Shale Oil Fiasco

[James Gautreau + 86]

$250 billion is with Tier 1 acerage, the so-called "sweet spots." We are now moving to Tier 2. Expect a $1 trillion in the red to bring that oil to the surface. Ain't going to happen unless oil is $150 a barrel minimum. The rest of Permian oil is likely stranded.  

[wrs + 893]

7 minutes ago, James Gautreau said:

$250 billion is with Tier 1 acerage, the so-called "sweet spots." We are now moving to Tier 2. Expect a $1 trillion in the red to bring that oil to the surface. Ain't going to happen unless oil is $150 a barrel minimum. The rest of Permian oil is likely stranded.  

Can you explain what you mean by Tier 1 and Tier 2 acreage?  Where are they located for example in the Permian?

[James Gautreau + 86]

They do geophysics, which means placing a hydraulic battering ram on the ground and seismic gauges over the area being investigated. then they slam that battering ram into the ground and record the readings. Then they move it to a new spot and do it again until they have imaged the whole area. Then they evaluate the readings. I used to know a guy who did this. Had his own plane. Made real good money. But this was back in the days of conventional oil. 1980's & 1990's when they scoured the world for oil. I would imagine they do something similar with shale oil but I'm not sure. They may just go to where the most conventional oil was produced. The Permian has produced 20 billion barrels conventional crude and I think 5-6 unconventional. T. Boone Pickens, when he heard about the new 46 billion of barrels the USGS said they had discovered there said, "We've been drilling the Permian for 100 years and they just found another 46 billion barrels. C'mon man! " I posted a picture of the Bakken a few pages back that showed the sweet spots. I haven't found one for the Permian. In general Tier 1 are the best prospects.  

Edited December 9, 2019 by James Gautreau

[James Gautreau + 86]

“Effectively, the shale boom is over.” Colorado’s 8 largest public oil & gas producers spent $27 Billion more than they made in past 5 years. Is that why Alberta gov’t wants our pensions? To feed the bleed via AIMCo?

Posted on November 12, 2019 by Jessica Ernst

[James Gautreau + 86]

TROUBLE AT MIGHTY EXXONMOBIL: Record Number Of Shale Wells While Permian Oil Production Remains Flat
November 5, 2019 – There’s trouble brewing in the U.S. largest oil company while most investors remain in the dark.  ExxonMobil added a record number of wells in the Permian during the first three quarters of 2019, only to see the company’s oil production plateau. This is the BIG PROBLEM facing ExxonMobil and other oil companies trying to outrun the industry’s KILLER annual decline rate.

[Rob Kramer + 696]

1 hour ago, Jabbar said:

Unfortunately , their is no reasonable way for those buried in debt to get out from under it.  

If not for OPEC and Investment Banks efforts to talk up and inflate oil prices these firms with disastrous balance sheets would have been long gone before this , like they should be.

MAJOR MISCONCEPTION: It is the belief of some that as these insolvent shale players go under that production volume will go down.  .  .   temporarily it will grow at a slower rate thru the transition but not drop . 

I agree with the first 2 paragraphs. 

As for the MAJOR MISCONCEPTIONS: with the prolonged death of the companies (via the first 2 paragraphs) they scale down growth , sell assets , file for protection, ect so bankruptcy isnt wham bam as top paragraphs say it should be and that's why it's not "keep on drilling" as before and:

if company A has X capex and buys bankruptcy company B with Y capex ... does company A after have a capex of X+Y now = to Z? 

[D Coyne + 305]

On 12/7/2019 at 6:19 PM, wrs said:

For a situation like we have with our Orla section where the lease is old, the operator has no land costs or lease costs.  Chevron and XOM both have a lot of old leases out there.  Texaco got all of the TPLT minerals a long time ago and that is a lot of productive acreage in the Permian.  I imagine the fact that XTO had no land costs for our Orla section made it easier to put more into drilling which is good for the landowner too.  I am not commenting on anything other than the cost to drill and complete the well because that is the main cost of the well.  

I don't beileve lease bonus money is amortized, I think it's a direct expense, i.e. a rent expense.  I think you are incorrectly attributing rent to the cost of the well.  The rent is paid once, the drilling and completion costs are paid on every well.

