The North Dakota Department of Mineral Resources has released production numbers for The Bakken and for All North Dakota.
North Dakota surpassed one million barrels per day for the first time. ND production averaged 1,001,149 barrels per day in April while Bakken only production was 937,263 bp/d.
There were 218 additional wells in the Bakken and 225 additional wells in all North Dakota.
From the Director’s Cut, bold mine:
Comments:
The drilling rig count was down slightly from March to April and back up one rig from
April to May. The number of well completions was unchanged at 200. The Tioga gas
plant conversion transitioned from approximately 25% capacity at the beginning of the
month to full capacity by the end of April. Weather continued to impact activity in April with 3 days of road closures due to the heavy rain at the end of the month and 9 to 11
days with wind speeds in excess of 35 mph, too high for completion work.
At the end of April there were about 600 wells waiting on completion services, a decrease of 35.
600 wells is a lot of wells. If they stopped drilling new wells tomorrow it would be three months before anything changed. I am not sure if this 600 includes only wells awaiting fracking or all wells that are in the process of being drilled plus all wells awaiting fracking. If anyone can answer this question please post it in the comments section.
Bakken barrels per day decreased but only slightly, from 23,360 in March to 23,257 in April, a drop of 103 barrels per day. This is a rather important stat. Even though additional wells increased from 188 in March to 218 in April, the increase in production dropped by over 100 barrels per day. Well completions held steady at 200. The additional well in production number varies because some wells that had been shut down were brought back on line.
North Dakota has 10,317 producing wells, 7,468 of those wells are in the Bakken.
Barrels per day per well seems to have leveled out at 126 Bakken, 97 for North Dakota and 22 for all North Dakota wells outside the Bakken.
I know this is a rather short post but there is just not much else to report about the Bakken data release. I will have another post in a few days on Bakken production by county and also a Texas RRC report.
Thanks Ron.
Based on all in the individual well reports in the latest NDIC data, I also updated the following analyses (see graphs below):
1) Average cumulative well output : This shows that on average wells in North Dakota have somewhat improved since 2008 (higher cumulative output measured at similar moments in the wells life cycles), although so far 2014 wells produce somewhat less than 2013 wells. Also, 2012 wells are now dipping below the level of 2010 & 2011 wells. Based on this graph I conclude that new wells no longer seem to increase in quality, but are as of yet also not yet worsening.
2) Average monthly well output : Wells since 2010 have higher initial output, but you can see that after a year or so the monthly output is very similar as earlier wells.
3) Quality and quantity of new wells : March and April seem to have been good months for North Dakota. The average new well peak output (red graph) has gone up again in March to the middle of the 12000-16000 range that has been typical during the last 4 years. The number of new wells that started to produce has grown in the months feb-april.
4) Contribution of past wells to the total output : This graph shows for each month the total amount of oil produced in North Dakota (in bpd), and in which year the wells that are contributing started production. You can see that output from wells drilled in 2012 and earlier (the orange area and below) now produce almost half of what they produced at the end of 2012.
5) Dead wells : I was interested to see which % of wells are no longer producing with the aging of wells. This graph shows this %. After a year (month 11) producing just over 1% of the wells no longer have output, which increases to about 3% when wells have produced for about 3 years. Note that because there are not many wells yes that have produced more than 40 months, I expect the trend at the right of the chart to change relatively more with time passing.
Note : in earlier analyses I had a constraint that a well needed a minimum peak output of 1000 barrels in a month to be counted in the first 2 analyses. I now completely dropped this requirement.
Enno,
Great analysis!
Could you please give some more explanation about the “Dead Wells” graph? I understand it should be a continously increasing graph, but that is clearly not the case. Are some wells reopened, causing your graph to go down, or do I see things wrongly?
Hi Verwimp,
Yes, this looks a bit counter intuitive, but the reason is not difficult: many wells did not progress so far out yet in their life cycle, including some of the dead wells. I expect eventually that this function of dead wells will continue to nicely slope upwards, but it’s a random process and especially in the region where there is not much data yet, there will be more fluctuation. To clarify, see the graph below which shows the numerator and denominator to calculate that function. It shows how many wells since June 2009 (after which the average well production stabilized into the current production profile) have passed through which month in the well life cycle, and how many wells were non producing from the wells that passed that moment in well life.
Sure! It’s an inventory, not an evolution. That keeps confusing me.
That looks like 60% of total oil production is coming from wells less than 17 mos old.
Good evening, Watcher. While I am certainly not a “chart and graph guy” as a commentator posted months ago in a somewhat lighthearted jibe at the preponderance of charts/graphs on this site, if you are indeed accurate about 60% of production coming from wells less than a year and a half old, I would not be surprised.
Contrary to the oft repeated canard that “the sweet spots are drilled first” and therefore future production will be in increasingly poorer locations, the sweet spots have not even been remotely developed. What they HAVE had happened was to be rapidly “punched” and SOME hydrocarbons produced so as to protect the leases of the companies. In the “core of the core” sweet spot – the Parshall field in the Bakken, EOG has only one or two retention wells sitting on each 2 square mile Drilling Spacing Unit. They can/will return when it’s best for them (lottsa factors come into play), and – if the downspacing of others is a guide – drill 10 , 16, 24 wells of a far, far higher productive nature on each DSU which is now only producing a relative pittance of oil. (This is where Continental’s 26,000 barrels IP on their Rolfsted pad comes to mind.)
And this leads to Mr. Patterson’s curiosity of the 600 wells awaiting completion in the Bak … At the moment there is no ‘backlog/waiting’ for frac companies to do their thing. What IS happening is the huge increase in pad drilling with 4 to 12 or more wells being drilled essentially simultaneously and – as a consequence – will be fraced accordingly in groups as to save money. IOW, an 8 well pad will have up to 7 wells waiting to be fraced, then all at once will be done.
The months of August through December (the NDIC’s report has a 2 month lag) should show ‘off the chart’ (hadda throw that in there) production numbers.
The biggest decline recorded for a month was weather related, but that month had a decent number of new wells completed. What smacked production was less a scarcity of new wells than it was trucks hauling oil, not proppant, were scarce.
Trucks don’t just decide how fast wells are completed; they also decide oil production from completed wells. I haven’t heard anything about roads to multi well pads getting wider.
As for sweet spot scarcity not appearing, 60 stages on a sour spot might out produce a 30 stage well on a sweet spot. I don’t think we have definitive evidence yet that down spacing does not cannibalize an adjacent well, but if CLR does embrace that for ALL new drilling, we’ll know they think it’s safe.
IOW, an 8 well pad will have up to 7 wells waiting to be fraced, then all at once will be done.
Absurd! Fracking 7 wells all at once? One well cannot be fracked “all at once”. They can only frack one stage at a time. Then they plug that stage, back up and frack another stage and so on. Then they drill out all the plugs. You sure as hell cannot frack 7 wells on the same pad all at once.
I somewhat don’t understand the process of “one stage at a time” vs 30 at a time or 60 at a time, but the probabilities seem very low that there exists a pump that can apply enough pressure to 7 wells simultaneously and get the fracturing needed. That’s hard to imagine.
The mind also boggles at the weight of the proppant and water required to be sitting at that site for 60 stages in each of 7 wells.
I’m okay with stage count increase per well and ramping production per well that way, but nah, there aren’t any pumps that big to be doing multiple wells simultaneously.
I somewhat don’t understand the process of “one stage at a time” vs 30 at a time or 60 at a time, but the probabilities seem very low that there exists a pump that can apply enough pressure to 7 wells simultaneously and get the fracturing needed. That’s hard to imagine.
Okay, each well has 29 frack stages. These stages must be frcked one at a time. According to this video it takes three days to frack 29 stages. Watch it and you will understand.
What Is Fracking?
What this video does not show is that after each frack stage a plug must be inserted to keep the fracking fluid from going into stages already fracked. Then after the fracking is complete the plugs must all be drilled out. I saw that in one video but I could not find that one.
I don’t know that 29 stages is standard but that is the number this video uses. I guess it could be more or less. But they show a 2 mile lateral with 29 stages.
Good vid. The new downspacing experiments did get up to 60 stages and the talk was CLR may make such things the “new completion standard” vs 30 now — but the quarterly report did not outright claim that downspacing was not going to impact adjacent wells and a few of their results were suspect in that regard.
Another big deal was that the fracking is 3D and there were suggestions that the well output was not a legitimate measure because it was tapping downwards into TF layers, not just Bakken. You’re not really verifying your technique has no horizontal impact on adjacent wells of a pad if some of your output is a new vertical layer.
The vid btw notes 3 days to do 30 stages.
5 million pounds of proppant and 2ish million pounds of water is 7 million pounds hauled on trucks with about 75,000 pound max. The trips would only be about 15 miles, but on loading and off loading can’t be instant, and given that photo of **bags** of proppant, I’m going to say 2+ hours to load and another 2 to offload. You might get 2 trips a day, maybe.
This smells like at least a week to get all the proppant and water on site for 1 well.
Greetings, Mr. Patterson. For a glimpse – perhaps – at the future direction of well completion/stimulation – the short videos presented by Baker Hughes (Optiport) and NCS Energy Services might show what is to come. At least that is what a few in the fracing industry are saying as this type of Coiled Tubing Unit deployed offers several significant advantages over the current models. Time-saving, live time control/adjustment, much more effective/measurable stimulation, and future re-fracs doable in an economically viable manner.
Whiting’s 1Qtr conference call this past May described some of the benefits as well as results.
You’ve quoted that before, but CLR is the dominant lease holder and they lead the charge on everything.
If they aren’t doing something, it’s not going to be done at a magnitude that will affect numbers.
Exactly.
Enno,
A couple of months ago, you kindly sent me your metadata. That was an earlier version of the data you present here today. Nevertheless, for the essence of the story here that is not crucial.
I was intrigued by the graph “Average Cumulative Well Production per Starting Year.” This is a bunch of curves, but the curves are “family” of eachother. I tried to reverse engineer these graphs with mathematical functions. That is the empirical way. I found out the curves were best fit with functions from the form:
y=a*((2/pi)*(arctan(b*t)))^0.75
The broken exponent 0.75 makes clear it is an empirical formula, since broken exponents seldom make real fysical sense. Anyway: the nice thing is: I could keep this exponent constant for each curve, thereby excluding a variable parameter.
That leaves only two parameters:
a = the ultimate amount of oil one average well from the considered starting year will ultimately produce. That is the hight of the curve at the end (t=infinite). It is clear that the “sweeter” the spot, the higher variable ‘a’ will be.
b = a variable that defines the steepness of the curve at the beginning. It means a measure for the speed at which one runs through the resource base: the steeper the curve at the start, the faster the value of ‘a’ will be approached. The more sophisticated the technology, the higher the oil production will be… at the start.
After having made that exercise for every starting year, I got a row of different ‘a’ and ‘b’. There is a rather clear evolution. ‘a’ is dropping since 2010. That is a confirmation of the ‘sweet spot’ assumption. ‘b’ keeps on rising. That means technology is still improving. So I could extrapolate the evolution of ‘a’ and ‘b’. That meant I was able to ‘predict’ the future cumulative curves! 🙂
Then the only thing left to do was make a reasonable guess for the amount of wells that will be drilled for each starting year, transform the cumulative function in a production curve, add it all up and this is the result: Bakken will peak in early 2016. The steepness of the downslope will be smaller than the upslope (That is more Dennis-Style 🙂 ).
Note:
1) Left axis is barrels per month.
2) This is all based on an earlier version of the Enno data, witch did not contain 100% of the wells.
3) This story is about the shape of the curve, about the location in time of the peak, and about the magnitude of maximum production. Not about precise numbers!
I love it! I often imagined those future curves on top of what we had so far, great to finally see it.
I miss seeing a seasonal effect;-)
I’ll share my latest version gladly if I can have a peek at this.
Hi Verwimp,
I think this is a big improvement over a Hubbert curve. I would ignore any hints you think you might be getting from a Hubbert linearization (as you mentioned before, the method is rather weak). So the peak is expected at around 1 million barrels per day, interesting. Your analysis seems to end in 2020, I assume if the analysis was extended out to 2030 it would follow the curve from 2017 to 2021. How many wells out to 2020? Cumulative output to 2020? Great work!
Dennis, Please note this analysis did not take into account 100% of the ND Wells. So the peak will be something like 15% higher. Number of wells, please see below.
Six months after it was built it is time to evaluate the Season Effect Model. Winter conditions in North Dakota were more severe than average, so it is no surprise the data are lower than the model predicted.
The extent of the winter dip was modelled correctly: Bakken seems to have recovered. That is also clear by looking at the really close match between the first derivative of the model and the 5mth moving average of the change in the data. So I do not see the need of fiddling with the parameters.
The model predicts another surge in production now, reaching a new peak in October – November 2014. Depending on the winter conditions, the than following dip will be more or less deep. But by spring 2015 the Red Queen effect may start to really kick in, leading to a much less significant surge in the summer months of 2015.
The next peak in October – November 2015 has a great chance to be the all-time peak, because the Red Queen will make it really difficult for Bakken to recover from the winter 2015/16 dip.
This is all in an unchanged economic context (oil price, free money, …).
Love this work, Verwimp, Enno, DC, et al….
Oil company CEO Hamm predicts 2 million barrels per day potential
Today it takes about 150 wells per month just to offset decline. So if they ever did reach 2 million barrels per day in the Bakken then it would take about 300 new wells per month just to stay even. And those 300 wells would have to be as productive as the wells they are drilling today. In other words the sweet spots would need to stay just as sweet and not drop off any.
