Shale Oil Fiasco

[James Gautreau + 86]

An order of magnitude is 10 times. Where are the 2 orders of magnitude? That's 100 times. 

[James Gautreau + 86]

An order of magnitude is an exponential change of plus-or-minus 1 in the value of a quantity or unit. The term is generally used in conjunction with power-of-10 scientific notation. ... Thus, 23.15 is one order of magnitude smaller than 231.5, which in turn is one order of magnitude smaller than 2315.

[Bob D + 562]

25 minutes ago, wrs said:

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.

Please look at your Messages.  I'd like to talk to you about your Reeves/Culberson activity. 

TY 

Bob 

[Kirk + 12]

On 12/5/2019 at 6:55 AM, Jabbar said:

LOL

Look forward not backward.  When DUCs drawn down the weak go out of business.  The strong continue to drill now. 

At least half of the shale industry will merge consolidate or file bankruptcy.

Shale industry hiring .  . Mathematicians and Computer Science grads.  Don't need more field engineers.  

Don't fight it.

EMBRACE THE NEW SHALE INDUSTRY.

Yesterday Conoco CEO said U.S. will probably increase production about a million barrels a day by end of 2020.

U.S. Production up to 12.9 million barrels day week ending Nov 29th

Good post Jabbar.

What others aren't considering as well is that if it looks like Trump will lose or does lose, there will be a huge wave of completions and wells drilled in H2 next year. All those capex ranges will get blown past. And oil will collapse over winter 2020-21. That would wipe out many small players and almost any company in too much debt, i.e. 2/3 of them would have to merge, get bought (few buyers) or go BK.

Then, finally after summer 2021 clears inventory and massive capex cuts for 2021-22 happen, then oil price can rise to $70-80 area.

But it will never go higher. Why? Combination of Saudi supply and oil demand flattening much faster than people think.

We are very near peak oil demand: https://seekingalpha.com/article/4308760-peak-oil-plateau-is-close

[D Coyne + 305]

4 hours ago, wrs said:

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.

WRS,

Rystad gives average D+C cost per lateral foot, they are part of the industry.  You are correct we don't know the lease bonuses, I used your leases as representative, but I do not have data on lease bonuses, that is correct.  I imagine the average is more than zero per acre.

On the previous chart I do not have lateral length data.

Chart below has 2013 and 2014 Texas Permian wells from wolfcamp and bonespring formations with 60 month cumulative.

https://public.tableau.com/shared/7ZKBZHJ23?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y

Average is 130k, your 365k cumulative oil after 5 years is very good, if it is a Bonespring or Wolfcamp well in the Texas .Permian, it is the top 2% of all those wells drilled in 2013 or 2014 (2072 wells).  If we restrict to only 2014 wells in Wolfcamp or Bonespring the average cumulative at 60 months is 143k and a 365k cumulative at 60 months would be the top 2.6% of 1142 wells completed in the Wolfcamp or Bonespring formations in the Texas Permian Basin.

Very nice well congrats, but it is far from "typical", it is an outlier.

For 2017 wells in Texas Permian and in Wolfcamp or Bonespring formations, there were 1407 wells completed with average 24 month output of 196k and mdeian 24 month output of 181k, 58% of all wells had a 24 month cumulative of less than 200k.

This is for all lateral lengths, but in 2017 the average lateral length in the Permian basin was at least 7500 feet, I do not have a distribution of lateral lengths, that is subscription only data I do not have access to.

[wrs + 893]

2 hours ago, James Gautreau said:

An order of magnitude is 10 times. Where are the 2 orders of magnitude? That's 100 times. 

The Dale well produced 115 barrels of oil and 24mmcf in it's first full month of production.  That's when the operator determined that it wasn't what he was looking for.  My well produced 18,000 bbl oil in it's first full month of production.  Not saying that was the case for all the wells drilled back in 2011-2013 time frame but a lot of people were doing the wrong thing and looking for the wrong thing.  My operator was actually hoping to get big gas wells back then.

