[Tanada]

sparky - "...the possible scaling up of unconventionals crude , OK there has been a growth of ~ 2 Mb/d". I don't get your numbers...where did they come from? The EIA shows an increase in US shale production alone of a tad over 4.5 mm bopd at the peak and has fallen about 500k bopd as of the most recent count.

http://www.eia.gov/energy_in_brief/arti ... states.cfm

Given that during a high oil price period the US accounted for almost every bbl of shale production while the rest of the gained nothing worth mentioning I wonder why anyone bothers to hold out hope for global shale boom. If it didn't happen after years of high oil prices and many hundreds of $BILLIONS invested what future price and budgets would be needed for such a global surge?

What about the Vaca Muerta in Argentina? I am under the impression that exploration and development has continued and they will be starting substantial production there within a few months? I also seem to recall that KSA is exploring for shale methane right now as a way to refit their electric grid to burn Natural Gas instead of petroleum?

[sparky]

.
As I've said , all the other non-North America are at the project or pilot stage .
should some sustained output take place then OK
until then it's no more than some flourish

[ROCKMAN]

T - Lots of optimism about the future but not much to brag about today as far as actual production goes:

"In an interview with Bloomberg TV from Buenos Aires, Dudley said BP is planning on acquiring more assets in the Vaca Muerta. And it isn’t just the “enormous potential” from the oil and gas reserves in the shale basin, but also the friendly policy put forth by the new Argentine government led by President Mauricio Macri. “I’m really encouraged by what I see,” Dudley said. “There’s a lot of future here.” BP has a joint venture with Bridas Corp. – BP owns 60 percent of Pan American Energy LLC and Bridas controls the other 40 percent. BP will expand its presence in Argentina through this JV.

Argentina is quickly becoming one of the few countries that has achieved shale development outside of North America. One of the biggest incentives the government has offered is regulated oil prices, set at levels higher than the international price. Several of BP’s peers are already drilling in the Vaca Muerta, including Chevron, ExxonMobil, and Royal Dutch Shell."

Right now the Argentina govt wants to be Big Oil's f*ck buddy. And while companies (especially Big Pubcos) are desperate to add reserves to their books they haven't forgotten the country's history of how they've treated ex-pats in the past.

[AdamB]

Define conventional oil please.

Very good question. Why do we label LTO unconventional when the final product is the same? I'm not an expert, so I ask wikipedia:

These oil sands resources are called unconventional oil to distinguish them from oil which can be extracted using traditional oil well methods

Voilà. If you just drill a well and pump oil from a reservoir where it was accumulated, this is conventional oil.

Wikipedia doesn't know any more about conventional oil than it did peak oil apparently. I remember back in the day when they considered Richard Heinberg an "industry expert" rather that what he really was trained in.

But the question remains unanswered, because of A) your belief that wiki knows much of anything and B) the question, it was about conventional OIL, not the technologies involved to reach it or produce it.

If you have to do anything else to get that oil (like fracking), then it is unconventional. And we can argue about EOR, and if it means that reserves developped with it are unconventional or not...

You aren't described anything about conventional, or unconventional, oil.

Well, I just wanted to put LTO and oil sands apart to see how the "cheap" and "easy" oil is doing right now. And I didn't created this subdivision in the first place. I read frequently that conventional oil peaked 10 years ago, and wanted to understand what it meant and if it was true.

The subdivision was created when peak oil didn't happen as expected, because peak oilers don't know much about petroleum geology. Or economics. So they invented another category so they could say that peaked, in order to make a distinction without a difference to the consumers. Who, at least in America, are now running around appreciating the current glut caused by new supply, regardless of source. Because really, they don't care, and it doesn't matter.

"Conventional" also has a time component, "conventional" oil as defined only by the producing technology used to get it ended in 1901 when the rotary table unleashed spindletop, using a new and more efficient method of drilling than had previously been the primary provider of crude oil.

Peak oilers tend to miss this one as well, because the history of the industry they misrepresent isn't known to them either.

[AdamB]

tita - "Small fields, with reserves of a few millions barrels and rates of less than 10kb/d became also economic to develop with high prices, while they were simply dismissed at the time of they discovery."