WRS,

I will make this simple for you, lets say one pays a bonus=B dollars on a 1000 acre plot where 10 wells are drilled (100 acres per well).  The land cost in that case is B/10.  It is not really a difficult problem. For some wells the cost might be zero for older leases, and in other cases it might be more,  I am using the average cost of all wells.  As Rystad figures it, a 10,000 foot well (which may become standard practice in the Permian basin) will have D+C cost of about $9.5 million, and as I stated there are facilities costs (F) and if N wells are supported by the facilities the the cost would be F/N, and plugging cost at the end of the well's life.  To be honest, I wonder if the $10 million well cost would actually cover a 10,000 lateral well, it might only cover 8750 feet of lateral. 

[D Coyne + 305]

10 hours ago, wrs said:

Mike, you are making up numbers to suit yourself and then not even bothering to calculate the return.  I think my wells are indicative of successful shale operations.  I have to correct some of your misleading claims:

First.  Severance tax on oil is 4.4%, severance tax on gas is 7.5% and only represents about 15% of the revenue stream from the well.

Second.  You and other shale "truthers" only use oil to calculate revenues for a well but in fact, natural gas production grosses another 15% revenue due to the sale of the dry gas and liquids.  In winter months that can be as high as 30%.  

Third:  Your 15 year timeline on payout is only true for the older non-fracked wells whose production is so low and slow as to take a long time to get significant volumes.  With shale, a decent well produces 200,000 barrels in the first two years and many produce more than that.  Again, I have posted my oldest well which is a 4000 foot lateral and it's total production over 5 years is 365,000 barrels of oil and 2650mmcf of gas.

Fourth:  It's a minority of wells that get 25% royalty, especially for the older leases like our Orla lease.  We get 1/8th on that 1950 lease which was standard for years.  The old producer 88 leases typically allowed for a single well to hold the entire lease and there were no vertical Pugh clauses back then.  Chevron has hundreds of thousands of acres at 1/8th or 1/6th.  Getting 1/4th is something that has only been happening in the last 10 years and not all landowners are getting it.  We do have that royalty with our independent and we used vertical Pugh clauses and retained acreage clauses to get more bonus money because he couldn't exploit all the oil in the primary term of his original lease.  However, he is making a profit out there and has vertically integrated in order to save costs and retain the income stream from operations such as water disposal and supplying frac water.

So as I have repeatedly pointed out, you are painting a false picture of the industry with a very broad brush.  It's certain that plenty of operators did overpay for their leases and didn't do a good job exploiting them but that is far from the case for all of them.  Your claim about XOM is a good exercise in post-hoc logic, they have other issues unrelated to the Permian that weigh on their stock price.  I notice you haven't mentioned Chevron.  However, I posted the production XTO has gotten from 1/2 of my Orla section and it's pretty impressive, what is your response to that?  You are also free to use the RRC website to research the production on all their Wolfcamp operations if you are so inclined.

In any case, if the operators didn't think they would continue to make money out there, why would they keep drilling more wells on my land each year?

 

WRS,

Your land is a tiny part of the picture, lower royalty costs will help those companies that hold the older leases.

See

https://public.tableau.com/shared/GF7TTN6HC?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y

For productivity distribition, only about 20% of Texas Permian Basin wells get 200k bo after 2 years, though you might be using BOE  (Mike Shellman loves that   )  Chart below includes wells with first flow from 2013 to 2017, 9459 horizontal oil wells.

https://shaleprofile.com/2019/11/21/permian-update-through-august-2019/

The average cumulative natural gas for these wells was 406 MMCF after 2 years, about a million dollars at $2.50/MMCF and about $28/bo net at $50/bo at wellhead and 1/8 royalty gives us another 5.6 million, so a total of 6.6 million, now if we believe Mr Shellman (and I do) we expect about a $10 million well cost (all in costs).  The average well breaks even at about $60/bo and $1.50/MCF at wellhead for the average 2017 Prmian basin well.

[ronwagn + 6,290]

5 hours ago, jjj said:

Please don't confuse overall shale performance with specific performance from specific companies.. I don't think anybody can disagree that a significant amount of companies and financiers did some pretty stupid stuff betting on the price of oil. But I believe that some companies have figured it out and are making money from shale. Some people seem to think that the past overall performance is the future for all companies in shale. Just take a look at break evens for the different companies they are all over the place. I still sale 1960's designed Heater Treaters to a few companies trying to make it in the shale plays, those companies won't make it. They are dying a slow death while other companies are using larger modular equipment that greatly reduces overall equipment costs. (Not a good trend for the company I work for by the way) This is just one technological advance that is lowering the cost to produce from a shale well. Others are:

1) VRU's capturing flare gas to add to revenue.

