Level-Headed Analysis of the Future of U.S. Shale Oil Industry

Recommended reading, as it covers both pros and cons without the usual hyperbolic hysterics from either camp.  2 thumbs up to the author.

👍 👍

Is the Shale Revolution Here to Stay?

Summary

U.S. shale oil is a booming business. As it drives up global oil supply and puts downward pressure on oil prices, U.S. production of shale oil poses a geopolitical threat to other oil-producing states. But critics say that the boom won’t last. If true, that changes the geopolitical calculus.

How much longer will shale oil be a booming business? The answer to that question, while fuzzy, has long-term geopolitical implications. U.S. shale oil production has grown steadily, putting downward pressure on the global price of oil. We’ve written before about the power of shale oil and the impact it has on other geopolitically important oil producerslike Russia and Saudi Arabia, which rely heavily on oil revenue to either fund their government spending or support their economies. Our forecasts for these countries are built in part on the assumption that, as the global supply of oil increases, its price will hit a ceiling that could strain these countries’ public finances, which in turn would have political ramifications. But shale skeptics maintain that the industry is not sustainable. If they’re right, and if the shale industry were to die out in the next couple of years, tanking oil supply and spiking oil prices, the geopolitical calculus for Russia and Saudi Arabia would change substantially.

...

  • Like 2
  • Upvote 2

Share this post


Link to post
Share on other sites

That was a good article read, took the time to read it all.  It provides some positive news, but have to keep chipping away at mountain of debt.  I believe more small fish will be grabbed up by larger ones.  One question, when it says shale producers, is that referring to the producers, drilling companies, sand companies, service companies, or as a whole of all?  What is everyone's thoughts or guess on the duration of the boom, considering all the additiinal pipelines, refineries, etc. being built to support the continuation of things in the patch?

  • Like 1

Share this post


Link to post
Share on other sites

13 hours ago, Tom Kirkman said:

Recommended reading, as it covers both pros and cons without the usual hyperbolic hysterics from either camp.  2 thumbs up to the author.

👍 👍

Is the Shale Revolution Here to Stay?

Summary

U.S. shale oil is a booming business. As it drives up global oil supply and puts downward pressure on oil prices, U.S. production of shale oil poses a geopolitical threat to other oil-producing states. But critics say that the boom won’t last. If true, that changes the geopolitical calculus.

How much longer will shale oil be a booming business? The answer to that question, while fuzzy, has long-term geopolitical implications. U.S. shale oil production has grown steadily, putting downward pressure on the global price of oil. We’ve written before about the power of shale oil and the impact it has on other geopolitically important oil producerslike Russia and Saudi Arabia, which rely heavily on oil revenue to either fund their government spending or support their economies. Our forecasts for these countries are built in part on the assumption that, as the global supply of oil increases, its price will hit a ceiling that could strain these countries’ public finances, which in turn would have political ramifications. But shale skeptics maintain that the industry is not sustainable. If they’re right, and if the shale industry were to die out in the next couple of years, tanking oil supply and spiking oil prices, the geopolitical calculus for Russia and Saudi Arabia would change substantially.

...

Very good article and they refer to Rystad ...........

Hydraulic fracturing and horizontal drilling are only two aspects of the various techs that make shale production successful, there are hundreds of techs and combinations of those techs that are used to find, analyze , plan well sites, well designs, completions , drilling etc to improve the entire process from a-z and lower costs and improve profitability and sustainability in shale.

 

  • Like 1
  • Upvote 1

Share this post


Link to post
Share on other sites

What attracted me to the oil industry from high tech was the apparent opportunities for disruption. I went to the Energy Capital Conference to see what I could learn. I'd done roughneck work in college because it was the fastest way to make the most money (legally) in those days. I still remember my last day on a rig, 70 mph winds and a blizzard, wind chill probably took us to 40 below. The driller had to shout to be heard and yelled from two feet away, "If I knew one g-damned thing about computers, I wouldn't be out here freezing my nuts off! "

I took that as excellent advice and never looked back. After I'd sold my first two companies and fancied myself an "investor" I thought I'd look into the business end of the oil business. At that Energy Conference, a banker from Credit Suisse gave a presentation declaring in no uncertain terms that there was no greater destroyer of capital than the oil business. I was hooked. Taken as a whole, he was and is undoubtedly correct. On average, and without a doubt, tons of capital is being destroyed in this business by inefficient, fossilized thinking, and often unscrupulous operators. Even the super majors have those tendencies at the manager levels in their little fiefdoms.

So yes, money gets lost, but money also gets made. Think of microcomputers and the hundreds of companies that bubbled up and then died an ignominious death. Same with semiconductors and flat screens, you name it. My observation is that there will be operators who will intelligently embrace new technology and dozens more who won't. I had a senior VP of an oil company proudly tell me, "We strive to be the leader among the followers". 

The whole reason we're even talking about fracking is because there was a visionary named George Mitchell who, after getting turned down by every oil major out there, raised his own capital and cracked that nut himself. The "followers" soon followed and still do. Meanwhile there are other technologies and processes that can and will be utilized by some smart operator and the one thing I can guarantee is it won't be utilized first by any stinking major. 

Roger Butler with Imperial Oil invented SAGD and until the Aspen project (due in 2020) I'm unsure they ever once used it. Meanwhile look at all the other operators who embraced it Wholeheartedly. That to me is typical of this industry. 

