Why do oilfields take damage when production is paused?

[Coffeeguyzz + 454]

Artificial lift - red headed step child in the OFS world that it may be - will start to loom larger in the reporting of hydrocarbon happenings as the EFFECTIVE adopters/implementers in this rapidly evolving field stand to benefit the most when new drilling/completing activities come screeching to a halt.

The past 2 years have seen a steady shift to gas lift AL in the Bakken with sub categories described as 'plunger assisted' gas lift, 'gas lift assisted' plunger lift, plain ol' 'gas lift'. I do not know enough to confidently describe in detail the differences in these approaches other than to say different companies seem eager to 'label' their hardwares/techniques and so to market to  an expected large future base of customers.

Bakken operators now regularly use 500,000 cubic feet per month per well for 'other than flaring/selling" purposes ... aka onsite consumption.

In addition to fueling onsite compressors and generators (as needed), this natgas is going back downhole for AL purposes.

Now, it starts to get interesting as several companies are touting gas lift to address not merely the historical vertical lift properties (really neat advances introduced with the  newer valves and monitoring processes), but the LATERALS are now being targeted with several novel approaches ... the 'tube within a tube' being just one.

Essentially, if this stuff works (I make no claims that it will, but I would never bet against necessity-fueled innovation), sand issues related to ESPs, problems regarding capital infusions to shut ins will be tied into new production (more on that in a moment), future flexibilities/capital allotment/EURs, physical properties of long (>12 month) dormant wells, yada, yada ... this current nightmare may well be viewed in retrospect as another inflection point in the never ending history of the Oil and Gas industry.

More on elevated formation pressure, gas lift AL, 3 Bakken Kraken wells for illustrative purposes in next post.

(Like Mr. Smith, I cringe when long posts get 'lost' in transmission.

[Gerry Maddoux + 3,627]

26 minutes ago, Coffeeguyzz said:

The following is from my decade long observations of this 'Shale Revolution' with a somewhat granular look at 3 recent Bakken wells from Kraken.

Would the Bakken wells from Kraken happen to be the Knox-Ruby LW#1H and so on, Sections 16, 17, 20 &21--T158N-100W?

If so, would you please widen the scope of your comments?

Thanks. 

[Gerry Maddoux + 3,627]

3 minutes ago, Coffeeguyzz said:

More on elevated formation pressure, gas lift AL, 3 Bakken Kraken wells for illustrative purposes in next post.

Ah, I see that it is coming. 

I have a small stake in those recent Kraken wells, if they are in those tracts. 

[Coffeeguyzz + 454]

From Mr. martinrylance's excellent post (gotta love Engineer-speak, no?) ...

"... Average reservoir P* which will not be the original PR unless EOR has been taking place and water injection has been injected at a VRR of 1.0"

"Other than during initial flowback (post frac) i.e., soaking/imbibation which is a very specific case ... there is no real reason that relative perm values should be changed (note this soak/imbibation ONLY occurs post completion) ..."

For the past 3 years or so, several Bakken operators seem to have nearly completely eliminated historical flowback wherein the first week or so post fracturing, massive amounts of the injected fluid is/has been somewhat rapidly 'drained'.

Operators have now been maintaing much (all?) of the hundreds of thousands of barrels of fluid underground in a gradual drawdown extending several months.

This elevated formation pressure is directly tied into the descriptions (as I understand them) from Mr. martinrylance wherein higher formation pressure is 'pushing' hydrocarbons into the wellbores for many, many months post frac.

The 3 Kraken wells in the Burger field in Divide county (way out in Bumfuck Egyptville), are STILL producing ~1,000 barrels of water per day 4 months after the completion.

The declining profile of this 'produced' water clearly shows that it is NOT 'normal' produced water.

(233,000 barrels, 255,000 barrels, and 269,000 barrels from the Red, White, and Blue wells respectively total 'produced' water volumes after 4 months. Unable to find initial injection volumes).

Essentially, these operators are not only using the artificially induced elevated pressure to enhance current production, when these guys go back into the shut ins in the future, installing new hardware (gas lift especially), thorough clean out, topside enhancements, are all to be expected and - in fact - will be the precursors to much higher ultimate recovery from these old producers as they are brought back online coincident with new wells D&C on the same pad.

