Is $60/Bbl WTI still considered a break even for Shale Oil

(edited)

9 hours ago, ceo_energemsier said:

The only way it appears you will be happy is if shale gets shut down

Have we ever met working in the oilfield somewhere? Nobody even knows your name. What makes you think you know anything about me? Are you a phycologist as well as an oil mogul and ship owner?  

I want the development of shale oil and shale gas to be slowed down, not shut down, for the sake of pressure conservation, to prevent waste of associated gas, for conservation of our remaining oil resources and the sake of our children, to cooperate with the rest of the world in oil price stability and  to allow infrastructure (including refinery capacity to handle lighter oil), to catch up to production growth. I want to preserve fresh water in places that have NO fresh water to spare. Slowing down leveraged production will raise the price of product and allow the industry to  become profitable and pay back its debt. I don't want the shale industry to get bailed out by the government and taxpayers left holding the bag. I don't believe that exporting America's oil and gas resources is smart. Its a unique position I have, granted; I like to think of it as simply being able to think past next week. Please, save the stripper well bullshit, that's lame.  

The shale oil and shale gas industry is now trapped like goats in a pen due to debt, debt costs and drilling to earn commitments in leases, term assignments and farm-ins; its got no way out other than to borrow more money, defer old debt and keep drilling unprofitable wells. The American shale oil and shale gas industry needs to be REGULATED; it needs to be made to comply with spacing between wells and density of wells per acre rules (Statewide Rule 37 in Texas). There are laws in every producing state already on the books to implement those regulations and Americans need to put their feet down and elect those that will implement those laws. The idea that shale oil is, or will be profitable, that technology will save the day, and that there is oceans of the stuff... is deceitful, misleading and harmful to the American public. Lots of people don't seem to mind misleading people when they can make money from it. 

Don't forget to provide the API numbers on those "monster" shale oil wells you own. 

 

 

Edited by Mike Shellman
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  On 5/24/2019 at 11:01 AM, ceo_energemsier said:

Again, when most companies (equity investors, investors, operators etc), do their budgets for CAPEX and OPEX, they base everything on NYMEX or WTI and do not base the price of crude oil and or their other hydrocarbons streams on the regional basins prices where they will be operating and producing from. And therein lies a big problem in the disparity in what is projected and planned for and what they get for their products at the end of the day.

Ward said:  This. Of course analysts are lazy, so they just focus on spot pricing, which while it trends up and down is ultimately subservient to the futures contracts the refineries operate on. Imagine a refinery the size of Motiva trying to fill its production trains (635,000 bbls/day) on Spot pricing? Instead they have long term commitments and only poke into the spot market if one or more if their suppliers declared force majure. Otherwise if there's a tremendous bargain in the spot market they'll pick up as much as they can store, because that's just smart business. Then there's all the hedge funds who play in the market, and have no intention of ever picking up one ounce of the slimy stuff. 

ceo & Ward, I would agree on investors and analysts not using real numbers, thus giving them false hopes.  But, having done budgets for years for large and small companies, a couple of them pretty sad operators, we were never allowed to do budgets based on posted pricing.  Whether it be gas or crude, companies rarely if ever get spot pricing.  Both are subject to everything you note, transport costs, quality and other stipulations that are in their contracts.  Operators biggest misses in my experience are the projected pricing they base their futures off.  While working for both Western Gas and Encana, we based future numbers for projects and long term budgeting off very conservative numbers.  It was very interesting watching other companies, for instance when gas was going to $8 or $9/m basing budgets off those bubble prices or even higher for projects.  In my opinion this is the only reason Encana survived the switch from a "Gas Only Company" to becoming more "Oily" as Doug Suttles describes it.  I have worked for 2 companies that were very conservative on their numbers and even more so on their staffing.  They both hit home runs in the areas they were practicing those processes.  But that didn't get them all the way there.  It took unique innovation efforts on an ongoing basis and teamwork.  Companies that can wrap up those 3 efforts together are going to do fine.  The other process that works once a production company gets off the ground is to become a machine.  The Shell, BP or Chevron model works too.  They are machines.  It is hard work to get there.  They don't hit the home runs as quick, or as often.  They are boring in a lot of respects.  Opportunities to climb the ladder are rarer but they treat their employees well, pay them extremely well and turn out good numbers regularly.  But they don't drive outside the lines, so they aren't for everyone.   And they sure don't budget CAPEX or OPEX off of the WTI or other posted pricing!  PS; ceo & Ward, very much enjoy following your posts.