[Jabbar + 465]

4 hours ago, Kirk said:

Goo

What others aren't considering as well is that if it looks like Trump will lose or does lose, there will be a huge wave of completions and wells drilled in H2 next year. All those capex ranges will get blown past. And oil will collapse over winter 2020-2021

If looks like he's going to lose to Sanders, Warren or Styer maybe.

.  .  .  .  and only on federal leases (Delaware, Powder River, etc ) 

Others will not affect shale development.  

Obama campaigned against fracking and then never bothered shale. 

Edited December 10, 2019 by Jabbar

[wrs + 893]

37 minutes ago, D Coyne said:

WRS,

Rystad gives average D+C cost per lateral foot, they are part of the industry.  You are correct we don't know the lease bonuses, I used your leases as representative, but I do not have data on lease bonuses, that is correct.  I imagine the average is more than zero per acre.

On the previous chart I do not have lateral length data.

Chart below has 2013 and 2014 Texas Permian wells from wolfcamp and bonespring formations with 60 month cumulative.

https://public.tableau.com/shared/7ZKBZHJ23?:toolbar=n&:display_count=n&:origin=viz_share_link&:embed=y

Average is 130k, your 365k cumulative oil after 5 years is very good, if it is a Bonespring or Wolfcamp well in the Texas .Permian, it is the top 2% of all those wells drilled in 2013 or 2014 (2072 wells).  If we restrict to only 2014 wells in Wolfcamp or Bonespring the average cumulative at 60 months is 143k and a 365k cumulative at 60 months would be the top 2.6% of 1142 wells completed in the Wolfcamp or Bonespring formations in the Texas Permian Basin.

Very nice well congrats, but it is far from "typical", it is an outlier.

For 2017 wells in Texas Permian and in Wolfcamp or Bonespring formations, there were 1407 wells completed with average 24 month output of 196k and mdeian 24 month output of 181k, 58% of all wells had a 24 month cumulative of less than 200k.

This is for all lateral lengths, but in 2017 the average lateral length in the Permian basin was at least 7500 feet, I do not have a distribution of lateral lengths, that is subscription only data I do not have access to.

 

It's interesting that you would use a lease bonus that I gave you as representative but you won't do that with my production.  In any case, lease bonus is usually really low when it's a wildcat area.  In the Permian, as I explained, there is a tremendous amount of acreage already HBP by old producer 88 leases which means the land cost is zero per acre.  

What I can tell you about the production from my well is that the operator did a good job of managing the flow in order to maintain as much formation pressure as possible.  His geology isn't necessarily any better than someone who doesn't have such great cumulative production numbers but his flow management was.  A lot of operators in the early days over produced the wells in the first few months and drained away too much formation pressure which means lower eventual production without artificial lift.  Chalk that up to lessons learned.  Many of them didn't realize how steep the decline curve would be but most have learned now and going forward that will improve EUR.  They wanted big headline IPs and sacrificed EUR for big IPs. 

[James Gautreau + 86]

13 minutes ago, wrs said:

The Dale well produced 115 barrels of oil and 24mmcf in it's first full month of production.  That's when the operator determined that it wasn't what he was looking for.  My well produced 18,000 bbl oil in it's first full month of production.  Not saying that was the case for all the wells drilled back in 2011-2013 time frame but a lot of people were doing the wrong thing and looking for the wrong thing.  My operator was actually hoping to get big gas wells back then.

Just run the numbers. 46 billion barrels. Average EUR today has dropped from ~500,000 to ~200,000 on the first 6 billion, Tier 1 acerage. On the last 40 billion, and considering your well did 40,000 EUR, let's call EUR average 100,000 barrels. You'd have to drill 400,000 wells at $10,000,000 a well or $4 trillion dollars. The value of the oil at $50 a barrel is $2 trillion. Oil price would have to double to break even, triple to make a profit. That's assuming 100,000. Based on your experience I would bet Tier 3 acerage average EUR would be more like 50,000 barrels. 