[nsdp + 449]

I still have my old training manuals from when I started at Amoco.  They are Primer of Oil and Gas Production vol.1  Available from the Petroleum Extension Service, University Station  Austin TX 78712. Copy right 1976, A primer of Oil well drilling  fourth Edition copyright  1977 (for you Doug probably from before you started)) and Work Over  and Oil Well Service and Workover  Both are available from the Petroleum Extension service at University of Texas.  Mine are 40 years out of date but the more modern should be available at the Extension Service.  Very basic materials. https://executive.engr.utexas.edu/petex/index.php

Edited April 24, 2020 by nsdp

[Gerry Maddoux + 3,627]

^

I don't think I am smart enough to follow what you're saying, Mr. Coffee.

I must say, however, that it has been disturbing to me when I saw all shale basins and operators lumped together in the past. I have interests in ND, Co, Ok, Tx and it has been my gut feeling that these guys in the Bakken Basin were an unusual breed of cat. Seemed like they have a whole bunch of tricks up their sleeves. Plus, it seems to me that they are really getting to understand their basin too, with its many quirks.

I felt the same way with the Codel/Niobrarra but the governor really soured anyone from working there. 

I have quite a bit of acreage in Divide county ND, but was disappointed that the shale is thinner out there. Is this up north?

thanks again.

[Coffeeguyzz + 454]

Mr. Maddoux 

Permit #s 36650/1/2 ... Blue 26-35 1TFH/White 23-14 1H/Red 22-15 1H.

All Burgur field, Kraken operator.

From what I've seen, Kraken - along with Slawson - might be excellent 'canaries in the coal mine' as they are ultra nimble, scrappy, small operators who seem quick to embrace potentially promising technologies.

While Slawson is sitting atop some of the best rock in the US, Kraken has far flung properties ranging from oil-drenched to 'what are we doin' here? status.

This tier 2 (3?) Burgur field being one good example. It is located just a bit north of the Williams county line and pretty much mid point east/west. 

If you (or anyone) is pretty serious about learning about the Bakken, getting the ~50 buck annual subscription  fee from the ND DMR is well worth it.

I had a subscription for years.

In addition to having access to the ongoing wells' status (production profile, active/inactive, lift, etc ), the multi hundred page well files are available  ... including the origional geologist's drilling report which notes the thickness of the different formations.

Wonky stuff to be sure, but highly data filled for a serious student in these matters.

Edited April 24, 2020 by Coffeeguyzz

[Gerry Maddoux + 3,627]

Both Kraken and Slawson have produced good wells where I have small slices. But I'm mostly in Williams, McKenzie, Dunn and Mountrail west of the Nissen anticline. 

I'm not sure tier designation has anything to do with production: My best property in Dunn was designated Tier 3 when I bought it and my best property in Williams was designated Tier 2. 

Seems unusual to get a lot of water cut as far west as Divide County. Most of my problems have been east of the Nissen anticline. Actually, I'm beginning to think that some of the best property to have is that Divide stuff, but not for the usual, rather for the Red River Formation, which is pretty oil-soaked. 

Thanks, bud, for helping me understand this.

[Ward Smith + 6,615]

7 minutes ago, Gerry Maddoux said:

Both Kraken and Slawson have produced good wells where I have small slices. But I'm mostly in Williams, McKenzie, Dunn and Mountrail west of the Nissen anticline. 

I'm not sure tier designation has anything to do with production: My best property in Dunn was designated Tier 3 when I bought it and my best property in Williams was designated Tier 2. 

Seems unusual to get a lot of water cut as far west as Divide County. Most of my problems have been east of the Nissen anticline. Actually, I'm beginning to think that some of the best property to have is that Divide stuff, but not for the usual, rather for the Red River Formation, which is pretty oil-soaked. 

Thanks, bud, for helping me understand this.

If I understand @Coffeeguyzz That isn't really "water cut". 