Certainly you're not including the US, are you?. We've had hundreds if not thousands of fields that fall into that category.

Tens of thousands according to the Nehring Database Rockman. If I recall correctly, back in the late 90's the Dallas office of the EIA maintained a file of all fields in the US, including some that would knock a history buffs socks off, and that number of fields was >45,000, probably 44,000+ being of the size class being discussed here.

As far as EOR goes it is a great way to pull more oil out of old fields. Which is why it's been applied to the vast majority of fields for 30+ years where it has made economic sense.

Oh, there are more requirements than just making economic sense. Political sense has become an issue as of late as well.

[ROCKMAN]

Adam - And adding to the confusion...from the EIA:

Tight gas (or oil) refers to natural gas (or oil) produced from low-permeability sandstone and carbonate reservoirs."

So how does one classify production from a Permian Basin well drilled horizontally and frac'd in a low permeability sandstone and carbonate CONVENTIONAL reservoir?

[AdamB]

Adam - And adding to the confusion...from the EIA:

Tight gas (or oil) refers to natural gas (or oil) produced from low-permeability sandstone and carbonate reservoirs."

So how does one classify production from a Permian Basin well drilled horizontally and frac'd in a low permeability sandstone and carbonate CONVENTIONAL reservoir?

I attended the most recent EIA conferences and spoken with those folks, they really don't like calling shale production shale production, because of the issues of migration from source rock to a nearby by "tight" formation, such as the Middle Bakken, compared to the upper and lower , which are shale, and the middle which isn't. Shales being low permeability, it really seems easier to just lump shales with tights and call everything tight gas or oil.

So that scheme makes perfect sense in terms of how to differentiate normal production from tight production, WITHOUT getting conventional/unconventional involved. The terms I've heard them use are "discretely reservoired" versus "light/tight oil/gas", skipping the entire conventional/unconventional nonsense altogether. Seems like a reasonable compromise, and recognizes that nobody gives a crap about unconventional/conventional when in fact oil is oil, gas is gas, it is trapped in rocks of all types and permeability, and regardless of the rock it sits in, it can be turned into the products the consumer wants, and in the end that is all that matters.

[rockdoc123]

As I've said , all the other non-North America are at the project or pilot stage .
should some sustained output take place then OK
until then it's no more than some flourish

not the case for the two examples Tanada mentions Argentina and Saudi Arabia. In Argentina the YPF/Chevron project was producing ~55,000 bopd from the Vaca Muerta at the end of 2015. Exxon is busy ramping up wells with an intent to spend $10 billion over the next couple of years. It is early days but moving forwards at a good clip do in part to the fixed oil price of $67/bbl. In Saudi Arabia they are producing gas from tight formations with horizontal fracked wells currently and have a huge effort to accelerate their unconventional natural gas program, the idea being they can replace fuel oil consumption with natural gas.

[sparky]

.
rocdoc , thanks for the upgrade , I'll keep an eye on those .

from the EIA

"http://www.eia.gov/todayinenergy/detail.php?id=19991

Notable shale resource exploration efforts are underway in several countries, including Algeria, Australia, Colombia, Mexico, and Russia. However, commercial shale development of the type demonstrated in the United States requires the ability to rapidly drill and complete a large number of wells in a single productive geologic formation. The logistics and infrastructure necessary to support this level of activity, including the drilling and completion processes, the manufacturing of drilling equipment, and the distribution of the final product to market are not yet evident in countries other than the United States, Canada, China, and to some extent, Argentina. Other above the ground factors such as ownership of mineral rights, taxation regimes, and social acceptance also play a role in decisions regarding the development of shales and other tight resources."

[ROCKMAN]

"...in countries other than the United States, Canada, China, and to some extent, Argentina." In Dec 2014 the rig count in A topped out at 113. In the US at that time: 1,780 rigs. Today 70 in A and 787 in the US. In March 2016: the US rig count was at 476, the lowest in 67 years of since the counting began.

For Argentinian shales to boom like they did in the US they'll need to import about $3 to $5 BILLION in new drill rigs. But XOM, Chevron, et al to have the money.