Off my soapbox 

  • Like 2
  • Upvote 1

Share this post


Link to post
Share on other sites

(edited)

2 hours ago, Ward Smith said:

What attracted me to the oil industry from high tech was the apparent opportunities for disruption. I went to the Energy Capital Conference to see what I could learn. I'd done roughneck work in college because it was the fastest way to make the most money (legally) in those days. I still remember my last day on a rig, 70 mph winds and a blizzard, wind chill probably took us to 40 below. The driller had to shout to be heard and yelled from two feet away, "If I knew one g-damned thing about computers, I wouldn't be out here freezing my nuts off! "

I took that as excellent advice and never looked back. After I'd sold my first two companies and fancied myself an "investor" I thought I'd look into the business end of the oil business. At that Energy Conference, a banker from Credit Suisse gave a presentation declaring in no uncertain terms that there was no greater destroyer of capital than the oil business. I was hooked. Taken as a whole, he was and is undoubtedly correct. On average, and without a doubt, tons of capital is being destroyed in this business by inefficient, fossilized thinking, and often unscrupulous operators. Even the super majors have those tendencies at the manager levels in their little fiefdoms.

So yes, money gets lost, but money also gets made. Think of microcomputers and the hundreds of companies that bubbled up and then died an ignominious death. Same with semiconductors and flat screens, you name it. My observation is that there will be operators who will intelligently embrace new technology and dozens more who won't. I had a senior VP of an oil company proudly tell me, "We strive to be the leader among the followers". 

The whole reason we're even talking about fracking is because there was a visionary named George Mitchell who, after getting turned down by every oil major out there, raised his own capital and cracked that nut himself. The "followers" soon followed and still do. Meanwhile there are other technologies and processes that can and will be utilized by some smart operator and the one thing I can guarantee is it won't be utilized first by any stinking major. 

Roger Butler with Imperial Oil invented SAGD and until the Aspen project (due in 2020) I'm unsure they ever once used it. Meanwhile look at all the other operators who embraced it Wholeheartedly. That to me is typical of this industry. 

Off my soapbox 

I have said this before but there are a few people who just dont believe anything good about shale or any existing or new techs will help lower costs and make shale further sustainable and a long term fixture in the upstream oil and gas sector.

There are companies that will pop up and fail because of no planning, bad planning, bad money management and bad operational structure and practices. It has happened in the shale sector 3 times and will happen again and again. Survival of the fittest.

Not all companies survive, not all companies make a profit in a few years, not all companies succeed. Some shale extremely bloated, they got their bubbles burst and it will happen again. The issue was technology and its place in shale. Some say there has been zero new tech for shale , its all old, well kind sirs, new technology doesnt just pop up overnight, technology evolves from old and new, you use a combination of various techs to make things work. A biotech, a pharma company fail in their R&D so all of their other projects are bad failures too? look at how much money and time is required by biomed companies, by pharma companies and IOT and tech companies to bring forth something to the market and they keep using the same tech to improve upon and launch into something better and newer. Same thing with shale. Obviously most of the people have an agenda against shale or have lost big in shale. Either way, some folks just dont want to hear or know about hundreds and hundreds of new breakthroughs from seismic processing and interpretation to proppant tech, or waterless fracturing, or gasfracs, or hitech rigs, walking talking rigs, or the successes of multi well pad drilling, because it is all old.

So is heart surgery it keeps on improving everyday as are organ transplants and from growing bacteria in petri dishes, we are now growing cells and tissues for entire organ growths.

It is like Apple, how it started what happened to it? and where it is now?

If someone's relative or friend died from a bad stent job, or chemo didnt work for their loved one, or the kidney or liver  transplant failed, then it would be fair to say all these medical developments and techs and procedures are bad failures? Fisker failed so all EV companies are failures? Tesla ?? there were hundreds of small computer companies back in the 70s/80s? how many survived today? so all computer companies are failures, and yet they were using more or less the same tech and tools? Some drug companies that spend billions of $$$ on R&D fail on a few of their products in the pipeline, some fail completely but does it mean for example one company's specific anti cancer immunotherapy failed for sometime so they all have to fail> and all the other companies in the same line of r&d will fail too?

The fly by the night operators who thought they would make a "killing" overnight in shale got "killed off", they overpaid, they under planned or with no plans charged onto armies of shales like Don Quixote , they used service companies who also for the same reason jumped into that boat with many holes. They actually had no clue what they were doing, except they were able to raise some $$$ and go overpay for leases and had no clue what was under their leases.

Eagle Ford has produced over 2,500,000,000bbls of oil ...................................... it may take some sort of brains to produce that much in a short amount of time and it will keep producing more. Just think of the fact that only 10-15% of the oil is recovered in the first go at it!!!! Refrac and other EOR tech will recover much more than that.

Permian is vast multi layered chocolate cream cheesecake!!! with all kinds of textures and flavors. Like a human organ built of many layers of tissues, keep on peeling the layers back using the hitech MRI, CAT scans ultrasounds and nano tech to deliver all the hidden data  find those neural pathways and those inter and intra cellular spaces filled with fluids and how they move about and their properties so on.....

some shale takeaways for better profitable sustainable bizz model

1)  acquire larger acreage and drill and complete longer laterals for lower per foot

2) The data they acquire or will acquire for larger acreages will come in @ a lower cost and processing the large data base for sub surface geology, including 2D and 3D seismic (and or reprocessing existing 2D or 3D) , mapping of structures in the subsurface, analyzing the data and obtaining the interpretive results of that will be easier, and lower in costs using high tech computers and AI and IOT. Same goes with geochemistry and geophysics.

