Shale Oil will it self destruct?

DanilKa · July 18, 2019

38 minutes ago, Rasmus Jorgensen said:

@DanilKa

What is your take on shale in Mexico? I know PEMEX will be main road block, but do you have an idea of quality of the resource and access to water etc?

I haven’t seen quality shale (TOC, clays, phi and k) from there yet. Water is location-specific; won’t be a problem in Veracruz but may be an issue in Reynosa.

Falcon · July 18, 2019

12 hours ago, Wastral said:

That and about 2 Trillion in foreign money pouring into the USA during the financial crisis looking for a "safe" 😎resting spot. The oil patch was at the right time in history to benefit.

It's quite simple.

All used to be worried about peak SUPPLY. The world was running out if oil.

All now are worried about the peak DEMAND . The world has too much oil.

One simple fact.

Business models and investment were all based on $100 + oil price. Very few saw what was coming.

CAN'T TURN BACK THE CLOCK.

DanilKa · July 18, 2019

5 minutes ago, Falcon said:

No not everything.

I don't believe anything you write.

Baker Hughes did the reservoir estimates. Have you heard of them ?

I know BHGE, just haven’t heard they are in reserves business.

Worked in Bahrain, have my sources.

It’s easy to remove me from your feed - no hard feelings, won’t miss anything

Falcon · July 18, 2019

3 minutes ago, DanilKa said:

I know BHGE, just haven’t heard they are in reserves business.

Worked in Bahrain, have my sources.

It’s easy to remove me from your feed - no hard feelings, won’t miss anything

They are a service Company (FULL SERVICE) if you don't know.

See ya ! Bye . . . Bye . LOL

Never been on your feed. Why would I do that ?

Edited July 18, 2019 by Falcon

DanilKa · July 18, 2019

28 minutes ago, Falcon said:

They are a service Company (FULL SERVICE) if you don't know.

See ya ! Bye . . . Bye . LOL

Never been on your feed. Why would I do that ?

That’s how you do this:

Falcon · July 18, 2019

2 hours ago, DanilKa said:

That’s how you do this:

When you lose the debate go home to Mommy. LOL

D Coyne · July 18, 2019

On 7/17/2019 at 10:45 AM, Mike Shellman said:

Thanks, Dennis. Berman's opinion as to LTO as a percentage of total.

Hi Mike,

I guess Mr Berman uses a different tight oil estimate.

See page below and look for "tight oil production estimates by play". The EIA has 7368 kb/d in April 2019 for US tight oil output.

https://www.eia.gov/petroleum/data.php

Berman's estimates don't match up with the EIA numbers. Note that the 914 table 1 gives us total US C+C output and Gulf of Mexico output, but no tight oil estimates. For EIA estimate, Bakken is 1372 kb/d, Eagle Ford is 1213 kb/d, Permian is 3403 kb/d, Niobrara is 508 kb/d, and all other plays had output of 877 kb/d, Berman's estimate is about 874 kb/d less than the EIA estimate.

He may have better information than the EIA.

Thanks.

In either case whether it is 53% or 60% (I mistakenly used May 2019 rather than April 2019 in my first calculation for tight oil percentage) tight oil is a significant portion of total US output. Also tight oil is responsible for 97% of the increase in US C+C output from Dec 2005 to April 2019, based on the EIA tight oil estimates.

Edited July 18, 2019 by D Coyne

D Coyne · July 18, 2019

On 7/17/2019 at 1:28 PM, Falcon said:

You make numbers up.

Falcon.

I do make numbers up for future production, it is a guess.

For the past I look at trends using a simple least squares fit on output data. For the past 7 months the average annual rate of increase for Permian tight oil output has been 338 kb/d (using linear trend on data from Nov 2018 to May 2019), the linear trend from Jan 2017 to Dec 2018 for Permian output data was an average annual increase of 1555 kb/d each year. The past 4 months the annual rate of increase in Permian output has been 1100 kb/d. I cannot predict the future rate of increase.