[Rob Kramer + 696]

2 hours ago, wrs said:

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.

WRS - thanks for the posts I'm learning here I'm sure alot of others are also. Were the 3 duds on your land? So 3/19 wells plus one with higher expenses? .... I've asked before as I'm not hands on in the industry what's the success rate for wells? Last time I asked if there was any way to know as your drilling but this shows clearly they had  o idea the 3 duds wernt gonna work. 

Edited December 10, 2019 by Rob Kramer
Or 19 on production wells?

[wrs + 893]

Just now, James Gautreau said:

Just run the numbers. 46 billion barrels. Average EUR today has dropped from ~500,000 to ~200,000 on the first 6 billion, Tier 1 acerage. On the last 40 billion, and considering your well did 40,000 EUR, let's call EUR average 100,000 barrels. You'd have to drill 400,000 wells at $10,000,000 a well or $4 trillion dollars. The value of the oil at $50 a barrel is $2 trillion. Oil price would have to double to break even, triple to make a profit. That's assuming 100,000. Based on your experience I would bet Tier 3 acerage average EUR would be more like 50,000 barrels. 

James you are confusing the wells.  I said the youngest Delaware well on my Orla section was drilled in 1992 and has produced 40,000 barrels in 28 years.  The first shale well I had out there made 40,000 barrels in it's first three months.  The cumulative production on that well is currently, after 5 years, 365,000 bbl.

[jjj + 26]

1 hour ago, ronwagn said:

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. 

In the Permian it had less to do with the equipment more to do with the lack of infrastructure. NG is not easy to economically transport. The price of oil was high enough they felt they could burn the excess gas and still pay for the well so they drilled to produce oil before pipelines were built. Regulations could have forced them to not burn the gas but then they wouldn't have drilled. You could argue that both ways whether it was right or not. But the pipelines are now opening up allowing them to install the equipment. The VRU is nothing more than a NG compressor. The earlier ones we sold were ran from NG engines but the market has mostly switched over to electric motors driven compressors now. 

 

Jay

[wrs + 893]

2 minutes ago, Rob Kramer said:

WRS - thanks for the posts I'm learning here I'm sure alot of others are also. Were the 3 duds on your land? So 3/19 wells plus one with higher expenses? .... I've asked before as I'm not hands on in the industry what's the success rate for wells? Last time I asked if there was any way to know as your drilling but this shows clearly they had  o idea the 3 duds wernt gonna work. 

No, the duds were elsewhere.  Mine was his first properly drilled and completed well.  I have three operators, this is just one of them, an independent.  XTO is the big one and BHP was the third one.

I think at this point the success rate is over 90% and it's 100% for the good operators.  The reason is that the lessons learned are often shared and because shale is contiguous and fairly uniform, there aren't misses like where you are trying to hit a small pocket of oil with a vertical straw and miss.  With shale, the part that needs to be hit is the most oil rich part and that moves from west to east.  It gets deeper in the Wolfcamp from west to east.  

For example, on the Culberson section, the sweet spot is around 9050 feet on the west side but on the east side (one more mile to the east) it's at about 9200 feet.  Understanding where the sweet spot is makes a big difference in shale wells.  I would think that a geologist could shed more light on that than me, I just know that the sweet spot in the play is about a 50 foot window and it moves so having a good geologist is important.

[D Coyne + 305]

5 hours ago, wrs said:

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.

I do not have data on NGL output or average NGL per MCF of gas.  I used 2.50 to account for NGL, the dry gas is probably about $1/MCF at the wellhead on average in the Permian.  Note that Natural gas that is flared burns the NGL along with the gas.  So 1.5 times 1.25=1.875, I used 2.5 which would equate to $2/MCF dry gas, which is generous for a wellhead price.  The Waha natural gas price is currently about $1.50/MCF.  So my Natural gas price estimate is generous.

For my more detailed breakeven analysis I us a DCF and figure both oil and natural gas in the analysis.