[rockdoc123]

For Argentinian shales to boom like they did in the US they'll need to import about $3 to $5 BILLION in new drill rigs. But XOM, Chevron, et al to have the money.

That remains to be seen. The Vaca Muerta is very thick but comprised of shales and siltstones and very tight sandstone stringers. It is definitely not the same beast as any of the "shales" in North America. The vertical fracked wells in the VM produce at high rates given it isn't all really low K shales but somewhat low K sandstones and siltstones. That being said to get the same amount of production volume from VM may not take the same intense drilling campaign as we saw in the US. From having looked at all of the unconventionals at one point or another I would say the VM is sitting pretty high up in the realm of best areas to go to.

The stress in Argentina is going to be availability of services related to fracking, no two ifs ands or buts about it.

[ROCKMAN]

"I would say the VM is sitting pretty high up in the realm of best areas to go to." Which begs the question: why only 113 rigs drilling at the height of oil prices? And why isn't the VM producing 3 or 4 million bopd now? The future will be what it will be. But that won't change the current stats: US shakes are producing significant more oil then the VM today. And there are many more rigs still drilling those shales at the current low price then all the rigs drilling in Argentina.

Why don't we table the discussion of the great potential of the VM until it's producing, let's say, a couple of million bopd?

[sparky]

.
Well Argentina certainly has some barrels in production ,
but , again , the rest of the world outside the Americas is nowhere to be seen
that seems strange as russia has the deposits and china has the thirst

[ROCKMAN]

sparky - From Platts in March 2016:

"Argentina's oil production declined 1.6% in January on the year, extending a slide that started in 1998, energy ministry data shows. Crude production dropped to 524,947 b/d in January from 533,261 b/d in January 2015, and was 1.4% less than the 532,228 b/d in December, the ministry said. This means that January's production was 38% less than the record 847,000 b/d in 2004.

"Most of the fields in Argentina are mature and they are declining in production," Alejandro Gagliano, a partner at Giga Consulting, an oil industry consulting firm in Buenos Aires, said Tuesday. "A lot of investment is needed to sustain production."

Argentina ranks #25 in oil production. Just above Malaysia. It currently produces 0.8% of the global oil rate. At the moment the primary hope would be for the VM to halt the 18 year define in Argentina production. Do that first and then we can start talking about the upside of the play.

Always easier to talk about potential QUALITATIVELY then QUANTITATIVELY. A lot more difficult to hype a play when confronted with actual numbers.

So next time oil prices spike up the VM may take off like the Eagle Ford and Bakken did a few years ago. But it didn't happen when oil busted the $100/bbl ceiling last time.

BTW did you know Argentina has been a NET OIL IMPOTER for the last 23 years...as far back as the records go? Again we might want to table the discussion of the huge VM potential until the country actually begins exporting oil.

Just sayin', ya know. LOL.

[rockdoc123]

"I would say the VM is sitting pretty high up in the realm of best areas to go to." Which begs the question: why only 113 rigs drilling at the height of oil prices? And why isn't the VM producing 3 or 4 million bopd now? The future will be what it will be. But that won't change the current stats: US shakes are producing significant more oil then the VM today. And there are many more rigs still drilling those shales at the current low price then all the rigs drilling in Argentina.

Why don't we table the discussion of the great potential of the VM until it's producing, let's say, a couple of million bopd?

there was very little activity in Argentina with respect to oil or gas back when oil was $100 mainly because the country under Christina Kirshner had fixed oil prices at anywhere from $62 to $72/bbl. Companies such as Exxon, Total, Chevron who now have holdings in the VM rightfully dedicated their investment dollars to parts of the world where they were dealing with Brent pricing. They have got more active as of late because the fixed price of $67/bbl (on average) is much higher than the world price. In terms of natural gas the market is a bit strange in Argentina. Prices for industrial gas can be high but the issue is companies producing gas in Argentina are required to provide gas to the local markets during peak season at prices that are ridiculously low (around $1.50/Mcf). Meanwhile the government has been importing gas from Bolivia at around $7/Mcf and at one point were bringing in LNG at prices above $10/Mcf. President Macri is pushing to have natural gas prices rise to around $6/Mcf which will make much of the dry window of the Vaca Muerta much more attractive.