D Coyne · July 18, 2019

On 7/17/2019 at 2:53 PM, Falcon said:

Yes, other parts of the world.

Every knows of Argentine Vaca Muerta

Some in the know say it could be more productive than Permian. Lots of logistics problems. Availability of enough water and sand, pipelines, etc.

Like all shale there is a learning curve before can fully exploit.

An huge shale opportunity and little talked about is Libya. All in addition to their conventional. Est over 100 Billion BBL.

Little Bahrain who had nearly ZERO oil now has est 80 Billion BBL in shallow offshore. They are negotiating with US Service companies to develop.

Keep in mind the World consumed about 30 billion barrels of C+C in 2018, so 180 billion barrels lasts about 6 years at 2018 rates of consumption. Also the 180 Gb is likely a TRR estimate, the ERR is likely to be about 70 to 80% of TRR, so URR would be about 4.5 years at 2018 rates of consumption, if the estimates are accurate.

In late 2018 Vaca Muerta output for tight oil was about 54 kb/d, this does not really move the needle for World C+C output of 83,000 kb/d.

https://www.rigzone.com/news/wire/vaca_muerta_shale_output_projection_revised-26-oct-2018-157322-article

The article linked above says expected Vaca Muerta growth rates are 7% per year through 2023. If we assume that rate of growth continues for 74 years, they reach US tight oil output levels in 2092.

In 2023 they would reach 75 kb/d of output, not really very impressive.

D Coyne · July 18, 2019

6 hours ago, wrs said:

The Orla section is on 652 only 1 mile east from 652 and 285, the Culberson section is 12 miles due west and 2 miles south of 652. There was never any drilling in the Delaware on the Culberson section but there are still two strippers on the Orla section which at one point had about 10 in the Delaware. XOM drilled a dry hole into Cherry Canyon back in 1987 and tossed the top lease to some other outfit but held the deep rights.

The Culberson wells are pretty good and the geologist has always liked that section according to my independent. He claims there are 110 million barrels under that one section. I think we have one of the oldest Wolfcamp A wells out there. It's first production was 5 years ago yesterday and through April it has produced 358k bbl of oil. In May it produced 2779 bbl with peak production in Sep 2014 of 18,500 bbl. Here is the chart I made of it's production from the RRC data I downloaded. I estimate it's good for another 5 years and 60k more barrels which are all free cash-flow by now. I think this is the point at which shale wells are going to produce a lot of profit for their owners, it's still making 82 bbl /day. How does that compare to all those shallow wells that were drilled out there in the 70s and 80s?

Any idea what the economics of that well is, how much was the total capital cost of the well including land cost. The average Permian basin well in 2017 when fitting a hyperbolic to first 24 months of output might have about 282 kb cumulative output after 60 months. So your well is much better than average (the average well in 2014 was probably much worse than the average 2017 well, about 149 kb after 60 months).

The problem for the industry, is that most of the completed wells do not look like your wells, well profile of average 2014 Permian well in chart below EUR=212 kb after 15 years, assuming the well is shut in at 8 b/d (240 barrels per month).

wrs · July 18, 2019

That well was very expensive to drill because the operator had to sidetrack after drilling 8000 feet. The total cost of drilling and completion was $15m (capitalized cost) but the second well only cost $6m by comparison. This well was a learning experience for the operator but he put it to good use. Even at that, the current per barrel cost of completion and drilling is $42/bbl. There are of course the royalty expenses which I believe for him run about 20% so multiplying by 1.2 gets us to $50/bbl. Finally there are the normal lifting, transport and storage costs which tend to be around $15/bbl on top of that. This gets us to $65/bbl breakeven but the well hasn't played out and should produce about 60kbbl over the next 5 years. At that point the well will have produced 408kbbl and so the breakeven price drops to $60/bbl.