[D Coyne + 305]

1 hour ago, wrs said:

It's interesting that you would use a lease bonus that I gave you as representative but you won't do that with my production.  In any case, lease bonus is usually really low when it's a wildcat area.  In the Permian, as I explained, there is a tremendous amount of acreage already HBP by old producer 88 leases which means the land cost is zero per acre.  

What I can tell you about the production from my well is that the operator did a good job of managing the flow in order to maintain as much formation pressure as possible.  His geology isn't necessarily any better than someone who doesn't have such great cumulative production numbers but his flow management was.  A lot of operators in the early days over produced the wells in the first few months and drained away too much formation pressure which means lower eventual production without artificial lift.  Chalk that up to lessons learned.  Many of them didn't realize how steep the decline curve would be but most have learned now and going forward that will improve EUR.  They wanted big headline IPs and sacrificed EUR for big IPs. 

WRS,

The data shows very little productivity improvement from 2016 to 2018 in the Permian basin, particularly when normalized for lateral length.  Your story works for 2014 and 2015, but by 2016 this had been figured out.  I used your land cost number because it is all I have, I have plenty on data on well output and the Rystad estimate for D+C average cost.  For the average 2017 well I expect 60 month cumulative will be about 280 kbo. Breakeven is about $52/bo at wellhead.  Payout is reached in 67 months at 288 kbo and 19.6 MMCF natural gas (both 60 month cumulative output).

[Bob D + 562]

Seems like I'm reading a whole lot of 

2 hours ago, James Gautreau said:

Just run the numbers. 46 billion barrels. Average EUR today has dropped from ~500,000 to ~200,000 on the first 6 billion, Tier 1 acerage. On the last 40 billion, and considering your well did 40,000 EUR, let's call EUR average 100,000 barrels. You'd have to drill 400,000 wells at $10,000,000 a well or $4 trillion dollars. The value of the oil at $50 a barrel is $2 trillion. Oil price would have to double to break even, triple to make a profit. That's assuming 100,000. Based on your experience I would bet Tier 3 acerage average EUR would be more like 50,000 barrels. 

What Is EUR (Estimated Ultimate Recovery)?

Estimated ultimate recovery (EUR) is an approximation of the quantity of oil or gas that is potentially recoverable 

NO WAY anybody drills a Permian Shale horizontal well expecting an EUR of 100,000bbls.  Sorry no way!

According to my guys, the EUR of the next shale well drilled with a 1 mile lateral will have an EUR of 600,000 bbls and 2 mile lateral will have an EUR of 900,000-1,200,000.  Call it Tier 1 if you want. 

Since everybody's so keen to do everybody else's math ... here's mine on that 100,000bbl EUR well.

$10 million to drill/complete  vs  $5 million revenue @ EUR100,000 & $50/bbl    NOPE!   NO WAY!

Edited December 10, 2019 by Bob D

[Jabbar + 465]

6 hours 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.

Do you realize that we call conventional oil is estimated at only 12% of total oil in a given geography. The rest being tight oil.

Granted, the best performers presently presently get 9% to 11% yield.  Conoco says they will be able to get 20% on most new wells in Eagleford and Delaware. They believe they can do even better.   Also said they are refracing vintage 1 , 2 , 3 wells and are producing oil sub $30.

Some say it's bull.  Looks real to me. 

 

 

[James Gautreau + 86]

37 minutes ago, Bob D said:

Seems like I'm reading a whole lot of 

What Is EUR (Estimated Ultimate Recovery)?

Estimated ultimate recovery (EUR) is an approximation of the quantity of oil or gas that is potentially recoverable 

NO WAY anybody drills a Permian Shale horizontal well expecting an EUR of 100,000bbls.  Sorry no way!

According to my guys, the EUR of the next shale well drilled with a 1 mile lateral will have an EUR of 600,000 bbls and 2 mile lateral will have an EUR of 900,000-1,200,000.  Call it Tier 1 if you want. 

