How many drilling sites are left in the Permian?

[Christopher Ryan Robinson + 3]

For me, this is the $64,000 question.  When I hear all the prognostications, I always wonder.  Thoughts?

[Douglas Buckland + 6,308]

Christopher,

An excellent question. I just read an article which mentioned that the newer drilling locations are getting further and further from the 'trends'.

This makes sense as the rational operator would have drilled the 'sweet spots' first for financial reasons.

This would make you assume that each new well, drilled further and further from the trend (sweet spot) would have an incremental drop in productivity potential.

When your production decline curves are already frightening in the 'sweet spot' wells, this would be a grave concern.

[Christopher Ryan Robinson + 3]

Thanks for the input, Douglas.  There just seems to be so many wild predictions that I'm curious if any detailed analysis has been done.  Are we 20,40,60% tapped?  Who knows.  

[AcK + 50]

I have been thinking/wondering about the same thing - but from a much wider top-down angle.

Looking at the data - slide 22 - (and I dont know how good/bad it is cause US reserve numbers are all over the place), US reserves of 42bn bbls and production of ~11mn bbls now (crude oil, not counting NGLs et al of which plenty is there supposedly) - or 4bn bbls of consumption annually. Does that mean US will run out of oil in 10-odd years. That does not seem right?

@Tom Kirkman

[Jan van Eck + 7,558]

58 minutes ago, AcK said:

I have been thinking/wondering about the same thing - but from a much wider top-down angle

 Does that mean US will run out of oil in 10-odd years. That does not seem right?

 

The USA is not about to run out of oil any time soon. It has huge reserves of oil sources, including "oil-sands" bitumen and lots and lots of coal.  Both are readily extracted and convertible into oil and gasoline by mature technologies. Then there is oil trapped in shale, and there is shale near or underneath all the legacy oil sites.  My guess is that the USA has another 500 years' worth of oil out there to be conquered.  Might have to pay $130/barrel for it, though, but that is a political consideration. 

[Old-Ruffneck + 1,177]

On ‎4‎/‎18‎/‎2019 at 2:48 PM, Christopher Ryan Robinson said:

For me, this is the $64,000 question.  When I hear all the prognostications, I always wonder.  Thoughts?

https://seekingalpha.com/news/3415135-permians-delaware-basin-2x-bigger-midland-usgs-survey-says

This article is from 12/8/18. The Permian alone is 86,000 sq miles and there is a lot of newer discoveries that are in some time get drilled. Some is easy, some not worth drilling at even 65.00bbl. Some more not even at 110.00bbl. Technology is getting better at discovering oil but on the mechanical side to get out of the ground, even todays modern rigs still best left in the ground. So no real answer to how many wells will be drilled in the next 3-4 year. Rig counts are dropping, I think 485 rigs operating in the whole Permian. Not for the lack of oil, but lending practices over the last 6 years+ has made a volatile predicament. A helluva lot of operators owe hundreds of millions of interest payments alone and you can't borrowing on promissory notes. The crash of 2013-2014 was a very fast forgotten lesson. @Tom Kirkmancan probably gather actual numbers, but even at 65.00 lenders are getting skittish.

[Tom Kirkman + 8,860]

@Old-Ruffneck WTI is a different animal than Brent.

I still maintain that from what I have observed, a suitable balance between most global oil producers and most global oil consumers is around $70 Brent.

WTI is trickier, due to the burden of the neverending hamster wheel of debt that finances much of U.S. tight oil.

$50 WTI still seems to me to be around the centerpoint of the price See Saw for U.S. tight oil.  $65 WTI is too high, in my opinion, which will likely result in WTI price crash by this Summer, as an over-reaction to WTI price and production at too high levels.

If Brent can stay in the neighborhood of $70 and WTI stay below $60, then I can see oil prices staying relatively stable for a while, for the rest of this year.

But if either Brent or WTI prices get too high, then beware, the oil price rollercoaster will likely start up again.

[Old-Ruffneck + 1,177]

2 minutes ago, Tom Kirkman said:

@Old-Ruffneck WTI is a different animal than Brent.

I still maintain that from what I have observed, a suitable balance between most global oil producers and most global oil consumers is around $70 Brent.