I just don’t think either is going to happen. They will not add 300 wells per month and the sweet spots will not stay just as sweet.
Hi Ron,
I think you mean 150 wells per month 🙂
The average wells per month has been about 150 wells per month for about 2 years. The 200 new wells would produce about 77 kb/d if they are average wells. Output increased by 23 kb/d so old wells declined by 54 kb/d, this would result in about 140 wells needed to stay even.
Such a calculation does not consider that the decline rate of legacy wells decreases over time.
When I use the Bakken model to see what number of wells keeps output relatively flat (a slight dip as the number of new wells decreases from 200 well completions to 100 well completions per month and then rising later). Note that lately the output has been somewhat higher than the model predicts so well productivity may be increasing with more proppant and frack stages.
Chart below assumes 100 new wells added each month from May 2014 to Jan 2016 with no change in well productivity(new well EUR) over that period.
I made a mistake on the chart above and in my spreadsheet, it is incorrect. Corrected chart below, 110 wells per month keeps output relatively flat if new well EUR is unchanged from May2014 to Jan 2016, it has been increasing over the period from mid 2013 to the present (roughly 8%).
Dennis, I have corrected my typo. The North Dakota stats do not record the number of well completions. What they do record is “wells producing”. And we can subtract each month from the previous month to find out how many “additional producing wells” there were that month.
However that does not tell us how many well completions there were that month. Usually a lot of wells were shut down. If you notice many months, especially in the “All North Dakota” stats show a negative number in additional wells.
Director’s Cut March 2013
January brought us winter storm Gandolph followed by over a week of sub-zero temperatures and wind chills. Even though the drilling rig count held in the middle 180s rig efficiency fell and the number of well completions plummeted 26% to 85. That number of completions is half previous 12 month average and below the threshold needed to maintain production.
That means the average number of new well completions the previous 12 months were 170.
Now look at the chart below. “Additional wells” in December 2013 were -51. Yet: Director’s Cut February 2014
The drilling rig count was up from Nov to Dec, but the number of well completions dropped from 138 to 119. Days from spud to initial production increased 18 days to 132.
And North Dakota production in December plunged 50,000 barrels per day. But the point is though additional “Wells Producing” have averaged about 150 per month “Wells Completed” have been well above that number, or they were in 2012 anyway.
Hi Ron,
Good point. I will attempt to adjust my model accordingly.
I think Helms may have miscalculated based on the Monthly Report (not the Director’s cut).
In Jan 2013 there were 9277 wells capable of producing and in Jan 2012 there were 7397, if we take the difference and divide by 12 we get about 157 wells added per month. However for Jan 2013 to Jan 2014 I get 174 wells per month on average.
So I agree with you (in case that was not clear). Excellent point.
So based on the excellent observation by Ron, I adjusted the model to use estimated well completion data, the increased number of wells required a reduction in the average well profile by 5 %, there is still an overestimate of output during much of 2013 and then an underestimate for early 2014. The number of wells needed to remain flat (the Red Queen number) is about 110 wells.
Chart below.
Dennis, this is an uncertain science. But we could make it an exact science if we knew just two numbers.
1. The Legacy Decline Rate
2. Average first months production of new wells.
The EIA says the legacy decline rate is about 70,000 barrels per day. I tend to agree with that number. I have read several reports that puts the average production per well for the first month at about 400 barrels per day. That number seems a bit low. If that were the case it would take about 175 new wells per month to stay even.
But if we use 500 barrels per day for the average new well then it would take 140 new wells per month just to stay flat. That sounds about right.
But if we assume it would only take 110 new wells then the average new well would need to produce 636 barrels per day the first month. I think that is a tad too high.
Of course you may dispute the IEA’s Drilling Productivity Report that the Bakken Legacy Decline Rate is 70,000 barrels per day. But I think that number is pretty accurate. The chart below says it is 72 but that is for July. This is June and the legacy decline rate is increasing by about 1.5 kb/d each month. Of course that would stop increasing if production stopped increasing.
If you are wondering, the EIA Drilling Productivity Report puts the Bakken decline rate at 6.6 percent per month.
Hi Ron,
There are a number of problems with the drilling productivity report, most of which you have posted about.
The number that the EIA uses for the output of new wells is too high the increase from 200 completed wells is about 76 kb/d, legacy decrease in April was about 53 kb/d. I think the 70 kb/d legacy decline number is incorrect (also it includes Montana which confounds the analysis).
If the number of wells completed falls to 110 from 170, the legacy well decline will become smaller (in absolute value), so whatever the legacy decline number really is at present, it does not remain fixed. Look at Haynesville natural gas charts to see what happens to legacy decline when the number of wells completed decreases.
We will have to just disagree on this, the drilling productivity report is not very good.
Hi Ron,
On the idea of an exact science, part of the problem is that the legacy decline is a moving target.
As the number of wells completed decreases the legacy decline becomes larger (or smaller in absolute value).
Dennis, I have replied below in an original post in order to get the post wide enough for graphs.
Hi Dennis,
Does this Chart with the Flatline production through 2018 include the amount of land available for drilling in the 4 counties? Does any one have any data that would estimate when they would run out of areas to drill over the sweet spot? I suspect this is available but I thought I would ask anyway.
Correction:
I suspect this is NOT available but I thought I would ask anyway.
Hi Tech guy,
No land data is not included, but I am pretty sure we can drill at least 20,000 wells, from May 2014 to Dec 2019 would be about 7400 wells for a total of less than 15,000 wells, I think if oil prices don’t crash and there is as much oil in the Three Forks as the USGS estimates we will reach at least 27,000 wells in the Bakken. If oil prices drop, that guess will be too high, but I think it is very likely we will reach 15,000 wells.
Dennis,
CLR’s age old, now mostly obsolete original development plan called for 48,000 wells @500k EUR to produce 24 billion BOE. Because of down spacing and discovery and delineation of TF2 and TF3, the # of wells is now anyone’s guess, but you can start with a conservative # of 100,000 wells and go up from there as new news comes in. Are you sure you are talking about development of the Bakken?
Verwimp,
Nicely modelled! Seems like you captured the seasonal effect very well.
I guess the biggest unknown factor will be oil price. In my opinion it will be difficult to quickly ramp up the pace of drilling, due to new bottlenecks popping up, but a sudden lower oil price will very quickly reduce drilling and then the declines would take over. However, with global drilling prospects being limited, and continued geopolitical risks I only see a recession being able to cause a drop in price. Both current and future oil prices have risen very fast the last months.
Which Bakken EUR are you using?
Hi Verwimp,
What is the URR of your Hubbert Model? I think you mentioned it in an earlier post, but I forget.
USGS mean estimate for TRR is about 10 Gb for ND Bakken/Three Forks and with reasonable economic assumptions (similar to those used in the past by Rune Likvern) ERR will likely be at least 8 Gb. Note that proved reserves plus production at the end of 2012 were 3.9 Gb for the North Dakota Bakken/Three Forks, the USGS mean undiscovered TRR (UTRR) for North Dakota Bakken/Three Forks is 5.8 Gb.
Dennis,
I made the Hubbert analysis on the dataset. That gave me an URR (UR in the legend) of 2.2Gb. That is low. It is known that the Hubbert analysis is a rather weak instrument when the peak is far from being reached.
The original (above) graph was made with an UR of 2.8Gb. In the below graph I added a UR = 3.8Gb curve and a UR = 5.8Gb curve.
You see it needs an UR of 3.8Gb at least to have an autumn 2016-peak higher than the autumn 2015-peak.
The UR = 5.8 Gb means the infliction point is not yet reached. I just do not believe that. The 5.8Gb curve, and even the 3.8Gb curve need parameters that are quiet a bit away from the ones that came out of the Hubbert analysis. So I just stick to the green 2.8Gb curve. As long as it gets.
I am not an oil man, but I have a rather solid mathematics background. I try to use that to make extrapolations of the data, without other oil-knowledge than what I learned here and on TOD. Later tonight I will bring a completely different extrapolation of the ND Bakken data. Fundamentally other math. Same result. Wait and see. 🙂
Verwimp why not use a convolution of your reverse engineered curve and number of producing wells rather than a Hubbert curve which has no real physical basis but is just a heuristic. Also note that a minimum of 3.8 Gb would be expected as proved resrves plus production by year end 2012 is 3.9 Gb.
It would only be that low if we assume future additions to proved reserves will be zero. A pretty unrealistic assumption, 7Gb matches with the USGS F95 estimate for the North Dakota Bakken.
See https://drive.google.com/file/d/0B4nArV09d398cDZMNW5yRWxVM1k/edit?usp=sharing
For USGS assessment and note that they estimate undiscovered resources(UTRR), proved reserves and produced oil must be added to that to get a technically recoverable resource (TRR).
5.8Gb is the mean ND Bakken estimate for UTRR
‘Why not…?’
Just because I am not an oil man and I will never pretend to be one. I am an engineer in civil construction. I have a solid mathematical background and that is it. I actually don’t really care about UTRR, ERR, TRR and whatever more. I count on what has been pumped up. I analyse the way that has been done. The speed, the change in speed (first derivative!) and so on. I look for patterns (like the seasonal effect), for trends and for how trends have changed over time.
I rely heavily on Hubbert for my Seasonal Effect Model. Why? Just because I need to have something to start from. Main purpose of that model is to warn Ron’s readers: multiple peaks are coming: it will be a bumpy ride.
The reverse engineerded model (Enno data) is a pure mathematical exercise. The funny thing is: I get approximately the same results. That fact alone gives it some value to me, you see?
Furthermore: I am surprised by the discussion between you and Ron about legacy decline and the ‘typical Bakken well’. Enno just provided you all you need. Surprise! The typical Bakken well is a changing thing: a typical 2010 well is something else than a 2007 or 2013 well. So my analysis started from that change: What happens if that change, and the way that change evolves (second derivative!), continues? What do we get?
I read high numbers, and I see optimistic graphs. And I think about the magnitude of change I need to implement to my parameters to make that sort of things become reality, and I think: “No. That’s not gonna happen.”
Hi Verwimp,
The mathematics is more useful when applied to physical principles in my opinion. It was just a suggestion, the hubbert curve is not a very useful way to proceed.
On Enno’s data and field decline, when wells are aggregated in a field the decline rate will not be the same as that of the “average well”. You are correct that the average well changes over time, the model is simply an approximation.
It would be interesting to see what your model would say about how many new wells are needed to keep output at the present level (within +/- 5%). Note that Enno is analyzing all North Dakota wells, I focus on only Bakken/Three Forks wells in North Dakota. Part of the change from 2008 to 2014 in Enno’s charts is due to the changing proportion of Bakken wells over time (in 2008 they were a smaller proportion of all North Dakota wells than in 2013), the difference is smaller when non-Bakken wells are eliminated.
Dennis, The Hubbert based Season Model is not well count based. The extended Enno-exercise was built with this number of wells:
2014: 185 extra wells per month
2015: 190 extra wells per month
2016: 185 extra wells per month
2017: 178 extra wells per month
2018: 168 extra wells per month
2019: 155 extra wells per month
2020: 135 extra wells per month
————————————
= 14,352 extra wells in 7 years.
Since the 12mth trailing average of additional wells has been steady at around 150 wells per month (see Rons grapf above), you see that my sudden surge to 185 wells per month is rather optimistic.
I let the number of additional wells decline slowly after 2015, to reflect financial concerns. (Capex and debt may result in a slowdown in investment.) That is the wildest guess in this model. That is “gut feeling based” 🙂
DC has a strong point. The mathematical technique of convolution is the key to doing the analysis so that it makes physical sense. I have been pushing the Oil Shock model, which is a convolution-based depletion analysis, since the early days of The Oil Drum.
Nope.
Stage count per well is clearly changing which renders it all bogus.
Hi watcher,
there has not been that big a change so far. The model has done a pretty good job so far, if the well profile changes, that can be added to the model, the average well profile has fluctuated a little from 2008 to 2014, but not enough to affect the model greatly.
The increased fracking stages and proppant and other techniques will be battling the tendency for EUR to decrease as the sweet spots run out of downspacing potential. The model already assumes there will be decreases in EUR and the timing and the level and speed with which that happens are all adjustable.
We can only guess at when these things will occur and how fast the decrease will be, so far the big changes have not really had much effect.
Is it possible that the extra stages quickly run in to the issue of diminishing returns?
Congratulations to all the hard-working roughnecks, roustabouts, and truck drivers who got us to the 1,000,000 bpd milestone! Words can’t express how proud I am of all ya’ll for getting the United States closer to energy independence.
Now, onward to 2,000,000 bpd! God bless.
https://www.youtube.com/watch?v=UthoPmbZLTM
Yep, ND is now producing 1/19th of our daily needs.
You better get busy comrades!
Condolences to all the women who suffered them.
http://www.examiner.com/article/what-s-the-matter-with-north-dakota-rise-of-a-male-dominated-dystopia
Thanks for the post, Funnel. You probably know – if you are following the operational aspects of this ongoing venture, that 2 million barrels a day would simply be what both Goldman Sachs and Credit Suisse forecast – in almost simultaneously released reports this past fall – would be produced in about 6/8 years time.
If Mr. Patterson’s response to Wood McKenzies’ prediction of 20 billion barrels or so being ultimately produced, (taking into account, among other things, the results of the Torquay/Three Forks wells recently completed over the border, thereby extending dramatically the areal extant of the TF, and the successful, early downspacing projects), he may really flip out if he finds out what the lab results are showing (admittedly NOT real-world conditions) using CO2 enhanced oil recovery techniques.