Since everybody's so keen to do everybody else's math ... here's mine on that 100,000bbl EUR well.

$10 million to drill/complete  vs  $5 million revenue @ EUR100,000 & $50/bbl    NOPE!   NO WAY!

Scroll up a few posts. One guy drilled a well and got 44,000 barrels. You don't drill expecting it, it is what it is. Your guys are talking about Tier 1 wells. This is a Tier 3 well. They drill 4 or 5 crappy wells to find one good one. Do the math. If every well was 600,000 EUR shale oil companies would be swimming in dough.

Edited December 10, 2019 by James Gautreau

[James Gautreau + 86]

3 hours ago, wrs said:

James you are confusing the wells.  I said the youngest Delaware well on my Orla section was drilled in 1992 and has produced 40,000 barrels in 28 years.  The first shale well I had out there made 40,000 barrels in it's first three months.  The cumulative production on that well is currently, after 5 years, 365,000 bbl.

OK sorry about that.

[D Coyne + 305]

7 hours ago, Jan van Eck said:

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. 

Jan,

With today's technology what is your estimate for the cost to produce a barrel of Oil using water and CO2 from the air?

Just because something can be done does not mean it is profitable to do so.  Pretty obvious future technology is not possible to predict, your proposed "what if" seems about as likely as "what if nuclear fusion reactors become viable.  A more likely scenario is that the cost of wind, solar, and battery or fuel cell backup becomes cheaper than any type of fossil fuel, either fuel cells or batteries powering electric motors seems a more viable long term option, natural gas can serve as backup during the transition to non-fossil fuel energy.

[D Coyne + 305]

1 hour ago, James Gautreau said:

OK sorry about that.

Here is the Productivity distribution of 2018 Permian Wolfcamp wells, based on 12 month cumulative output, 2312 wells, with 56% of wells less than 150k cumulative after 12 months and the rest more than that, when an Arps hyperbolic is fit to the early data for 2017 wells the EUR is about 380 kb for the average well, the well profile for 2018 looks similar after 16 months, the first 16 months has about 15 kb higher cumulative so a rough estimate might be 395 kb for the average 2018 well.  Lateral length on average increased from 7500 feet in 2016 to 9000 feet in 2018, but it may decrease in the future as different counties tend to have different average lateral lengths and as sweet spots get full drilled lateral length could decrease as production might move to counties with shorter average lateral lengths.  Chart from advanced insights productivity distribution (slide to right).

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

[Jan van Eck + 7,558]

9 hours ago, D Coyne said:

Jan,

With today's technology what is your estimate for the cost to produce a barrel of Oil using water and CO2 from the air?

Just because something can be done does not mean it is profitable to do so.  Pretty obvious future technology is not possible to predict, your proposed "what if" seems about as likely as "what if nuclear fusion reactors become viable.  A more likely scenario is that the cost of wind, solar, and battery or fuel cell backup becomes cheaper than any type of fossil fuel, either fuel cells or batteries powering electric motors seems a more viable long term option, natural gas can serve as backup during the transition to non-fossil fuel energy.

Short answer as to costs of air-extracted oil:  I dunno. 

Let's remember something:  "oil," that is, crude oil, is an inconvenient mineral slime.  We use it and delight in it because it contains lots of energy which we can extract by burning it after refining it.  We got into using oil after the early wells came with lots of pressure behind them so that pumping was unnecessary. Even as late as 1956 crude oil cost about $3 a bbl to pull out of the ground.  So, there was no incentive, other than by nerdy eccentrics looking for intellectual satisfaction and bragging rights to their pals, for anyone to go figuring out some other way to make oil, or some other alternative to oil.   Basically, we have oil because we discovered it by accident, and the stuff is (or was) cheap. 

Yet, oil is inconvenient.  It starts out as a mineral slime and tends to be mixed with other stuff, including NGLs and natgas. It is found in areas remote to where most of the usage is.  The stuff has to be tankered, sometimes half-way around the globe.  So, it is inconvenient.