Normally you inject a massive amount of frac water and sand, along with soap and maybe biocide. The usual method was to immediately produce that water (with some of the sand back and initial oil). It sounds like the savvy operators are skipping that step and just leaving the frac water in the formation, to gradually come with the oil. Sounds brilliant to me. I'm guessing they did it the other way to diminish handling costs and quickly get rid of the stuff in disposal wells. Now they have to "handle" the water and fines for longer, but the benefit is increased Downhole pressure for longer. 

[Coffeeguyzz + 454]

Mr. Smith 

Your description is correct.

This entire 'elevated formation pressure' situation actually goes back several years.

In 2013 or so, a suit from Kodiak mentioned production uplift from offsets when new wells were fractured.

About a year ago, a suit from Whiting shone a little more light on this completely non discussed topic when he described 'parent well uplift' which describes parent wells showing increased production (along with big increase in 'produced' water) when new wells are completed.

Bruce Oksol, on his 'themilliondollarway' website has discussed this for years and gave it the term 'halo effect'.

 

It is both a chrystal clear phenomenon to anyone willing to spend a little time going over Bakken well profiles combined with location identification (Gis map), well file histories, and nearby offset completion timing.

I did it for about 150 wells with maybe 120 showing obvious, sometimes dramatic, increase in output.

Anyone can do this for themselves to verify.

 

Mr. Maddoux, interesting that you mention the Red River as there has been significant acgivity targeting the RR in recent years.

So much so that the ND DMR folks have been agitating the USGS to publish an updated assessment as they (the DMR folks) feel the big boost in TRR projections will encourage future investments.

Which touches upon a related, virtually never mentioned topic ... the vast, vast expansion of potentially (key word there) viable hydrocarbon regions that will come into consideration with all this technological progress that has emerged in unconventionals these past few years.

From the Clinton Sandstone, Trenton Black River, TMS, Uinta,  on and on.

Lottsa hydrocarbons out there.

Sorry, Greta.

[Gerry Maddoux + 3,627]

Okay, now I get it. Thanks to you both. Yes, I knew they were doing that----I am very sensitive about a fairly extensive acreage in Divide County that stretches from the southern end to the north right up against Canada. I've been waiting years for the world to catch up to it and what with has been happening just thought the worst without analyzing it much. I miss Mr. Oksol quite a bit--though I must confess that I didn't ever fully understand what he meant by the halo effect . . . I thought he just meant improved production of the parent well when children wells were fracked.

I have fairly extensive holdings in the Bakken and have felt for the last several years that the small, scrappy operators just have it nailed up there. Crescent Point has developed some good wells for me, but I have a half-dozen operators up there that have been swell to me (including Whiting, which just went into Ch 11). Coming out of this godawful downturn, I believe the Bakken Three-Forks wells will become much more economical, as the acreage is so cheap, the IP is huge, the decline is less steep (especially with ethane gas-lifting) and there is less methane gas . . . at least that's the way I see it when I compare it to the Niobrarro/Codel, Granite Wash and Eagle Ford. 

[Ding Ray Chung + 8]

Mr Coffee,

I am sorry in advance about the lay questions, but I am not sure I understand your points.

1. If current practices keep the formation pressure elevated, wouldn’t that circumvent the need for artificial lift? The way the situation is, in the next few years only the low cost producers will survive. Artificial lift, with needs to install pumps and gear for tens of thousands of sub-1kbd wells does not seem a very economical way of doing things. But if the formation pressure is high, then why is that needed?

2. Your point about child wells boosting the parent is very interesting, but goes against everything I have read on the subject. Everyone else I’ve read talks about "canibalizing" the parent. Can you provide some links regarding the effect that you describe.

 

thanks!

[D Coyne + 305]

23 hours ago, Coffeeguyzz said:

There have been some great contributions on this thread.

 

The following is from my decade long observations of this 'Shale Revolution' with a somewhat granular look at 3 recent Bakken wells from Kraken.

General cost to Drill and Complete (D&C) an 'unconventional' well can range from under $3 million for ~5,000 foot laterals in the Niobrara (mononbore drilling playing a big role) to well over $10 million for various Permian Basin efforts.

Several Bakken operators now state ~$5 million to D&C, with Marathon claiming a recent 4 well/pad operation coming in at ~$4.3 million per, IIRC.

To depict an "average" cost is both fruitless and counterproductive, I believe.