The second well was drilled 3 years later and has produced 241kbbl in 15 months which is a capitalized cost of $25/bbl. I come up with an average decline rate of 3.3% per month (assuming exponential decline) on the first well which I can assign to the second well. In that case by 5 years the second well will have produced 455kb oil for a capitalized cost of $13/bbl. The lease for that half the section cost him about $1m because he had to re let it from us due to the fact that he didn't drill soon enough in the primary and lost any deeper depths on the east side. The Woflcamp falls off to the east and so in order to hit the sweet spot he needed to do another lease in 2017 before he could drill that side. He sat on our lease for four years and the first lease he got dirt cheap in 2010 for abou $375k total. So he paid about $1m for the lease on the Wolfcamp A horizon for our section. Including that additonal expense he is at a capitalized cost of $15/bbl after 5 years. With royalty cost of 20% and assuming a $50 average selling price you get $25/bbl and then you can add on whatever additional lifting and pipeline costs you wish, say $15/bbl and you are at $40/bbl after 5 years. That is a 25% pre-tax profit margin assuming the average $50 selling price over the five year term.

This guy is a profitable producer and so is Cimarex. I think XTO probably is too. Volume is very important and I think that lumping bad wells together with good wells in an analysis the way you have done is a mistake. These wells are not outliers but the operator does a good job managing his formation pressure with the chokes.

Edited July 18, 2019 by wrs

Ward Smith · July 18, 2019

7 minutes ago, wrs said:

I think that lumping bad wells together with good wells in an analysis the way you have done is a mistake.

I also believe that too much valuable information gets lost in excessive "averaging". Not just completed wells, but when analyzing companies you're looking at wells being drilled in the same breath as wells completed and other wells depleted.

Average Bill Gates' net worth with 1000 homeless people and they all "average" as millionaires. Averages rarely tell the whole story

wrs · July 18, 2019

8 minutes ago, Ward Smith said:

I also believe that too much valuable information gets lost in excessive "averaging". Not just completed wells, but when analyzing companies you're looking at wells being drilled in the same breath as wells completed and other wells depleted.

Average Bill Gates' net worth with 1000 homeless people and they all "average" as millionaires. Averages rarely tell the whole story

The other thing overlooked by almost every analysis of "breakeven" I have seen on this board is that there is no accounting for the fact that this is a declining cost of goods sold product. What that means is that there are initial production costs that are amortized over the life of the product and as volume of goods sold increases, the cost per unit drops. Most of the analysis I have seen from the shale skeptics assumes some nonsensical fixed value for the cost of goods sold. A declining cost of goods sold business is good to be in, Bill Gates knows all about that.

Edited July 18, 2019 by wrs

Falcon · July 19, 2019

23 hours ago, D Coyne said:

Keep in mind the World consumed about 30 billion barrels of C+C in 2018, so 180 billion barrels lasts about 6 years at 2018 rates of consumption. Also the 180 Gb is likely a TRR estimate, the ERR is likely to be about 70 to 80% of TRR, so URR would be about 4.5 years at 2018 rates of consumption, if the estimates are accurate.

In late 2018 Vaca Muerta output for tight oil was about 54 kb/d, this does not really move the needle for World C+C output of 83,000 kb/d.

https://www.rigzone.com/news/wire/vaca_muerta_shale_output_projection_revised-26-oct-2018-157322-article

The article linked above says expected Vaca Muerta growth rates are 7% per year through 2023. If we assume that rate of growth continues for 74 years, they reach US tight oil output levels in 2092.

In 2023 they would reach 75 kb/d of output, not really very impressive.

Good info.

Vaca Muerta, 7% next few years sure. All basins start out slow. Big oil reluctant to jump in South America countries. plus they have all they can handle in U.S. GoM and shale.Each has different characteristics. Exxon bought into Vacation Murray years ago and done little. Exxon just starting to ramp this year. It's coming along slowly for now.

I first heard about Permian potential February 2013. Everyone back then thought only productive basins would be Bakken and Eagleford. They completely ignored Permian.

Edited July 19, 2019 by Falcon

James Regan · July 19, 2019

The latest doomsday prediction from a Brahan Seeer type.