3)  have access to easier and lower costs financing.

 

4) Lack of takeaway capacity in the Permian will be resolved within 2 yrs, maybe 3 at the max for the projected oil gas and liquids increased production.

5) Not all shale wells have drastic decline curves. Once again it comes back to using the right tech or suite of techs to acquire the quality rocks to drill. If you buy "schitty" quality of anything you get "schitty" results. Companies have gone bankrupt and have had to offload their shale acreages because they purchase not so good assets and overpaid for them. Recall the days when companies were paying 20,000-100,000$ an acre (Shell paid 100,000$/acre in the Eagle Ford and ended up selling it for very very cheap, the rancher that was paid the bonuses was the real winner). A new shale industry practice should emerge and be used in acreage leasing/acquisitions i.e. landowners are paid a "reasonable" fee or option fee to evaluate the area/acreage of interest. I can elaborate on this later if there is interest.

6) Tech is the key for success at each and every aspect of shale development as it is in any other advanced business, or medicine or any enterprise that is high value , high risk. Using combinations of techs that are synergistic and complementary reduces costs at all levels and brings unprecedented efficiencies. Example using combination of 2D/3D and other seismic techs to develop an accurate picture of the subsurface and identifying the shale structures in terms of their geological value in terms of holding hydrocarbons. Followed up by finding and identifying where there are the naturally occurring clusters of natural perforations or fractures in the shale where the hydrocarbons will accumulate and post drilling and completion will have an area where due to natural pressure and inflow will maintain good production WITHOUT DRASTIC decline. We have had tremendous success and have experienced extremely low decline rates comparatively. Majority of companies dont  follow this or use this geo tool. It is akin to have a phlebotomist trying to draw blood from a not so good spot. Medicine has had a huge impact on oil and gas in terms of application of technologies, CAT scan, MRI etc among others. Drilling and completion techs used in combination to provide the best suited application in that specific formation or acreage, and remember shale isnt homogeneous. Geosteering techs , completion techs, water use, type of proppants and the list goes on.

7.) Initial recovery in most cases is very low, so shale EOR enhances that in a large perspective.

 

8.) companies are becoming nimble and able to adapt. BP, XOM others are paying lot more attention to new energized talent that are extremely tech savvy and working towards disruptive techs and processes that are bringing about major changes. They are promoting out of the box thinking by being proactively seeking and employing talent that does that. Due to the low oil price environment for longer, several majors and independents have had good success in cutting their overheads.

9) have cash available and easy access to financing to fund new tech R&D or acquire it from others or buy entire companies and or are able to form JVs and enterprises with service companies to do develop or add onto existing techs. BP, XOM others are continuously funding start up techs and service companies are making new innovations to reduce the cost per foot to drill, complete and recover more oil

10) Another cost reduction, production improvement process is the multi well pad drilling, smaller companies using service providers under contract can also achieve it but larger companies may also have their own specialized fleets for this or due to their large acreages maybe able to get better rates for retaining service contractors for this purpose plus other services. Even for small companies , multi-well  pad drilling proves very productive and cost effective and greatly improves the bottom line, given all other aspects are also done in a  very hitech streamlined manner. I have seen production levels ranging from 9,000bopd-28,000bopd (excluding gas, condensates, ngls etc) from a single pad. I have used this process in conventional fields, mature fields and have seen amazing production results.

 

Shale is not for everyone, not everyone has got the guts, the discipline and the resources , the right and strategic resources to succeed, have zero or no debt, be able to pay the shareholders and create free cash to move forward with development and growth in size, quality of acreage and production volumes. Those who do have been reaping the benefits and will reap the benefits for decades and decades to come. As in any industry in this day and age, the breakthrough technologies, new disruptive technologies, evolution and adaptation of existing technologies and improvements at each and every stage of a given process are the key. The days of throwing down a flag and say drill here are over. They werent good to begin with, that is why you have stripper and marginal wells. With new techs those are becoming profitable and sustainable as well. Techs from shale and shale EOR can be applied to those fields and oil formations to recover more oil, bypassed and stranded oil and recover additional barrels at lower costs for longer.

I am also not against other sectors of the oil and gas business, conventional ....

 

Edited by ceo_energemsier
addition
  • Like 1
  • Great Response! 2
  • Upvote 1

Share this post


Link to post
Share on other sites

My estimate of US tight oil output, URR=91 Gb

uslto1905b.gif

  • Like 1

Share this post


Link to post
Share on other sites

(edited)

4 hours ago, D Coyne said:

Dennis, you know I think you are nuts, right? But you are faithful to EIA price predictions, persistent in your models, smart, use your own name on public forums and put your reputation on the line with some reasonable, rational  understanding of the oil business. You always ask questions of people IN the industry and seem to be able to set aside the BS and think for yourself. 80 more billion barrels is pretty far fetched, however. Don't get sucked into the hyperventilation that is going on around here. Remember, in the end Mother Nature always gets Her way. Always. 

 

Edited by Mike Shellman
  • Like 3

Share this post


Link to post
Share on other sites

1 hour ago, D Coyne said:

My estimate of US tight oil output, URR=91 Gb

~50% growth would require enormous amount of drilling and financing - with ~60% annual production decline which steepens every year with more wells added (picture triangles stacked on its head; perhaps it'll start tipping over b4 reaching the peak...) more and more wells required to maintain production plateau. Heck of a lot more needed to grow it - which was not an issue so far. I'm not sure it'll continue as investors appetite seems fading and at some point financing become more expensive - in part due to dismal financial performance of majority (not all) operators and negative free cash flow even during period of high oil prices. Nothing ~$100 oil can't fix, though...