The Vaca Muerta is just one of the unconventional targets, Los Molles shales are another as are some of the tight sandstones above the Vaca Muerta. There are not a lot of rigs available in Argentina (import/export restrictions keep a lot of drilling companies from bringing in equipment they fear may be stranded) and there is little in the way of fracking units for similar reasons. Schlumberger has been reticent to bring in much of the needed logging equipment (tractors for horizontal hole logging, micro seismic tools etc) with similar worries about not being able to get the equipment back out of country. So there are a number of reasons why things have been going slow to this point, but they are gaining momentum.

[sparky]

.
well , I've learned quite a lot on the dead cow ,
it seems to fit in the many reasons why tight oil has not become the great new big thing .

the geology seems OK , the political side suck
I remember articles a few years back on Argentinian politicians making speech on the depletion of their production
and the need to boost exploration , but let it slip out of my mind .

I suppose that's a common issue in a fair few countries with some old production
by the way are you aware the Paris region has been producing oil for decades ?
http://ogst.ifpenergiesnouvelles.fr/art ... _v57n6.pdf
https://www.lundin-petroleum.com/eng/pr ... Europe.php

[ROCKMAN]

Doc "...the political side suck". I've heard stories from insiders about dealing with the Argentina govt that makes dealing with the Nigerians seem like a walk in the park. LOL

[rockdoc123]

Things are definitely improving in Argentina since the Macri government took power. There is even an investigation ongoing into corruption under the former Kirshner government which was fairly rampant.

Macri is pro-business and more centre of left than the former Peronists. Most of the oil folks I know still working down there are pleased with the changes made so far and the promises for further improvements. He does have quite a mess to clean up though.

[tita]

the geology seems OK , the political side suck
(..)
by the way are you aware the Paris region has been producing oil for decades ?

And that the actual minister of ecology (yes, they have that in France, don't laugh) wants to get rid of the small production of oil they have by forbidding any new research permit. This will probably change with the next government.

BTW, you were asking about how high shale oil can ramp up, and what was the possibility of 10Mbbls/d. I made some calculation assuming that legacy production decreases by 50% in a year (which is roughly what we saw last year in US shales), and that new wells peak is 250 bbls/d. To maintain a production of 10Mbbls/d in shale fields similar to US, you need 1600 wells addition per month (which is also roughly the rig count).

Argentina may have a different geology than US. But fast depletion means continous drilling, the higher the production is, the higher the number of drilling has to be. This is the difference I see with conventional reservoirs, which is why I just wanted to put them apart in this post to focus more on what was happening outside US shale and Canada oil sands. Not start a debate about definitions of conventional and unconventional. But thanks to Rockman for his knowledge, which is always interesting.

[Tanada]

As someone who has read a great deal of history including the history of petroleum production and use the fact that definitions are kind of squishy is very disturbing.

For a couple of examples. If you had asked a geologist in 1840 what Petroleum was they would have told you something along the lines of, "A liquid whose name means rock oil that seeps out of the ground in many places on a small scale. The resulting oil which can be anything from a light slightly discolored liquid to a heavy dark colored grease has been used since ancient times as a natural lubricant and occasionally as an ingredient for medicines and ointments."

Flash forward 30 years to 1870 and Petroleum was a substance that seeped from the ground in many places but recently had begun production via drilled shallow wells lowering the price until it had become a popular feedstock to produce Kerosene for lamp oil.

Flash forward 30 more years to 1900 and Petroleum still conventionally produced from shallow drilled wells was mostly used for Kerosene lamp oil but two byproducts Gasoline and Diesel Fuel were starting to find markets as internal combustion engine fuels though these byproducts were still often dumped because they were of such low market value compared to lamp fuel.

Flash forward 30 more years to 1930 and major changes in Petroleum use and production had taken the world by storm. During these three decades deep drilling through hard rock caps had been developed to the point that the shallow pumped wells could hardly compete with geopressured deep wells that would produce gushers if not done carefully and which would produce oil for months to many years without mechanical lifting of any kind depending on how tightly clustered wells were within a naturally pressured reservoir. These self driven wells were very unconventional when the first few were successfully drilled but over the period they had become the majority of the supply and were seen as conventional.