This stance - eschewing "averages" - has been but one of a long string of differences between Dennis and myself.

Basin by basin, formation by formation, operator by operator, well by well ... if these vast differences are not recognized and taken into account, false conclusions will be projected from fundamentally flawed originating premises.

 

In a nutshell, to address Mr. Faber's original post and incorporating several of the excellent contributions upthread, it would seem reasonable to me that operators will immediately  curtail production in the unconventional world. (Continental has just announced this).

Looking forward, operators may incorporate new well D&C with a sharp eye on maximizing the expected FUTURE production profiles of the now shut in wells.

Incorporating artificially induced formation pressure (might want to look again closely at Mr. martinrylance's second post) along with the several excellent - and accurate - comments regarding reworking/artificial lift conditions associated with re-opening shut-ins, I will post a follow on comment on what might be expected regarding the status of thousands of now - or soon to be - unconventional wells taken offline.

 

Coffeeguyzz,

Mr Smith gave intitially what the average well produced, then later told me he was talking about the Bakken.  So I used Bakken average well output, I know you only like to talk about the top 1% of wells as far as performance.  The reality is that all the wells that have been drilled have to be paid for.  I used the well costs that Mr Smith gave an my calculations.

Also I include all costs for a well not just drilling and completion.  There are costs for the land, pad, gathering lines, storage tanks, and plugging at the end of the well's life.  It is the way a proper economic analysis is done.

[D Coyne + 305]

23 hours ago, Ward Smith said:

@Coffeeguyzz, I think you and I are in the same page and if D is Dennis I agree even further

Way back when I was in computer science in university I had a prof who said, "Never mistake data for information". This about 4 decades ago, and it's only gotten worse, not better. I just spoke with one of my experts, now retired who worked for one of the majors. We spent about an hour discussing all of these points. He reiterated that anything less than 600 bbls/day of oil was considered a dog well. I asked about shaleprofile's numbers and he said, "I can't comment if I don't know how and where they got their numbers". I agree with you coffee that once data gets normalized by averaging, all the information is probably lost. 

As for Continental Resources, we'll soon have real data on what massively shutting down active producers does in the real world, and hopefully from that data can suss out some information about whether it's a good or bad idea. 

Ward,

The shaleprofile site uses data from the NDIC for individual wells for North Dakota reports on the blog.

I will note that you gave output for first second and third year, was that for a single well rather than an average of most wells.

I agree having specific data on all producing wells is best, perhaps on a daily basis, but that is a lot of information to digest.

You should check out shale profile, the data is excellent, despite Mr. Coffee's misgivings.

https://shaleprofile.com/

then click on blog

Edited April 25, 2020 by D Coyne

[D Coyne + 305]

22 hours ago, Coffeeguyzz said:

Mr. Maddoux 

Permit #s 36650/1/2 ... Blue 26-35 1TFH/White 23-14 1H/Red 22-15 1H.

All Burgur field, Kraken operator.

From what I've seen, Kraken - along with Slawson - might be excellent 'canaries in the coal mine' as they are ultra nimble, scrappy, small operators who seem quick to embrace potentially promising technologies.

While Slawson is sitting atop some of the best rock in the US, Kraken has far flung properties ranging from oil-drenched to 'what are we doin' here? status.

This tier 2 (3?) Burgur field being one good example. It is located just a bit north of the Williams county line and pretty much mid point east/west. 

If you (or anyone) is pretty serious about learning about the Bakken, getting the ~50 buck annual subscription  fee from the ND DMR is well worth it.

I had a subscription for years.

In addition to having access to the ongoing wells' status (production profile, active/inactive, lift, etc ), the multi hundred page well files are available  ... including the origional geologist's drilling report which notes the thickness of the different formations.

Wonky stuff to be sure, but highly data filled for a serious student in these matters.

Coffeeguyzz,

I imagine Enno Peters uses that for his Bakken data, or he may get the $175/year subscription, I don't know.

[Coffeeguyzz + 454]

Mr. Chung

The following is offered up with deepest apologies ahead of time to engineers and professionals everywhere who may understandably go down another beer at the simplistic, incomplete depiction that follows ...