Your terminal decline is quite generous - it'll require substantial activity to maintain.

Not sure if saving grace or double whammy - the worse it gets now with overproduction from shale, the bigger deficit would be when we stop drilling it for any reason (resource depletion, run out of OPM etc). World demand grew by 1-1.5MMbopd and expected to do so https://www.iea.org/oil2019/

Shale HC is viable resource but it is not an easy one. Permeability is less than that of a brick or concrete, porosity and TOC in single digits, recovery factor <10% (with no viable secondary or tertiary recovery yet) - it takes millions of ft2 reservoir contact by fractures to drain it. If not for shale - we would be in much different world now. Likely one with more nuclear and heavy oil production; higher oil prices and inflation.

US5034.png

  • Great Response! 2

Share this post


Link to post
Share on other sites

23 minutes ago, Mike Shellman said:

Dennis, you know that I think your nuts, right? But you are faithful to EIA price predictions and persistent in your models, smart, use your own name and put your reputation out there with some basic understanding of how the oil business works. You have always been willing to leave internet dribble behind and think for yourself. I admire that a lot. 

^ agreed.  I tend to disagree with Dennis on any number of issues.  But Dennis, you are no coward, you stick to your guns and argue the points you believe are correct, while looking at views of others.

  • Like 1
  • Upvote 2

Share this post


Link to post
Share on other sites

On 5/16/2019 at 9:54 PM, Tom Kirkman said:

^ agreed.  I tend to disagree with Dennis on any number of issues.  But Dennis, you are no coward, you stick to your guns and argue the points you believe are correct, while looking at views of others.

Thank you Tom and Mike,

I respect the views of those in the oil industry as I know they know the business far better than I could ever hope to.

Mike,

I realize that the EIA price forecasts are usually incorrect, but rather than create my own incorrect price forecast, I just choose an authoritative source, even though their forecast will almost certainly be incorrect.

Note that if I use low or high price forecasts, the result is different.  In the chart below I show two different price forecasts on right axis and on the left axis  the output for the two scenarios is shown.  The only change is the price and the completion rates (which changes due to lower prices making fewer profitable to complete.

These are scenarios for the Permian basin using the USGS mean TRR estimate (75 Gb) as a starting point, the economically recoverable resources will always be less than the TRR unless a very high oil price scenario is utilized (and even in that case ERR will be less than TRR, but they might be close).  The medium oil price scenario (AEO reference case) has URR=58 Gb for Permian Basin.  The low oil price scenario (maximum price is $68/b) has a URR of 26 Gb for Permian basin.

It all depends on the price of oil in the future.  If someone would tell me what that is, I could give a decent model (with correct assumptions). :)

permian1905.png

Share this post


Link to post
Share on other sites

(edited)

On 5/16/2019 at 9:26 PM, DanilKa said:

~50% growth would require enormous amount of drilling and financing - with ~60% annual production decline which steepens every year with more wells added (picture triangles stacked on its head; perhaps it'll start tipping over b4 reaching the peak...) more and more wells required to maintain production plateau. Heck of a lot more needed to grow it - which was not an issue so far. I'm not sure it'll continue as investors appetite seems fading and at some point financing become more expensive - in part due to dismal financial performance of majority (not all) operators and negative free cash flow even during period of high oil prices. Nothing ~$100 oil can't fix, though...

Your terminal decline is quite generous - it'll require substantial activity to maintain.

Not sure if saving grace or double whammy - the worse it gets now with overproduction from shale, the bigger deficit would be when we stop drilling it for any reason (resource depletion, run out of OPM etc). World demand grew by 1-1.5MMbopd and expected to do so https://www.iea.org/oil2019/

Shale HC is viable resource but it is not an easy one. Permeability is less than that of a brick or concrete, porosity and TOC in single digits, recovery factor <10% (with no viable secondary or tertiary recovery yet) - it takes millions of ft2 reservoir contact by fractures to drain it. If not for shale - we would be in much different world now. Likely one with more nuclear and heavy oil production; higher oil prices and inflation.

US5034.png

Danika,

I use Enno Peters data from www,shaleprofile.com to develop the well profiles for my analysis. I use past rates of growth in the well completion rates to guide my future assumptions about completion rates as well as profitability and mean USGS estimates for the major tight oil plays.

For a flavor of the analysis see, focus on Bakken and Eagle Ford in that piece, these models have been updated as of Dec 2018

http://peakoilbarrel.com/oil-field-models-decline-rates-convolution/

I did a poster on Permian Basin at Fall AGU meeting in 2018, the models I presented have since been adjusted upward to reflect new USGS Permian estimates (Delaware Basin) published a few days before the AGU meeting.  The poster linked below does not reflect the increased Permian TRR estimate (mean estimate went from 36 to 74 Gb).  Click on eposter and view at 75%, go column by column, there are 4, top to bottom then left one column, etc.

https://agu.confex.com/agu/fm18/meetingapp.cgi/Paper/446221

Edited by D Coyne
  • Great Response! 1

Share this post


Link to post
Share on other sites

Revision to figure 7 from the AGU Fall Meeting Poster referenced above, with higher Permian TRR estimates, F95=43 Gb, mean=74 Gb, F5=113 Gb.  The EIA AEO 2018 reference oil price case is applied with the same economic assumptions presented in the poster to arrive at these three scenarios which correspond with the F95, mean, and F5 TRR cases.

