…
Tony
No you are not understanding Enno’s Charts.
What you have defined as tier 1, 2 etc is not correct.
Even a tier 1 well declines quickly. Use productivity distribution to judge tier 1, tier 2, by looking at 24 month cumulative output.
The chart you are using just gives daily output of all wells in different bins. Older wells have lower output whether tier 1 or tier 2.
Eagle Ford update from
https://shaleprofile.com/2019/11/27/eagle-ford-update-through-august-2019/
Tier 1 production from wells > 800bd continues decline as sweet spots decline. Tier 1 production was 250kbd in June 2018 and in Aug 2019, 155 kbd, a drop of 38%.
Not tier 1 Tony just newer wells. A lower completion rate would result in fewer high output wells.
Link to high output wells from 2015 to 2016 for Eagle Ford.
“https://public.tableau.com/shared/SMCS5HHYJ?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y”
The decline in wells with output more than 800 b/d was due to fewer completions.
Need to copy paste link.
Fewer completions? It really doesn’t matter. Declining production is declining production, no matter what causes it.
There is a reason drillers are drilling fewer wells. They are running out of good spots to drill.
Ron,
Perhaps, or oil prices are too low for a high completion rate to be profitable. I assume you are aware that oil prices fell quite a bit since Oct 2018, that affects profits. There is little evidence that average well productivity has fallen in either the Bakken or Permian, it has fallen a bit in Eagle Ford, but a higher completion rate could easily offset the falling productivity and so far the evidence is that output in the Eagle Ford has been flat, so that is exactly what is likely to be occurring.
Enno Peters says about Eagle Ford:
Oil production in the basin has hovered around 1.3 million bo/d since the start of this year. Through August, just over 5 wells have been completed every day, on average, which has countered the natural decline in legacy wells.
https://shaleprofile.com/2019/11/27/eagle-ford-update-through-august-2019/
Eagle Ford Average well profile for 2017 and 2018, 2017 was the peak average productivity, not a huge change in 2018.
If prices are low but they need cash flow to avoid bankruptcy, why would they not complete the best known producers? Makes no sense that companies that can’t wait are choosing to complete less profitable wells.
They are not, ofc they complete the best locations first no matter price of oil.
The companies that went belly up already did so drilling their best locations.
The ones that are struggling today or barely makes a living did so drilling their best stuff.
Eagle Ford 2018 wells production level. note that nowhere on shaleprofile are these referred to as tier 1, tier 2, etc, it is simply output level bins.
“https://public.tableau.com/shared/TG7HJ825Q?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y”
copy and paste link above to see better resolution image
The world’s biggest shale patch is now officially a drag on jobs creation in the Lone Star state.
Employment in the Permian Basin of West Texas has fallen by 400 jobs through the first 10 months of the year, a massive change from the 16,700 jobs added through the same period last year, according to a report Wednesday from the Federal Reserve Bank of Dallas.
“Permian Basin job growth has been sluggish this year,” according to the report. “This marks the first time since 2016 that Permian Basin employment has lagged Texas job growth.”
https://www.dallasnews.com/business/energy/2019/11/27/dallas-fed-permian-basin-slowdown-is-creating-a-drag-on-texas-jobs-machine/
Business investment is waking up to the change in the oil patch. Think you all will find this interesting also…
https://app.hedgeye.com/insights/79437-a-real-conversation-with-mark-gordon-an-unprecedented-opportunity-i
Karen,
Mark Gordon does a great job talking about oil in an hour interview. He says Bakken and Eagle Ford declining but Permian still showing strength.
However, Shaleprofile is showing some weakness in the Permian as Tier 1 production from wells > 800bd shows recent decline as sweet spots decline. Tier 1 production was 818kbd in Mar 2019 and in Aug 2019, 688kbd, a drop of 16%. As more well data is gathered by Shaleprofile, this decline might be less of a drop, say 10% but still showing weakness.
https://shaleprofile.com/2019/11/21/permian-update-through-august-2019/
Tony,
Paper below discusses tier 1 to tier x wells in the Bakken, see especially pages 4-5 and 7-8. Also see table 2 after page 24. The tiers are based on initial well productivity.
https://agecograds.tamu.edu//wp-content/uploads/sites/49/2016/11/Shale-Oil-Supply.pdf
Thanks for this link espesialy table 4 page 25 that stated break even price for different
well types Tiere 6 -1. Seems Tiere 6 will mean sweet spots WTI 18 USD , but that is history I believe.