When will the USA take responsibility for its negligent actions with its “own” regional oil policy. It’s ironic that whenever the numbers come out for US oil from anyone of the lounge lizzarding US organizations they always refer to OPEC, do these organizations really think OPEC are going to bend over and take one for Team USA?

Team USA needs to take a look in the mirror and accept a horoscope reading from the rest of the world that OPEC know the latest US regional oil play is a one sided arrogant deal which will come back to haunt them with vigor.

OILPRICE QUOTE- Weak demand and rising supply are creating a perfect storm heading into 2020. The IEA said that the “call on OPEC” could fall by 0.8 mb/d next year, and even that is based on the agency’s rather optimistic demand growth figures.

D Coyne · July 19, 2019

13 hours ago, Falcon said:

Good info.

Vaca Muerta, 7% next few years sure. All basins start out slow. Big oil reluctant to jump in South America countries. plus they have all they can handle in U.S. GoM and shale.Each has different characteristics. Exxon bought in years ago and done little. Exxon just starting the end of this year to ramp. It's coming along slowly for now.

I first heard about Permian potential February 2013. Everyone back then thought only productive basins would be Bakken and Eagleford. They completely ignored Permian.

I too missed the Permian potential back in 2013, there was not a lot of buzz about it, the action at that time was Bakken and Eagle Ford. As oil prices tanked in 2015 the focus moved from Eagle Ford to Permian basin and the growth has been significant, but new well EUR has stopped growing when we normalize for lateral length (see shale profile for free reports on this).

https://shaleprofile.com/blog/

"The 4 Major US Tight Oil Basins Update"

Enno Peters does excellent work.

At low oil prices (WTI 62/bo or less) Permian basin tight oil output will peak at about 5.25 Mb/d in 2026, for the higher price AEO reference oil price scenario the Permian basin tight oil output might reach 7.45 Mb/d by 2028, but that will be the peak and falling output in other US tight oil plays (excluding the Permian basin) will more than offset rising Permian basin output from 2025 to 2028 (with an increase over that period of only 250 kb/d in Permian basin tight oil output from Dec 2025 to Dec 2027) so the peak for US tight oil output for the AEO 2018 reference oil price scenario may be 2025. In a low oil price scenario (WTI at $62/bo or less) the peak occurs earlier in 2022 and the peak output is lower due to poor economics at lower oil prices.

James Regan · July 19, 2019

8 minutes ago, D Coyne said:

I too missed the Permian potential back in 2013, there was not a lot of buzz about it, the action at that time was Bakken and Eagle Ford. As oil prices tanked in 2015 the focus moved from Eagle Ford to Permian basin and the growth has been significant, but new well EUR has stopped growing when we normalize for lateral length (see shale profile for free reports on this).

https://shaleprofile.com/blog/

"The 4 Major US Tight Oil Basins Update"

Enno Peters does excellent work.

At low oil prices (WTI 62/bo or less) Permian basin tight oil output will peak at about 5.25 Mb/d in 2026, for the higher price AEO reference oil price scenario the Permian basin tight oil output might reach 7.45 Mb/d by 2028, but that will be the peak and falling output in other US tight oil plays (excluding the Permian basin) will more than offset rising Permian basin output from 2025 to 2028 (with an increase over that period of only 250 kb/d in Permian basin tight oil output from Dec 2025 to Dec 2027) so the peak for US tight oil output for the AEO 2018 reference oil price scenario may be 2025. In a low oil price scenario (WTI at $62/bo or less) the peak occurs earlier in 2022 and the peak output is lower due to poor economics at lower oil prices.

Why are we seeing posts and news which seem to follow the same topic which is one of debt and bad fiscal policies, this is not just a Shale problem it’s mirroring offshore.

S.P. "Chip" Johnson, IV, President and CEO at Carrizo,

“As the shale basins continue to mature, it has become evident that large co-development projects represent the optimal development strategy. We believe that size and scale drive the efficiencies that are critical to this strategy and the long term success of an E&P company.”