permian err 1905.png

Share this post


Link to post
Share on other sites

One thing I noticed about your model is that the ultimate output of any one well is about 340-345kbbl of oil.  Looking at my original well which is almost 5 years into production now and it still produces 100bbl/day and has to date produced 355kbbl of oil and 2500mmcf of gas so the BOE is more like 750kbbl.  Are your numbers using BOE or bbl?  Secondly, over time it's clear that the wells probably will produce more than 350kbbl so is there any allowance for that in your model?  I should add that the area this well is in isn't considered prime and the well operated by Cimarex on the adjacent section that preceded it in production by a year has produced 308kbbl oil and 2200mmcf gas.  I think that the frac techniques and the way the wells have been operated are the difference in output to date.  The Cimarex well looks like it might be near the end of life but not sure.  It's only producing 50bbl/day now and last month it had it's production curtailed for some reason.  Using BOE on that well we are still over 700kbbl.

Share this post


Link to post
Share on other sites

(edited)

57 minutes ago, wrs said:

One thing I noticed about your model is that the ultimate output of any one well is about 340-345kbbl of oil.  Looking at my original well which is almost 5 years into production now and it still produces 100bbl/day and has to date produced 355kbbl of oil and 2500mmcf of gas so the BOE is more like 750kbbl.  Are your numbers using BOE or bbl?  Secondly, over time it's clear that the wells probably will produce more than 350kbbl so is there any allowance for that in your model?  I should add that the area this well is in isn't considered prime and the well operated by Cimarex on the adjacent section that preceded it in production by a year has produced 308kbbl oil and 2200mmcf gas.  I think that the frac techniques and the way the wells have been operated are the difference in output to date.  The Cimarex well looks like it might be near the end of life but not sure.  It's only producing 50bbl/day now and last month it had it's production curtailed for some reason.  Using BOE on that well we are still over 700kbbl.

WRS,

I use the average output of all Permian Basin horizontal wells as reported at www.shaleprofile.com.  I include crude plus condensate only and do not account for either natural gas or NGL output, generally there is not very good data for NGL output per MCF of natural gas produced, and NGL pricing is also a problem.  The fact that much of natural gas is flared in the Permian basin suggests it may not be generating a lot of revenue, that might change in the future.

I do not use BOE in the analysis, it is barrels of oil only.

You have presented your price per BOE for natural gas in some of the better months.  Can you tell us what your average $/BOE, for natural gas and NGL has been for the past 12 months (single number just roll it up).  Take total MCF and barrels of NGL produced convert to BOE and divide by total revenue received for that output to get a $/BOE.

I ask because I purposely underestimated LOE, by about $4/bo, my guess is that the $/boe received after paying royalties and taxes for the operator (typically about 33%, so take home pay would be 67% of the wellhead price for the gas and the sales of NGL.  Though in fact I don't know how this all works,  Mike Shellman would though as he has been at this for 40+ years.

Also note that the EUR depends in part on the price of oil.  An average Permian well that was completed in Dec  2017 would reach the end of life in about 16 years or in 2033.  I expect oil prices to be $85/b in 2017$ by that time at minimum.  The EUR of that well would be about 375 kbo.  The average well reaches cumulative output of 350 kbo at about 10 years, my guess is that you have an above average well.

Look at page below go to productivity distribution and select 2016 and 2017 wells, you will find that the average 24 month cumulative output of the 2672 wells completed in 2016 and 2017 that have been producing for 24 months is 184 kb.

My average well profile has 196 kbo at 24 months, for hyperbolic Qi=30180, b=1.042, Di=0.3129, at month 64 when annual decline rate reaches 16%, I assume exponential decline at 16% per year based on research by Enno Peters( note that Mr. Peters believes my estimate is on the low side, I believe he thinks 20% is more accurate.)

For comparison at 5 years the average well has 284 kbo cumulative output at 60 months from first flow, at 72 months it is 302 kbo and daily output of 45 bo/d for average monthly output in month 72.

One more thing, we have you implying that my model is too low, and Mr Shellman suggesting that it may be too high.  I would suggest that often when one receives criticism from people arguing "too low" and "too high", that is encouraging, my guess is that it may be about right.

I love the criticism as mistakes pointed out by others is how I have come this far, thank you everyone who has taken the time to help make my "crazy" models more realistic.  (Mr Shellman and Shallow Sand have been very helpful along with many others at www.peakoilbarrel.com )

Edited by D Coyne
  • Upvote 2

Share this post


Link to post
Share on other sites

@Mike Shellman

Note that I have a LTO model based on the AEO 2018 reference oil price case which is a "low peak" scenario.  The URR of that model is 93 Gb, with 63 Gb from the Permian Basin, 10.5 Gb form Eagle Ford, 10 Gb from ND Bakken/Three Forks, 3.5 Gb from DJ Basin (aka Niobrara), and 6 Gb from the "rest of" US tight oil (areas that are not part of the first 4 basins mentioned).  In a low price model this URR might be cut in half (I have only run the low price model for the Permian), so perhaps 47 Gb in a low price scenario where oil price never rises above $68/b in 2017 US$.