Mr. Chung, there are at least 2 distinct physical properties involved here ... gravity and pressure (specifically our ol' buddy Delta P, i.e., pressure differential).

Take, if you will, a pressurized soda bottle that is frequently used to describe original-state hydrocarbon wells.

Now, make this bottle into the shape of a cylinder, say 2 foot long/1 inch diameter, and lay this cylinder on its side.

Now, insert a rigid, clear straw into one end of our cylinder so that everything is still enclosed (able to hold elevated pressure).

Now, place this 2 foot long, 1 inch diameter cylinder  - with affixed straw - into a bathtub-like container that is 90%filled with sand, balance being water.

This bathtub has a lid on top that - crucially - not only moves up/down slightly (like a membrane), but it can ALSO hold pressure.

Prick about 1, 600 teensy weensy holes in our cylinder.

Now, place your hands atop the 'lid' of our bathtub and gently push down.

Push down harder.

What you may see, Mr. Chung, is a small amount of water now rising up in the vertical 'straw' as the water-in-the-bathtub has been 'pushed' into our originally-empty cylinder and up , slightly, into the vertical straw.

The gas lift approach in the field will 'aerate' our water-filled straw making it more able to overcome gravity along with a near-venturi-like effect to assist in the vertical travel of our water. (Jet pumps in the field rely mainly upon this venturi effect as fluid is employed. Story for another time, perhaps).

So, Mr. Chung, the gravity principal is surmounted with the fluid - water in our example - being aerated and brought to the surface by the innate principle of pressurized gas flow.

 

Returning to this intriguing 'elevated formation pressure/driving hydrocarbons-into-the-wellbore' topic (gotta keep Delta P in mind), our original bathtub 'pressure' might be related to the weight of our original 'lid'.

The more you push down upon the lid, the more 'drive/pressure' will exist to get the water into our tube. (Let us set aside the - hopefully - clear explanation of our gravity-defying gas lift ... with one related caveat ... the reduced internal pressure of our straw/cylinder gizmo as our injected gas is now 'sucking' up the water inside the cylinder and - in fact - might be creating a microscopically small 'vacuum' relative to our outside-the-cylinder, yet inside-the-bathtub apparatus.

The more you push down on the lid, the more impetus for the water to enter the cylinder.

The more pressure that arises from pumping hundreds of thousands of barrels of water into the formation from 1,000 feet away (horizontally), from new completions from nearby offsets, the more 'push' into our wellbore will exist for our hydrocarbons.

 

Mr. Chung, in the real world, our cylinder is about the size of your fist ... 4 inches in diameter.

It extends about the length of 30 football fields (10,00 feet).

In addition, it goes UP about the height of 10 Empire State buildings (10,000 feet).

Did I mention that this steel tubing is about the size of your fist?

The ~1,600 tiny (~1/4 inch) pinpricks are what a 5 perf, 1 cluster per 30 feet standard Bakken well has.

These guys have been doing this for over 10 years, battling physics, economics, competitors in various industries, technologies, countries, and the seemingly ubiquitous foes dressed in Polar Bear costumes waving posters.

 

And still, they stand.

 

[Coffeeguyzz + 454]

Mr. Chung 

Quick follow up regarding your questions ...

Yes, retrofitting thousands of older wells will be more than a small challenge.

At least two factors may influence the operators' decisions ... how much product may ultimately be recovered ... and how much MORE recovery might be obtained by inserting the necessary hardware (gas lift specifically), at the outset with new wells in contrast - as always - to the anticipated financial returns.

Regarding your point #2 ... I have always found it fascinating that so little has been put forth on this topic ('halo effect'/'parent well uplift) as the results are overwhelmingly obvious to anyone willing to spend the time and see - for themselves - the public production/completion data that is readily available.

One perspective comes to mind, and it relates to EQT's experience the Very. Next. Day after they anmounced the stupendous 24 hour IP from the legendary Scotts Run Deep Utica well (72 MM cubic feet from a 3,200 foot lateral) ... EQT's stock dropped over 7%.

Reasons?

Who knows? But strong speculation was that when Mr. Market realized that ANOTHER massive gaseous resource existed below the Mighty Marcellus - a century's worth of cheap, abundant fuel -  it might be tough to tout your product as an expensive, scarce resource.