WTI is trickier, due to the burden of the neverending hamster wheel of debt that finances much of U.S. tight oil.

$50 WTI still seems to me to be around the centerpoint of the price See Saw for U.S. tight oil.  $65 WTI is too high, in my opinion, which will likely result in WTI price crash by this Summer, as an over-reaction to WTI price and production at too high levels.

If Brent can stay in the neighborhood of $70 and WTI stay below $60, then I can see oil prices staying relatively stable for a while, for the rest of this year.

But if either Brent or WTI prices get too high, then beware, the oil price rollercoaster will likely start up again.

Yes, I would tend to agree with 52 Permian and 68 Brent. As you point out we have in the past 10 years seen some dramatic rollercoaster pricing. I am guessing that at 64 today, they are trying to recoup some Capital but I've really a feeling it's too late, and there are going to be pace of bankruptcies slow in next couple months, then increasing. @Mike Shellmanmight be able clue us in on this. Just a feeling...….

[Tom Kirkman + 8,860]

6 hours ago, Old-Ruffneck said:

Yes, I would tend to agree with 52 Permian and 68 Brent. As you point out we have in the past 10 years seen some dramatic rollercoaster pricing. I am guessing that at 64 today, they are trying to recoup some Capital but I've really a feeling it's too late, and there are going to be pace of bankruptcies slow in next couple months, then increasing. @Mike Shellmanmight be able clue us in on this. Just a feeling...….

We seem to be pretty much on the same page, then.

In another thread, someone is trying to convince me that $100+ oil is a good thing.  I do *not* agree.  I understood their viewpoint and their argument, but nope, I have a different viewpoint (which I have stated ad nauseum about $70 Brent.) 

My concern is Oil Traders and Oil Producers are starting to get too greedy, and are going to throw this lovely oil price recovery out of whack.

Even the Saudis seem happy lately with $70 Brent. Why choke the oily golden goose with greed, and go on another crazy rollercoaster ride?

[Mike Shellman + 548]

Thanks, Mr. Roughneck. The short term investment cycle of US shale oil and the unfettered use of borrowed capital, or deferred debt at +6% interest rates, to drill that stuff has now made medium range price predicting next to impossible. So, I don't. For drilling budget purposes a wide price range is necessary but economics must work on the low end of the range. Hope for higher prices is a bad business plan. I am expecting $52 Cushing, in fact, by August. 

Nothing has improved much financially for the US shale oil industry, in spite of higher well productivity. When 75% of the wells one drills annually is necessary for reserve replacement, and to pay interest, how does one deleverage debt and/or grow? They don't. Not without borrowing more money. Hope to be bought out is not much of a business plan either and I agree, 2020 is going to see some big guys go down and lots of debt, gone. If this Chevron deal goes thru the jefes at APC will likely get falling down drunk with joy the night of closing; Anadarko had $15B of debt, paid +$800MM in interest in 2018 and had a debt to EBITDA ratio of 1.4. Not all of that was shale related... but that sucks. 

One last word, if I may; "500 years of oil reserves in America" is a bad guess and serves no one. We use nearly 18MM bbls. of C+C in our nation every day; that equates to 6.5G bbls. C+C annually. At the end of 2017 we had 36G BO of proven producing reserves in America. Google it. Probable and highly unlikely "possible" reserves (technically recoverable, as yet undiscovered, economical at some unknown oil price) will be incredibly expensive to recover and require trillions of dollars of capital.  The term "peak oil" seems to scare people to death so they dismiss it, or diminish its importance by referring to as running out of oil. That was, and is not what peak oil means. Peak oil means that there is a fear that the world might reach a point in time when affordable oil production levels will not be able to meet demand.

We are there already. The American shale oil phenomena has confused the picture, for some, and gratefully delayed the process of peak oil for all. But it is actually very expensive to extract and not very affordable. If it were, the public and private shale industry in America  would not be $300 billion in debt. As I have said before, the US shale oil industry, at $60 gross/$25 net, will have to produce more LTO than it already has produced the past decade, just to get out of debt. All Americans should be deeply concerned about that. 