Mr Edwards believes that is the most likely scenario, I think he sees $20/bo in the long run, so he would believe the 47 Gb URR is far too high, a very low oil price makes the Permian basin not viable as a long term project.  The debt would never be paid back and everyone would go out of business at $20/bo.  I am thinking even an old pro needs $40/bo just to pay the bills.

usltolow1905.png

  • Upvote 1

Share this post


Link to post
Share on other sites

(edited)

Dennis,

Here are the numbers from one of the Culberson wells. The XTO wells haven't been producing a year and that really good $/BOE I gave you there was from the XTO lease.  This is from the independent operator and the prices are inclusive of flared volumes which were usually a little less than 10% of the total production each month.  The total gas production from that well in those months was right at 1,000,000 mcf with 718,000 mcf actually sold into the pipeline.  There was 53,000mcf of lease use i.e. for running compressors and 45,000mcf flared.  Another 185,000mcf was in category 9 which I have yet to find the explanation for.

3/2018 $21/BOE

5/2018 $22.50/BOE

6/2018 $19.60/BOE 

7/2018 $19.12/BOE

8/2018 $18.12/BOE

9/2018 $22.28/BOE

10/2018 $23.16/BOE

11/2018 $19.03/BOE

12/2018 $20.68/BOE

1/2019  $22.21/BOE

2/2019  $19.91/BOE

3/2019 $14.34/BOE

 

Edited by wrs

Share this post


Link to post
Share on other sites

(edited)

1 hour ago, wrs said:

Dennis,

Here are the numbers from one of the Culberson wells. The XTO wells haven't been producing a year and that really good $/BOE I gave you there was from the XTO lease.  This is from the independent operator and the prices are inclusive of flared volumes which were usually a little less than 10% of the total production each month.  The total gas production from that well in those months was right at 1,000,000 mcf with 718,000 mcf actually sold into the pipeline.  There was 53,000mcf of lease use i.e. for running compressors and 45,000mcf flared.  Another 185,000mcf was in category 9 which I have yet to find the explanation for.

3/2018 $21/BOE

5/2018 $22.50/BOE

6/2018 $19.60/BOE 

7/2018 $19.12/BOE

8/2018 $18.12/BOE

9/2018 $22.28/BOE

10/2018 $23.16/BOE

11/2018 $19.03/BOE

12/2018 $20.68/BOE

1/2019  $22.21/BOE

2/2019  $19.91/BOE

3/2019 $14.34/BOE

 

Thanks.  Looks like around $20/boe on average, lets take 57% of that to account for royalies, taxes and flaring so a net of about  $11.4/ boe, roughly 1 boe of NG plus NGL  for the average well for every 2 bo produced so about $5.70 of net income from NG for every barrel of oil produced, so I am off in my costs by about $1.7/b, if Mr Shellman's estimate of about $13/b for LOE and overhead is correct.  It also occurs to me that Mr Shellman might have meant $13/boe, I had always assumed he meant $13/bo.

I will wait for Mr Shellman's response as he is the expert in producing oil and natural gas.  As an independent owner of an oil company for 40 years, I try to listen and learn from pros like Mr. Shellman.

Though I must admit I often speak out of turn, sorry. :)

If it turns out that LOE and overhead should be less than the $2.3/bo plus $15000 per month (for downhole maintenance), that I have assumed due to the net income from NG of about $5.70/bo, then the model is easily adjusted to $0.55/bo plus $15000 per month.  Breakeven using NG output and $20/boe in the analysis results in a wellhead breakeven price of $61.50/b assuming $10 million well cost and an annual discount rate of 10%, interest costs are ignored for the breakeven calculation.

Edited by D Coyne

Share this post


Link to post
Share on other sites

(edited)

3 hours ago, D Coyne said:

I will wait for Mr Shellman's response as he is the expert in producing oil and natural gas.  As an independent owner of an oil company for 40 years, I try to listen and learn from pros like Mr. Shellman.

Your are kind, Dennis, but you will never get me to predict oil prices. Nobody in the oil business using they're own money does that. All I can say is that my budget for the year is based on $53 by mid summer and what happens after that is lagniappe; I hope. I will engage in some infill drilling but that is based on two year payouts and greater that 300% rates of return over 15 years. The IEA, for instance, that has suggested that my break'evens are the same as shale oil break'evens is laughable. There are many of us out here grinding away quite happy with $60 oil and humbled by OPEC's help with that, waiting on the US shale oil phenomena to screw that all up. Again.  

Your EUR's are OK, Dennis: I stand firmly by Enno's data. It is meticulous and I am proud of the truth his data brings to this debate. Its interesting, isn't it, how many people criticize my "bias," then again somehow think a few wells they have interest in circumvents all other factual data, and they are NOT bias?

Your incremental lift costs per BO are too low; I am unclear why you purposefully do that? GOR and WOR is going up; water costs in the Permian are astronomical. I did a quick thing on JIB data I've seen from W. Texas associated with ESP's. Maybe $5 bucks per incremental BO, just to use that crap for AL. We are getting shaked, rattled and rolled in the EF right now with earthquakes: finding fresh water to frac with and where to put produced water is the biggest hurdle the shale oil industry faces. You do what you want and you will of course understand why I think your model suggesting debt can be paid back over time is, forgive me, ridiculous.There are too many greedy folks associated with the shale gig to EVER let that happen. You have too much faith in human goodness. Google Floyd Wilson, Gary Evans, Tom Ward and a bunch of other "wildcatters," hee hee;  that should change your mind. Walker was driving  his company into the ground and he walked last week with $70MM. He didn't think twice about any of that and will be at it again by year end, with more borrowed money.

