World "Awash" in oil. Sec Perry says Goldman Sachs wrong.

[Guest]

Haha I'm kidding     Gerry always gives huge detailed answers, so I tell him I want more detail rather than his one-liners

It's my amazing sense of humoUr again ... 

#butcheredourlanguage 

Edited November 1, 2019 by Guest

[Jabbar + 465]

3 hours ago, D Coyne said:

Jabbar,

Don't do investor hype.  When the average new well EUR of Eagle Ford wells increases by a factor of 2, I will believe it.

DC

Read GERRY,S post. Plenty of reserves in U.S shale and GOM. 

The Peak Oil Supply theory started over 20 years ago. I thought it was dead and buried in 2010.

I would bet you were a believer from the get go. May be a University professor and been teaching it to students for 20 years.  

Belief systems are funny.  Hard to let go when you have invested a lifetime working on it.

Things change.

Keep on going you may be correct.

 I'm not asking you to believe 20% yield obtainable.  Just do me a favour and plunk my assumptions in your model.

Let me know what you get.

 

 

3 hours ago, D Coyne said:

 

[D Coyne + 305]

18 hours ago, Jabbar said:

 

CD 

I'M NOT ASKING YOU TO BELIEVE POSIBLE YIELDS IN THE HIGH TEENS OR EVEN 20% CAN BE ACHIEVED.  

ITS JUST AN ASSUMPTION JUST LIKE THE ONES YOU USE IN YOUR MODELS AND GRAPHS.

Your models are on a computer.  How long to input the assumptions I have given you into your computer ?  Ten minutes at most ? 

Let me know.

PS : do you teach at University ?

Jabbar,

I try to not use garbage for assumptions, essentially Conoco is claiming  EUR can be doubled from current levels.

When I see evidence that the average new well EUR in the Eagle Ford has actually increased by a factor of 2 (that is what the 10% to 20% claim implies) I will input that assumption into my model.  Otherwise I simply get garbage out due to a garbage input to the model.

Check post below from shaleprofile

https://shaleprofile.com/2019/10/31/eagle-ford-update-through-july-2019/

A major issue for the basin is that well productivity has been stagnant in the last 3 years. As you can see in the ‘Well quality’ tab, which shows the production profiles for all these wells, well productivity has no longer increased since 2017.

Check well quality tab for details on well productivity, Eagle Ford average well productivity has been stagnant for past three years, average well productivity shows no signs of increasing.

I attempt to model reality rather than what some wish to be true.

No I am not a university professor, base my models on scientific research.

Mean USGS estimates and average basin new well EUR are the basis for the model.

Look at the Bakken, which is the oldest basin for tight oil.

https://shaleprofile.com/2019/10/14/north-dakota-update-through-august-2019/

See chart below, especially cumulative output section.

From 2008 to 2014 there was very little change in average new well EUR, from 2015 to 2018 EUR increased to some degree, but this was likely due to high grading as producers focused all drilling on the sweet spots.  This will only serve to use up all the tier one areas more quickly, after they run out of space it is likely that average new well EUR will decrease as operators move to tier 2 and tier 3 areas for new wells.  

 

Edited November 1, 2019 by D Coyne

[D Coyne + 305]

Jabbar,

Here are the USGS mean TRR estimates (note these are resources not reserves, which depend on the price of oil)

Bakken- 12 Gb

Eagle Ford- 14 Gb

Permian-75 Gb

https://pubs.usgs.gov/fs/2013/3013/

https://pubs.er.usgs.gov/publication/fs20183033

https://pubs.er.usgs.gov/publication/fs20163092

https://pubs.er.usgs.gov/publication/fs20173029

https://pubs.er.usgs.gov/publication/fs20183073

So roughly 100 Gb for mean TRR for these plays, perhaps another 20 Gb of continuous C+C TRR from other tight oil plays in the US.

At the end of 2017 tight oil reserves were about 20 Gb and cumulative tight oil output was 11 Gb for a total of 33 Gb, my optimistic scenario suggests  96 Gb of tight oil output (using reasonable oil price assumptions from EIA), so my model agrees there are a lot of potential resources that will be added to reserves at the end of 2017 (most recent EIA estimate), about 63 Gb, for my best guess.

Note that these tight oil resources are tiny relative to World remaining C+C resources, which are about 1900 Gb. so tight oil about 85 Gb remaining and other C+C resources about 1900 Gb, tight oil comprises about 4.5% of the total.

Does not really move the needle.

The rapid rise of tight oil output may be followed by an equally rapid fall in output, wishing it was not so and that new well average productivity will magically double, is a case of wishful thinking.