 

 

 

 

 

[Jan van Eck + 7,558]

48 minutes ago, Mike Shellman said:

One last word, if I may; "500 years of oil reserves in America" is a bad guess and serves no one.

Since that was my statement, I would respond.  Please note that that includes oil to be obtained from conversion of coal, of all grades, the technology of which is mature.  Germany ran the entire Wehrmacht and Luftwaffe on lube oils and fuels made from coal.  Are such fuels expensive?  But of course. How about oil-sands oils?  Re they likely to be expensive?  But of course.  That said, that does not mean that those oils are not out there, to be tapped (eventually) and used for whatever society decides to use it for, including lube oil and plastics. 

The point I make  (and made) is that the supply is there, not that it would be available at today's costing levels. And I stand by that assessment.  You do likely have 500 years' worth.   But you will have to pay for it. 

[ceo_energemsier + 1,818]

In theory, just about every patch of the Permian could be a production field depending on how many formations are stacked , even a single formation would be considered "a drill site" or a "producing field" subsurface.

The Permian Basin is an oil-and-gas-producing area located in West Texas and the adjoining area of southeastern New Mexico. The Permian Basin covers an area approximately 250 miles wide and 300 miles long and is composed of more than 7,000 fields (best represented in Railroad Commission of Texas production figures as districts 7C, 08, and 8A) in West Texas. Various producing formations such as the Yates, San Andres, Clear Fork, Spraberry, Wolfcamp, Yeso, Bone Spring, Avalon, Canyon, Morrow, Devonian, and Ellenberger are all part of the Permian Basin, with oil and natural gas production depths ranging from a few hundred feet to five miles below the surface. Other areas within the greater Permian Basin include the Delaware Basin and Midland Basin. The Delaware Basin includes significant development in the Bone Spring and Wolfcamp, together known as the Wolfbone. The Midland Basin includes significant development in the Spraberry and Wolfcamp, together known as the Wolfberry. Recent increased use of enhanced-recovery practices in the Permian Basin has resulted in a substantial impact on U.S. oil production.

Given the enormous land mass of the Permian, it boils down to the quality of rock!!! GEOLOGY !!!

Without good geology there can be no production, or dismal production or just about your "stripper" well production of 10bpd or less.

Good geology= good quality rocks in the sub surface that contain high organic matter that results in hydrocarbons (oil, gas, ngls, condensate, natural gasoline etc)

I see all kinds of numbers being thrown out on this forum about how terrible and horrible shale is......

But unless you are doing it right then obviously just like any other business , a very highly technical business that relies on science and technology, you will not be as successful as others or will fail outright. Just like a doctor who has access to medical technology but doesnt apply it well doesnt make that doctor very good in terms of diagnostic understand capabilities and the application and implementation of that to a particular patient's case.

We have all read, heard about and seen hundreds of companies vanish, go under, go bankrupt and cease to exist in the shale patches across the country, a lot of them were fly by the night operations, who thought they could hit a few wells and be millionaires. Others backed by debt financing leveraged their potential reserves, only to find out that the quality of their rock wasnt so good and they overpaid for the leases.

The is highly competitive, risky and extremely technical (not that other oil and gas exploration isnt) as shale is a completely different animal and game than your conventional formations.

There are a lot of aspects of shale successes, some of them

1) Due diligence on the prospect , quality of rocks and the complete and thorough mapping of the subsurface formations, structures and shale layers and total analytical understanding of what each section means.

2) Not over paying for acreage. If companies pay (as they did in the past 10,000-100,000$ an acre and a lot of companies failed)) without proving out the geology , it could very well be a losing game from the start. The cost of acquisition should be reasonable and not be a burden going into a project. In the pre shale boom, companies played the land game than actually playing oil gas production game, buying up hundreds of thousands of acres of greenfield leases for very high prices and then flipping it. I call them lease flippers, they did make money for a time "flipping" and going into JVs with foreign companies as was the case with Chesapeake and CNOOC and Reliance etc , who ended up paying billions of $$ for just leases and at the end they exited these JVs with a very bad taste in their mouths. And look what happened to Chesapeake for a long time.