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9 hours ago, Mike Shellman said:

Have we ever met working in the oilfield somewhere? Nobody even knows your name. What makes you think you know anything about me? Are you a phycologist as well as an oil mogul and ship owner?  

I want the development of shale oil and shale gas to be slowed down, not shut down, for the sake of pressure conservation, to prevent waste of associated gas, for conservation of our remaining oil resources and the sake of our children, to cooperate with the rest of the world in oil price stability and  to allow infrastructure (including refinery capacity to handle lighter oil), to catch up to production growth. I want to preserve fresh water in places that have NO fresh water to spare. Slowing down leveraged production will raise the price of product and allow the industry to  become profitable and pay back its debt. I don't want the shale industry to get bailed out by the government and taxpayers left holding the bag. I don't believe that exporting America's oil and gas resources is smart. Its a unique position I have, granted; I like to think of it as simply being able to think past next week. Please, save the stripper well bullshit, that's lame.  

The shale oil and shale gas industry is now trapped like goats in a pen due to debt, debt costs and drilling to earn commitments in leases, term assignments and farm-ins; its got no way out other than to borrow more money, defer old debt and keep drilling unprofitable wells. The American shale oil and shale gas industry needs to be REGULATED; it needs to be made to comply with spacing between wells and density of wells per acre rules (Statewide Rule 37 in Texas). There are laws in every producing state already on the books to implement those regulations and Americans need to put their feet down and elect those that will implement those laws. The idea that shale oil is, or will be profitable, that technology will save the day, and that there is oceans of the stuff... is deceitful, misleading and harmful to the American public. Lots of people don't seem to mind misleading people when they can make money from it. 

Don't forget to provide the API numbers on those "monster" shale oil wells you own. 

 

 

@Mike Shellman Reading your text relates the Tight Oil Industry to the Old Bull and Young Bull story looking down on the herd of cows. Shale is looking like that young bull....

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On 6/7/2019 at 6:47 PM, Ward Smith said:

When you say "completed" do you mean drilled and cased, or fractured also? My understanding was that wells are being partially completed then fracked later. 

By completion I mean fracced they have started producing oil.

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On 6/8/2019 at 1:43 AM, Wastral said:

 USGS/EIA assume basic total and recovery % and they have been horrifically wrong as they are always 5 years out of date and no their data prediction does not shadow actual production.  Picking your "prediction" after the fact is not prediction....   Mike Shellman already gave a MUCH superior rebuttal to my point regarding water cut percentage.  My only rebuttal to that is that the resource is being wasted in that too much gas is being pulled from the formation dropping URR except for those companies who are not doing so.

Hi Wastral.

The model takes well completion data and average well profile data to model past output, then guesses at future well completion rates.  If the average well profile does not change and the completion rate guess is correct, then it is likely the model will be close, but it will never be perfect because every well is not an average well and the well profiles sometimes change over time.

I use NDIC output data fro North Dakota Bakken/Three Forks output.  Well completion data is from shaleprofile.com up to March 2019, completion estimate after March 2019 is a guess, well profiles are also based on a hyperbolic fit to shale profile average well data.  The USGS mean estimate for North Dakota TRR informs the rate of EUR decrease over time.  If 45,000 wells are completed and EUR of new wells starts to decrease in Jan 2019 then the URR matches the mean USGS TRR.  Fewer wells are actually completed in the scenario because I have assumed oil prices never rise above $70/b, this limits Economically recoverable resources to 6.2 Gb in this scenario (the mean USGS TRR is 11 Gb for the North Dakota Bakken/Three Forks).

bakken1906.png

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On 6/9/2019 at 7:46 AM, James Regan said:

That’s a considerable amount of wells, I’m guessing that most are producers and by default could be considered appraisals, as the geology is well known very few wild cats or exploration?

What is the legal distance allowed between pads?

The distance Between well head won’t really matter when drilling directional although I’m sure there are rules and data to stop wells from collision or break through into and existing well.

At some point there will be a physical land mass issue and with a rate of almost 2000 wells a month 24000 a year surely this can’t continue to be a long term solution using the info above and fast depreciation of a typical Tight oil well of 74,47 & 19% losses in production at Eagle Ford for instance. ( not implying all Wells are drilled  at EF).