 

[Danlxyz + 63]

35 minutes ago, D Coyne said:

When I see evidence that the average new well EUR in the Eagle Ford has actually increased by a factor of 2 (that is what the 10% to 20% claim implies) I will input that assumption into my model.  Otherwise I simply get garbage out due to a garbage input to the model.

Dennis, this is just a WAG but perhaps the new well EUR is the result of refracking the old well. On another thread Butasha posted a graph showing production decline of a couple of wells/leases One group of 4 wells started at about 65,000 bod which declined to 10,000 bod and was refracted. The production went up to 70,000 bod and started declining again.

 

From Butasha post on 9-21-19

"The second graph is 4 wells drilled, fracked and placed into service as one package. This lease and I assume that meant all 4 wells were refracked back in 2015-16 time frame. This lease is approximately 1.5-2 miles from the well of the first lease and would be considered short lateral leases. The second lease as of July 2019 has produced 1,735,670 barrels of oil and 4,010,245 mcf. 

All this information is available via the Texas Railroad Commission web site."

[ronwagn + 6,290]

On 10/28/2019 at 6:37 PM, Gerry Maddoux said:

Have you ever personally seen what it takes to get a barrel of oil out of the ground and into a barrel? I doubt it; correct me if I'm wrong.

Do you have any idea of history? With barrels of oil in reserve, we're about right: no less, no more. 

IMO-2020 takes place January 1, 2020. Do you have any idea what it's going to cost to transport a VLCC full of oil to China after the low-sulfur bans are in place? I didn't think so. 

Do you have any idea what the Saudis have in reserve? I don't either, but it's a given that it's less than they had five years ago. 

Occidental has ten billion borrowed at 8% interest--but they're trying to sell property. Continental is doing okay. Hess is also doing okay. Several small players are doing okay. Some are going to go broke, but you know what, it's not their money----it's funny money, from pooled investors, pay your way and find your way. 

Secretary Perry doesn't have a f****** clue. The Department of Energy is one of the departments he claimed he was going to eliminate when he was campaigning for president. He forgot its name on stage! And now he's head of it! Does that not strike you as ironic?

Whether Perry's guess is right or Goldman Sachs has it right is of very little significance: it is what is is. And what it is is a market, with fear and greed moving it, along with surplus and . . . ultimately, shortages. But I'll damn sure guarantee you one thing: the world is NOT currently awash in oil. The world's storage is just about on par. The world's proved up reserves are no longer even verifiable; if they were the Saudi Aramco IPO would be ongoing. In truth, the world doesn't have a clue what the reserves are, and which ones will be used. Most of the articles on Oilprice are meant to scare people, written by someone like you: who hasn't a brain cell's idea of what it's like to go take a risk, bring up a barrel of oil, try to peddle it. It's just bullshit. I don't mind you saying it, but I do want to call it out as bullshit. It's not even provocative. 

One thing IS for sure is that we are awash in ENERGY between oil, natural gas, biogas, hydro, wind, solar, nuclear, coal, ethanol, cellulose, etc. Only people in the poorest of countries will go without power much longer Hopefully, they will be helped with energy, clean water, hygiene, medicine, food, etc. The main obstruction for the poor is violent political and religious conflicts, not lack of those willing to help. 

Edited November 1, 2019 by ronwagn
addition

[ronwagn + 6,290]

On 10/30/2019 at 4:11 PM, D Coyne said:

Old-Ruffneck,

Note that I presented two scenarios, a "medium scenario" with a plateau from 2023 to 2028 (C+C output between 85 and 86 MMbopd) and  and a "high URR scenario" with a plateau from 2028 to 2038 (C+C at 91 to 92 MMbopd), you might prefer the "high" scenario.

You could be right, we will find out in 5 to 10 years, my best guess scenario has been revised to 3200 Gb. Output of C+C is between 85 and 86 Mb/d from 2023 to 2028, so essentially a bumpy plateau for this narrow band of output.  No future scenario is a fact, facts are history, different from scenarios of the future.  Good thing that demand will slow as my best guess scenario has output at about 60 MMbpd in 2050.  We have not been discovering much oil lately see

https://www.ogj.com/exploration-development/reserves/article/14068305/rystad-oil-and-gas-resource-replacement-ratio-lowest-in-decades

liquids discoveries were 5.6 Gb in 2018 and so far in 2019 (Jan to Sept 2019) only 3.2 Gb of liquids have been discovered.  About 32 Gb of C+C was produced in 2018, there are about 1300 Gb of conventional and tight oil reserves (leaving out oil sands in Canada and Venezuela), lets say we discover 5 Gb of oil each year and production remains 32 Gb, so each year proved reserves fall by 27 Gb, in 48 years reserves would be zero (1300/27=48).  Obviously output starts to fall before we get to year 48.  My model assumes about 188 Gb of discoveries over the next 80 years.  Chart below  shows the discovery model I use for future C+C discovery of conventional oil, which excludes extra heavy oil (oil sands with API Gravity <10) and tight oil.