“The combination of Callon and Carrizo should form a stronger company with positions of scale in the Permian Basin and Eagle Ford Shale, providing an extensive runway of high rate-of-return drilling locations and the potential to realize meaningful synergies and generate significant free cash flow,” Johnson added.

The cash-flow holy grail could in theory prompt increased M&A activity across the shale patch.

After oil prices crashed in the fourth quarter of 2018, many independent producers trimmed their spending budgets for this year, but investors continue to be unconvinced that they will see steady healthy returns.

While the largest players, including supermajors Exxon and Chevron, are expanding their Permian presence and aim to grow production volumes significantly over the next few years, small, third-tier exploration and production companies have been struggling even when WTI Crude prices were above $60 a barrel.

Some small players who have been relying on borrowings to finance drilling are now finding themselves in a position to look for options to restructure debt, including by seeking Chapter 11 bankruptcy protection.

Tomasz · July 19, 2019

If you talk about future shale oil formations in other countries I suggest reading about Bazhenov Formation in Western Siberia - it needs a quite a higher price environment but look on gigantic potential technically recoverable resources according to EIA.

https://en.wikipedia.org/wiki/Bazhenov_Formation

Quote

According to U.S. Energy Information Administration estimates published in June 2013, the total Bazhenov shale prospective area has a resource of a risked tight oil in-place of 1,243 billion barrels (1.976×10¹¹ cubic metres) and a risked shale gas in-place of 1,920 trillion cubic feet (54 trillion cubic metres), with 74.6 billion barrels (1.186×10¹⁰ cubic metres) of oil and 1,920 trillion cubic feet (54 trillion cubic metres) of gas as the risked, technically recoverable.^[8] Total hydrocarbon resources are estimated in 50 to 150 billion tonnes.^[3]

Sometimes in next decade with chinese engagement Gazprom Neft plans to start production and its said you can produce here even up to 8 milions barrels per day in distant future..

https://de.reuters.com/article/russia-oil-shale-gazpromneft-idAFL4N23O1J0

Edited July 19, 2019 by Tomasz

specinho · July 20, 2019

Ian Austin · July 21, 2019

On 7/15/2019 at 6:46 AM, BenFranklin'sSpectacles said:

I'll make this simple for you:

1) Oil production is ongoing and costs money.
2) Discovery of new reserves is ongoing and costs money.
3) The people discovering new reserves won't want to invest in discovery if they already have decades of reserves. The future is unpredictable that far out. Thus, they'll set a target for how much reserve they need. If reserves fall short, they'll increase discovery activities. If reserves get too large, they'll pare back discovery activities.

Thus, it's inaccurate to say the US only has X years of oil. We don't know that. What we do know is that we've discovered quite a bit, it's probable we'll discover more, and no one can say exactly how much that is. Predictions of doom are unnecessary.

By that argument, you could replace the US with (insert country here) and make the same argument. Is your position that we will have more oil than we need for generations?

Tommie77 · July 21, 2019

On 7/15/2019 at 3:22 PM, Douglas Buckland said:

How do you 'explore as needed'? Do you think that exploration, in and of itself, yields reserves? Exploring is just what it says, you are looking for something with no guarantee that you will find it.

You then extrapolate your previous misconception and say, "Thus, reserves are continually being replenished."

Most exploration is performed by seismic studies. You really can not determine a meaningful 'reserves' number unless you then drill the prospect and test it.

Exploration drilling, generally speaking, has been on hold globally due to the price of oil and the volatility of the price since the present slump took hold.

Seismic studies and exploration drilling are expensive with the risk of not findind any reserves which are volumetrically and financially feasible in today's market.

Finally, I would like to know what fracking has to do with reserves? Does fracking somehow increase the original oil in place? When do you assume fracking started? The hydraulic fracturing process and technology has been utilized for at least the past 50 years!

Reserves are not only about STOIIP.

More efficient and/or effective fracking can (of course) increase reserves, e.g. because costs go down (and lower quality rock can be exploited) or economic breakeven rates are reached after higher cumulative production. There is of course a limit to this.