2) New rigs drill faster with A/C motor controls, move faster between wells with ability to walk, and can handle exceptions faster such as stuck casing ETC., Longer tool life because of improved Load on Bit ability. to just name a few.

3) Longer tool life from materials science. Such as Carbide slurries brazed in Vacuum furnaces.

 

Some of the technological advances are not new technology but they are being applied either differently or more widespread than the past. 

Jay Johnson

Jay

I have been promoting conserving flare gas for years. I would appreciate any references you might recommend. I realize there is a lot of equipment available to use onsite but am not aware if the technology is actually being purchased and used, especially with the low natural gas price. 

[Mike Shellman + 548]

On 12/9/2019 at 7:38 AM, wrs said:

Mike, you are making up numbers to suit yourself and then not even bothering to calculate the return

 

Edited January 1, 2020 by Mike Shellman

[Rob Kramer + 696]

According to that graph rounded UP . 

136,400 oil average.  I've read nat gas is usually 11% of income from a well  at 10m $ per well looks like 66$ is needed.

136,400 x (66 x 1.12) = 10, 82,700$ 

Now finance is included in the well costs BUT if you dont pay the loan off and have years of debt build refinance and other bank costs that's not added in then you still need more per barrel. 12% of 66 is 8$ per boe of gas . 

Edited December 10, 2019 by Rob Kramer
Typo

[D Coyne + 305]

10 hours ago, Mike Shellman said:

No, I am not "making numbers up." Severance tax on oil is 4.6%, not 4.4%. I guess you have become so wealthy from Permian royalty that you let somebody else write checks for your share of property taxes, which is generally 2.5-3.0% of the revenue stream; everybody pays ad valorem taxes. Even you. 7% is a good number. Chevron and UPRC fee land (now Oxy) is an oddity in the Permian and older HBP leases throughout the Permian have been burdened with horrendous overriding royalty burdens; everybody has their finger in the pie. 25% royalty burdens is a good number, as is my OPEX and G&A and interest expense per incremental BO. I might be a little out of whack but I just showed you how a 400,000 BO well barely pays out at $55, what difference does 10% make one way or another? Explain to us all, please, how one can increase its revenue stream 10%, or reduces its costs 10%, and why that is going to make any difference in the big picture. I believe the price of oil now has to get above $70, and stay there forever, for the shale oil industry to even have a remote chance of ever getting out debt. 

https://www.oilystuffblog.com/single-post/Beware-the-Bearer-of-BOE. I don't use gas in my economic estimates; it doesn't make much of a difference. BOE is bullshit for most operators in the Permian; Rystad just estimated nearly 1BCF per day is being wasted in the Permian and what's not being wasted goes from making negative $3 per MMBTU to a positive 1 dollar. From a working interest standpoint, whoop.

The relevant issue in this debate is not how good you think "your (?)" operators are doing in providing you free income, it is whether our country can depend on these guys in the future to deliver what they have promised us  That is ALL that matters. 

Mr Shellman,

Great stuff, thank you.

In an earlier comment you mentioned 10 to 11.5 million for some wells you are familiar with in the Permian. Is that Midland or Delaware and are they Spraberry, Bonespring, or Wolfcamp wells?  Also what lateral length and TVD is the rough average for a horizontal oil well in the Pemian with a lateral of say 9000 feet?  Rystad seems to think about $8.5 million for D+C for an average well with a 9000 foot lateral, perhaps $9 million to $9.5 million (a guess by me because I do not know the details you would know as I am an outsider) for full cycle well cost (CAPEX, including facilities and plugging at EOL.)  Does the $950/ foot of lateral estimate by Rystad for D+C seem reasonable from your perspective?  Also does my guess that average lateral length in the Permian might gradually move towards 10,000 feet (I believe the current average is 7500 to 8000 feet) seem reasonable?

In short does an average well cost of $10 million for average Permian basin wells in 2019 seem like a good guess.

Thanks.