Im trying to visualize the view in 5 years of the amount of wells that will need to be drilled and completed to keep the net export levels currently in place, the footprint will be massive in comparison to offshore.

Can this be considered sustainable in our industry which is based on recovery of unsustainable resources?

The number of wells completed per month falls from 1500 in June 2020 to about 550 new wells per month in 2023 and to 425 new wells per month by 2028.  The model has about 134,000 wells completed in the US by March 2019 and another 108,000 wells from April 2019 to Dec 2035 (no wells completed after that date).  This is for a low price model where oil prices remain at $70/b long term.  Total Economically recoverable tight oil is about 52 Gb in this scenario.

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On 6/7/2019 at 6:24 PM, ronwagn said:

Sorry, I am retired so have no access due to no institutional e-mail. Maybe you can give me the gist.

In the Update they added speculative resources from kerogen for oil resources and methane hydrates for natural gas, if those resources are excluded (as is the case in their best guess estimates from their high case, it remains similar to Steve Mohr's estimate in his PhD Thesis from 2010, about 28 Trillion Cubic Feet of Natural Gas in the High case estimate with potentially 10 trillion cubic feet from methane hydrates for a total of 38 Trillion cubic feet.  They note that the methane hydrate estimate is highly speculative, so I exclude it.

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30 minutes ago, D Coyne said:

Hi Wastral.

The model takes well completion data and average well profile data to model past output, then guesses at future well completion rates.  If the average well profile does not change and the completion rate guess is correct, then it is likely the model will be close, but it will never be perfect because every well is not an average well and the well profiles sometimes change over time.

I use NDIC output data fro North Dakota Bakken/Three Forks output.  Well completion data is from shaleprofile.com up to March 2019, completion estimate after March 2019 is a guess, well profiles are also based on a hyperbolic fit to shale profile average well data.  The USGS mean estimate for North Dakota TRR informs the rate of EUR decrease over time.  If 45,000 wells are completed and EUR of new wells starts to decrease in Jan 2019 then the URR matches the mean USGS TRR.  Fewer wells are actually completed in the scenario because I have assumed oil prices never rise above $70/b, this limits Economically recoverable resources to 6.2 Gb in this scenario (the mean USGS TRR is 11 Gb for the North Dakota Bakken/Three Forks).

bakken1906.png

Note that I do not necessarily thing the USGS TRR estimates are correct, it just happens to be the information I start with.  There are many who believe the USGS estimates are far too high and many others that believe they are far too low.  I just choose the mean estimate because that is the geoscientists best guess at the time of the estimate.  When the USGS revises their estimate, I revise my estimate accordingly.  My guess is that the oil pros generally think the USGS TRR estimates are far too optimistic and others with less knowledge believe the USGS estimates are far too low.  Note that the USGS TRR estimates for the US are roughly 110 Gb, my low price scenario ($70/bo) has economically recoverable resources at about 50 Gb and my medium oil price scenario (based on EIA's AEO reference oil price scenario) has economically recoverable resources at about 85 Gb.  Mr Shellman often points out that the EIA's AEO reference oil price scenario is unlikely to be correct, I agree.  Nobody knows the future price of a barrel of oil.

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29 minutes ago, D Coyne said:

Hi Wastral.

bakken1906.png

If you believe this is how you calculate ERR, 🤔😆🤡

Lets make this very simple...

Area/Volume of formation(Unknown, make assumption) = total barrels... 😜

Divide area by what?  # of oil wells?  🤣  No. 

Divide area by what? oil production per well? 🤣  No. 

Divide area(unknown, make assumption) by recovered oil/area 😎 using 'x' method of drilling?  😎😎😎  Yes!

If you drill enough over a wide enough area, can you make a guesstimate with ever increasing accuracy?  Yes. 

Bakken total recoverable used to be listed at ~3.5Gb of oil recoverable when Shale started, actually it was listed as much less(0.5Gb).  Your graph magically morphed into ~6Gb in a matter of ~5 years and even if you use shale profile you will note that the amount of oil/gas per well increasing every year in a near linear fashion.  So much for the USGS "prediction" and the word, accuracy correlating.  Oh wait, I said off by at least 200% earlier in the thread.  Hmm😎   What changed?  ERR/area changed mostly, just like I said.  As for URR and  EOR; both are forever changing, tied directly to economic feasibility and number of wells drilled/depth cores taken for study.  And the fact, most of these cored wells are fairly shallow. 