Flash forward 30 more years to 1960 and unconventional offshore drilled wells were the new source on the block starting with shallow water like Lake Maracaibo, Venezuela and advancing steadily to deeper and deeper water. Drillers were also exploring far northern locations like Alaska's north slope and Siberia in Asia but not much had yet come from those efforts.

Flash forward 30 more years to 1990 and a long list of new techniques were in use from directed drilling /horizontal drilling along with ever deeper offshore drilling and the new processing of Athabasca bitumen sands in Alberta on a pilot scale. Various techniques to produce petroleum and gas from tight reservoirs like deep shale beds had been done for decades by at first lowering conventional explosives down well bores to fracture the rock near the well and stimulate production all the way up to detonating low yield nuclear devices in the Atoms for Peace program to cause more extensive fracturing of the formations to cause the petrochemicals to be released. This coupled with the collapse of the USSR and deep cuts in military petroleum demand led to an era of very cheap motor fuel and enough excess Natural Gas that new Gas Turbine peaking electric plants became cost competitive in certain regional applications where gas was abundant and cheap.


Flash forward 30 more years to 2020 Brings us up to the present era. Long cycle cheap oil from 1990-2005 passed into awareness of Peak Oil and rapid price increases with a brief dip in late 2008-early 2009 founding the era of large scale hydraulic fracking of Natural Gas and Petroleum reservoirs that had previously been small scale producers. By 2015 this rapid fracking boom led to a second price crash and decadal scale low prices in early 2016 that remained moderate until 2021 when Demand once again caught up with supply. On the whole the high price oil era really hit in 2007-2008 and 2010-2015 outside of those seven years the era was predominantly one of cheap oil and abundant supply.

We can argue all we want that high prices and limited supply are what we have but in fact outside of those seven expensive years out of the last 30, 23 years of this just past era were abundant cheap oil years.

Also I hope I made my point that the definition of "Conventional" oil has shifted every few decades to include supplies that were previously impossible to exploit or so difficult as to be minor sources in the world totals.

As far as that goes "Condensates" and "Natural Gas Liquids" deliver a lot of Butane which is used as a gasoline blending component in winter and a lighter & grill fuel. LPG/Propane/Butane are used as heating fuel for homes & businesses, cooking fuel and road fuel and dividing them out from Petroleum and Natural Gas just seems asinine to me. A lot of industrial equipment like forklifts are fueled with these components as are most delivery trucks which carry these fuels in compressed liquid form. Conversion of a Gasoline vehicle to run on these fuels is very easy and adding them in moderation to the intake air on Diesel engines can also supply major benefits in terms of emission reduction and combustion efficiency.

How long before hydraulic fracking is the vast majority of reservoir completion method even for many "conventional" reservoir formations and it is seen as "conventional" by people in the industry? 2025? 2030? 2050?

The way I see it Petroleum and Natural Gas including Condensates and NGL should be evaluated or described by the blend of molecular hydrocarbons in their make up, not the old not very scientific descriptions in common use today. My understanding is a molecule like Pentane can be a Condensate in one formation because of the greater heat and pressure in it compared to a second shallower formation where it is defined as Petroleum. It is the same flipping chemical molecule in both cases and is mostly used as a gasoline blending component. At standard temperature and pressure it is a light petroleum liquid and should be defined that way, not by what kind of formation environment it comes from. It is also a component in some Natural Gas Liquids, especially in the very 'wet' wells in some formations but instead of being counted as a Petroleum product it is defined in those cases as a Natural Gas Liquid because in the low pressure and temperature environment on the surface it is a liquid. It still gets used as a gasoline blending component when it comes from a "gas" well so why the silliness of defining it differently and applying different regulations/fees/taxes to it? I prefer a lot more logic in my regulation and tax codes, what is this the bureaucrat full employment definition act? Declare your source is a "Wet gas" well and you pay one set of fees and taxes but define the same well as a Petroleum well and pay different fees and taxes even though you are producing the exact same chemical bland for refining?!? That is regulatory insanity in my opinion. Especially when the owner is the one who defines which type of well they have in production!