When you have that, then an impetus develops for some alternative.  It always, inexorably, works that way.  Right now, there is all this hype about Elon Musk and his electric cars.  What nobody tells you is that Mr. Elon is emphatically not a philanthropist, and he does not give his parts away.  If you burn out that drive motor on that fancy Tesla, you find out that there is no off-the-shelf replacement.  It is made custom for Tesla, probably even by Tesla.  So you have to go beg Mr. Elon to sell you a new motor.  Maybe he does and maybe he doesn't.  If he does, it will whack you for $6,000.  And that is before installation.  Same with the rest of the parts, which is why even minor collisions end up with the car being a constructive total loss ["totalled"] by the insurance company.  Are there spare parts available in the automotive aftermarket?  No chance.  And the volume is not high enough for some independent fabricator to go take apart an Elon Motor and figure out how to build a spare. So you get on your knees and genuflect to Mr. Elon or your fancy set of wheels stays sitting on cement blocks, forever. 

These situations are called "frictional inefficiencies" by economists.  I call them "deliberate inefficiencies," because the original builders, in this case Tesla, designed it that way. What that implies is that the optimal technology and the hardware to put it in motion is not yet developed.  My hunch is that autos and trucks will be running on flywheels instead of batteries, and that each house and apartment block will have this flywheel sitting in the basement silently spinning and holding this reserve of power, there to be called out in the case of grid failure or overload.  Flywheels made of carbon-fiber textile layup are a lot easier and cheaper than some exotic battery with arcane minerals mined in the Congo will ever be. 

The other thing you want to keep in mind is that all manufactured goods will, after enough experience is gathered in their manufacture, suddenly have a sharp cost drop.  It is a totally universal phenomenon.  So whatever the cost of oil from air is today, that will not be the cost tomorrow or next year.  You suck CO2 out of the air and you add some hydrogen compound such as CH4 and you will get all the gasoline you could dream of soon enough.  It is only a matter of scale. 

Meanwhile, there is lots and lots of oil out there, and a lot of smart guys who have figured out how to get it out of the ground (or ocean).  So, I anticipate that conventional oil  (I include shale oil in that descriptor) is going to be around for quite a while yet.  Centuries. 

 

Edited December 11, 2019 by Jan van Eck
typing error

[D Coyne + 305]

2 hours ago, Bob D said:

Seems like I'm reading a whole lot of 

What Is EUR (Estimated Ultimate Recovery)?

Estimated ultimate recovery (EUR) is an approximation of the quantity of oil or gas that is potentially recoverable 

NO WAY anybody drills a Permian Shale horizontal well expecting an EUR of 100,000bbls.  Sorry no way!

According to my guys, the EUR of the next shale well drilled with a 1 mile lateral will have an EUR of 600,000 bbls and 2 mile lateral will have an EUR of 900,000-1,200,000.  Call it Tier 1 if you want. 

Since everybody's so keen to do everybody else's math ... here's mine on that 100,000bbl EUR well.

$10 million to drill/complete  vs  $5 million revenue @ EUR100,000 & $50/bbl    NOPE!   NO WAY!

BobD,

We have been talking about cumulative production at 12 months, 24, months, 60 months etc, with numbers like 200k at 24 months, 370 k at 60 months (for a single well).  Today the average Permian well is likely to have an EUR of 400 kb, note many companies tout the EUR in BOE, but in revenue terms natural gas is far less valuable so using 6 MCF to 1 bo sounds impressive, but in financial terms the ratio is more like 22 MCF to 1 bo at 55/bo and 2.50/MCF.

So the average 2017 Permian well has an EUR of 385 kbo and 282 kboe for natural gas for a total EUR of  667 kboe.

In financial terms the EUR would be equivalent to 460 kboe, due to low natural gas prices.

[D Coyne + 305]

6 minutes ago, Jan van Eck said:

Short answer as to costs of air-extracted oil:  I dunno. 