I have no clear explanations for many of these matters and - like you and several others - continue to approach these topics with as open minded a perspective as is possible.

 

[Coffeeguyzz + 454]

Dennis

Not going to distract from people's time - including yours and mine - on this fine Saturday in regards to our ... differences ... in this Hydrocarbon World other than to note these points ...

"I know you only like to talk about the top 1% of wells as far as performance", so sayeth Mr. Coyne.

So, naturally, any input from moi is in disrepute as my 'bias' - as inaccurately professed by Mr. Coyne - precludes serious consideration.

In a somewhat similar vein, your cavalier dismissal of even LOOKING at Gail Tverberg's outstanding analysis vis a vis the operational shortfalls of increasingly higher use of wind-derived electricity (a view, btw, PROVEN by the disastrous recent history from South Australia!!!) might prompt a disinterested observer to look at Dennis Coyne's inherent prejudices.

You are clearly a bright guy, Dennis, who has displayed - to me -  a near-unbroken history of high integrity inquisitiveness.

As I have shown - in my final postings on your site - Enno Peters'data is outstanding with at least one HUGE caveat ... the numbers are compiled/displayed on a CALENDAR (specifically MONTHLY)  basis, NOT an online, per production day framework.

When you now have wells - as I had shown with the specific cohort from EOG - that are ONLINE only 70% of the time, it is absurd to attempt to make geologically-based assumptions without AT LEAST being aware of the true production (i.e., online) history.

Enno does outstanding work and the data from his site can be incredibly useful. (Only site of which I am aware that publicly differentiates Upper Devonian, Point Pleasant, Utica formations from Marcellus, as just one example).

But to continue to project future potential based on a fundamentally flawed premise will ensure that, say, come 2030, you all will continue to be sayin' " Runnin' out soon, guys. Any day now!"

Srsly, you could/would do much better if you were able to set aside Mr. Patterson's ancient, oh-so-true adage of "Believing to be true that which one desires to be true".

[Mike Shellman + 548]

3 hours ago, Coffeeguyzz said:

These guys have been doing this for over 10 years, battling physics, economics, competitors in various industries, technologies, countries, and the seemingly ubiquitous foes dressed in Polar Bear costumes waving posters.

 

And still, they stand.

"They've" been battling economics alrighty; they've destroyed hundreds of billions of dollars of capital, sucked all the life out of shareholder equity and will NEVER be able to pay their approximately $300 billion of  long term debt back. 85% of America's shale oil companies now have impaired reserve assets worth significantly less than what they owe, making them basically insolvent. Who, exactly, is "still standing?" Continental? Even mighty EOG can only borrow more capital thru junk bonds at this point. You must have just gotten back from a vacation to Jupiter, Coffee. The price of oil in North Dakota is south of zero.

The US shale oil phenomena is a study in socialized capital gone completely haywire. Believing in its continued sustainability ignores reality. Reality as in where is the money going to come from to fund it?  More socialized capital from the Federal government? 

 

 

 

[D Coyne + 305]

On 4/25/2020 at 4:22 PM, Coffeeguyzz said:

Dennis

Not going to distract from people's time - including yours and mine - on this fine Saturday in regards to our ... differences ... in this Hydrocarbon World other than to note these points ...

"I know you only like to talk about the top 1% of wells as far as performance", so sayeth Mr. Coyne.

So, naturally, any input from moi is in disrepute as my 'bias' - as inaccurately professed by Mr. Coyne - precludes serious consideration.

In a somewhat similar vein, your cavalier dismissal of even LOOKING at Gail Tverberg's outstanding analysis vis a vis the operational shortfalls of increasingly higher use of wind-derived electricity (a view, btw, PROVEN by the disastrous recent history from South Australia!!!) might prompt a disinterested observer to look at Dennis Coyne's inherent prejudices.

You are clearly a bright guy, Dennis, who has displayed - to me -  a near-unbroken history of high integrity inquisitiveness.

As I have shown - in my final postings on your site - Enno Peters'data is outstanding with at least one HUGE caveat ... the numbers are compiled/displayed on a CALENDAR (specifically MONTHLY)  basis, NOT an online, per production day framework.