3) Using all the available technologies and data to create an ultimate picture of the subsurface including geology, petrophysics/geophysics, geochem, petroleum and reservoir engineering and finding and creating a multi tiered rock quality package for drilling. You can have sweetest, sweeter and sweet spots. ( For my own operations, I dont even touch the sweet spots first-- other companies sweet spots are their top tier, for us it the last drill site on the charts, sometimes you balance the drilling between the 3 tiers). 

4) Given that the Permian is a multi faceted geo formation, as it contains shale and non shale, the success rate can be very good if all things that are key are done right.

5) After having identified all the aspects in 3) and 4), next is the choice of drilling services and technologies , again the most advanced and feasible ones to be used that are best suited to those geo conditions, then followed by the testing and if the testing is good and within the criteria of a company, moving onto the production and development phase. Again all highly technical.

 

6) We are seeing costs in the Permian ranging from $30$-$45$/bbl some state it to be in the $48-$55/bbl , while most shale naysayers keep parroting $65-70$/bbl. That was true several years ago.

Another fine example is the Eagle Ford where costs now are down to $24-$35$/bbl

7) Type of funding is also very critical

Just a quick overview.

IN the end technology and science application of how, when and where is the key. Technologies are evolving everyday either brand new, or improvement and enhancement of existing ones, or combining a suite of technologies and application and merging of technologies from other business and industrial sectors.

We are not wildcatting for shale!!!

The major oil companies coming into the Permian are going to change the whole landscape and will more than likely see a lot of M&A's happening and also a lot of companies just exiting because they do not have the capability to do what it takes to be a shale player.

If XOM starts producing 1MMBPD and CVX does 900MBPD , that is a game changer, over time they can be producing more than that.

The Permian is already producing more than the Ghawar field.

Even with the shale well declines (which can be cured to a big degree now), new and better wells will take over. The older wells will be reworked and EOR applied to recover more oil, as only 10-15% of the oil gets recovered. However with new and advanced tech, we can see initial recoveries boost to over 25-35% and secondary recoveries can also match that range.

So there is still so much oil left in those declining older or parent wells that will keep the supply of oil going for much longer when reworked or companies will go back and study the subsurface geo and data and drill and complete better bigger wells.

The Permian has been producing commercially since 1921 and it will keep producing for a lot longer into the future. How much longer? are we going to be around to find out? LOL

 

 

 

Despite recent low crude prices and a significant drop in the DrillingInfo rig count during January, the giant Permian Basin of West Texas and Southeast New Mexico continues to expand its role as the main driver of energy growth in North America. In just the past week, we have seen the following significant events that are attributable all or in part to what has become the world's second most-productive oil and gas resource:

A driver of upstream and midstream profits - Both ExxonMobil and Chevron beat analyst expectations with their 4th quarter earnings announcements, driven mostly by their upstream and midstream developments in the Permian. Exxon beat forecasts by almost one-third, with its full-year 2018 earnings coming in at the highest level since 2014. Driven by its Permian drilling, Chevron's oil and natural gas production rose to an all-time high as the company produced a record 3 million barrels of oil per day (bopd) during the 4th quarter.

A driver of downstream expansion and acquisitions - Early last week, Exxon also broke ground on a major expansion of its Beaumont refinery, a project that will add the capability of processing an additional 250,000 bopd and make it the largest refinery in the country. The new refining train being installed will be fit for processing the light, sweet crude produced in the Permian Basin and other North American shale plays, a growing volume of which must currently be exported in order to be refined. Meanwhile, Chevron confirmed on February 1 that it was acquiring the interest in the Pasadena Refining System owned by Petrobras America Inc. This purchase gives Chevron an additional 110,000 bopd of capacity to refine its own light sweet crude.

 

 

A driver of record domestic production - In its new Annual Energy Outlook released on January 24, the U.S. Energy Information Administration (EIA) now projects in its reference case that domestic crude oil production will rise to more than 15 million bopd by 2022, years before previous projections, and will remain above 14 million bopd through the year 2040. The main driver of this record production? The Permian Basin:

"Growth in Lower 48 onshore crude oil production occurs mainly in the Permian Basin in the Southwest region. This basin includes many prolific tight oil plays with multiple layers, including the Bone Spring, Spraberry, and Wolfcamp, making it one of the lower-cost areas to develop."