Let’s just say the 3-5% or so recovery rate of the 900 billion barrels of OOIP currently achieved may turn out to be way low over time.
Youse “guyzz” don’t understand the science behind diffusion-limited flow. That’s your loss, and I see why you would prefer to listen to public relations flacks instead.
using CO2 enhanced oil recovery techniques.
Let’s just say the 3-5% or so recovery rate of the 900 billion barrels of OOIP currently achieved may turn out to be way low over time.
I agree with Web, there is a lot you guys don’t understand. Water injection won’t help in shale plays and neither would CO2 injection. And I have yet to see any studies that indicate old conventional wells can be re-invigorated with CO2 injection.
The reservoirs have already watered out. So they are hoping the CO2 will mix with the water and that would mix with the oil in the rocks and lower the viscosity and allow more oil to be produced. But whatever is produced by this process would still have to be mostly water.
At any rate I would like to see some studies showing how much “additional” oil can be produced by this process in conventional fields
But for “fracked” wells… Fractures, created to allow the oil to bleed from the rocks are exactly that, fractures. Fractures in a water injection reservoir are a real problem. They create a channel that allows the water to flow directly from the injection well to the oil well intake, bypassing all the oil. A fracked well is nothing but fractures.
That is one reason water injection will not work in fracked shale. The other reason is the rocks are “oil wet” rather than “water wet”. Pressurizing the reservoir only forces the oil into the rocks rather than sweeping it toward the well. Or at that is what I have read in several reports on the subject.
The DOE has been doing and assisting studies in CO2 EOR and carbon capture systems for a while now.
Here is a list of projects and details:
http://www.energy.gov/search/site/co2%20eor%20oil
These use a combination of fossil fueled electric generation and the CO2 from the process is piped to oil wells where it enhances oil production and stores CO2 underground at the same time. Since CO2 is already a limited resource in the oil fields, generation and pumping of CO2 gets around that problem.
I haven’t found the article, but an original DOE project used about 5 times the normal level of CO2 and enhanced production at an old well to the point of doubling it’s total cumulative production.
However, as detailed in the study below, CO2 enhanced oil recovery will take quite a long time to implement and will eventually only increase production by less than 1 million bpd.
http://netl.doe.gov/File%20Library/Research/Energy%20Analysis/Publications/Near-Term-Projections-CO2-EOR_april_10_2014.pdf
Nice idea but only a partial solution due to the rate problem.
Even if we use an optimistic TRR (technically recoverable resource) of 11 Gb and assume 170 new wells are completed per month (about the 2013 level), the ERR (economically recoverable resource) under reasonable economic assumptions is 9.6 Gb with a peak of 1.3 million barrels per day.
Note that I do not think this is the most likely scenario, the point is that we have to assume the USGS was very low in their 2013 estimate (TRR=10 Gb for mean value) to reach 2 million barrels per day, 1.5 million barrels will be the limit and I doubt we will reach that, I think 1.2 MMb/d will be the peak, probably in 2018 give or take a year.
Chart below.
Fracking’s magic-bullet moment fading fast
Ralph Surette, Halifax Chronicle Herald, Published June 13, 2014
Beef Reaches U.S. Record as Rancher Sees More Gains
By Megan Durisin, Bloomberg, Jun 17, 2014 4:06 PM ET
Also worth being reminded of the impact of last October’s freaky winter storm on cattle numbers…
Why Did South Dakota Snowstorm Kill So Many Cattle?
Early October blizzard took a devastating toll on the state’s cattle ranchers.
Irina Zhorov, National Geographic, Published October 22, 2013
I recall reading that some of those cattle in South Dakota had been moved up from Texas because of the drought.
Hottest Spring On Record Globally, Reports Japan Meteorological Agency
By Joe Romm, Climate Progress, June 17, 2014 at 3:53 pm
The Japan Meteorological Agency (JMA) reported Monday that March-May was the hottest in more than 120 years of record-keeping. It was also the hottest May on record.
Kinda PC, but interesting:
http://www.latimes.com/local/lanow/la-me-ln-berkeley-gas-pump-warnings-20140617-story.html
Soon we will all have to personal stickers on our foreheads to warn people that our farts contain methane and hydrogen Sulfide, and may cause global warning and acid rain.
My point is where do we stop? I am waiting for them to ban breathing?
I hear ya, Push (you guys were gods on the offshore rigs I worked on years ago … mucho respect for all your collective wisdom/experience) … but I don’t think the breathing itself is in danger of being banned … jes the CO2-producing exhaling, perhaps …
Coffee,
What is your line of work? You sound like you are in to the current shale plays.
Greetings, Toolpush. I am not involved in these shale plays in any fashion other than as a keenly interested observer. My several years long work aboard offshore rigs in the 70’s prompted both a familiarity with and a respect for the “All Bidness”.
A couple of ‘cyber spats’ a few years ago regarding the status/future of shale production spurred me to do a fair amount of reading and research in this field – primarily focusing on operations and technology – and it has become an educational, enjoyable hobby to me.
I appreciate all the input – as well as Mr. Patterson’s efforts – in this ongoing topic. To paraphrase Teddy Roosevelt in his famed “Man in the Arena” speech, we are all of us engaged to some extent in that in which we believe to be important … and as such have earned the right of respect simply for having made the effort.
Hi Toolpush,
The idea is simply to inform people of the dangers of climate change. It is no different than the Surgeon General’s warning on cigarettes in the 60s which the tobacco companies claimed was unproven.
The complaint by the Western Petroleum Association that the warning is not a “fact” is very similar to the stance of the tobacco companies in the 60s.
People who think global warming is not a problem will do the same as cigarette smokers, they will simply ignore it. The point is to get those who agree to think about their choices every time they fuel their car.
Some may drive less, use public transportation more, or even buy an electric car, the more people that do these things, the more it becomes the norm.
Do you think there are as many cigarette smokers as a percent of the population today as there were in the 60s in the US?
The warning label was only a small part of why this change occured, but things have indeed changed with respect to cigarette smoking.
In forty or 50 years people may look back and say, “Can you believe that many people back in 2014 didn’t think global warming was a problem?”
Others will quip that people back then thought cigarettes were good for them and that the earth was flat as well 🙂
I have primary experience dealing with Western States Petroleum Association (long story, but it involved Trout Unlimited).
Pretty sleazy bunch, without a moral compass– but that is typical of industry advocacy groups.
Indeed, the planet is flat.
May here was HOT! Record or equal record many days and almost all above average. The rainy season started a month early but not the quiet start. building up as usual. No, straight into a rainy season typical of July or August, like 2 months early. Can’t wait for El Nino 🙁
NAOM
All the people who insist that a bad winter here in the states last time around disproves warming invariably overlook the excessively warm winter in Siberia etc.
The average taken over a decade or so is slowly creeping up.Well, maybe not so slowly in terms of the consequences over time. One or two years doesn’t prove much of anything.
All the data I am aware of indicates that sea water temperatures are creeping up in the top few hundred feet. A good bit of that heat is going to find it’s way into the atmosphere pretty soon thru increased evaporation unless something such as greater than average cloud cover prevents it.
There may be a number of short term cyclical influences that are not yet discovered or if discovered not yet well understood that are slowing warming rates or accelerating them.
But the basic equation is simple. The heat coming in is fairly constant on an annual basis and the insulating effect of co2 is constantly increasing on an annual basis. This cannot end well unless you like it exceedingly hot.
The average is going to go up unless there is some sort of negative feedback process coming into play to prevent it.I am waiting for a good explanation of what that negative feedback process will be.
When Russia said they were going to cut gas supplies to Ukraine, I thought they were just going to shut a valve, not cut the pipeline itself? Those boys play rough.
MOSCOW — A major natural gas pipeline exploded in central Ukraine on Tuesday, a day after the Russian energy behemoth Gazprom said that it was cutting off supplies to Ukraine in a dispute over pricing, and officials immediately labeled it a possible act of sabotage.
http://www.nytimes.com/2014/06/18/world/europe/ukraine-suspects-terrorism-in-pipeline-explosion.html?partner=rss&emc=rss
PIPELINE EXPLOSION WAS NOT AN ACT OF SABOTAGE
Ukrainian authorities have determined that the explosion and fire of the gas pipeline in the Poltava region on 2014-6-17 was an accident caused poor maintenance and disrepair and not an act of sabotage as previously reported.
h**p://ria.ru/world/20140617/1012449406.html
Call me skeptical, but I would be a little suspicious about a report from the party most likely to gain from the explosion. Very co-incidental that it blew up the day after reduced pressure, though the article claims that is was the contraction of the pipe due to reduced pressure caused subsidence. I may be wrong but it just doesn’t pass the smell test to me.
We will see how the story develops.
Blast now reported as bomb.
In 2004, in Ghislenghien, Belgium, a high pressure (80 bars) gaz pipeline was hit by a machine. To avoid losing gaz, the company exploiting the pipeline decided the cut off the pipeline. As the gaz was not in movement, the pression on the surface increased dramatically and caused an explosion, 24 dead and 132 people severely wounded (burned). Everything at 200 m was fused. This is apparently “just” fluid dynamics on this weak part of the pipeline. It might be that the lack of maintenance in Ukraine would have the same effect.
Anonymous, You can post links without the comment being held for moderation. There is no need to put “h**p” in your links.
Is the Utica shale another Bakken in the making?
In October 2012, the U.S. Geological Survey estimated the Utica shale to contain approximately 38 trillion cubic feet (Tcf) of technically recoverable natural gas, 940 million barrels of oil, and 208 million barrels of natural gas liquids. In comparison, the agency’s April 2013 assessment placed Bakken recoverable reserves at 6.7 Tcf of recoverable natural gas, 7.4 billion barrels of oil and 530 million barrels of natural gas liquids.
A word of caution … like the Bakken and most every other shale gas play, oil company officials, many regulators and other industry watchers view USGS estimates as highly conservative. For example, in March 2011, Larry Wickstrom, Ohio state geologist, estimated his state’s share of the Utica shale alone would ultimately produce 5.5 billion barrels of oil.
The Utica shale has been known to harbor vast quantities of oil and natural gas for more than a century. However, as with the Bakken and other shale oil plays, the lack of appropriate drilling technology and the relative ease of developing other reservoirs with conventional drilling methods kept it from achieving its due as an energy target.
Well BP didn’t like what they found:
http://wkbn.com/2014/04/29/bp-pulling-out-of-utiica-shale-in-valley/
Yes the article mentions that.
Twenty-four companies have Utica shale production in Ohio. Oklahoma City-based Chesapeake Energy is by far the largest leaseholder and producer, followed by Denver-based Antero Resources. In early May 2014, Chesapeake said its well-yield breakdown is approximately 60 percent natural gas, 30 percent natural gas liquids and 10 percent oil. In a move that surprised industry watchers, BP announced on April 29, 2014, that it would abandon its Ohio Utica shale leases and, in so doing, take a $521 million dollar write-down. BP had 84,000 acres under lease in northeastern Ohio.
The Utica shale play is still in its infancy – perhaps comparable to the Bakken play one half-dozen years ago. However, it has a great deal of potential from several perspectives. It is close to markets in the heavily populated northeastern U.S. In addition, development of transportation infrastructure will be accomplished in conjunction with the Marcellus play, which is occurring in the same region. Also, the play is taking place in states that recognize the important role it will play in helping provide domestic energy resources, increased tax collections, and sorely needed jobs.
Good posts, B. A lot of people – even those that follow this stuff – do not seem to grasp that the Utica play is actually twice the size – in areal extent – of the better known Mighty Marcellus. And also thicker in much of the area (300 to 1,000 foot thick pay zone).
Where the Utica drilling has almost exclusively occurred is in its western most part, which is where it is most ‘oily’ and also shallower.
One company, Range, I believe is going to drill both formations from the same pad shortly in western Pa.
As per your cited article, one of the main reasons it has not been developed yet is that it is about 7,000 feet deeper than the Marcellus. But it is there and will be accessed at some point in time.
I have trouble believing BP abandoned Utica for any other reason than it being uneconomical to extract. Natural gas prices are probably way too low at the moment.
Exactly! As per Andy’s link above:
BP Spokesman Curtis Thomas said four of the eight wells drilled were not producing the oil the company had hoped. The leases and buildings BP owns are now going up for sale.
Disappointing results and low or negative profit margins is exactly why they pulled out.
Pretty much that. Even a nat gas price increase won’t make these prospects drillable. Only liquids makes gas plays drillable.
No liquids. No drilling. Not rocket science.
err only liquids makes those gas plays drillable.
The non fracked conventional wells are probably cheap enough. A big deal, of course, is trucks/pipelines. You can’t lay a pipeline on a well that will die in a year.
B,
Utica is back in news due to our old friend, Aubrey McClendon, but the news is Utica is no longer wet and oily, but dry and gassy. I did read a different article than this that talked about some wells, IP being 40mmscfpd. Sounds big for a land well, but that was their claim, but can’t find it at the moment. But the net is full of stories about McClendon raising billions and but Utica acrage from Exxon and Hess, who were looking for oil and have given up and sold out.
http://www.fool.com/investing/general/2014/05/29/aubrey-mcclendon-continues-to-bet-big-on-the-utica.aspx
“This is despite the fact that some of the acreage he is buying didn’t hold compelling economics for the seller. Hess, for example, noted that the acreage it sold was primarily dry gas. The company concluded that the potential returns from the investment at both current and projected natural gas prices didn’t justify retaining and drilling the acreage. That, however, doesn’t mean it won’t be economically appealing for McClendon’s company to drill.