When you now have wells - as I had shown with the specific cohort from EOG - that are ONLINE only 70% of the time, it is absurd to attempt to make geologically-based assumptions without AT LEAST being aware of the true production (i.e., online) history.

Enno does outstanding work and the data from his site can be incredibly useful. (Only site of which I am aware that publicly differentiates Upper Devonian, Point Pleasant, Utica formations from Marcellus, as just one example).

But to continue to project future potential based on a fundamentally flawed premise will ensure that, say, come 2030, you all will continue to be sayin' " Runnin' out soon, guys. Any day now!"

Srsly, you could/would do much better if you were able to set aside Mr. Patterson's ancient, oh-so-true adage of "Believing to be true that which one desires to be true".

Coffeeguyzz,

I don't think number of days online changes the analysis much.  Using well profiles based on the data from shaleprofile and completion rates for the Permian basin, the model matches actual output data basin wide with an R squared of 0.9995 from Jan 2010 to Jan 2019.

The data may not be perfect, and there may be wells here and there that are off line 30% of the time, I would think this points to problem wells or possibly well that had bad completions and needed to be reworked, I doubt many of these companies would be profitable if on average there wells were down 30% of the time.

At some point we will need to find alternatives to fossil fuel, and you are correct that some of my past predictions have proved pessimistic (did not realize how big the tight oil resource might be) while others have proved optimistic.  The prediction of future prices has been a particular problem for me.  Note that an oil price scenario matching the steo to Dec 2021 and then the AEO 2020 reference oil price scenario from 2024 to 2050 (straight line estimate from Dec 2021 steo to June/july 2024 aeo) has a US tight oil URR of about 90 Gb.  Mike Shellman thinks my estimate is ridiculously large, while you might think it absurdly low.

[D Coyne + 305]

22 hours ago, Mike Shellman said:

"They've" been battling economics alrighty; they've destroyed hundreds of billions of dollars of capital, sucked all the life out of shareholder equity and will NEVER be able to pay their approximately $300 billion of  long term debt back. 85% of America's shale oil companies now have impaired reserve assets worth significantly less than what they owe, making them basically insolvent. Who, exactly, is "still standing?" Continental? Even mighty EOG can only borrow more capital thru junk bonds at this point. You must have just gotten back from a vacation to Jupiter, Coffee. The price of oil in North Dakota is south of zero.

The US shale oil phenomena is a study in socialized capital gone completely haywire. Believing in its continued sustainability ignores reality. Reality as in where is the money going to come from to fund it?  More socialized capital from the Federal government? 

 

 

 

Mr Shellman,

Consider the following hypothetical, all tight oil companies go bankrupt in the current crisis and the debt is wiped off the books, You get hired by a billionaire to evaluate good prospective existing wells and potential PUD reserves in some tight oil play you are familiar with (maybe Midland basin, not sure where you operate mostly).  Assume oil prices have risen to $70/bo and seem relatively stable.  If you were running the show, is there a way tight oil could be developed profitably in your opinion, at some price level (I am guessing that $70/bo might do it, you likely have a better guess than me.

Note that I agree none of this works at $40 to $50/bo, if oil prices remain at that level or lower over the long term, it seems tight oil may be done for.

[Ding Ray Chung + 8]

1 hour ago, D Coyne said:

Debt wipe-out does not factor much, except for acquiring DUCs for less than the cost to drill them. If you’re acquiring just acreage assets out of BK administrators, then you still need capital to drill and frac. The Q you’re asking is "can you get decent return on capital in the conditions you describe, with $70 stable price."

The answer would be YES, but who can guarantee stable $70/bo price? 

Mr Shellman,

Consider the following hypothetical, all tight oil companies go bankrupt in the current crisis and the debt is wiped off the books, You get hired by a billionaire to evaluate good prospective existing wells and potential PUD reserves in some tight oil play you are familiar with (maybe Midland basin, not sure where you operate mostly).  Assume oil prices have risen to $70/bo and seem relatively stable.  If you were running the show, is there a way tight oil could be developed profitably in your opinion, at some price level (I am guessing that $70/bo might do it, you likely have a better guess than me.