Notice how the model over predicts discoveries in 2018 (at 8.1 BBO) and possibly in 2019 as well (7.7 BBO).

You are forgetting about coal to oil and natural gas to oil products. 

[Jabbar + 465]

1 hour ago, D Coyne said:

Jabbar,

Here are the USGS mean TRR estimates (note these are resources not reserves, which depend on the price of oil)

Bakken- 12 Gb

Eagle Ford- 14 Gb

Permian-75 Gb

https://pubs.usgs.gov/fs/2013/3013/

https://pubs.er.usgs.gov/publication/fs20183033

https://pubs.er.usgs.gov/publication/fs20163092

https://pubs.er.usgs.gov/publication/fs20173029

https://pubs.er.usgs.gov/publication/fs20183073

So roughly 100 Gb for mean TRR for these plays, perhaps another 20 Gb of continuous C+C TRR from other tight oil plays in the US.

At the end of 2017 tight oil reserves were about 20 Gb and cumulative tight oil output was 11 Gb for a total of 33 Gb, my optimistic scenario suggests  96 Gb of tight oil output (using reasonable oil price assumptions from EIA), so my model agrees there are a lot of potential resources that will be added to reserves at the end of 2017 (most recent EIA estimate), about 63 Gb, for my best guess.

Note that these tight oil resources are tiny relative to World remaining C+C resources, which are about 1900 Gb. so tight oil about 85 Gb remaining and other C+C resources about 1900 Gb, tight oil comprises about 4.5% of the total.

Does not really move the needle.

The rapid rise of tight oil output may be followed by an equally rapid fall in output, wishing it was not so and that new well average productivity will magically double, is a case of wishful thinking.

 

CD 

You sound like broken record.

So I guess you won't oblige me and run you End of the World Shock model using my assumptions. 

let me know if you change your mind.

[Jabbar + 465]

1 hour ago, Danlxyz said:

Dennis, this is just a WAG but perhaps the new well EUR is the result of refracking the old well. On another thread Butasha posted a graph showing production decline of a couple of wells/leases One group of 4 wells started at about 65,000 bod which declined to 10,000 bod and was refracted. The production went up to 70,000 bod and started declining again.

 

From Butasha post on 9-21-19

"The second graph is 4 wells drilled, fracked and placed into service as one package. This lease and I assume that meant all 4 wells were refracked back in 2015-16 time frame. This lease is approximately 1.5-2 miles from the well of the first lease and would be considered short lateral leases. The second lease as of July 2019 has produced 1,735,670 barrels of oil and 4,010,245 mcf. 

All this information is available via the Texas Railroad Commission web site."

Not refracting.  I'm told Energy Department founded research that takes s sampling of the core reserve rock. By analyzing the sample all the way down to the microscopic level they are able to customise frac fluids , drill path, etc.

Was research grant to a University , Conoco worked with them closely.

One problem is many of the majors are reluctant to share EUR advancements.  They believe price competition is coming to the oil industry and being the lowest priced producer is an advantage. 

Wasn't a problem before when demand always coveted supply.  Shouldn't be a problem yet. But they believe it is coming. 

[Douglas Buckland + 6,308]

3 hours ago, Jabbar said:

CD 

You sound like broken record.

So I guess you won't oblige me and run you End of the World Shock model using my assumptions. 

let me know if you change your mind.

Not really the cleverest strategy to use if you are asking someone to do you a favor (or favour if it’s DT).

[Guest]

2 hours ago, Douglas Buckland said:

to do you a favor (or favour if it’s DT).

LOL don't say it like I'M the one in the wrong, ''or favour if it's correct'' that should say 

[D Coyne + 305]

3 minutes ago, Danlxyz said:

Dennis, this is just a WAG but perhaps the new well EUR is the result of refracking the old well. On another thread Butasha posted a graph showing production decline of a couple of wells/leases One group of 4 wells started at about 65,000 bod which declined to 10,000 bod and was refracted. The production went up to 70,000 bod and started declining again.

 

From Butasha post on 9-21-19

"The second graph is 4 wells drilled, fracked and placed into service as one package. This lease and I assume that meant all 4 wells were refracked back in 2015-16 time frame. This lease is approximately 1.5-2 miles from the well of the first lease and would be considered short lateral leases. The second lease as of July 2019 has produced 1,735,670 barrels of oil and 4,010,245 mcf. 