One thing that his former employer, Chesapeake Energy, is finding is that the dry gas potential of the Utica Shale is proving to be more lucrative than investors realize. The company and many of its peers are drilling impressive wells as seen on the following slide:”
Depending on how you viewed the hysteria about Iraq last week the situation is either getting worse or better.
For those who thought the Baiji oil refinery and power plant were captured then the good news is that they still haven’t been. For those who didn’t believe the hyped news reports, the bad news is now that they really are under attack, both are shut down, and all foreign staff have been withdrawn.
An article about the evacuation of Siemens workers is here – http://www.thelocal.de/20140617/trapped-german-siemens-workers-air-rescued-in-iraq
BBC now reporting most of the refinery in ISIS hands.
With shelling from mortars and artillery, it is uncertain how soon it could restart operations.
I guess that ISIS are intent on controlling fuel and water supplies to Baghdad. They don’t have the forces to overrun the capital, but they can besiege it.
FYI interesting tidbit.
Interdicting water to a location with a civilian population is a war crime per Geneva.
Interdicting gasoline or nat gas is not.
Isis seem quite keen on posting their war crimes on u tube. Don’t think they are too bothered about the Geneva convention.
Way too much history book writing before winners are determined.
Hard to see how those vids came from them.
Some good news from Ukraine. Ukraine’s Poroshenko offers unilateral ceasefire. http://www.bbc.co.uk/news/world-europe-27902109
I don’t think Russia invaded Ukraine last week but if the war continues it might soon. If it does it is hard to see how WW3 can be avoided. I congratulate Poroshenko for his attempt to cool things down. Lets hope Putin can pressure his side to follow suit.
This is likely surrender. A cease fire doesn’t mean separatists can’t continue to solidify their holds.
It just means the Kiev troops and separatists stop shooting at each other.
Interesting comparisons:
Baaken and all ND now up to roughly 1,000,000/day + industry hype hype hype, Saudi America articles and other inane comments by MSM. This was going to change the geo political world and save everything!!
Conjecture on this site is when will it peak? 2017? 2020?
Alberta Oil Sands
“The board, which regulates the province’s oil and gas industry, said it expects oil sands production to hit 3.8 million bpd in nine years, up from 1.9 million bpd in 2012.”
http://business.financialpost.com/2013/05/08/alberta-oil-sands-production-likely-to-double-by-2022/?__lsa
So, in 2012 the Oil Sands produced 2X Baaken yet cannot get XL approved. In fact, the bitumen (which when refined burns quite nicely in all manner of equipment including my brother’s Prius and my little farm tractor and PU), is villified and demonized even though it is a big player in keeping the entire NA economy limping along…..buying transition time if you will. Plus, production is 2X shale right now.
Mind you, it is a toss up as which is supposedly the most evil form of production? Fracing and waste water disposal vrs. tailing ponds and co2 emissions?
I just wish some outfit like Natl Geo would put on a year-long series on energy; energy uses, production, sources, reserves, uses, waste…and most important, outlook and warnings. 1st and 2nd law would be a nice introduction, wouldn’t it?
I do accept that my objections and willingness to protest Northern Gateway is in apparent conflict to my stand on Oil Sands development and ND shale plays. Nevertheless, if we did not have these sources on tap (excuse the pun) right now, we would be in a world of hurt as far as jobs and social stability. Yes, in North America. This is buying some time and I am frustrated with how energy is simply taken for granted and not given any real credit as to its role in who, what, why, and how we live our lives. I can watch Anthony Bourdain scoffing up and getting drunk around the world, almost nightly, but all we hear about energy is from twits like John McCain suggesting we use exports to influence world affairs.
I could cry….just cry. Rant over, thanks.
Paulo
Eyes opening to the seriousness of the situation. but if you read the article, it all about production, so they are oblivious to the ELM hammer on importers . .. … so far.
http://www.marketwatch.com/story/if-iraqi-oil-goes-off-line-200-oil-is-next-2014-06-17
“The sad fact is that out of 12 OPEC members, eight of them are collectively in decline. When summed together Algeria, Angola, Ecuador, Iran, Libya, Nigeria, Qatar and Venezuela were producing just over 14.5 million barrels per day in early 2005; but are now producing just 11.25 mbd.
These countries are losing nearly 500 thousand barrels per day of production per year.”
Guy, nobody’s eyes are going to open.
This is like traveling to countries at war. If you go just 50 miles from the shooting, no one will hear it or see it and the top concern in the town will be the baker’s daughter is getting married and the wedding is this weekend, so people are arranging their schedule.
Nobody’s eyes are going to open until they can’t fill their gas tank because the underground tank is empty. Even that won’t bother them until they go to the next place and find it empty, too. Then and only then will they drive home, staring at the gas gauge and hoping they get there and walk in to turn on the news to see what happened.
http://www.cnbc.com/id/101762384
“The head of Iraq’s state-run South Oil Company Dhiya Jaffar said on Wednesday that ExxonMobil has carried out a “major evacuation” of their staff and BP had evacuated 20 percent of its staff.
snip
“I assure the companies that the current developments in the country have not affected and will not affect in anyway the operations in the south,” he said, adding that the export level for June will be 2.7 million barrels per day.”
Well some oil companies are getting their people out of Iraq. I note the service companies have not. Exxon lost several people in Chad quite a few years ago and look after their people. The service companies are renown for not taking care of their people, and it shows once again. Some of the service companies were willing to leave their people behind in Libya and the drilling company I was working for at the time, let them on their charter evacuation flight.
Be nice to America. Or we’ll bring democracy to your country.
I wanted to pass along this link which includes a Crude Oil only world production chart. Interesting article gets into Eagle Ford and Bakken peaks as well.
Click Here for Article
(I hope image and link work. 1st attempt.)
I now see this chart was created in late 2010 and the following years are estimates. I’m contacting the creator of the chart to see if he has an updated one.
Get this – ISIS are fighting for control of Iraq’s biggest oil refinery today!!!
http://tribune.com.pk/story/723656/iran-vows-to-defend-iraq-shia-sites-insurgents-battle-for-refinery/
Iran vows to defend Iraq Shia sites; insurgents battle for refinery
BAGHDAD: Rebels battled their way into the biggest oil refinery in Iraq on Wednesday, and the president of neighbouring Iran raised the prospect of intervening in a sectarian war that threatens to sweep across Middle East frontiers.
Hard to bomb troops out of a refinery.
I compared April 2014 with April 2013 and got about $10-15B more in wells ($6-8M per well) and about $600M more in production (assuming $100 barrel). If that’s close to reality, you cheerleaders in the comments are quite delusional.
It;s worse than that, out of that $100 comes royalties and it isn’t a C-note (think transporation costs to the refiner)….
I hope, the fine folks that actually “think” that ND Bakken production will soon peak, realize that only about one billion barrels of ND Bakken oil has been produced so far. If you also “think” there is only going to be about 4-10 billion barrels recoverable oil in all, that means you are assuming a total recovery of 10-25%!!! And, you say the oil industry is hyping ??? FYI – NO ONE in the oil industry is seriously talking about much more than a 3.5% recovery of total OOIP, which by the way still hasn’t even been determined, as the oil companies haven’t even found the bottom of it yet.
Try listening to what Coffeeguyzz is saying. He is the only one at this site with any real understanding of the Bakken commenting here. Sorry everyone else, but you got it all wrong. Or, you can do what he (and I) do, which is to go to the company websites, that are actually on the ground doing the work, and get the correct information for yourselves right from the horse’s mouth. Best company website for this is contres.com. Just click on Investor Information, then June 2014 Presentation, and you are right smack in the middle of the reality of the Bakken and the shale oil revolution.
The Bakken peaking anytime soon???? Actual production of the Bakken is only expected to BEGIN…. in the year 2015 in the Antelope area and by ONLY two companies, CLR and EOG, who are going face to face in a friendly competition with different full production models to see which one works best. Meanwhile, CLR can’t even agree with themselves about which of their own full production models works best, because they keep finding better ways of extracting more oil cheaper.
As all Bakken oil produced so far is from exploration, lease holding, and experimental efforts only, and exactly NONE from actual full production mode, according to you guys this will be the first oil field in history to peak BEFORE actual production even begins. Yes, you read this post correctly. You folks got it all exactly dead wrong! Go to contres.com and face reality.
Just click on Investor Information,…
That kinda says it all right there doesn’t it. I hope you invested a bundle based on that information.
You just need the correct facts:
This guy used to routinely try to pump up Continental Resources stock (the website that he listed), on The Oil Drum, until the editors told him to go away.
I’m reminded of implicit and explicit recommendations on The Oil Drum regarding Pacific Ethanol and Petrobank (remember how the THAI Process was going to revolutionize tar sands plays?).
There was a oil savvy character that passed away while the Drum was active, his name escapes me but he tipped me off to PBT and SBR and buying those in 2006 were definitely home runs….
In a great what could have been, I once owned 5000 shares of KOG at a cost basis of $0.34….
C’est la vie…
I looked at CLR. I looked at EOG.
EOG is better. But they are both rowboats waiting for a tide.
Jeffrey J. Brown, Your statement about me is incorrect. I’m the guy who told you the truth at TOD. I was NOT told to go away by the editors. I challenged them all as a team to a public debate about PO against me, alone. They wisely declined, however one editor said that he might well choose my side. I do not push stocks.
I merely assume that people at this site are mature adults and are used to separating the wheat from the chaff. Am I wrong?
Carl, you are welcome to post here as long as you make no derogatory remarks about any posters here. I have deleted the post where you called me an idiot. Do it one more time and you will go away from this site.
Hi Carl,
As you claim to have all the information, I hope you can answer just 3 questions:
1) How does the average Continental well profile in North Dakota compare with the 603 k BOE model for a typical well presented by Continental?
2) How does the average Continental well in North Dakota compare with the average well there?
3) During the last 3 years, what is the trend of the performance of new Continental wells?
I would appreciate a detailed response.
Enno,
I don’t claim to have all information, but I do try to be open to and have access to all types of publicly available information.
1.) CLR has about 1,200,000 acres and is the biggest land holder in the Bakken, and has also drilled the most wells. Many of these were their own, but they have traditionally taken a working interest (WI) in as many competitor’s wells as possible. This was not to make money, but rather to gain INFORMATION. Therefore, they are like a proxy for the whole Bakken, so if you understand what CLR is doing, you will understand the entire ongoing development process for the Bakken. Otherwise you are way out in left field, somewhere. They also put out the most and easiest INFORMATION to understand about the Bakken.
Furthermore, they have used their standard 603k BOE model (30 fracks, 10,000 ft laterals, specific amounts of sand and water, etc) in various places all over the entire Bakken….even when they knew that certain of their wells would NOT be profitable, or when they knew that other operators were using other types of wells, that were much better, than their own. This is because they wanted to create a standard, a fast point, a sure set of data to compare everything and everyone else to. They now have that.
1.) Your first two questions are rather circular in nature, but I believe you want to know if CLR’s wells represent the “average” Bakken well, or not. The answer is unfortunately yes, and no. When they completed their “White Paper” in October, 2010, they were using 500k wells in their assertion that 48,000 wells would be used to get out 24 billion BOE from the top two, then not completely delineated layers, of the Bakken. Then they upped their own EUR’s to 603k shortly thereafter.
I could say that 603k is now the going average, but several companies are way above that, while many others are still below. All Companies are still exploring, derisking, and experimenting. None are in full production anywhere in the Bakken.
You need to wrap your brain around this sentence fom page 10 of their June 2014 investor presentation….. “13 of 14 wells trending on average 50% above 603 MBoe model EUR” to understand what is going on now. They have changed their standard model in a test, and preliminary results suggest a 50% impovement in EUR’s. If true, then this would then apply to the entire Bakken.
It is the Red Queen fairy tale that is causing all the misunderstanding problems for the PO community. Rune used his own average of 290k when he should have just used CLR’s then average of 500k, then updated it along with CLR to 603k. So, as starters everything in the Bakken is at least twice as big as whatever you now think.
3.) Generally up, but not absolutely so. They are still mostly exploring, derisking, and experimenting so that greatly lowers the EUR’s that they could otherwise get. They presently still value INFORMATION higher than short term money, because they still have 1,200,000 acres to fully develop. Not one single acre of CLR’s or anyone else’s is fully developed, as yet. The Bakken has not yet been completely delineated.
Dear Carl,
First of all, I really appreciate your detailed response.
Before commenting, I want to mention that I may not follow the situation in the Bakken as closely as you, but that I do have an easy way to analyse the public NDIC data in detail. Furthermore, my aim is to provide objective analyses based on the public data, in contrast to lots of groundless claims that are being floated about the shale production in the US.
What especially triggered my skepticism are the in my eyes highly optimistic projections mentioned by several of the shale companies. Continental is not alone in that, but to give you some examples : the 603 K well model, 50 year well lives, high reserve estimates, whereas the USGS comes up with much lower numbers. You may be right that the USGS underestimates, but I prefer to just let the data be the judge of that.
Coming back to several points you mention that I can verify in the data:
1) 603 K BOE model. Although I do not have the actual model, this model is shown in several Continental presentations, and therefore I can compare the actual ND wells with this model.
The 603 K BOE model seems to assume a total return of about 230 K after 50 months for the average well. After June 2009, when the better wells were drilled, the average 50 month BOE return for ND wells was 195 K BOE, and for Continental wells that was 190 K BOE. That is about 20% lower than the 603 K model, which I think is quite a difference. Furthermore, the 603 K model assumes an average well life of 50 years. I can’t really comment on that, as I don’t have any special insight on whether that is reasonable, but it is quite higher than the USGS mentions (around 30 years I belief).