 

 

“Recent development in the Permian, driven by favorable economic conditions, is leading the new growth in the North American shale oil market.”

The rise of North American shale represented an enormous success, but the oversupply it created also helped contribute to the downturn. What changes have been made to shale oil operations so far as a result of that low-oil-price environment, what developments can we expect to see going forward, and what role will each basin play in future production? Our North American Shale Oil Outlook to 2025—developed using our North American Supply Model and other proprietary data collected by Energy Insights—explores the answers to these questions in greater detail.

Meanwhile, the EIA's "High Resource and Technology" case projects U.S. domestic production to grow to an even more impressive 20 million bopd by the year 2040. This case may well be the most relevant here since, if we know anything about EIA projections as they relate to the Permian Basin over the past decade, it is that they are constantly having to be revised upwards.

A driver of record exports - In that same report, the EIA also finds it necessary to accelerate its previous projected date for when the U.S. will become a consistent net exporter of crude oil. The agency now projects that that threshold will be crossed in 2020, two full years sooner than it had previously anticipated just last year:

“The United States becomes a net energy exporter in 2020 and remains so throughout the projection period as a result of large increases in crude oil, natural gas, and natural gas plant liquids (NGPL) production coupled with slow growth in U.S. energy consumption.”

Those "large increases in crude oil", as quoted above, are driven mainly by the Permian Basin.

It's important and almost stunning to remember that, just a decade ago, the dusty plains of West Texas and Southeast New Mexico that make up the greater Permian Basin were widely considered to be a "dead area" by most in the oil and gas industry. Major oil companies like Chevron and ExxonMobil had pretty much abandoned any drilling activities or other major capital investments in the region, preferring to focus their capital dollars on searching for oil in more promising parts of the world. In September of 2008, total U.S. oil production was roughly 3.2 million bopd. This month, the EIA projects that the Permian Basin alone will put that much crude onto the market.

Now, just 10 years later, this basin is the hottest oil and gas play on the face of the earth, the driver of energy growth for the world's largest oil and gas-producing nation.

 

Permian poised to drive the shale oil market for the next 10 years

From Q2 2014 to Q1 2016, oil oversupply—in part caused by rising shale oil production—led oil prices to fall 50 percent and the number of active rigs to fall 80 percent. Though the market remains constrained by capital and rig or labor availability, we’ve seen oil prices recover, drilling activity more than double, and key operational improvements enable the shale oil industry to endure through the low-oil-price environment and beyond.

Recent development in the Permian, driven by favorable economic conditions, is leading new growth in the North American shale oil market. The Permian’s initial production (IP) growth rate for the past 5 years was 20 percent—compared to 2 percent in the Eagle Ford and Bakken—and its early development stage means there are more remaining drilling locations to explore. The basin also benefits from an average core breakeven price for 2017 that is less than $41 per barrel, enabling it to stay profitable despite well-cost increases of 30 percent.

As far as operational improvements are concerned, better drilling efficiency, completion design, and high grading have sustained and will continue to drive growth despite the foreseeable cost escalation of 15–25 percent in the next 2 years. Operators have reduced drilling days by 5 days while improving IP by 33 percent from 2014 to 2016. Improved completion design—like those that use higher volumes of proppant—has increased IP by 35 percent, and high grading in each subbasin has enabled operators to continue to drill and produce even considering the current oil price.

Going forward, under our base case that sees WTI at $60–70 per barrel from 2019 onward, we expect drilling and completions (D&C) activity to grow 20 percent per year and production to grow 12 percent per year through 2021. That increased D&C activity will require total capex spend to grow to near 2014 spend levels, and production will have nearly doubled since 2014, reaching around nine million barrels per day by 2025.

 

Edited April 20, 2019 by ceo_energemsier
to add information

[Mike Shellman + 548]

I heard EXACTLY the same spiel five years ago; word for word, and every year since. It never ends; things will always get better... NEXT year. And it almost always comes directly from the shale oil industry itself, or from those who can benefit from it, personally, the most. In early February 2018 the IEA said the shale oil industry was set to turn it around, make oodles of free cash flow. In spite of $65 oil prices in 2018, low costs from squeezed service providers and higher well productivity, only seven public companies eeked out free cash flow and the shale oil industry outspent revenue once again. 