It seems that companies are no longer improving the productivity of their wells. On the other hand, I don’t have insight into their drilling / fracking cost. These may still be declining. Does anyone have recent data?

I am overall sceptical about the economic viability of US unconventional oil and gas. Low interest rates definitely plays a role in it’s substantial growth. Interesting to see big players moving in. Interested to see how it will unfold.

BenFranklin'sSpectacles · July 21, 2019

3 hours ago, Ian Austin said:

By that argument, you could replace the US with (insert country here) and make the same argument. Is your position that we will have more oil than we need for generations?

Per my previous comment, my position is that we don't know how much oil the US has and, therefore, shouldn't use proven reserves to predict shale's longevity.

DanilKa · July 21, 2019

On 7/20/2019 at 8:42 AM, Tomasz said:

If you talk about future shale oil formations in other countries I suggest reading about Bazhenov Formation in Western Siberia

Bazhenov is indeed THE source rock for entire Western Siberia but its a complicated play. Maturity and butumen content is an issue. It is also located in tectonically relaxed basin, meaning there is no stress containment. In fact when I frac'd Upper Jurassic, Bazhenov was my upper stress barrier. Achimov formation on top of Bazhenov may be of greater interest.

This is not to discard Bazhen - this thing produced oil w/o fracturing at Samotlor field; shale got cracked when by huge amount of organics in it generated oil.

James Regan · July 22, 2019

SHALE DOOMED - OILPRICE

With financial stress setting in for U.S. shale companies, some are trying to drill their way out of the problem, while others are hoping to boost profitability by cutting costs and implementing spending restraint. Both approaches are riddled with risk.

“Turbulence and desperation are roiling the struggling fracking industry,” Kathy Hipple and Tom Sanzillo wrote in a note for the Institute for Energy Economics and Financial Analysis (IEEFA).

They point to the example of EQT, the largest natural gas producer in the United States. A corporate struggle over control of the company reached a conclusion recently, with the Toby and Derek Rice seizing power. The Rice brothers sold their company, Rice Energy, to EQT in 2017. But they launched a bid to take over EQT last year, arguing that the company’s leadership had failed investors. The Rice brothers convinced shareholders that they could steer the company in a better direction promising $500 million in free cash flow within two years.

Their bet hinged on more aggressive drilling while simultaneously reducing costs. Their strategy also depends on “new, unproven, expensive technology, electric frack fleets,” IEEFA argued. “This seems like more of the same – big risky capital expenditures.”

EQT’s former CEO Steve Schlotterbeck recently made headlines when he called fracking an “unmitigated disaster” because it helped crash prices and produce mountains of red ink. “In fact, I'm not aware of another case of a disruptive technological change that has done so much harm to the industry that created the change,” Schlotterbeck said at an industry conference in June.

IEEFA draws a contrast between Schlotterbeck and the Rice brothers. While the latter wants advocates a strategy of stepping up drilling in an effort to grow their way out of the problem, the former argues that this approach has been tried over and over with poor results. Instead, Schlotterbeck said that drillers need to cut spending and production, which could revive natural gas prices.

But while the philosophies differ – relentless growth versus restraint – IEEFA argues that “neither of these strategies seem viable.” On the one hand, natural gas prices are expected to stay below $3 per MMBtu, a price that is unlikely to lead to profits, IEEFA says. That is especially true if shale companies aggressively spend and produce more gas.

However, a strategy of restraint may not work either. “[E]ven if natural gas producers coordinate their activities and reduce supply—a highly unlikely prospect—Schlotterbeck’s expectation that natural gas prices would inevitably rise is questionable,” IEEFA analysts wrote.

The upshot is that while companies like EQT undertake a major shift in strategy, the road ahead remains rocky either way. “More bankruptcies are all but certain as oil and gas borrowers must repay or refinance several hundred billion dollars of debt over the next six months,” IEEFA concluded.

Cherry picked to make the point.

James Regan · July 24, 2019