Let's remember something:  "oil," that is, crude oil, is an inconvenient mineral slime.  We use it and delight in it because it contains lots of energy which we can extract by burning it after refining it.  We got into using oil after the early wells came with lots of pressure behind them so that pumping was unnecessary. Even as late as 1956 crude oil cost about $3 a bbl to pull out of the ground.  So, there was no incentive, other than by nerdy eccentrics looking for intellectual satisfaction and bragging rights to their pals, for anyone to go figuring out some other way to make oil, or some other alternative to oil.   Basically, we have oil because we discovered it by accident, and the stuff is (or was) cheap. 

Yet, oil is inconvenient.  It starts out as a mineral slime and tends to be mixed with other stuff, including NGLs and natgas. It is found in areas remote to where most of the usage is.  The stuff has to be tankered, sometimes half-way around the globe.  So, it is inconvenient.

When you have that, then an impetus develops for some alternative.  It always, inexorably, works that way.  Right now, there is all this hype about Elon Musk and his electric cars.  What nobody tells you is that Mr. Elon is emphatically not a philanthropist, and he does not give his parts away.  If you burn out that frive motor on that fancy Tesla, you find out that there is no off-the-shelf replacement.  It is made custom for Tesla, probably even by Tesla.  So you have to go beg Mr. Elon to sell you a new motor.  Maybe he does and maybe he doesn't.  If he does, it will whack you for $6,000.  And that is before installation.  Same with the rest of the parts, which is why even minor collisions end up with the car being a constructive total loss ["totalled"] by the insurance company.  Are there spare parts available in the automotive aftermarket?  No chance.  And the volume is not high enough for some independent fabricator to go take apart an Elon Motor and figure out how to build a spare. So you get on your knees and genuflect to Mr. Elon or your fancy set of wheels stays sitting on cement blocks, forever. 

These situations are called "frictional inefficiencies" by economists.  I call them "deliberate inefficiencies," because the original builders, in this case Tesla, designed it that way. What that implies is that the optimal technology and the hardware to put it in motion is not yet developed.  My hunch is that autos and trucks will be running on flywheels instead of batteries, and that each house and apartment block will have this flywheel sitting in the basement silently spinning and holding this reserve of power, there to be called out in the case of grid failure or overload.  Flywheels made of carbon-fiber textile layup are a lot easier and cheaper than some exotic battery with arcane minerals mined in the Congo will ever be. 

The other thing you want to keep in mind is that all manufactured goods will, after enough experience is gathered in their manufacture, suddenly have a sharp cost drop.  It is a totally universal phenomenon.  So whatever the cost of oil from air is today, that will not be the cost tomorrow or next year.  You suck CO2 out of the air and you add some hydrogen compound such as CH4 and you will get all the gasoline you could dream of soon enough.  It is only a matter of scale. 

Meanwhile, there is lots and lots of oil out there, and a lot of smart guys who have figured out how to get it out of the ground (or ocean).  So, I anticipate that conventional oil  (I include shale oil in that descriptor) is going to be around for quite a while yet.  Centuries. 

 

Jan,

I doubt it will be centuries, at least in significant quantities, chart below has my best guess scenario for World C+C.

[D Coyne + 305]

2 hours ago, Jabbar said:

Do you realize that we call conventional oil is estimated at only 12% of total oil in a given geography. The rest being tight oil.

Granted, the best performers presently presently get 9% to 11% yield.  Conoco says they will be able to get 20% on most new wells in Eagleford and Delaware. They believe they can do even better.   Also said they are refracing vintage 1 , 2 , 3 wells and are producing oil sub $30.

Some say it's bull.  Looks real to me. 

 

 

Jabbar,

Conoco in 2017 Eagle Ford average 12 month cumulative output for 97 wells was 220 kbo.

For 2018 Eagle Ford wells completed by Conoco 12 month cumulative output for 105 wells is 205 kbo.

They seem to be moving in the wrong direction, they have very productive wells, but the number of wells is pretty small.

I will be convinced of Conoco's hype when I see performance 3 or 4 years out.