All this information is available via the Texas Railroad Commission web site."

Interesting,

So we have 4 wells out of about 24,000 wells that have been completed in the Eagle Ford.  I look at basin wide averages by year.  It is not clear that the cost of the refrack will pay out in most cases.

14 hours ago, ronwagn said:

You are forgetting about coal to oil and natural gas to oil products. 

Not forgetting, simply accounting for the fact that at present coal to liquids and natural gas to liquids are not competitive with petroleum fuels refined from crude plus condensate.  The discoveries shown in the chart correspond with conventional crude plus condensate discoveries, so far about 2600 Gb of conventional C+C have been discovered as of the end of 2017 (conventional excludes crude with API gravity less than ten and tight oil.)

Any idea how much of the World's light and middle distillate fuel is produced from coal and natural gas?  

Pretty sure the problem is the cost of production from non-crude sources.

[D Coyne + 305]

9 hours ago, Douglas Buckland said:

Not really the cleverest strategy to use if you are asking someone to do you a favor (or favour if it’s DT).

Douglas,

As an industry professional, does the claim that average new well EUR will double (as that is what Jabbar is claiming) with no increase in well cost pass the sniff test in your view?  When one considers actual data from state agencies new well EUR normalized for lateral length has been pretty steady in the Permian basin from 2016 to 2018 according to Enno Peters at shaleprofile.com.

https://shaleprofile.com/2019/10/28/permian-update-through-july-2019/

Initial well productivity is still slightly increasing, as you can find in the “Well quality” tab, which shows all the production profiles by year in which production started.

As mentioned in previous posts, this does not consider that well lengths and proppant loadings have increased over the years. Normalizing for lateral length, we still find that well results are basically unchanged since 2016, as shown in the following dashboard, which was taken from our advanced analytics service:

[Douglas Buckland + 6,308]

DC,

I am a ‘drilling guy’, not a production hand, who just happens to have a degree in Petroleum Engineering.

That said, it does not pass the ‘sniff test’. From what you described above, if I am reading this correctly, a new well, designed exactly like an old well, into exactly the same formation, with the same length of lateral, with identical technology (maybe the proppant utilized has been tweaked or some minimal change in the completion hardware (ie, no increase in well cost)), and the well for some reason yields a two-fold increase in the EUR. My question is ‘how’?

To get a two-fold increase in EUR you would have to either double the production rate for the same duration or extend the producing life of the well until it had doubled the production of the ‘old’ well.

Since the new well essentially mirrors the old well, there is nothing that would suggest either a doubling in flowrate over a set duration or to indicate that the production life would be extended to the point that the EUR would be doubled.

....if I am reading this correctly.

[D Coyne + 305]

7 hours ago, Douglas Buckland said:

DC,

I am a ‘drilling guy’, not a production hand, who just happens to have a degree in Petroleum Engineering.

That said, it does not pass the ‘sniff test’. From what you described above, if I am reading this correctly, a new well, designed exactly like an old well, into exactly the same formation, with the same length of lateral, with identical technology (maybe the proppant utilized has been tweaked or some minimal change in the completion hardware (ie, no increase in well cost)), and the well for some reason yields a two-fold increase in the EUR. My question is ‘how’?

To get a two-fold increase in EUR you would have to either double the production rate for the same duration or extend the producing life of the well until it had doubled the production of the ‘old’ well.

Since the new well essentially mirrors the old well, there is nothing that would suggest either a doubling in flowrate over a set duration or to indicate that the production life would be extended to the point that the EUR would be doubled.

....if I am reading this correctly.

Douglas,

I consider an industry consultant as someone who is part of the oil industry, though consultants may see themselves as outsiders.

Not sure what the secret sauce is in the recipe, but from a physics perspective I would agree with your perspective.

I imagine Conoco drills its wells in the sweet spots as their average Eagle Ford well looks like it will be about two times the EUR of the average Eagle Ford well for all producers in the basin.  Seems the claim that wells are recovering 2 times the oil in place as before is highly unlikely, seems to be a case of wishful thinking or investor hype.

Edited November 2, 2019 by D Coyne

[D Coyne + 305]

Douglas,

Average Eagle Ford wells from all operators chart below, for 2017 well perhaps 275 kbo at most, compared to 600 kbo (just doing simplistic straight edge extrapolation, which I realize will tend to overestimate EUR) for Conoco 2017 Eagle Ford wells (previous chart).