Thank you Karen,
I only read the text, didn’t watch the video, interesting and I agree with Gordon’s analysis.
I don’t think this article on Int’l oil consumption and production by country and region has been shared.
Another excellent one by Matt.
http://crudeoilpeak.info/uncertainties-following-the-abqaiq-attack-have-shrunk-the-worlds-safe-oil-reserves-by-around-half-part-2
ASPO Germany just released an analysis of IEA WEO 2019 and stated that world peak oil is within five years.
http://aspo-deutschland.de/dokumente/2019-11-21AnalysisOfWEO2019-ASPO-de.pdf
My guess is that world peak oil will happen in 2021 which also is when I guess that US shale oil peaks. This peak year of 2021 is similar to a forecast by DNV earlier this year. DNV said peak crude oil production would be 87 mbd in 2022, excluding NGLs and other liquids.
https://eto.dnvgl.com/2019
I have added the black text box, triangle and line to ASPO Germany’s chart.
Thanks for the links and info Tony, I really appreciate it. Great stuff!
DNV chart
Here is forecast from McKinsey earlier this year showing a peak of 105mbd in 2025, as shown by orange line below.
https://www.mckinsey.com/solutions/energy-insights/global-oil-supply-demand-outlook-to-2035/~/media/231FB01E4937431B8BA070CC55AA572E.ashx
Tony,
That is a demand peak due to rapid increase in EVs. It is not McKinsey’s forecast of the most likely development.
The ASPO graph is similar to the 2019 Exxon View to 2040 graph depicting a peak around 2040 with a number of new fields that have to be found and developed.
As a side note, I have been following each iteration of Exxon’s graph and I’m noticing an inflection point occurring earlier (2039?) between the 2016 and 2019 chart.
The McKinsey graph is very interesting and I read this article:
http://electric-vehicle-discussion-list.413529.n4.nabble.com/EVLN-Nikola-claims-4x-energy-2k-cycle-50-cheaper-li-ion-tp4695719.html and if true, this is a game changer for faster EV adoption. “The news comes with claims of a cathode with 4 times the energy density of today’s lithium-ion cells, lasts for 2,000 cycles, and at a cell cost of 50% less than today’s lithium-ion cells.” But I’ve seen a lot of these claims before and there is usually some critical factor left out.
TonyEriksen,
US tight oil is already at 8 Mb/d, the IEA is predicting 10.5 Mb/d tight oil output in 2025. That is an increase 400 kb/d each year, of we assume tight oil reaches 10.5 Mb/d in Oct 2025.
Doubtful peak will be 2021 for tight oil in my view, 2025 not a bad guess though and 10 to 11 Mb/d for tight oil is reasonable. World peak in 2025 also seems reasonable unless oil prices remain low long term.
Mark Gordon analyzes the industry from an investor’s perspective and says that the Permian still has room to increase production substantially with higher prices, but to expect very little production increase in the Bakken or Eagleford. He also says that low prices created by fracking (ironically in anticipation that prices would move steadily upward to 200 a barrel, an anticipation that they themselves temporarily short circuited) postponed “Hubbert’s peak” to a later date when the total resource will be closer to 60% than 50% depleted. He cites very mainstream sources to support his forecast that peak oil will return with a vengeance in 2021, and he expects prices to start surging in 2020. A must-hear conversation between Gordon and hedge fund CEO Keith McCullough, although Gordon does most of the talking:
https://www.youtube.com/watch?v=dhc6vyxVsDs
Mark Gordon is feeding people what they want to hear. The run up to the 2008 highs. Was that due to oil scarcity? Was there any orders not getting filled? Exactly who didn’t get the oil they needed during the run up to 2008’s highs. Last time i checked Saudi Arabia doesn’t look at their stock and say hey we got way too much oil lets cut price. Or we don’t have near enough oil so lets charge more. Refineries are the only buyers of crude. Oil producer can adjust their production. Big deal. So what. Supply and demand don’t matter as much as people believe it does.
There is only one thing that matters. That is monetary liquidity. Think about this for a minute. If there were no trade wars or anything else that would weigh the economy down. What would the FED’s or any other central banks excuse for the next round of monetary easing be? They’d have to create an excuse. There has to always be a reason for further rate cuts and more QE. Because if there isn’t a reason then QE would stop and rates would rise and well the debt bubble would be no longer expanding. It would be contracting in leaps and bounds.