You say that 603k is the going average, and based on the NDIC data I say you are clearly wrong.
2) Average Continental well. Below I show a graph of the cum curves for Continental. You can compare that with the graph I posted in the beginning. You will see 2 interesting facts:
– Continental wells are under performing average wells in North Dakota
– Despite all the mentioning about new techniques to enhance extraction, Continental wells have worsened during the last 3 years : the average 2011 wells outperform any later wells on average. 2014 wells are of the lowest quality since 2009.
You say that Continental wells are “generally up”. I say you are clearly wrong based on the NDIC data.
3) Beginning of the play. You mention several times that the biggest growth is still ahead. However, it looks as if capital expenditures are hardly growing anymore, and the growth of output in ND in 2013 was the lowest in 3 years. Even Continental is hardly spending more CAPEX in ND in 2014 compared with earlier years, despite their growth as a company. Therefore, I don’t buy it.
4) Hawkinson wells. Continental and other companies keep highlighting a few success stories, and for Hawkinson it is claimed that 13 of the 14 wells produce more than 50% more than the 603 K model. Sure, with so many wells drilled, you will always be able to highlight success wells. The point is that the average well is not improving, and Continental wells are trending down. Did you see the disastrous results at the Tangsrud wells? Therefore, I don’t buy these success stories.
5) Financials. You mention elsewhere that wells are earned back in 6-24 months. If that is the case, I would expect many companies in the Bakken to be cashflow positive. That is not the case, and borrowing continues. You ignore all other costs, such as exploratory, seismic, production costs/taxes & income taxes. Include those, and then I would like to see how quickly wells are earned back. If you just divide capex over the amount of development wells being drilled, well costs are more in the 13-16 million USD range, instead of the sub 10 million range that is very often mentioned.
Looking forward to your comments.
Hi Carl Martin,
You referenced Rune Likvern’s work,
“Rune used his own average of 290k when he should have just used CLR’s then average of 500k…”
I am quite familiar with Mr Likvern’s work and think it is excellent.
The well profile that he used was based on actual data from the NDIC and the 290 kb was for 20 years, at thirty years his well profile was about 460 kb so not all that different from that of CLR at the time.
Also keep in mind that the 603 kboe well profile includes natural gas which is about 30% of the barrels of oil equivalent, Mr. Likvern’s analysis is for crude plus condensate only. When we scale back the 603 boe type curve to include only C+C we get about 420 kbo (using CLR 2014 Q1 oil and gas production).
If any thing Mr. Likvern’s analysis was too optimistic, USGS analysis points to a lower type curve of about 360 kbo over 30 years as does the actual NDIC data that Enno Peters has graciously shared with me.
Technology may help a little, but the sweet spots will eventually run out of room for downspacing and at that point EUR per well will decrease. In addition the increased proppant and other technology will raise well costs by 1.5 to 2 million which will tend to reduce the profitability.
Dennis,
So, why didn’t he just use the 30, or even 40 years model, if that was what the industry uses anyway?
His predictions did not come true at all, which kind of negates his whole article. But his later idea of a “speed limit” on the # of average wells needed to maintain production is valid and relevant, but wells are unfortunately not very average in the real world.
I don’t understand why you people are so concerned about average EUR’s anyway. Lower average EUR’s just means that even more wells will be required to get all the recoverable oil out. As recoverable oil is by definition profitable, the more wells for profitable oil, the more profit.
I’ve read all the CLR materials and there is nothing in them to suggest any sort of pursuit of a new standard completion technology. The exploratory wells talked about were exploring downspacing, not a new standard for well completion itself.
And what it said was not conclusive. The operative issue in downspacing wells is cannibalizing oil from the adjacent well. They fracked wells closer together horizontally, but their fracking extended downwards into the TF formation and drained oil from it. So the flow in that well and the adjacent well failed to accomplish the test intended. They do not know if they cannibalize. The flow from the lower formation corrupts the result.
There is no evidence of them establishing a new standard completion technology. You’re imagining things the report did not say.
Hi Watcher,
In the most recent CLR quarterly investor presentation (or the 2013 annual report) there was something about improving the output by using more proppant, 200,000 pounds per stage or 300,000 pounds per stage instead of the standard 100,000 lbs., they also said it would increase costs by 1.5 to 2 million per well.
Yup, I remember the discussion.
I’m in wince mode from water. The water totals are quoted in millions of gallons some places and millions of pounds other places and I think . . . 5 million gallons is intended. That’s 40 million pounds of trucking. No damn wonder it takes 100 days.
Watcher,
This thread might show up way down the page.
The reason you didn’t pick it up is that CLR’s 30 frack standard well is old news, not new. They have been using it about 3-4 years.
Exploratory wells are (high risk) wells in relatively new unknown territory. The down spacing well you are referring to is an experimental well, in a very well known area with good EUR’s.
Your second and third paragraphs are well off the mark. They drilled down to the TF then horizontally and stayed at all times within the TF’s. They are both testing downspacing within zones, and also seeing if the downspacing is going interzonal. It’s not! There is a certain amount of planned cannibalzation, also called well interference or well communication, going on within zones, but not between zones, which is what they are testing, just to see how much can they get away with. It’s working.
Sweet! I just loaded up on a bunch of their stock! Can’t wait until they start the “actual production.” I’ll surely make a killing.
Finally somebody who “gets it” that the shale revolution is really just in the first inning and is truly changing the geopolitical landscape of the world…the Bakken is just starting out folks…it’s a trillion barrel oil resevoir so just think about that…every 1% more oil recovered due to enhanced technique amounts to billions more domestic oil that we can use right here at home and not have to get oil from countries that hate us…I fully trust Harold Hamm and the other CEOS when they say this is a generational play that will outlast all of us and produce billions of barrels of oil for hundreds of years…in what way is 2 mil. barrels per day out of the question???the amount of ingenuity creativity and brain power that the companies like Continental (CLR), EOG (EOG), Whiting (WLL), WPX Energy (WPX), Oasis (OAS) are bringing on to fuel this economic miracle is an amazing feat that should be applauded and admired…these risk-taking prosperous companies and the hard-working people they have working for them provide us with heat, transportation, food, defense, electricity and so on…thanks to them we Americans are able to live in the most prosperous and free country of all time…
fcs, I just stood up and saluted the flag.
I don’t think you understand the details.
2 million bpd is absolutely possible. For a few hours.
Your own quote is “and produce billions of barrels of oil for hundreds of years…in what way is 2 mil. barrels per day out of the question???”
The USGS estimate is 7ishB as I recall. Take that up to 14 billion and pump it out over just 100 years, not 100s.
14 billion / 100 is obviously 140 million barrels/year. That’s about 380K bpd.
Just do the numbers and listen to these CEOs. They will ALWAYS talk about “this oil field will be producing for the next 50 years. Your grandchildren will work here.”
They don’t ever say it will do 1 or 2 million bpd for those 50 years. It may be doing 500 bpd for the whole field in 50 years and what they said will be true. Though of course the oil field workers will have starved to death by then, so production will be 0.
CLR has estimated the total OOIP in just the Middle Bakken and Upper Three Forks just in the four counties of ND and one in Montana to be about 900 billion BOE. The TF2 and TF3 zones in that area are still being delineated, but the sweet spot is so far identified as being about 3,800 sq.miles, (and growing) as opposed to the two upper layer sweet spots, that have been determined to be about 14,000 sq. miles EACH. The TF4 level has not yet been delineated. Below that are the oil bearing and oil producing formations called the Nizku (BirdBear) and Duvernay.
Therefore, an OOIP of one trillion barrels of oil just in those five counties is not at all unrealistic, just unproven as yet. It is quite likely that there is also one trillion barrels of OOIP in all other US shale plays together. We shall see.
Bakken production is scheduled to be at least two million BPD, and probably within the next five years. No one can pove the future, but you might as well get used to that number. That’s what all the investors use, so that’s where all the investment money is going to.
If anyone thinks this isn’t true or possible, it might be interesting to hear their reasons why. Being a government entity, the people at USGS are actually paid to be out of touch wih reality, so I think they are doing a splendid job of it. Sorry, but if you use any of their numbers, you will get very lost in all this.
CLR is the best source of INFORMATION out there. I could say trust me on this, but I’ll say just the opposite, and say to do all your own work instead.
I think OOIP estimates from everyone are up in that range of total.
I think you don’t understand the difference between the categories. Read up on OOIP, TRR, Reserves, Proven Reserves. These are all different things. They aren’t different words for the same thing.
You need to understand geology. Visualize a plastic 1 gallon milk jug. The oil down underground is not a lake or an ocean or even a puddle. It’s porous rock. The pores are different sizes, and they sometimes interconnect, and sometimes they don’t interconnect.
But visualize a 1 gallon milk jug pore of oil in the rock. The next pore is 50 feet away. No interconnectedness, but that next pore has many more attached to it.
You may drain that second pore and it’s many attached pores. But unless you’re willing to drill a 10 million dollar hole for that 1 gallon pore of oil, you’re never going to recover it.
This is the difference between OOIP and the other categories. You need to go get up to speed.
Watcher,
As OOIP simply means Original Oil In Place, I don’t think that needs further explanation. It obviously is referring to what is there, not what will be gotten out.
But, when people here are saying that the URR of the Bakken is only going to be 9 billion barrels, I do hope they realize that that is only a 1% recovery rate. Why so low?
Proved reserves are about 3.3 Gb in the North Dakota Bakken/Three Forks as of Dec 2012, the US inputs about 5.5 Gb of C+C into refineries each year. If the USGS mean estimate is correct we might eventually get 7 or 8 Gb of oil from the North Dakota Bakken /Three Forks. Clearly there are some optimists who think that the USGS F5 estimate is better (5% probability that TRR will be higher than this) which at very high oil prices might result in 13Gb of oil which is not even 3 years of current US crude input to refineries. Note that I think the 13 Gb estimate is too high, but we might get 9 or 10 Gb which is pretty insignificant out of World Reserves of 1200 Gb (oil yet to be produced).
Note that I think the 13 Gb estimate is too high, but we might get 9 or 10 Gb
That gives North Dakota a reserves to production ratio of 27. That is a little high for conventional fields, fields that decline at about 6 percent per year after peak. But that astonishingly high for a shale field that has a decline rate of 6 percent per month.
The higher the decline rate the lower the R/P ratio will just naturally be. I cannot believe the Bakken has anywhere close to 10 Gb.
I am glad we disagree on so many things Dennis, otherwise things would get pretty dull. 😉
Hi Ron,
(Doug TRR alert don’t read this 🙂 )
We agree on that (that disagreement is fun).
According to the EIA there are proved reserves of about 3.3 Gb in the North Dakota Bakken as of Dec 2012, about 0.6 Gb had been produced by the end of 2012 for a total of 3.9 Gb. All of this is economically recoverable by definition.
The USGS estimate of undiscovered TRR in April 2013 at the 95% probability level (5% chance there will be less than this discovered) was 3.5 Gb so I would say the minimum TRR would be 7.5 Gb=3.9+3.5. Reasonable economic assumptions would yield an ERR of 6.5 Gb.
Note that resources are not reserves, the 2012 reserves are 3.7 Gb so R/P in 2012 was about 15. The resources get added to reserves over time. The R/P for the US in 2012 was about 14.
We will just have to disagree, I think the USGS mean TRR estimate of about 10 Gb is correct and ERR will be 9 Gb.
On the 900 Gb of OOIP, we would expect 1 to 3% recovery from this field or 9 to 18 Gb, I think it will be 10 Gb just as the USGS estimates, but time will tell, if its 18 Gb that is enough for almost 4 years of US refinery inputs at today’s input levels.
Continental has 0.561 Gb of proved reserves in the North Dakota Bakken and another 0.05 Gb in the Montana Bakken as of Dec 31, 2013, not really a lot of oil (this includes both developed and undeveloped proved reserves).
Dennis,
CLR says it has 1.08 billion BOE proved reserves as of April, 2014.
BTW with oil at $106 ($102-103 before any Ukraine or Iraq tensions), I gotta think the SPR release threat is being Xed onto the calendar based on how long it takes for gasoline prices to fall after a WTI fall, and get that to happen in mid to late Oct.
The big panic starts when an SPR release happens and WTI goes up. That will be amusing.
On the idea of an exact science, pat of the problem is that the legacy decline is a moving target.
Yes and no. Of course the more oil the Bakken produces the greater the amount of decline will be. 6.6% of 1.2 million barrels per day is a lot more than 6.6 of .7 million barrels per day. But the percentage don’t change that much. And they are very close to what the NDIC says the Bakken decline rate is.
The above chart is from The Oil Drum
“Is the Typical NDIC Bakken Tight Oil Well a Sales Pitch?”
I did the math. The NDIC said, when they compiled this chart, that the Bakken was declining by 6.1% per month. That is a bit lower than the EIA is saying the Bakken is declining right now, (6.6%). But it is almost exactly where the EIA says the Bakken was declining a couple of years ago when the above chart was created.
So I have both the EIA and the NDIC saying the Bakken is declining at above 6% per month.
I rest my case.
That above item from hmmm Enno I think, didn’t go look just now . . . but 60% of production is from brand spanking new wells less than 1.5 years old — and that’s going to increase.
These young wells are in the steepest part of their decline curve. There are more of them.