Lastly, shale oil "haters" is a really high school term for knowledgeable folks concerned about the long term sustainability of shale oil in America. There are, gasp, a lot of us, actually. Implying that shale oil haters relish in  people losing their jobs in West Texas is actually grade school stuff. But it is, after all, the nature of our industry, to lose your job. It is precisely BECAUSE of the shale oil business model that over the ensuing years more people will lose their jobs in the shale oil industry, sadly. BTW, there are several tens of thousands of good men and women in the US conventional industry, including the GOM, that have been out of work for years...because of the shale oil industry. Do shale oil "lovers" care about that? Or wrecked social structures throughout the world because of shale oil induce price volatility? Of course not. They could care less. Some of us are striving for price AND employment stability, industry wide.

Stick to your guns. Remember, royalty owners and people who think they are in the oil business via MLP's with five zeros in front of their interest don't know shit about well economics. Royalty owners wiggle out of paying for everything, even marketing costs to get their minerals sold. Leave the links behind and think for yourself. Think about it as though you were IN the shale oil business, running the show, up to your ass in debt, facing maturities, with no cash on hand and production that is dropping like a rock everyday.  Think of it all as though you are using your own money and it all gets real clear, real fast. And quit hoping for higher oil prices ! That's no plan ! 

 

 

  

 

Edited by Mike Shellman
  • Like 2
  • Great Response! 2

Share this post


Link to post
Share on other sites

Towards the beginning of the comments, before they took a more 'financial' turn, I once again saw references regarding the magical technologies which will allow the shale oil industry to go forth and prosper.

I am sure that there are technologies out there that can enhance initial production rates and also technologies which can be used to flatten out the decline curves (for awhile anyhow), but at the end of the day you work with what God gave you.

Tight rock is tight rock. Fluid pressure in the tight rock is a given.

I have not seen any technology which will change the matrix permeability. Fluid dynamics are also a given. Technology will not change the underlying principles of either the inherent rock properties of shale or fluid dynamics.

Sure, you can frac until the cows come home and create flowpaths to the well, but the matrix rock properties will determine the flow feeding these fractures.

In my mind technology can help the production of shale oil wells initially and for a period early in the life of the wells, but eventially it all goes back to the basics of rock properties and fluid dynamics.

  • Like 1
  • Upvote 3

Share this post


Link to post
Share on other sites

10 hours ago, D Coyne said:

Danika,

I use Enno Peters data from www,shaleprofile.com to develop the well profiles for my analysis. I use past rates of growth in the well completion rates to guide my future assumptions about completion rates as well as profitability and mean USGS estimates for the major tight oil plays.

For a flavor of the analysis see, focus on Bakken and Eagle Ford in that piece, these models have been updated as of Dec 2018

http://peakoilbarrel.com/oil-field-models-decline-rates-convolution/

I did a poster on Permian Basin at Fall AGU meeting in 2018, the models I presented have since been adjusted upward to reflect new USGS Permian estimates (Delaware Basin) published a few days before the AGU meeting.  The poster linked below does not reflect the increased Permian TRR estimate (mean estimate went from 36 to 74 Gb).  Click on eposter and view at 75%, go column by column, there are 4, top to bottom then left one column, etc.

https://agu.confex.com/agu/fm18/meetingapp.cgi/Paper/446221

Dennis,

Great work, thanks for sharing. Biggest uncertainty I see are variable decline rates and resulting EUR. SPE URTeC paper 2892966 "Variation of Hyperbolic-b-parameter for Unconventional Reservoirs, and 3-Segment Hyperbolic Decline" advocates for use of 3 segments; initial b-parameter of 2. Your Eagle Ford Di of 0.25 is brutal - is decline that bad?

Enno @shaleprofile did a lot of work on terminal declines and his figures are in double-digits.

There is also wide range of IP probability distribution (not sure average is as good as presented) and DUC wells which may or may not be completed but needs to be counted. Ultimately, drilling 175K (+/- 60%) wells likely to meet resource constrain - rigs, sand, HHP, $$$ etc. With more infill wells we may not get same IP and parents are affected - none of it is easy to model.

Your work is a best stab I've seen at what it'll take to grow LTO production. Did you published your xls by basin? Thanks again!

  • Like 1
  • Upvote 1

Share this post


Link to post
Share on other sites

(edited)

19 hours ago, Mike Shellman said:

Your are kind, Dennis, but you will never get me to predict oil prices. Nobody in the oil business using they're own money does that. All I can say is that my budget for the year is based on $53 by mid summer and what happens after that is lagniappe; I hope. I will engage in some infill drilling but that is based on two year payouts and greater that 300% rates of return over 15 years. The IEA, for instance, that has suggested that my break'evens are the same as shale oil break'evens is laughable. There are many of us out here grinding away quite happy with $60 oil and humbled by OPEC's help with that, waiting on the US shale oil phenomena to screw that all up. Again.  

Your EUR's are OK, Dennis: I stand firmly by Enno's data. It is meticulous and I am proud of the truth his data brings to this debate. Its interesting, isn't it, how many people criticize my "bias," then again somehow think a few wells they have interest in circumvents all other factual data, and they are NOT bias?