Folks seems quite content with ignoring this industry's financial woes, for whatever personal reasons they might have, and assuming it has legs and is sustainable for the long term. Good luck to America on that. 

 

 

 

Edited April 21, 2019 by Mike Shellman

[Gorizia + 3]

There is obviously a great deal of Shale oil, how much is extracted depends on the price of oil. OPEC+ have cut production by over 2 million barrels per day in order to allow US shale oil to expand while bringing the price of oil up to a price they need.

I know some people think the price of oil is fixed by traders but the reality is traders gamble on the real world and are often wrong.

https://www.reuters.com/article/us-usa-oil-prices/traders-bet-on-oil-at-100-as-iran-sanctions-loom-idUSKCN1ME0C2

After this article was published, one would expect oil prices to go up, if traders really did control the price.

In fact oil prices fell from $85 at the beginning of October down to $50 by Christmas. Why?

https://oilprice.com/Energy/Crude-Oil/Saudi-Oil-Output-Hits-Record-High-In-November.html

https://www.reuters.com/article/us-usa-oil-eia-outlook/u-s-crude-output-to-surpass-12-million-barrels-per-day-by-mid-2019-eia-idUSKCN1NB2F5

Simple really, lots more oil was produced than expected. The traders guessed wrong and lost.

[GuyM + 7]

It's not going to grow much this year. Read Schlumberger, they know better than anyone.

 

The major activity in 2019 will be majors gobbling up independents. They are not exporters, so doubtful that will support huge growth later. Fundamentals change.

Edited April 21, 2019 by GuyM

[Karl Milhon + 1]

Never run out. I still remember at 12 listening to my dad being offered a job as superintendent of the school system for American ARAMCO employees in Saudi Arabia. That would be 1967. I distinctly remember the guy, and engineer exec with Aramco telling my dad that the world would never run out of oil he mentioned the tar sands in Canada.  It was just getting to it.  We also used to travel a lot and my dad asked him about the shale oil research going on around Rifle CO as we were out there most years camping

And now, the oil challenged Japanese are going after methane hydrates the "reserves".of which are essentially unlimited.  

I really believe that 50 bucks a barrel is about a "real" basis for pricing internationally without political manipulation and notwithstanding revolutions or wars that might take out a given amount of supply that would quickly (within months) be replaced.  All else is pretty much BS. 

And so, the concept of peak oil was always fallacious. And now we are at peak demand. 

 

[ceo_energemsier + 1,818]

2 hours ago, GuyM said:

It's not going to grow much this year. Read Schlumberger, they know better than anyone.

 

The major activity in 2019 will be majors gobbling up independents. They are not exporters, so doubtful that will support huge growth later. Fundamentals change.

Major oil companies are not exporters?

Every major oil company and independent producer has set up a trading division just for exports and they are investing a lot of $$$ towards export oriented infrastructure.

The US crude oil exported to Asia and Europe is sold on Brent (dtd) and or other benchmarks for Asia which are higher than WTI. Exporting the Permian, Eagle Ford, Bakken etc crude is netting the exporters 3-8$ sometimes 10$/bbl above WTI!!!!!

[wrs + 893]

11 hours ago, Gorizia said:

 

Simple really, lots more oil was produced than expected. The traders guessed wrong and lost.

There are two sides to every trade and the winners were the shorts in the fall at the expense of leveraged longs.  

[Ian Austin + 131]

2 hours ago, wrs said:

There are two sides to every trade and the winners were the shorts in the fall at the expense of leveraged longs.  

Important point and comment. I feel like many don’t understand that the Futures Market is a zero sum game

[ceo_energemsier + 1,818]

16 minutes ago, Ian Austin said:

Important point and comment. I feel like many don’t understand that the Futures Market is a zero sum game

Futures market is also an insurance risk policy for producers, manufacturers of commodities , like oil, gas , gold, corn, orange juice, soybeans, just about anything... hedging !!!