Thinking a moment in terms of stage count hmmmm
If you have 30 stages, that’s so much cylinder and fractures to flow and then die. Then go to 60. The curve doesn’t change I guess, but the number of barrels lost in month 2 should be much higher hmmm than what.
Oooh, that’s the right question. Would a single 60 stage well decrease its barrel flow in month 2 vs month 1 — a greater amount than two 30 stage wells decrease their flow month 2 vs 1?
This seems non trivial. That usually means it’s the same or not important.
The decline rate DECLINES each month at an exponential rate for about 5 and 1/2 years, then it switches to a slower hyperbolic decline rate which also DECLINES each month. Actually it holds pretty steady by then, but it declines each year.
If the declines rates are a problem to anyone, then just turn the graphs upside down and you’ll get the accumulation rates. That’s all that matters. Who cares how big doughnut holes are?
Most Bakken wells pay for themselves between six to twenty four months. As a rough model use $8,000,000 wells, and an $80 well head price gotten by the operator. Then it’s all about when the first 100,000 barrels are gotten. That’s usually in abou 6-24 months. End of story.
Hi Ron,
I agree that the legacy decline may be about 6 % or so. So for April, we would take the March output and multiply by 6% to get legacy decline for April.
For the North Dakota Bakken in March we had 914 kb/d and legacy decline would be about 55 kb/d at 6% and 60 kb/d at 6.6% for April. Output went up by 23 kb/d from March to April so the new wells contributed 83 kb/d. There were 200 wells completed so each completed well on average produced 415 barrels per day in the first month of production.
We may or may not agree on that. It is possible I have misunderstood you.
Where we do not seem to agree is on the number of wells needed to keep production relatively flat.
The method that is intuitive does not work in practice.
The intuitive method is if we have a 60 kb/d legacy decline and new wells produce 0.415 kb/d we would need 60/0.415 or about 144 wells just to keep production flat.
If we plug 144 wells into the model for May 2014 to May 2017 and assume no well productivity decrease, production stays flat for 3 or four months and then starts to increase. The reason for this is that the magnitude (or absolute value) of the legacy decline will decrease with fewer new wells added. A chart with output for the North Dakota Bakken with 140 new wells completed from May 2014 to Jan 2018 is below.
A simple spreadsheet can also be downloaded at the link below, it does not give the full Bakken model just a quick ramp up to 170 wells added per month and then a decrease to 105 wells per month (change wells added in cell D1 to play around with the result.)
https://drive.google.com/file/d/0B4nArV09d398VjdDLXFzTDVKN2M/edit?usp=sharing
What does most mean?
The EIA is not always correct. I don’t have any track record for NDIC predictions to know whether or not they are correct. But in this case they are making no predictions, just posting stats of past performance. And since they both agree on what has happened in the past, I see no reason to doubt their word about what happened in the past. And since they both agree on what has already happened, why do you so seriously doubt it?
Of course if either made predictions of future decline rates then I would have reason to doubt it.
About the EIA using all Montana in their decline stats. Then that means they are including a lot of conventional wells in their decline stats. That should make their decline curve a lot lower, like it does in the Permian. That could explain why Eagle Ford has a higher monthly decline rate than the Bakken.
Hi Ron,
I trashed that earlier comment sorry.
I was talking about the NDIC type curve, which does not match the actual data from Enno Peters very well. I trust the NDIC and EIA data, but I do not trust the Drilling Productivity report or the NDIC type curve chart, Rune Likvern has also questioned that NDIC type curve.
The fact that the EIA is including all Montana C+C in their Montana Bakken numbers and are doing the same in the Permian Basin makes me question that report, it is just very poorly done.
In another comment I suggested that a 6.6% legacy decline would give about 60 kb/d decline for April in the North Dakota Bakken (914 times 0.066), since production increased by 23 kb/d in the ND Bakken output from new wells is 83 kb/d and since 200 wells were completed we get 415 b/d for the average new well in April. This suggests 149 wells would be needed to offset next month’s 62 kb/d legacy decline (assuming 6.6%). See my chart above for what output looks like with 140 wells completed per month. The problem is that as the number of wells added goes down so does the magnitude of the legacy decline (that’s what I mean by a moving target).
Hi Ron,
I think I tried to reply to you but the reply ended up down here. There is a comment on page one you should check out
http://peakoilbarrel.com/bakken-update-april-production-numbers/comment-page-1/#comment-41016
In that comment I gave a link to a spreadsheet with a simple Bakken-like model (using the Bakken average well profile) it is below with a chart created using the model. 134 wells is the “intuitive method” for flat output, 105 wells is closer to flat output.
https://drive.google.com/file/d/0B4nArV09d398VjdDLXFzTDVKN2M/edit?usp=sharing
Dennis, great charts and I don’t find a lot to disagree with. I think what we both have been overlooking is that 200 new wells were completed in each of the last two months reported. Bakken increase in production was 24,360 bp/d in March and 23,257 in April. For all North Dakota the numbers were 24,386 and 23,971 bp/d respectively. Doing the math and assuming 400 bp/d for each new well, then it took approximately 140 wells to offset decline and the production of 60 wells were added as new production.
Now the we can play with these numbers and assume different barrels per day per new well. But the more barrels per day per new well we assume the greater decline rate we must assume. That is if we assume 480 bp/d for new wells then it would take about 150 wells to make up for decline and production of the other 50 wells production makes up the increase in production.
So 140 wells to make up for legacy decline seems about right and 400 bp/d for new wells seems about right. But just playing with these numbers one thing jumps out at you. That is as production increases the number of new wells just to keep production flat rises alarmingly fast.
“…. as production increases the number of new wells just to keep production flat rises alarmingly fast.” Therein lies the rub.
Hi Ron,
The legacy decline starts to level off as number of completed wells per month also levels off.
In fact, unless the EUR decreases (and it will we just don’t know when) as long as the number of wells completed does not decrease the legacy decline never rises above the new well output.
This is not intuitive at all, but when the model has no new well EUR decrease and 115 new wells added each month from May 2014 to August 2041 (45,000 wells total), the oil output does not stop increasing until the wells stop being added.
This is not intended to be a realistic scenario,
only to show that legacy decline will increase more and more slowly and approach new well output, but never reach that level. Chart below with number of new wells added on right axis.
This is not intended to be a realistic scenario,…
We can both agree on that. The below is not intended to be a realistic scenario either, only to show what would happen if 115 new wells were added each month, and I assume that the legacy decline rate would remain constant. It will not of course but in this illustration it is assumed.
What would really happen of course is that the legacy decline rate would drop, but very slowly, as more and more wells moved into the stripper stage and declined less each month. But the fact that they are producing only a tiny amount so their declining only a tiny amount will not have that great an effect.
However what will have a far greater effect will be new wells producing less and less as drillers move further and further away from the sweet spots. So instead of producing an average of 400 barrels per day new wells will produce 375, then 350, then 325 and so on. The decline in new well production will be greater than the decline in the legacy decline rate.
So the production curve, instead of being a straight line as shown below will actually turn down pretty fast. After all the EIA says that decline will start in 2020. I disagree, I think it will start in 2015 or no later than 2016.
The chart below assumes 115 new wells per month with an average of 400 barrels per day per well the first month and a legacy decline rate of 6.5 percent per month.
After Bakken peaks, it will very likely be a game changer for shale investing. For instance CLR borrows about $210 Million a quarter to expand operations. Once CLR can no longer show growth, investors are much less likely to throw money at CLR. I think with within 18 Months of Peak, CLR will find it much more difficult to borrow which will make it difficult for them to offset depletion, which is right about the time your graph flats out. I presume if drilling stops production drops as fast as it shot up.
I see the Shale boom another bubble like the Tech Bubble of the late 1990’s. Consider that Shale drilling is an Tech advancement, just like the Internet (1990’s) or the radios (1920’s). Investors are always willing to throw money into a bubble as long as companies show growth. Once growth disappears, investors usually start taking money away.
Hi Ron,
It is precisely because the legacy decline rate does not remain constant, that the chart you produced is incorrect, you should download the spreadsheet and play around with it. So far there is no evidence that new well EUR has begun to decrease. You seem to assume it will begin soon. If fewer wells are drilled it will take longer to reach the point where EUR starts to decrease.
My scenario is correct (and uses a well profile based on Enno Peter’s data) until EUR begins to decrease, this could start tomorrow or in 5 years time it depends on technology and the rate of drilling. Clearly it won’t start in 2040.
Hi Ron,
Thanks.
Yes I was missing the number of wells completed until you pointed it out.
We will have to find something else to disagree about 😉
” the more barrels per day per new well we assume the greater decline rate we must assume. ”
” as production increases the number of new wells just to keep production flat rises alarmingly fast.”
Ron, I agree. That is all there is to say. The Red Queen shows up.
Hi Verwimp,
Download the spread sheet
https://drive.google.com/file/d/0B4nArV09d398R1JCVkNKUFBiMHM/edit?usp=sharing
Until the new well EUR starts to decrease, if the number of new wells stays flat, output goes up, simple mathematics. Show me where I am in error. The scenario starts in Jan 2010 (month 1).
Chart below for case where 115 wells are added from May 2014 (month 54). Any number of wells can be tried in Cell D1.
Hi Ron,
The legacy decline rate percent does not remain constant. See chart for a case with 115 wells added from May 2014 to May 2020. The decline rate decreases in magnitude when the number of wells decreases. Your assumption that it remains constant is incorrect.
For 160 wells added per month the legacy decline rate % also decreases, obviously oil output increases more than the 115 wells per month case (as before it is assumed that new well EUR remains constant until 129 months), month 1 is January 2010 and month 52 is April 2014.
Same as previous chart except 100 wells added per month
The following scenario is somewhat similar to what Ron showed earlier as far as the output level.
However only 72 new wells are added each month, where Ron’s scenario uses 115 wells and assumes the legacy decline rate is fixed at about 6 %. My scenario takes the actual well profile used in the model from 2010 to April 2014 and assumes the well profile does not change until October 2020 (in fact the EUR will decrease, but we do not know when or by how much or at what rate it will decrease).
The decline rate % is based solely on these assumptions the model output is just a matter of adding up the output from each “average well”, pretty simple really.
Hi All,
The Decline rate in the four previous charts was done incorrectly, I used all oil output in the denominator rather than just legacy output. Sorry, dumb mistake. I won’t bother to re do them all, I will just correct the 72 well chart immediately before this comment, if anyone is interested in any particular case I can repost that corrected chart. The data before month 53 will be the same for all the charts and that is where the correction is most important (legacy output gets close to total output as time moves forward).
http://peakoilbarrel.com/bakken-update-april-production-numbers/comment-page-2/#comment-41262
The comment at the link above was supposed to go here. It is a somewhat more realistic 70 wells added per month scenario with EUR decrease and economically recoverable resources calculated.
The spreadsheet link in my comment to Verwimp above is broken
The correct link is below (old spreadsheet calculated legacy decline rate % incorrectly)
https://drive.google.com/file/d/0B4nArV09d398WXI5TTFaME8xYzg/edit?usp=sharing
Hi Dennis,
Thanks for sharing your spreadsheet. I completely agree with “Until the new well EUR starts to decrease, if the number of new wells stays flat, output goes up, simple mathematics.” But your error is the uniformity of the used well profile. The bunch of cumulative curves Enno shows, makes clear that well profiles are changing over time. When I reverse-engineerded those cumulative curves, I saw that EUR is decreasing since 2011. I read assumptions several times of “sweetest spots drilled first” . Looking at the data I am forced to see that, indeed, the sweetest spots were drilled first.
I am affraid Rune Likverns well profile is outdated now. The well profile is a changing thing. And that change is an overall decrease.
Hi Ron,
On future decline rates, isn’t the DPR predicting future decline rates from April to July?
Post on: 06/19/14 00:05 UTC
Climate Change Comment #34
According to science in the distant future the Sun will engulf and destroy earth. How can anyone say that any warming trend we see isn’t at least partially due to this? What can be proven is that Government always looks for ways to control the general population and Climate Change is the latest tactic in their arsenal to control us in every way. Ultimately never trust the Government and you will be correct 100% of the time.
\facepalm
According to science in the distant future the Sun will engulf and destroy earth. How can anyone say that any warming trend we see isn’t at least partially due to this?
I hope you are being sarcastic. Otherwise you are totally ignorant of science. Astronomers know exactly where the sun is along the main sequence. The sun will not leave the main sequence and start expanding until it runs out of hydrogen to fuse. That will be in about 5 billion more years. Of course the sun will heat up slightly before then but the change will take place over many millions of years.
What can be proven is that Government always looks for ways to control the general population and Climate Change is the latest tactic in their arsenal to control us in every way.
Spoken like a person who is truly paranoid. Just who is “the government” anyway? The president? Congress? Or someone else?
Ultimately never trust the Government and you will be correct 100% of the time.
No, you would be incorrect almost 100% of the time. I trust the government to deposit my Social Security payment into my bank account every month. And for the last 246 months they have not failed me even once. So I trust that it will be there this month also. Of course if the government collapses then that will not likely happen anymore. But as long as the government is intact, I will trust them to do what they say.
Bottom line William, climate change is not a conspiracy created by the government to control you. Also the government is not your enemy.
Sadly, this probably isn’t paranoia – it’s just listening to Koch brothers/Fox News type propaganda.
“The Paranoid Style in American Politics” by Richard J. Hofstadter (1964) makes for amusing reading, given that the ravings of previous generations (against the Masons, the Pope in Rome himself, etc.) can be subsituted perfectly for various current claims against, oh, I don’t know, the United Nations, the IPCC, etc. One may not be surprised to learn that ostinato and obstinate share the same root.