Note that I agree none of this works at $40 to $50/bo, if oil prices remain at that level or lower over the long term, it seems tight oil may be done for.

 

[D Coyne + 305]

1 hour ago, Ding Ray Chung said:

 

Mr Chung,

Nobody can guarantee stable $70/bo price, I should have said more than $69.99/bo, the idea is that there are a bunch of operating wells that will be temporarily abandoned by bankrupt tight oil companies and wells recently completed, and DUCs, all will be available at fire sale prices along with leases that may be able to be renegotiated at more favorable terms.  A smart operator like Mr Shellman, with a billion dollars to back him up could make a killing and actually produce the oil profitably.

All theoretical as Mr Shellman, though very successful no doubt, may not be a billionaire, nor am I.

[Mike Shellman + 548]

2 hours ago, D Coyne said:

Mr Shellman,

Consider the following hypothetical, all tight oil companies go bankrupt in the current crisis and the debt is wiped off the books, You get hired by a billionaire to evaluate good prospective existing wells and potential PUD reserves in some tight oil play you are familiar with (maybe Midland basin, not sure where you operate mostly).  Assume oil prices have risen to $70/bo and seem relatively stable.  If you were running the show, is there a way tight oil could be developed profitably in your opinion, at some price level (I am guessing that $70/bo might do it, you likely have a better guess than me.

Note that I agree none of this works at $40 to $50/bo, if oil prices remain at that level or lower over the long term, it seems tight oil may be done for.

I am not allowed the luxury of what if's, Dennis; I am required to deal with reality 24/7. "If" your scenario were to come true and all debt was wiped clean, say from the Midland Basin, and the price was guaranteed $70,  my advice to my client would be to stay out of the shale oil business. Get out, stay out and never come back.

No oil price can ever be guaranteed; it's a world oil market, not an American market. Even at $70 my client would still be dependent on credit and that does not work...if you've been paying attention, that should be clear. I'd ask him why in the hell he thinks he can borrow more capital going forward. Productivity is waning already in the Midland Basin and as producers move off onto flanks, economics will get worse. As that basin declines, GOR goes up,  gas is the metric to use, not oil; can your gas, Mr. Client, compete with APP Basin gas? No. Then there is water for frac use and water for disposal. It's a desert, sir and all that tremblin' is problematic. There is also American politics to deal with in the future, and liberal dumb asses that can't think past next week. There are a dozen other reasons I would say to my client to bury his money in the back yard with the dog bones. 

For Americans who can't stand the thought of not having shale oil in their lives, best prepare for nationalization. That's the ONLY way it works going forward. Good luck with that. 

 

 

[D Coyne + 305]

2 minutes ago, Mike Shellman said:

I am not allowed the luxury of what if's, Dennis; I am required to deal with reality 24/7. "If" your scenario were to come true and all debt was wiped clean, say from the Midland Basin, and the price was guaranteed $70,  my advice to my client would be to stay out of the shale oil business. Get out, stay out and never come back.

No oil price can ever be guaranteed; it's a world oil market, not an American market. Even at $70 my client would still be dependent on credit and that does not work...if you've been paying attention, that should be clear. I'd ask him why in the hell he thinks he can borrow more capital going forward. Productivity is waning already in the Midland Basin and as producers move off onto flanks, economics will get worse. As that basin declines, GOR goes up,  gas is the metric to use, not oil; can your gas, Mr. Client, compete with APP Basin gas? No. Then there is water for frac use and water for disposal. It's a desert, sir and all that tremblin' is problematic. There is also American politics to deal with in the future, and liberal dumb asses that can't think past next week. There are a dozen other reasons I would say to my client to bury his money in the back yard with the dog bones. 

For Americans who can't stand the thought of not having shale oil in their lives, best prepare for nationalization. That's the ONLY way it works going forward. Good luck with that. 

 

 

Thanks Mike,

Interesting, my guess is that someone will find a way to make it work,but likely I am wrong. So your best guess scenario would be no future tight oil completions by anybody that is as smart as you about the oil business?  That is a shame, there's a pretty large resource which might be viable at higher oil prices.