Edited November 2, 2019 by D Coyne

[Boat + 1,324]

Year after year productivity keeps rising. Doesn’t this debunk the o’l tier 1, tier 2, tier 3 promise of tight oil demise? 

[Boat + 1,324]

On 10/29/2019 at 12:20 PM, J.R. Ewing said:

You seem to have difficulty understanding that the weekly EIA data is not data.  It is based on surveys, opinions, guesses, etc. and made up by bureaucrats.

A 800,000 barrel difference between the current EIA estimates and the last actual data reported is not minutia.

Thanks in advance for trying to be more accurate with your future posts.

It’s popular to deride the poor EIA even though they have been proven to be very accurate if you just wait a month or two for revisions. Why folks can’t wrap their heads around that is a mystery.

[Rob Kramer + 696]

D Coyne - I have no numbers to add to this input but shell uses natural gas to make their synthetic oil it's in their pennzoil platinum brand also. How much they sell I have no idea and I haven't seen other brands advertising using natural gas to oil but I think it will become more popular. On sale its 28$/5L not on sale 46$ CAD . 

[CMS 0]

On 10/28/2019 at 10:21 PM, Jabbar said:

YES .

You stand corrected.

Uh, trick question. Oil goes into tanks when it comes out of the ground. Not barrels. So no, you’ve never seen it. No matter what you claim.

[Section37 0]

1 hour ago, CMS said:

Uh, trick question. Oil goes into tanks when it comes out of the ground. Not barrels. So no, you’ve never seen it. No matter what you claim.

Somebody should tell you about a barrel test...

[PE Scott + 563]

5 hours ago, D Coyne said:

Douglas,

I consider an industry consultant as someone who is part of the oil industry, though consultants may see themselves as outsiders.

Not sure what the secret sauce is in the recipe, but from a physics perspective I would agree with your perspective.

I imagine Conoco drills its wells in the sweet spots as their average Eagle Ford well looks like it will be about two times the EUR of the average Eagle Ford well for all producers in the basin.  Seems the claim that wells are recovering 2 times the oil in place as before is highly unlikely, seems to be a case of wishful thinking or investor hype.

In the Eagle Ford specifically the one big change I've seen is greatly increased injection rates. Where we used to run guar systems at ~60 bpm, now I'm seeing rates as high as 120 bpm with HVFR. Obviously, treating pressures are higher and ideally the fracture length should be greater.

I'm not privy to all the production data though, so who knows what's working or if it's working better. I think double the EUR is a big stretch though.

Edit: I'll go a step further and say that, from my experience, the focus hasn't been on driving productivity from a single well. Instead, it's been on cutting cost to complete that well while trying not to decrease EUR. For most wells, this means using less expensive chemicals (FR or HVFR vs Gel), running less expensive proppant, running only a single type of proppant (100 mesh usually), and of course multi-well pads. More and more produced water is being used. I even did a frac with a xlink gel in loco hills recently that was 100% produced water. They had to run pH buffer at the highest set point I've ever seen, but it worked.

Edited November 3, 2019 by PE Scott

[Douglas Buckland + 6,308]

Are people basing the EUR on these tight well’s rates during say the first 2 years of production? If so, the calculated EUR is meaningless due to the eventual drastic declines in production.

[D Coyne + 305]

14 hours ago, Boat said:

Year after year productivity keeps rising. Doesn’t this debunk the o’l tier 1, tier 2, tier 3 promise of tight oil demise? 

Boat,

See 2017 and 2018 for all of Eagle Ford, pretty much the same.

Edited November 3, 2019 by D Coyne

[D Coyne + 305]

9 hours ago, Douglas Buckland said:

Are people basing the EUR on these tight well’s rates during say the first 2 years of production? If so, the calculated EUR is meaningless due to the eventual drastic declines in production.

Douglas,

I agree, though typically the daily vs cumulative lines tend to be parallel in a given basin. generally the function is not a straight line so any assumption that it is will tend to overestimate EUR.  Typically I fit an Arps hyperbolic to first couple of years of data, then assume when hyperbolic gets to 10% effective annual decline rate that terminal decline from that point is at 10% per year with well shut in at 5 to 10 b/d output (depends on oil price assumption for scenario).  For 2016 Eagle Ford average well, I get an EUR about 230 kbo with 5 bopd at end of well life and a 12.5% terminal decline assumption after 9 years (cumulative output at 207 kb at that point).

14 hours ago, Boat said:

It’s popular to deride the poor EIA even though they have been proven to be very accurate if you just wait a month or two for revisions. Why folks can’t wrap their heads around that is a mystery.

Boat,

Weekly EIA data is never revised, only the monthly and annual data is revised.

Edited November 3, 2019 by D Coyne