Hofstadter is primarily talking about people who are irrational.
The Koch brothers aren’t irrational – they’re defending their (fossil fuel) economic interests. On the other hand, they do take advantage of irrational people, by providing them with irrational ideas that are attractive to them. In other words, they’re cultivating astroturf.
A quick google search reveals that the “first inning” metaphor is popular among tight oil enthusiasts. Comparing problems to sports is a common and effective way of making a point, even if the comparison makes no sense.
Let’s leave the analogies behind and just deal with facts. It’s a fact that tight oil is expensive to produce. It’s a fact that the decline rates on tight oil wells are huge. It’s a fact that many, if not most, companies are having trouble making money on the tight oil fields as indicated by asset divestitures and cash flow problems.
Clearly, there is a reason why nobody drilled tight oil when oil prices were low. And now that we are forced to go after this expensive resource using the most advanced technology available to squeeze as much as possible out of the ground, it’s hailed as a triumph. As if the fact that we are forced to use advanced technology is a sign of progress.
Some people are very good at putting lipstick on pigs — we call them CEOs.
Even the Financial Times is beginning to warn over shale oil hype:
http://www.ft.com/intl/cms/s/0/d71febe2-f6ae-11e3-b271-00144feabdc0.html#axzz352sC1SkI
”The cost to extract “tight oil” reserves, held in shales and other challenging rocks, is significantly higher in other countries than in the US. This suggests they will need a higher price of oil to be commercially viable, even amid a glut of US shale oil.”
Does anyone know a good source of info on how oil is moved from original source to a refinery? I’m curious about the details of the logistics and costs associated with this. I imagine that big well developed fields must have temp storage tanks but what is going on in the newer smaller locations? Is it a trucked to intermidiate storage until pipelines are built? Are trucks used to load onto rail direct? Seems like there must be many thousands of wells that are stripper status. Do trucks do milk runs to pick up their output? I realize that there are thousands of miles of pipelines but I am curious as to how the pipeline are fed. Who pays for the transportation costs? How does pipeline pricing work? Back of the envelope calculation shows me that rail trans alone could add $5 – $10 per barrel. Are all the smaller sources just mixed into tanks in distributed tank farms? Google view of Cushing shows lots of tanks. Are there smaller “Cushings” all over the palce? How much does it cost to ship via tanker? Looking at the sizes of some of the bigger refineries, 100k bbls / day and bigger, I would think that they must have their oil sourcing done months ahead of time. Not enough room for unlimited tanks and they really don’t want to shut down.
18 mill bbls / day is one hell of a complicated supply chain.
Dang, the more I think about this, the more questions I have.
subscribe to the rbn site newsletter, that should keep your busy. PO is not really discussed, it is more about the infrastructure, markets, and whatnot. Basically how oil moves and money is made, and you can still make money even on the downslope…..
thanks. bit of a steep paywall but enough free stuff to get a taste. appears to be major issues with actuall measurements of volumes which is connected to how royalties are calculated.
the oil related infrastructure is effin’ amazing. I constantly am reminded on how diffecult and energy/time consuming it will be to replace. not quite all out doomer, but very close.
Yeah, I should have mentioned there is a free daily blog that is accessible for 30 days…
I get the link e-mailed daily…
It is a helluva complex supply chain on a global scale. To get at your question about who pays for the transportation, it is the producer by virtue of a reduced net back price (netted back to the well head). So we start with Cushing WTI and then knock off the costs of transport be it truck, rail or pipeline (or some combination).
Example: $100/bbl WTI – $6/bbl trucking and then -$8/bbl pipeline gets a netback of $86/bbl at the wellhead.
FYI with these newest proposals there are now 8 mini-refineries (20,000 bpd input to produce approx. 7,000 bpd of diesel) in the planning stages in the Bakken region. Additionally, there is one in the Dickinson, ND area that is almost fully constructed and will soon be operational (the Dakota Prairie Refinery).
Oil refinery project proposed for Baker: More facilities possible for Minot, East Fairview
Quantum Energy CEO Andrew Kacic, who visited Baker [Montana], said he plans to build five…oil refineries, called “21st century energy centers” by the company.
Quantum announced plans for the first such center in April, when it secured 122 acres to build a Bakken crude oil refinery in Fairview, Mont., more than 40 miles west of Watford City. The facility is projected to generate $60 million annually, and employ more than 100 full-time workers, according to a Quantum announcement.
The company is in the process of getting permits for that refinery, according to its website.
Refineries will use enhanced oil recovery methods to increase diesel production with carbon dioxide, Kacic said. Some propane byproduct will also be stripped from the crude oil to decrease the diesel’s volatility when being transported by rail.
Baker City Councilman Brandon Schmidt said Quantum’s presentation on June 4 still leaves questions unanswered.
“It wasn’t anything solid,” Schmidt said. “It was more basically just a heads up that this might be going on.”
Fallon County Commissioner Deb Ranum said she doubted the success of the proposal. She said the county commission would need to meet many more times to hash out utilities issues.
“Our problem here is water,” Ranum said. “We wouldn’t even have enough wastewater to operate an oil refinery.”
[Mona Madler, director of the Southeast Montana Area Revitalization Team] countered that she is confident that Fallon County officials can find a way to provide the water through wastewater sources, similar to Dickinson’s refinery.
“Refineries will use enhanced oil recovery methods to increase diesel production with carbon dioxide, Kacic said. Some propane byproduct will also be stripped from the crude oil to decrease the diesel’s volatility when being transported by rail.”
haha what?
“Baker City Councilman Brandon Schmidt said Quantum’s presentation on June 4 still leaves questions unanswered.”
Ya, like . . . what?
Thanks for the update. “Barrels per day per well” should be written in the graphs as “b/w/d” or “b/well/d”; as it stands it is not at all obvious what the last graph is about. Cheers.
Okay, the top blue line is barrels per day per well for all wells inside the Bakken.
The middle orange line is barrels per day per well for all wells in North Dakota.
The bottom grey line is barrels per day per well for all North Dakota wells that are not inside the Bakken.
New York Assembly Overwhelmingly Passes Fracking Moratorium
Brandon Baker | EcoWatch | June 17, 2014 9:25 am
Pressure on Oil Megaprojects
By MURIEL BOSELLI, NY Times, JUNE 17, 2014
Impressive that they can write that article with out a single mention of peak oil when basically the entire article is describing peak oil’s impact pretty darn clearly. But I guess that’s how this will play out in public consciousness. Oil production hasn’t peaked, it’s just that the cheap oil is gone, oil prices per barrel are too low, and the costs of producing new oil are too high. Steven Kopits called the oil majors plummeting desire for more capex exactly right in his presentation in February.
In December 2012, Michael Kumhof (an economist researching for the IMF) talked about the need for increased oil prices to maintain increasing production- “if the world economy wanted to make oil output grow by about 0.8% per annum (which is what the International Energy Agency has been predicting), oil prices would have to rise very dramatically, by almost 100% over the coming decade !”
It remains to be seen whether the world economy could tolerate such increases. It looks like the oil majors don’t think so. Peak oil is either here now or very close.
Energy and financial pundits take lessons at professional wrestling referee school. You cannot graduate until you prove conclusively you cannot see an elephant in a living room with you.
A Continental well in the Bakken went bad and cost approximately 60 grand per acre at the 1280 acre spacing to fix the problem. It was a drain on the pocketbook for one participant and was forced to liquidate some of an account to pay cash for the damage.
Not all wells are going to be a success.
Continental was applying pressure to the mineral owner maybe in hopes of acquiring the well, but alas, the participant held on to the cash royalty payments for that rainy day occurrence which did happen.
The production does add up to an amount that is more than zero. You have to cover all bases, you have to have cash in accounts to be able to weather the setbacks.
It is not about oil, it’s about money.
The rig count is at 189 and most activity is in Dunn, Mountrail, Mackenzie, Williams and Divide counties.
https://www.dmr.nd.gov/oilgas/riglist.asp
An error of a factor of 10 in the math, the cost was approximately 6000 dollars per acre, not 60,000. Sorry.
Eno,
I’m not at all certain about the 50 years number, but I’ve always just used 30, sometimes 40 years. No one knows for sure. These are only estimates. The most important item is payback time. All the rest is gravy.
“You say that 603k is the going average, and based on the NDIC data I say you are clearly wrong.” This is a valid point, but it depends on what you mean by the Bakken. For me the Bakken means the 10,000 sq mile thermally mature area (sweet spot) (most OOIP flows here with fracking) that CLR mostly delineated (derisked) years ago, plus the roughly 4,000 marginally mature area (not so sweet spot, where only some of the OOIP flows with fracking). That which doesn’t flow with fracking is kerogen, which is pretty much present and dominating everywhere outside of the CLR designated areas. I am only referring to wells within this designated area as that is where the ultimate Bakken production will come from.
CLR has considerable acreage outside of this designated area. This area must also be drilled, even at a loss, if they are to retain their leases there. That is what they are doing, and that is why you are correct, but your information is not particularly relevant. It would be if……everyone was drilling all the sweet spots first. But they aren’t! That said, the oil industry runs on a concept called best practices, which means all companies will eventually copy whoever is best. CLR is NOT the best in the Bakken. They are just damn good. EOG is considered much better because they can get nearly the same amount of oil out with half the lateral length.
CLR’s SCOOP play is better for them than the Bakken, so much of their current focus is there. EOG greatly lowered their Bakken activity last year because their holdings in EF and the Permian gave them a much better return on investment. But, they are back this year. Remember, these are corporations, and it’s not really about oil. It’s all about money. Believers in PO are barking up the wrong tree, because you are following oil production (actually production declines) instead of following the money. EOG recently bought into four other NEW/old shale plays located between the Bakken and EF. What does that tell you?
You can be sure that CLR has cherry picked their best locations for their downspacing experiments, their multilevel development experiments, and their increasing amounts of sand experiments. So, obviously such results cannot be extrapolated to their whole land area. Tangsrud is not quite disasterous, but it surely isn’t at all impressive. But, it is only a delineation experiment to test how far North the economic viability of TF2 and TF3 extend. If they have got that right, all that’s left to delineate on those levels are E,W, and S directions. It costs them time and money and holds down their average EUR, but it must be done someday.
If you want to consider the total cost of drilling wells and running the whole company, you are free to do so. It is a valid thing to do. But, most analysts are just looking at the payback time of well production. That is how you can compare apples to apples, but not to oranges. Whether a company is cash flow positive or negative doesn’t tell you much. It is common practice to use large amounts of debt to buy up all available shale leases. Speaking for all investors, we are mostly interested in good (honest) management, a good land position, being pretty far up on the learning curve, increasing production growth, increasing reserves, and last but not least, an increasing land position (resources) by going INTO debt to buy more land.
The equation is simple. The shale oil is there. It can easily be gotten out with a good profit at today’s prices….if one knows how to use today’s technology. However, today’s technology quickly becomes yeasterday’s technology, as new breakthroughs are always occurring. Sorry, but there is no reason to doubt all the shale hype out there. But, if there is, I’d be the first person to want to hear about it.
Did I address all of your concerns?
“This area must also be drilled, even at a loss, if they are to retain their leases there. ”
So you are expecting a decline in average barrels/day per well? That’s not very bullish.
Watcher,
Having to drill low EUR wells just to hold on to a lease is all part of doing business in the oil patch. Such practices obviously put downward pressure on average EUR’s for any given area. On the other hand drilling high EUR wells puts upward pressure on same. For any given month Bakken production results (divided by the # of wells) simply reflect such pressures. No, I am not expecting a decline in average bpd/well, although that may well happen until the industry starts to shift to full field development in 2015. That’s when the development focus shifts to the 10,000 sq mile sweet spot of thermally mature oil known as “The Kitchen” starts to takes place, and work on lower EUR wells starts to taper off. Sorry, but you folks at this site got it exactly backwards, cuz you don’t follow what is going on at the company websites.
Personally I am highly skeptical about the long term possibilities of tight oil but there are some things that don’t quite make sense to me in terms of the dollars and cents end of the business at the ultimate level.
It seems that most people who are skeptics are convinced that tight oil is a money loser as the industry exists today. If the cost of buying up land leases at exorbitant prices is included, and the price of learning the tight oil drilling business is included- which has taken a few years and is an ongoing process- maybe it is a loser.
If somebody puts way too much money in buying up oil rights, and on top of that doesn’t have state of the art cost versus production skills–then it is indeed easy to see that they might be losing money and have to get out of the business.
But if somebody else can come in and get that same ground for substantially less money -knowing a lot more about it before they make an offer for it- the new operator might do ok or even a lot better than ok.For now.
It doesn’t take that many barrels of oil to add up to ten million bucks at prices approaching a hundred dollars a barrel. Of course interest adds up fast- and I have no idea just what the interest rates are in the oil industry these days but they are apparently pretty low.
Just eyeballing the graphs published here without even using a pencil and enelope it looks as if a whole lot of wells will generate ten million bucks in revenue in three years or maybe even less.
Now if the net price received by the owners is only eighty bucks or so after shipping — things look a lot worse.
So – My questions .
When we see a cost per well figure such as ten million bucks, what is included and what is excluded in this figure?
What are the typical shipping costs paid by well owners?
What are the interest rates typically paid in the tight oil biz?
It does seem that it is possible to make some money at first glance if you don’t have too much expense in terms of lease costs and shipping costs and reasonably good luck in average production per well.
But even if this is so it does not prove that the ” sweet spots” extend out over long distances beyond the spots currently being developed.