Your incremental lift costs per BO are too low; I am unclear why you purposefully do that? GOR and WOR is going up; water costs in the Permian are astronomical. I did a quick thing on JIB data I've seen from W. Texas associated with ESP's. Maybe $5 bucks per incremental BO, just to use that crap for AL. We are getting shaked, rattled and rolled in the EF right now with earthquakes: finding fresh water to frac with and where to put produced water is the biggest hurdle the shale oil industry faces. You do what you want and you will of course understand why I think your model suggesting debt can be paid back over time is, forgive me, ridiculous.There are too many greedy folks associated with the shale gig to EVER let that happen. You have too much faith in human goodness. Google Floyd Wilson, Gary Evans, Tom Ward and a bunch of other "wildcatters," hee hee;  that should change your mind. Walker was driving  his company into the ground and he walked last week with $70MM. He didn't think twice about any of that and will be at it again by year end, with more borrowed money.

Lastly, shale oil "haters" is a really high school term for knowledgeable folks concerned about the long term sustainability of shale oil in America. There are, gasp, a lot of us, actually. Implying that shale oil haters relish in  people losing their jobs in West Texas is actually grade school stuff. But it is, after all, the nature of our industry, to lose your job. It is precisely BECAUSE of the shale oil business model that over the ensuing years more people will lose their jobs in the shale oil industry, sadly. BTW, there are several tens of thousands of good men and women in the US conventional industry, including the GOM, that have been out of work for years...because of the shale oil industry. Do shale oil "lovers" care about that? Or wrecked social structures throughout the world because of shale oil induce price volatility? Of course not. They could care less. Some of us are striving for price AND employment stability, industry wide.

Stick to your guns. Remember, royalty owners and people who think they are in the oil business via MLP's with five zeros in front of their interest don't know shit about well economics. Royalty owners wiggle out of paying for everything, even marketing costs to get their minerals sold. Leave the links behind and think for yourself. Think about it as though you were IN the shale oil business, running the show, up to your ass in debt, facing maturities, with no cash on hand and production that is dropping like a rock everyday.  Think of it all as though you are using your own money and it all gets real clear, real fast. And quit hoping for higher oil prices ! That's no plan ! 

Hi Mike,

My LOE is an incremental plus fixed estimate, this type of model has LOE costs gradually rising over time as the well is less productive.  You have often said LOE plus overhead (excluding interest cost) is around $13/b in the Permian, for the well profile I use this works out to $6.25/bo plus $15000 every month, over the life of the well this works out to $13/bo.

WRS gave some natural gas price information and when this is accounted for in the model it reduces LOE by 5.7/bo  ( I have assumed royalties plus taxes equal 33% for both oil and natural gas), I also deducted 10% for NG that is flared.

On the debt being paid off, that only works if oil prices rise.  Scenario below (the low oil price scenario I presented previously) for Permian basin shows cumulative net revenue when oil prices are low.  The debt never gets paid off in this model, they run out of steam in 2037 and then debt continues to increase (assuming no bankruptcies, some of this debt will be forgiven in the Bankruptcy filing).

Perhaps this scenario will seem a little less ridiculous, of course nobody knows future oil prices, I expect oil will be short and oil prices will rise until at least 2040, then potentially EVs may start to cut into demand enough to start prices lower from 2040 to 2060.  Of course as you know I never get oil prices right. :)

 

permian lp1905.png

Edited by D Coyne
  • Like 1
  • Upvote 1

Share this post


Link to post
Share on other sites

(edited)

15 hours ago, DanilKa said:

Dennis,

Great work, thanks for sharing. Biggest uncertainty I see are variable decline rates and resulting EUR. SPE URTeC paper 2892966 "Variation of Hyperbolic-b-parameter for Unconventional Reservoirs, and 3-Segment Hyperbolic Decline" advocates for use of 3 segments; initial b-parameter of 2. Your Eagle Ford Di of 0.25 is brutal - is decline that bad?

Enno @shaleprofile did a lot of work on terminal declines and his figures are in double-digits.

There is also wide range of IP probability distribution (not sure average is as good as presented) and DUC wells which may or may not be completed but needs to be counted. Ultimately, drilling 175K (+/- 60%) wells likely to meet resource constrain - rigs, sand, HHP, $$$ etc. With more infill wells we may not get same IP and parents are affected - none of it is easy to model.

Your work is a best stab I've seen at what it'll take to grow LTO production. Did you published your xls by basin? Thanks again!

Thanks Danika,

I do a more simple analysis that fits a standard Arps hyperbolic to data pulled from shale profile, I do this for several groups of years and sometimes more.   Note that I assume new well EUR starts to decrease after 2018 for Bakken and Eagle Ford and after 2022 for other plays (which I consider less mature), between 2018 and 2022 for Permian and other plays (excluding Bakken and Eagle Ford) I assume new well EUR remains constant.  The average well profile I use matches Enno Peters data through 2017 (not enough data for 2018 yet to do a decent curve fit.)  So in reality the model holds EUR fixed from 2017 to 2022 except for the Permian where I use average output data for the first few months and then use the 2017 well profile for future months, the curves tend to merge at 18 to 25 months.

Absolutely realize that new well EUR is highly variable, but note how well the model matches the data over the historical period.

This gives me confidence that with correct assumptions about the future the model will be fairly good.

If anyone has future oil prices written down, I could run a model for now I use the AEO reference case a second case using Tom Kirkman's hypothesis that oil prices will never rise above $68/b.  If Tom is correct the tight oil producers in the US will be in a World of hurt going forward and they will never be able to pay off accumulated debt.

In the comment above 2017 to 2022 means Jan 2017 to Dec 2022, same for all other cases it is the entire year, the model is a monthly model.

Edited by D Coyne
  • Like 1

Share this post


Link to post
Share on other sites