[Ian Austin + 131]

22 minutes ago, ceo_energemsier said:

Futures market is also an insurance risk policy for producers, manufacturers of commodities , like oil, gas , gold, corn, orange juice, soybeans, just about anything... hedging !!!

Yes....and if they make the right bet, somebody else loses equally. If they’re wrong, it’s somebody else’s good fortune. Also works with unrealized gains/losses.

 Hence zero sum game 

Edited April 21, 2019 by Ian Austin

[Tom Kirkman + 8,860]

42 minutes ago, Ian Austin said:

Yes....and if they make the right bet, somebody else loses equally. If they’re wrong, it’s somebody else’s good fortune. Also works with unrealized gains/losses.

 Hence zero sum game 

In case there are any lurkers unsure about zero sum game.

Zero sum means there can only be winners and losers.  Someone else must lose in order for the winner to win.

 

[ceo_energemsier + 1,818]

Qatar Petroleum issued an invitation to tender for construction of the LNG carrier fleet for its North Field Expansion (NFE) project. The invitation foresees initial delivery of 60 LNG carriers, with the potential to exceed 100 new carriers over the next 10 years. The tender would increase the global LNG fleet by 11-19%. International Gas Union counted 525 LNG carriers at end-2018.

In addition to addressing shipping requirements for NFE, the tender covers shipping requirements for LNG that will be purchased and offtaken by Ocean LNG—a joint venture between Qatar Petroleum (70%) and ExxonMobil (30%)—from the Golden Pass LNG export project in Port Arthur, Tex., which is under construction and planned to start by 2024. The tender also includes options for replacement requirements for Qatar’s existing LNG fleet.

NFE will increase Qatar’s LNG production capacity to 110 million tonnes/year (tpy) starting in 2024 from 77 million tpy. The project will include construction of four new 8.25 million tpy LNG trains, which Qatar Petroleum tendered earlier this month

.

Qatargas will execute the LNG ship building program on Qatar Petroleum’s behalf.

[ceo_energemsier + 1,818]

https://www.hartenergy.com/industryvoice/IHSMarkit?mkt_tok=eyJpIjoiWlRBeU5tVXhaRGd4TVdZdyIsInQiOiJXb0FvS0s3M2hGVzVDSlRlU3N0TGxOXC9MUjB1SStyNzE4eDZNNm90Qm1VOXVUWWx2MlFva2RYZXhneU9zUEFuc1BEelwvcVllWTRGQlFBUHpHemRuMjc2YTZONkVZbjdhN2dcLzlKdkxRQ3hGaUFvVlN4bmRpZUZMaU11QW94WUJzTiJ9

[ceo_energemsier + 1,818]

Oh my oh my, TECHNOLOGY, TECHNOLOGY!!!!

 

____________________________________________________________________________________________________

Artificial intelligence firm gets second funding round for shale

 

Artificial Intelligence (AI) is gaining favor across the oil patch. OAG Analytics, an AI-specialist focused on oil and gas, announced this week it has received a second round of strategic funding from Rice Investment Group. Rice is a $200 million strategy fund based in Pennsylvania that targets oil and gas.

OAG said funding will be used to help customers add AI to the their asset portfolios. Subsurface engineers and scientists use AI to organize data and run billions of simulations before deploying capital, OAG said. OAG’s system provides a cloud-based platform that has interactive visualizations. The technology has already been used in the Permian, Eagle Ford, Bakken, Anadarko and Haynesville shale plays. According to the company, U.S. operators have optimized more than $10 billion in capital expenditures using OAG’s tech.

"Our industry is entering the next phase of the shale revolution by moving to full-field development. As such, we need the next

generation of analytical capabilities to maximize capital efficiency," said Derek Rice, partner at Rice Investment Group and Director at OAG. "Large-scale development optimization requires an in-depth understanding of hundreds of uncorrelated data points, which OAG provides through data management and advanced analytics to support profitable decision making. We are thrilled to partner with OAG's team, and believe our insights and experience as an operator will continue to add value to the platform," Rice said.

OAG was founded by Luther Birdzell, an entrepreneur, data scientist and engineer focused on energy efficiency, AI and self-service machine learning.