[D Coyne + 305]

8 hours ago, Rob Kramer said:

According to that graph rounded UP . 

136,400 oil average.  I've read nat gas is usually 11% of income from a well  at 10m $ per well looks like 66$ is needed.

136,400 x (66 x 1.12) = 10, 82,700$ 

Now finance is included in the well costs BUT if you dont pay the loan off and have years of debt build refinance and other bank costs that's not added in then you still need more per barrel. 12% of 66 is 8$ per boe of gas . 

Rob,

That would be to reach payout in 2 years, which most average wells may not accomplish.  At 36 months the average well has cumulative output of 187k, payout is based on net income, 32% goes to royaties and taxes, and another $13/bo for LOE and G&A.  So we would need $48/bo take home pay at the wellhead for the average well to payout in 36 months (assuming 11% income from natural gas).  Add back the $13 we get $60/bo, add back royalties and taxes (we will be conservative and use 20%) and we need $72/bo for payout in 36 months, which smart operators aim for to stay out of debt.  For a more realistic 32% for royalties and taxes the wellhead price would be $79/bo.  Mike or some other industry insider can correct me if I have gone astray.  A less conservative metric like payout in 60 months, would lead to roughly a $60/bo wellhead price needed, clearly that would be higher risk/ less profitable.

[wrs + 893]

11 hours ago, Mike Shellman said:

No, I am not "making numbers up." Severance tax on oil is 4.6%, not 4.4%. I guess you have become so wealthy from Permian royalty that you let somebody else write checks for your share of property taxes, which is generally 2.5-3.0% of the revenue stream; everybody pays ad valorem taxes. Even you. 7% is a good number. Chevron and UPRC fee land (now Oxy) is an oddity in the Permian and older HBP leases throughout the Permian have been burdened with horrendous overriding royalty burdens; everybody has their finger in the pie. 25% royalty burdens is a good number, as is my OPEX and G&A and interest expense per incremental BO. I might be a little out of whack but I just showed you how a 400,000 BO well barely pays out at $55, what difference does 10% make one way or another? Explain to us all, please, how one can increase its revenue stream 10%, or reduces its costs 10%, and why that is going to make any difference in the big picture. I believe the price of oil now has to get above $70, and stay there forever, for the shale oil industry to even have a remote chance of ever getting out debt. 

https://www.oilystuffblog.com/single-post/Beware-the-Bearer-of-BOE. I don't use gas in my economic estimates; it doesn't make much of a difference. BOE is bullshit for most operators in the Permian; Rystad just estimated nearly 1BCF per day is being wasted in the Permian and what's not being wasted goes from making negative $3 per MMBTU to a positive 1 dollar. From a working interest standpoint, whoop.

The relevant issue in this debate is not how good you think "your (?)" operators are doing in providing you free income, it is whether our country can depend on these guys in the future to deliver what they have promised us  That is ALL that matters. 

LOL!  Property taxes vary from county to county and they are not a percentage of the gross earnings, they are based on the assesed value of the minerals which deplete each year and is an estimate that can be disputed, furthermore, they are another direct expense that doesn't apply to any single well.  This is another area where  you simply make stuff up.  Do you even know how a county asseses the value of minerals on their tax rolls?  You are so desperate to include all the costs of running a business into the cost of the well so you can claim failure that you don't realize how ignorant you really are.

Your argument about how you don't consider gas in your calculations simply buttresses my claims that you are biased and not credible.  I am damn sure the IRS is interested in me paying taxes on my gas revenues so they aren't ignored by the govt in my income statement or those of my operators.  Who cares if some gas is being flared.  I would say the majority of the gas out there is being processed and sold, flaring is wasteful of the resource and the operators know this as well as the RRC. Both of my operators make money on the gas and liquids.  The only reason that there were negative numbers on the gas for a couple of months was due to pipeline problems and it's not the case now.

No one has promised anyone, anything.  The operators are out there running their businesses to make a profit and provide jobs.  What the country can depend on has nothing to do with it.  You are conflating a lot of topics in your hatred for shale which just makes you look silly and non-credible.  