A few years down the road it might take a substantially higher price to cover the cost of drilling an average well that will produce less because the ground is not as good, all other things held equal.
Maybe the wells will mostly produce a trickle of oil for thirty or forty years or longer.It seems obvious that it would take a substantial amount of electricity to keep them producing that trickle but if any use can be found for cheap intermittent wind power this would seem to be a good one if the lines can be extended to the wells- not for drilling but simply for pumping. That would require a much smaller line and much less energy for a substantial period of time – decades- and might be economical.
Or maybe the well would produce enough gas to run the pumps on gas.
Once the well is down to that eventual few barrels a day trickle electricity is probably the biggest expense involved it keeping it in production. I have read that as much as half or even more of the revenue from stripper wells in Texas is needed to keep the pumps running but with that being the only real expense- Texas stripper wells are apparently quite profitable to the owners.
I recently met a man who moved to my neighborhood (-which is unfortunately filling up fast with vacation houses- ) who drives a Viper and the biggest motor home I have ever seen as well as couple of other new cars. He has built a million dollar property.Being nosy I ask about the money and he said he was smart enough to marry a woman who inherited a dozen stripper wells in Oklahoma and that they have been living pretty high on the hog for the last ten or twelve years since oil went past twenty bucks and stayed there.He says he used to work by the hour in construction and he looks it- you can tell easily enough as a man gets older.
Other than knowing people online I guess this ” seventeen barrels a day and that ain’t hay” guy is the closest I will ever get to knowing an oil man. That is a line from an old country and western song.I guess he and his wife have at least a hundred barrels a day with twelve wells. At fifty bucks net a barrel that would add up nicely.Their net might be double or triple that.
Noting again, a 60 stage fracked sour spot can outproduce a 30 stage fracked sweet spot.
No such thing as a sweet spot unless all things are held stagnant.
Hi Watcher,
Any proof of that? If the extra oil from 60 frack stages more than pays for the extra expense it would be the norm, that is the way business works, you invest until marginal revenue is equal to marginal cost in a competitive industry to maximize profits, Econ 101.
Proof of what? That a 60 stage frack in a sour spot can outproduce a 30 stage frack in a sweet spot? It’s an assertion with no dollar input.
60 is 100% more than 30. For it not to be true then sweet would have to be 100% superior to sour. Or 100% superior to average. Odds of that seem low. Then there is the strategy potentially of fracking 3D with the bore positioned below the Bakken layer targeted, so that the downward frack can get into the TF layers. That would *create* a sweet spot.
Or one can change definitions. A 60 stage frack can become by definition a sweet spot.
Watcher,
You are really getting into some very dangerous territory here. Would you mind defining what you are calling a Bakken sweet spot in EUR’s. And, it would certainly help if everyone else who uses that expression would please define it in EUR’s.
It’s defined by latitude, longitude and depth. Not by EUR.
Watcher,
Okay. Could you please define your Bakken sweet spot(s) by latitude, longitude, and depth, so I will at least have some idea of what you are referring to? Because, I have absolutely no idea what any of you people here are referring to when you use this expression, and I’m rapidly coming to the conclusion that none of you happen know either.
You just might be able to clear up a lot of misunderstandings here.
Carl,
Thanks for your response. I have explained to you the reasons that have made me suspicious/cautious, and I think those reasons are still valid. You sketch an optimistic picture about sweet spots hardly drilled, but so far the data tells me differently. But if you’re right, we should soon see the evidence of that in the data, and then I’ll be happy to admit that I was too critical.
Benjamin Graham mentions that he as an investor looked at the future as a source of concern, and demanded current value. I see that you have a different investing attitude, and I hope that works out for you.
Enno,
I think your replys are valid. I just don’t think they are very relevant.
My assertion that the sweet spots have hardly been drilled is based upon CLR’s October, 2010 technical paper which can be accessed at their website by clicking on “Our Operations” then upper center “Technical Papers”, then you’ll find it at the bottom of the page. It is because 48,000 wells with average EUR’s of 500k will need to be drilled to produce the 24 billion BOE, that CLR claims are recoverable from the two upper layers of the Bakken. As only about 8,000 wells have even been drilled so far, it wouldn’t even be possible to have hit all the sweet spots, as YOU seem to call them. For me the 10,000 sq mile core of the Bakken is the sweet spot. Do you not understand/accept that oil companies are FORCED to drill all the low EUR wells, (that you are so focused on), in order to hold on to their leases????? At present all of these 8,000 wells drilled so far are merely exploration, lease holding, or experimental wells. None are what are known as full field development wells. That first starts in 2015. But, as the total producing area will be about 14,000 sq miles, about 6,000 low EUR leaseholding wells still need to be drilled….just to hold on to the leases. That’s why your data doesn’t show the increase in EUR’s, that the top oil companies are actually getting. It is not because it is not there. It is because you can’t see it from the data you are using. Try getting your data from company websites. Then you will agree with me.
The current value I am invested in is how much oil companies are pulling out of the ground right now. The future value, which is assumed to be far greater, is how much oil they expect to produce in the future.
Seems to be in ISIS hands:
http://talkingpointsmemo.com/news/sunni-militants-claim-iraq-s-largest-refinery
Dave,
According to BBC yesterday, 15,000 refinery workers were evacuated in anticipation of anticipated battle with ISIS. That’s a lot of workers and it gives you an idea of scale.
Doug
180K bpd?
15K people?
Doesn’t sound right.
I know. Probably isn’t. That’s the trouble with reading the news but sometimes the BBC does a better job than some of the others!
Not often does my jaw just drop when I read a headline.
This was one.
http://www.theguardian.com/environment/2014/jun/19/russia-secretly-working-with-environmentalists-to-oppose-fracking
We greens are all really reds under the beds! Putin stage the hijacking of the Greenpeace ship and crew just to provide cover!
This is below the belt even by the loony right press standards these days.
I think you’re a little behind the times.
Putin is not altogether hated by the right wing. Being associated with him would be a positive thing.
There is no proof given for this allegation- nothing but the word of one politician.
But the article nevertheless makes perfectly good sense in every respect if you know a little bit about the Russians and their history. I will toot my horn a little and say that I am most likely the only person who comments here in this forum that has read a good bit of USSR history.Reading happens to be my primary pastime and history is my favorite subject so this is not saying a lot.I am most definitely only an armchair historian.
The old USSR had a very good and very extensive propaganda machine and made excellent use of it.They didn’t care if something happened to be true- they publicized it if it appeared to further their interests. It didn’t matter a hoot to them to tell any sort of lie, no matter how big or how small, if they thought it would further their interests.
The people who came up thru that system as young guys are running things in Russia today. Putin is a spook and a propaganda guy. He probably knows more personally about disinformation campaigns than all the professors at the Kennedy School of Business combined.
People can be the bitterest of enemies and still have common enemies.The fact that Putin and his buddies might be behind a campaign to slow or stop tracking is not evidence he gives a damn about the environment or anything of that nature.It is not an indication he or his team are interested in furthering any of the goals of Greenpeace in particular or the environmental movement in particular except as a matter of accidental convergence.
The Russian economy runs on oil revenues to the tune of at least a billion dollars a day.
There has been ample evidence presented in this forum that oil production world wide would already have passed a clear peak if it were not for the success of the tight oil industry in this country.
IF Putin and his team can slow down the fracking industry to any significant extent it means many many millions of dollars or Euros or rubles or whatever to Russia.A few million spent on discrediting the tracking industry would earn a return that might easily be as high as a hundred to even thousands to one by allowing the Russians to get a higher price for their exported oil.
If they manage to keep a million barrels a day off the market for ten years- not stopping the tracking industry but merely slowing it down-delaying it- that would probably mean any where from a couple of bucks on up more per barrel for every barrel they sell for that ten years.”On up” might mean another five or ten bucks per barrel.That times a few million barrels exported per day for 3650 days is a hell of a lot of money.I can’t put a precise figure on it but less oil on the market means a higher price for people who are selling oil.
I am most emphatically NOT SAYING THEY ACTUALLY ARE doing anything along this line.
But there is no question in my mind that such actions would be perfectly in keeping with their history.
There is no question that they have the money and the personnel necessary to doing it.
IF I were a betting man I would BET that they are doing it.The payoff in relation to the risk and expense is too tempting to be resisted on practical grounds.
American corporations do the same basic sort of thing day in and day out right out in the open.They support think tanks that tell us not to worry about running short of gasoline and donate to politicians that oppose higher fuel efficiency standards.No doubt they do plenty that is not so out in the open.
So far as I can tell just about all large businesses have scads of public relations experts on the payroll who are no more ethical than old commie propaganda experts – the jobs of these experts being to influence public opinion in such a way as to protect and nourish their employers.There is no question they will do anything they think they can get away with.
We know for instance that most of the bigger banks in this country were running scams and breaking the law thousands of times a day in the recent past.
Why should anybody think the Russians are any nicer people than our own bankers?
Our attorney general isn’t making any effort to lock up any bankers.
We don’t question whether the Koch brothers engage in such tactics but they are at least theoretically subject to prosecution.
He couldn’t touch a Russian oligarch inside Russia if his pension depended on it.
I will toot my horn a little and say that I am most likely the only person who comments here in this forum that has read a good bit of USSR history.
I actually did a thesis on the role of anarchism in the Russian Revolution.
UCSB accepted it.
This is good to know. The broader the combined expertise of the commenters the better the insights to be gleaned from participating in this forum.
That’s a little far back but if you studies reached into the thirties on up thru the cold war era you definitely know a hell of a lot more about USSR history than I do or ever will.
So- what is your opinion of the old soviet propaganda machine?
What is your opinion on the current question?
This sort of intrigue could- if the cards fall wrong- lead to an international crisis. Wars have been started over less.
“The Net Delusion” by Evgeny Morozov indicates that the propaganda system is alive, well, and updated for this binary age.
Useful Iraq summary:
http://oilprice.com/Energy/Energy-General/Iraq-Why-its-worse-than-you-think.html
Andy, I agree.
apparently, you all are just not significant.
“….but the fact remains that there is no significant work suggesting that world oil production must peak any time in the foreseeable future, unless demand-side pressures are the cause.”
http://www.forbes.com/sites/michaellynch/2014/06/19/peak-oil-1-what-is-peak-oil/
not sure why this comment ended up here
?
The odd thing is there are two Michael Lynch’s writing about oil. One is a somewhat crazy blue skies and rainbows guy and the other is low key.
It seems most of the trucks are conventional tankers of the sort used all over to haul liquids. Some articles talk about 8000 gallon loads but that seems a tad heavy considering weight limits on public roads.It probably takes between 125 and 150 trips to haul a million gallons. It is easy to see that with a lot of wells going in and old two lane rural roads that traffic jams are real headache by the time you consider pipe and sand and all the other stuff used on a well site.
Does anybody know how long a typical water haul is?
I know permanent pipelines are extremely expensive but water can be moved in temporary lines laid on top of the ground that are not very expensive- lots of farmers have few thousand feet of irrigation pipe they move around from place to place and use only a few days per year.Water is not a toxic substance and a blow out would not cause any significant damage.
It seems at first glance that temporary water lines would be economical investments even if they could only be used in warm weather.
The numbers could be 40 million pounds of water. 5 million gallons. There are references to gallons and to pounds around. It’s annoying.
A garden hose to a house does about 720 gallons an hour at household pressure levels.
2.5″ pipe will do a somewhat nominal 900 gallons/minute, so almost 6000 gallons/hour. 5000000 gallons /6000 –> just about 1000 hours. / 24 is 42 days.
Looks like truck may be better. I do wonder about the tank on site to hold it all. A gallon is 7 cubic feet. It would be a 350’X350’X350′ tank. No way. There’s something in this we don’t understand. We’ve seen lots of well site pics, there’s no tank that size there.
oops the pipe does 54000 gals per hour. Far less than 42 days.
900 gpm sounds high for a 2 inch pipe. about 7.5 gals per cubic foot or 0.13 cubic feet per gallon
Shrug, got it from a table online. I think it quoted a high and low end and I picked a number in the middle.
It IS pressure dependent of course.
For the third time in a week the New York Times claims that the Baiji Oil Refinery in Iraq has been taken by ISIS. Again I am doubtful. This time they are contradicted by an article in Platts’ The Barrel
see http://blogs.platts.com/2014/06/19/baiji-iraq-map/?sf3369839=1
Although the British security force has now been withdrawn.
The truth is probably somewhere in the middle. I read up a bit on the security features that were installed at the refinery. The army can be holed up in one or both control centres which are easily defended, whilst the bulk of the site is in ISIS control.
Either way, the refinery is offline, and could be trashed by ISIS at will. Situation on the ground will be very unclear, and all propaganda will be lies from both sides.
“and all propaganda will be lies from both sides.”
Distrust all data of all kinds in the new normal.
Using the full Bakken model including economics and with an EUR decrease resulting in a TRR of 8.5 Gb, I created a scenario with 70 wells added per month from May 2014 to Dec 2035 with the wells added decreasing after that to keep profits positive. The economically recoverable resources (ERR) are 8 Gb by Dec 2073. Output initially falls to 700 kb/d and remains at that level to 2021 and then declines slowly, output at 600 kb/d in 2029 and to 300 kb/d by 2040. No wells are added after August 2041 and the total number of wells is 25,700 wells.
Isis takes control of border crossing between Iraq and Syria
Militant group able to move weapons and equipment as fighters prepare for likely assault on Baghdad, say officials
Kevin Rawlinson and agencies, theguardian.com, Saturday 21 June 2014 15.53 BST