People believe this is a real economy that works on principles like supply and demand. It’s not. It works on liquidity. If oil ever makes it back $100 it will be because someone flooded the market with on going liquidity. The run up to $2008 high was liquidity created mainly by the largest banks in the world (not central banks) they bid it up with leverage. Mark Gordon is well aware of this. They know better than to do it again. The end result was almost the death of them.
The demand side is not at the reffineries – it’s at the gas station.
Believe me, with 10$ / barrel oil there would be much more traffic all around the world and we would have a demand of 150 mb/ day right now. Even african bush taxis would drive more frequently.
When european govenments would remove our high gas taxes (we’re at 1,35€ / litre at the moment), we would see much more pickup trucks and SUVs here, too – and bigger ones. And more fast driving on the Autobahn.
But there seems to be little incentive for European countries to do that.
Why should they, it would be completely useless.
Yes, the tax increase is going to be on EVs if they ever reach meaningful numbers.
We also have already round about 60% tax on electricity here – a Kwh goes for round about 25 cents. Not too much space to increase even further.
Dont underestimate politicians when it comes to increasing taxes in socialist countries. In mine it will for sure be more on electricity exactly as you mention but if EVs start to get numerous they need to fill the tax gap created on petrol. Petrol is about 60% tax atm and increasing.
It would create a gap in the budget, it will simply not be allowed, so there will be new taxes directed on EVs specific and on cars in general to decouple it from engine and fuel type.
So your from Germany? Would you say the all in on “renewables” in Germany is cause of your comparable high electricity cost?
HHH,
Liquidity matters, but is not everything, actual demand matters as well. After GFC, lots of liquidity pumped into economy, in response the velocity of money fell as money sat in bank accounts, but not much was spent. Money supply is important, as is actual demand for goods and services.
From the report from Bakken Case Study 2015 link earlier this site , table 4 page 25. wells > 800 Tiere 6 break even cost 18 USD each barrel , Tiere 5 400-800 bpd 47 usd , Tiere 4 200-400 bpd 128 usd , Tiere 3 100-200 374 usd , Tiere 2 50-100 bpd 1 141 usd , and Tiere 1 no limit for break even price. All prices WTI 2015 USD. There are several factors impacting the break even price and one of the most important is productivity, we assume cost of exstracting the tight oil will go down. Latest productivity report tells this have now almost stopped, in the report it is also stated the fact that what DUCs are fracked is the one with highest potential and that is why in average wells put in production will have lower production and higher break even price. The Question is will majours like Exxon abd Chevron be able to offset the increased break even price based on Tiere clasification by improving the fundamebtals as drilling productivity also implemented the fact development on drilling , fracking , propant, fluid have been ongoing for decades.?
Freddy,
Note that the tier 1 to tier 6 is based on initial productivity over first 30 days of output. This is different from the production level shown at shale profile where wells >800 b/d are all producing wells whether they are tier 1, or tier x as far as initial productivity. For the average 2017 Eagle Ford well (about 37% of wells are better than average), after 18 months the well with mean productivity will be at about 100 b/d of output. There are a lot of wells (over 60%) that are below average and many wells that are 18 months old or older, so output of wells between 100 and 200 b/d has very little to do with whether they are tier 1 or tier 4 wells.
Dennis, from the report it was stated they masured the average production after 30 days and from this they categorized whether it was Thiere 6 or 3…, I believe the break even cost is related to life time production and adding all cost with some inflation. There is also used a factor for improvement of fracking tecnology, drilling routines . One thing that might should be implemented is the impact off drilling many wells related to fractions in the structure, increased water cut and in general reduced input as the Area is getting drained from oil gradualy. There will also be cost off frack hits that starting increase . I wonder what is the average barrel shale oil today produve from, guess that might be Thiere 4 or 5 from this table 800-400 barrels pr. day and the breake even price of that is more than 50 usd WTI, that might exsplain why the ballance sheet of Exxon is covered by red inc and they need to sell assets to pay dividend and invest in shale.
Freddy,
See page 7-8 of the study.
For all other wells, we know the reported Initial Production (IP) rate, which measures the average daily flow of oil from the well over the first 30 days of operation.