Edited December 10, 2019 by wrs

[wrs + 893]

15 hours ago, James Gautreau said:

TROUBLE AT MIGHTY EXXONMOBIL: Record Number Of Shale Wells While Permian Oil Production Remains Flat
November 5, 2019 – There’s trouble brewing in the U.S. largest oil company while most investors remain in the dark.  ExxonMobil added a record number of wells in the Permian during the first three quarters of 2019, only to see the company’s oil production plateau. This is the BIG PROBLEM facing ExxonMobil and other oil companies trying to outrun the industry’s KILLER annual decline rate.

This is again, completely misledaing.  Increasing production isn't where everyone needs to be all the time. Having a stable production is what companies are after because it's predictable cash-flow.  This means that a plateau is what they are looking for.  They have likely drilled more wells than they can produce flat out all the time, there is spare capacity in the Permian just as the Saudis have spare capacity.  The ignorance of financial authors is not surprising but it makes people look dumb to quote them as credible commentators.

[wrs + 893]

12 hours ago, D Coyne said:

WRS,

Your land is a tiny part of the picture, lower royalty costs will help those companies that hold the older leases.

See

https://public.tableau.com/shared/GF7TTN6HC?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y

For productivity distribition, only about 20% of Texas Permian Basin wells get 200k bo after 2 years, though you might be using BOE  (Mike Shellman loves that   )  Chart below includes wells with first flow from 2013 to 2017, 9459 horizontal oil wells.

https://shaleprofile.com/2019/11/21/permian-update-through-august-2019/

The average cumulative natural gas for these wells was 406 MMCF after 2 years, about a million dollars at $2.50/MMCF and about $28/bo net at $50/bo at wellhead and 1/8 royalty gives us another 5.6 million, so a total of 6.6 million, now if we believe Mr Shellman (and I do) we expect about a $10 million well cost (all in costs).  The average well breaks even at about $60/bo and $1.50/MCF at wellhead for the average 2017 Prmian basin well.

Dennis,

I posted the chart of my oldest well which is one of the oldest out there.  It was not BOE, it was bbl oil and it is 365,000 over five years.  Your well productivity data is independent of lateral length, date of first production and well classification, i.e. gas or oil.  The older wells may not be as good as mine but some of them undoubtedly are.  If you want a proper comparison then lateral length, well classification and date of first production is how thta data should be analyzed, this is basically a worthless graph.

The more recent wells that have been drilled and fracked using the most up to date information are the ones that will do best and easily beat that 200k bbl in two years number I suggested.  You say ONLY 20% of the wells in your data are that good, well how many of those were drilled since 2017?  When were those 20% drilled?  Your data provides no way to assess that and thus, your data doesn't contradict my claim because it doesn't give us any idea if well prioductivity is improving, which I believe it is.

My gas numbers include liquids and so just putting the price of dry gas in your calculations makes them erroneous.  If you want to do a decent analysis, fix your numbers.  If you just want to make claims that are open to criticism, keep on going.  The BTU factor on most of the gas out there is over 1.25 so at least factor your dry gas numbers with that in mind.

Edited December 10, 2019 by wrs

[wrs + 893]

13 hours ago, D Coyne said:

WRS,

I will make this simple for you, lets say one pays a bonus=B dollars on a 1000 acre plot where 10 wells are drilled (100 acres per well).  The land cost in that case is B/10.  It is not really a difficult problem. For some wells the cost might be zero for older leases, and in other cases it might be more,  I am using the average cost of all wells.  As Rystad figures it, a 10,000 foot well (which may become standard practice in the Permian basin) will have D+C cost of about $9.5 million, and as I stated there are facilities costs (F) and if N wells are supported by the facilities the the cost would be F/N, and plugging cost at the end of the well's life.  To be honest, I wonder if the $10 million well cost would actually cover a 10,000 lateral well, it might only cover 8750 feet of lateral. 

I will make it even simpler for you, that is not how the cost of the well is calculated by the industry nor how it is accounted for tax purposes or financial reporting purposes.  Moreover, Rystad has no data on what lease bonuses are because it's an industry secret.