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8 hours ago, D Coyne said:

The number of wells completed per month falls from 1500 in June 2020 to about 550 new wells per month in 2023 and to 425 new wells per month by 2028.  The model has about 134,000 wells completed in the US by March 2019 and another 108,000 wells from April 2019 to Dec 2035 (no wells completed after that date).  This is for a low price model where oil prices remain at $70/b long term.  Total Economically recoverable tight oil is about 52 Gb in this scenario.

I would say there are some miss calculations to wells completed falling to 425 by 2035. There is no one entity that can predict 16 years out. 

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On 6/10/2019 at 12:16 PM, D Coyne said:

In the Update they added speculative resources from kerogen for oil resources and methane hydrates for natural gas, if those resources are excluded (as is the case in their best guess estimates from their high case, it remains similar to Steve Mohr's estimate in his PhD Thesis from 2010, about 28 Trillion Cubic Feet of Natural Gas in the High case estimate with potentially 10 trillion cubic feet from methane hydrates for a total of 38 Trillion cubic feet.  They note that the methane hydrate estimate is highly speculative, so I exclude it.

Thanks, but we are far off in our estimates, plus IMHO we must include biogas and methane hydrates. Remember that natural gas demand would not multiply overnight. It would take decades. It will keep oil prices in check, just as ethanol and other renewables can. That is why oilmen hate alternative fuels. 

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4 hours ago, ronwagn said:

Thanks, but we are far off in our estimates, plus IMHO we must include biogas and methane hydrates. Remember that natural gas demand would not multiply overnight. It would take decades. It will keep oil prices in check, just as ethanol and other renewables can. That is why oilmen hate alternative fuels. 

Tho us poor Illinois farm country is just now planted, so yield is going to take a real hit. There are still some fields too wet to get in. Corn may yet go up...…..

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On 6/10/2019 at 11:18 PM, Old-Ruffneck said:

I would say there are some miss calculations to wells completed falling to 425 by 2035. There is no one entity that can predict 16 years out. 

Old Ruffneck,

 

It is a scenario based on a set of assumptions.  I assume well profile from 2017 is unchanged through Dec 2018 and then the average EUR starts to decrease as producers run out of room in the sweet spots and start completing more wells in less productive areas.  I also assume if oil prices were very high that 45,000 total wells would be completed in the ND Bakken/Three Forks and find the decrease in EUR that would be required for each new well drilled that will result in a URR that is equal to the mean TRR estimate of the USGS (11 Gb).  The economic assumptions are applied with a $70/b (2017$) oil price assumption from 2020 to 2050.  If the net present value of future net revenue for a well is more than the cost of the well, it is assumed the well is completed.  When those assumptions are applied the model shown is the result.

 

Of course it will not be correct. I do not know future oil prices, future well costs, future well completion rates, and the USGS estimate is likely to be incorrect, also it may be that 60,000 wells should be used to guess at EUR rate of decrease, or 30,000 or even 90,000.  This is the difference between a scenario and a prediction, I lay out my assumptions and then I run the model.  There are an infinite number of different assumptions one could make and an infinite number of possible future scenarios.  The odds that any one scenario would be correct is approximately zero.

If you would like to provide the "correct" set of assumptions, I could easily run the model.  Nobody is willing to climb out on that limb.

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(edited)

10 hours ago, ronwagn said:

Thanks, but we are far off in our estimates, plus IMHO we must include biogas and methane hydrates. Remember that natural gas demand would not multiply overnight. It would take decades. It will keep oil prices in check, just as ethanol and other renewables can. That is why oilmen hate alternative fuels. 

Ronwagn,

I think methane hydrates are pretty speculative, sure we could include them, they will be the energy of the future, always.

Kind of like nuclear fusion reactors from Back to the Future. :)

Edited by D Coyne
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(edited)

On 6/10/2019 at 4:00 PM, Wastral said:

If you believe this is how you calculate ERR, 🤔😆🤡

Lets make this very simple...

Area/Volume of formation(Unknown, make assumption) = total barrels... 😜

Divide area by what?  # of oil wells?  🤣  No. 