The IP30 rate (where IP stands for initial production) is the average rate of output over the first 30 days of output. For a tight oil well it is typically the peak production rate over any 30 days of the well’s output over its productive life. This is what I mean by initial productivity over the first 30 days (whether we use the cumulative 30 day output or divide by 30 to get average output over that 30 days is of little consequence).
Dennis
You may have some error about Bakken/Three Forks. Having 44000 wells possible on 10 400 000 acres means 236.4 acres/well , not 423.9 as you posted. ( 10400000 / 44000 = 236.3636… ). Otherwise, with 424 acres/well , only 24530 wells are possible.
Thanks Alex,
I made some errors on my Bakken calculations.
The volume calculation is correct, as is the number of wells, but the net acre calculation is 18.6 million net acres, so 18600000/44000=423 acres per well. The only mistake was incorrect net acres, not sure what number I picked from the spreadsheet. For the Bakken USGS report they report “sweet” and non-sweet acres, the only report to do so, about 33,000 wells in “sweet areas”. When I use the reported sweet spot EUR, basically all of the undiscovered TRR is in the sweet spots, with about 14 million net acres and 33,000 wells, net volume of sweet spots is 2700 million acre-feet, average thickness is 192 feet for sweet spots.
November IEA OMR is available to public now
https://www.iea.org/media/omrreports/fullissues/2019-11-15.pdf
Could the IEA be reading peakoilbarrel? This chart seems to be based on my chart but with monthly changes added.
I’ve modified my chart to include monthly changes. If the shale slowdown is happening faster than is assumed, then those monthly changes could become negative within a few months, indicating that US shale oil production has hit a peak.
The DPR estimates for legacy decline are often revised significantly.
They seem to simply extrapolate past trends.
This misses changes when completion rate changes.
If completion rate decreases, the decrease in legacy production gets smaller in magnitude. DPR tends to miss this.
Bahzenov items:
74.6 billion barrels recoverable from 1.24 trillion barrels OOIP.
285 TCF of gas recoverable from 1.92 Tcf
(That is EIA data and is probably not impartial.)
Equinor is exploiting a loophole in sanctions and likely will get involved with development. The loophole seems to be exploring for unconventional deposits. BP has evaluated the same loophole and is asking to be involved with Rosneft.
Schlumberger seems to have found yet another loophole. They have bought a 51% interest in a Russian company that can purchase high pressure pumps and fracking equipment. Eurasian Drilling Company EDC.
Gazpromneft expects 8 million boepd to flow by 2022. The mix was not laid out numerically but the text suggested at least 10% oil.
Credible only because of infrastructure already in place in that region.
The project is insulated from mineral extraction tax for 15 years from date of first flow. There will be no export duty on Bahzenov oil.
I found no assay, but there was an explicit mention that the oil is more viscous than US shale and this will almost certainly mean much more richly endowed with diesel.
Any production rates yet?
Sorry, Watcher, you said 10% oil or 0.8 mbd. Could you please provide a link?
I will be surpriced if Equinor get involved in more shale plays after their investment in EF that have been a disaster.
For reasons unknown links sometimes send posts somewhere other than display. You have to get your own links.
But I’ll help. The stuff about loopholes in sanctions dated July and another August 2017 Reuters and Exxon and others tried staying involved 2015 time frame when sanctions then tightened.
Gazpromneft initially quoted commercial production for 2025. That was Reuters March 2018. They updated that production amount and time frame to 2022-2023. Oil viscosity data from Carnegie Endowment paper May 2018.
Or y’all can not bother looking it up and just ignore all of it. Always a viable option. Nothing anyone says here will affect anything.
Based on the EIA drilling productivity report there was at end of October 7642 DUC’s left in US Shale plays. The number decrease by 225 last month, 45 was in Permian. I believe this number will increase as a result off more Thiere 4-5 wells with lower output will be drilled and cash flow need to be stable or increase to pay the bills. It means until 01.08.2020 the nomber of DUC’s might be declined by 25-35%. Acc. to report the best DUC’s is the first used it might be than the DUC’s remain has below 400 bpd , that break even price might be 3x 50 usd WTI. EIA exspect the Majours shall save US shale and add increase of more than 1 mbpd in 2020. That might be a miracle in a 50-60 WTI environment.
https://www.eia.gov/petroleum/drilling/#tabs-summary-3
Two new posts
http://peakoilbarrel.com/is-us-oil-production-growth-slowing/
http://peakoilbarrel.com/open-thread-non-petroleum-december-1-2019/