Edited December 10, 2019 by wrs

[wrs + 893]

16 hours ago, James Gautreau said:

They do geophysics, which means placing a hydraulic battering ram on the ground and seismic gauges over the area being investigated. then they slam that battering ram into the ground and record the readings. Then they move it to a new spot and do it again until they have imaged the whole area. Then they evaluate the readings. I used to know a guy who did this. Had his own plane. Made real good money. But this was back in the days of conventional oil. 1980's & 1990's when they scoured the world for oil. I would imagine they do something similar with shale oil but I'm not sure. They may just go to where the most conventional oil was produced. The Permian has produced 20 billion barrels conventional crude and I think 5-6 unconventional. T. Boone Pickens, when he heard about the new 46 billion of barrels the USGS said they had discovered there said, "We've been drilling the Permian for 100 years and they just found another 46 billion barrels. C'mon man! " I posted a picture of the Bakken a few pages back that showed the sweet spots. I haven't found one for the Permian. In general Tier 1 are the best prospects.  

When you find one for the Permian, let me know.

[jjj + 26]

12 hours ago, ronwagn said:

I have been promoting conserving flare gas for years. I would appreciate any references you might recommend. I realize there is a lot of equipment available to use onsite but am not aware if the technology is actually being purchased and used, especially with the low natural gas price. 

What info would you be interested in? In short it is being used and it is expanding. I know of one company that will actually do revenue sharing to install Vapor Recovery Units (VRU's). Permian has/had an issue with pipeline to get the gas to market. The pipeline issue is much better today but still not perfect. I even talked to a company 2 weeks ago who is developing a Fischer/Tropsch process to convert small feed stocks to liquid. They are doing it at garbage dumps now and they are trying to develop the technology further to make it commercially viable at a single well head. The guy I talked to was the company finance officer and he was not confident they will get to that level but very confident that they could get to commercial viability with multiple wells ran to a Fischer/Tropsch plant. This could be a valid solution for stranded areas that don't have a pipeline. Another example of the technology working to make areas that today could not be drilled economically viable.to drill. 

 

Jay 

[Jan van Eck + 7,558]

There has been some interesting technical discussion in this thread, and also some rather aspersive comments (to which I groan).  The technical discussions all are founded on the implicit idea that there will be no quantum leap in technology in the future.  Yet, the entire shale exercise is a quantum leap in technology. 

Just for giggles, imagine that some new technique is developed to massively shatter that "tight rock" holding all that oil, which right now is feebly broken with hydraulic fracturing.  Let's suppose that it could be shattered into the equivalent of coarse sand, by some shock wave the equivalent of a nuclear explosion.  Now, all that trapped oil that only some small fraction is being recovered, comes flooding out of that well. Is anyone going to seriously maintain that this is impossible?  That there never, ever will be any major technical advancement in the oil patch?  I just do not view that proposition as being realistic, nor credible. 

OK, so now if you could bust the rock up into the consistency of sand, how much oil is really down there?   And whatever number you come up with, I can already tell you, it is going to be "quite a bit"!   I never underestimate the ability of smart guys to figure out some neat way to get at "more oil."   History of the oil patch, fellows. 

[Jan van Eck + 7,558]

7 minutes ago, jjj said:

The guy I talked to was the company finance officer and he was not confident they will get to that level

Of course they will.  I also remind readers that Fischer-Tropsch is great for converting America's vast coal deposits into pure liquid fuels.  I expect to see a lot more of this in the near future.   Never underestimate technology. 

[ronwagn + 6,290]

1 hour ago, jjj said:

What info would you be interested in? In short it is being used and it is expanding. I know of one company that will actually do revenue sharing to install Vapor Recovery Units (VRU's). Permian has/had an issue with pipeline to get the gas to market. The pipeline issue is much better today but still not perfect. I even talked to a company 2 weeks ago who is developing a Fischer/Tropsch process to convert small feed stocks to liquid. They are doing it at garbage dumps now and they are trying to develop the technology further to make it commercially viable at a single well head. The guy I talked to was the company finance officer and he was not confident they will get to that level but very confident that they could get to commercial viability with multiple wells ran to a Fischer/Tropsch plant. This could be a valid solution for stranded areas that don't have a pipeline. Another example of the technology working to make areas that today could not be drilled economically viable.to drill. 

 

Jay 

I am mainly interested in the technologies most likely to actually be marketable. The equipment has been available for years and has apparently not been used. As the largest companies take over I am hoping they will purchase it. The regulation has been lax so flaring has continued unabated with the excuse of no pipelines. 

[James Gautreau + 86]

2 hours ago, Jan van Eck said:

There has been some interesting technical discussion in this thread, and also some rather aspersive comments (to which I groan).  The technical discussions all are founded on the implicit idea that there will be no quantum leap in technology in the future.  Yet, the entire shale exercise is a quantum leap in technology. 

Just for giggles, imagine that some new technique is developed to massively shatter that "tight rock" holding all that oil, which right now is feebly broken with hydraulic fracturing.  Let's suppose that it could be shattered into the equivalent of coarse sand, by some shock wave the equivalent of a nuclear explosion.  Now, all that trapped oil that only some small fraction is being recovered, comes flooding out of that well. Is anyone going to seriously maintain that this is impossible?  That there never, ever will be any major technical advancement in the oil patch?  I just do not view that proposition as being realistic, nor credible. 

OK, so now if you could bust the rock up into the consistency of sand, how much oil is really down there?   And whatever number you come up with, I can already tell you, it is going to be "quite a bit"!   I never underestimate the ability of smart guys to figure out some neat way to get at "more oil."   History of the oil patch, fellows. 

I can tell you this. I'm with T. Boone Pickens on this one. The Permian produced 20 billion barrels of conventional oil over 60 years when it was shuttered as played out in 1971. To date they've produced around 6 billion of unconventional oil. They say there is 46 billion down there, some estimates are higher. I don't believe they will recover more than 10 billion out of there and if you recovered 100% by your super frack nuclear bomb, it will never be greater than the conventional crude production of 20 billion barrels. Just my .02.

[Jan van Eck + 7,558]

2 minutes ago, James Gautreau said:

I don't believe they will recover more than 10 billion out of there and if you recovered 100% by your super frack nuclear bomb, it will never be greater than the conventional crude production of 20 billion barrels. Just my .02.

James, you want to be real cautious about going out on a limb, when it comes to technology.  Specifically, it would be sobering for you to recognize that I could, even today and with today's technology, scale up a plant to recover even more than that 46 billion barrels of oil  - out of the air you breathe, standing on the surface of that oil field.  

And yes, for your newbies out there, gasoline can be manufactured from the components of air.  So, in reality, there is a totally inexhaustible supply of "oil" on this planet.  Something to sober the Saudis. 

[wrs + 893]

40 minutes ago, James Gautreau said:

I can tell you this. I'm with T. Boone Pickens on this one. The Permian produced 20 billion barrels of conventional oil over 60 years when it was shuttered as played out in 1971. To date they've produced around 6 billion of unconventional oil. They say there is 46 billion down there, some estimates are higher. I don't believe they will recover more than 10 billion out of there and if you recovered 100% by your super frack nuclear bomb, it will never be greater than the conventional crude production of 20 billion barrels. Just my .02.

James, I was skeptical of shale when I first started getting involved back in 2011.  My operator drilled three wells out there back in 2011 and they were duds.  He drilled them east to west and fracked them with gel.  The reasons for doing so made sense.  East to West was against the grain of the formation and so they thought that would expose more of the pores to the well bore.  I don't remember the reasoning for the gel but they found that it was clogging up the frac.

So Cimarex drilled a new experimental well which was just on the western boundary of my section in Culberson county.  That well was drilled north to south (wit the grain of the formation) and used what they call a slick water frac where most of the liquid was water and little or no gel was used.  This well produced 750bbl/day IP in 2013 which was considered fantastic at the time.  My operator then started using that technique and my oldest well was the first one he drilled that way, it produced 850bbl/day IP.

Just changing a couple of things increased the production by almost two orders of magnitude.  The other thing that you may not be aware of his how thick the Wolfcamp is and the fact that the Bone Springs just above it is also very prolific.  I don't see the 46B as unreasonable at all.  The evidence I have with the 19 wells I have been directly involved with says that the drilling and completion process is getting more effective in terms of cost reduction and increased well production.  The track record of my wells is what convinces me that shale isn't just a flash in the pan.

One last thing I wanted to add.  We have a lot of the shallow Delaware wells on our Orla section and the last one was drilled in 1992.  That well has produced 40,000 bbl over it's life and it took 20 years to pay out assuming a $500k drilling cost.  My first shale well produced 40,000 barrels in it's first three months of production and took only about two years to recover the costs.  Oil prices were quite high in it's first six months of production so that helped it pay out more quickly but it also was more expensive because it was a learning well.  They had to sidetrack it at 8000 feet so the driling costs were abnormally high.

Edited December 10, 2019 by wrs