Divide area by what? oil production per well? 🤣  No. 

Divide area(unknown, make assumption) by recovered oil/area 😎 using 'x' method of drilling?  😎😎😎  Yes!

If you drill enough over a wide enough area, can you make a guesstimate with ever increasing accuracy?  Yes. 

Bakken total recoverable used to be listed at ~3.5Gb of oil recoverable when Shale started, actually it was listed as much less(0.5Gb).  Your graph magically morphed into ~6Gb in a matter of ~5 years and even if you use shale profile you will note that the amount of oil/gas per well increasing every year in a near linear fashion.  So much for the USGS "prediction" and the word, accuracy correlating.  Oh wait, I said off by at least 200% earlier in the thread.  Hmm😎   What changed?  ERR/area changed mostly, just like I said.  As for URR and  EOR; both are forever changing, tied directly to economic feasibility and number of wells drilled/depth cores taken for study.  And the fact, most of these cored wells are fairly shallow. 

Wastral,

I take the average productivity per well drilled based on the data from the NDIC, the average well profile is assumed to eventually decrease.  The USGS mean TRR estimate is 11 Gb for North Dakota Bakken Three Forks (2013 estimate),  based on the data from shale profile the average North Dakota Bakken/Three Forks well will have an estimated ultimate recovery oil about 430,000 barrels of C+C (boe of natural gas is assumed to offset some of the LOE in cases where it is not flared).  Eventually the sweet spots will run out of room and more wells will be completed in the non-core areas, in that case the average EUR of new wells will decrease.  The scenario presented was a "low oil price scenario".  For higher oil prices the URR is higher.

Scenario below uses EIA's AEO 2018 oil price reference case for oil prices (oil prices rise to $113/b in 2017$ by 2050).

30,000 wells are profitable to complete with economic assumptions applied (as we assume that wells are only completed if it is profitable to do so under the economic assumptions used in the model.)  URR is 9.4 Gb for this scenario.  For 45,000 wells completed the URR would be 11 Gb but the last 15,000 wells would not be profitable to complete with the economic assumptions used.  Note that the last wells completed in this scenario in September 2041 have an EUR of only 134,500 barrels of oil.

If 45,000 wells were completed so that the URR was 11 Gb, the EUR of the last well completed is about 55,000 barrels of oil, at 9 million per well in 2017$, such a well would never pay out at the prices that I use in my model.

Post below give a flavor for how this works.

https://peakoilbarrel.com/oil-field-models-decline-rates-convolution/

bak1906.gif

Edited by D Coyne

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1 hour ago, D Coyne said:

Ronwagn,

I think methane hydrates are pretty speculative, sure we could include them, they will be the energy of the future, always.

Kind of like nuclear fusion reactors from Back to the Future. :)

Maybe, I think I will be in heaven before methane hydrates are actually used much. There is virtually an infinite supply of natural gas without them anyway. It comes from every living thing that dies. Peat bogs, lakes, oceans, feces from all species. Hey that rhymes! Trash heaps, etc etc!

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On 6/10/2019 at 12:32 PM, D Coyne said:

Note that I do not necessarily thing the USGS TRR estimates are correct, it just happens to be the information I start with.  There are many who believe the USGS estimates are far too high and many others that believe they are far too low.  I just choose the mean estimate because that is the geoscientists best guess at the time of the estimate.  When the USGS revises their estimate, I revise my estimate accordingly.  My guess is that the oil pros generally think the USGS TRR estimates are far too optimistic and others with less knowledge believe the USGS estimates are far too low.  Note that the USGS TRR estimates for the US are roughly 110 Gb, my low price scenario ($70/bo) has economically recoverable resources at about 50 Gb and my medium oil price scenario (based on EIA's AEO reference oil price scenario) has economically recoverable resources at about 85 Gb.  Mr Shellman often points out that the EIA's AEO reference oil price scenario is unlikely to be correct, I agree.  Nobody knows the future price of a barrel of oil.

So, if we really don't know how much OIL we have we better start valuing and conserving our natural gas!

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(edited)

On 6/7/2019 at 2:54 PM, James Regan said:

Having spent my life in Deepwater I beg to differ Brasil had 50+ units four years ago now we have 18.

I am talking about the dynamics of Deepwater over the past five years.

The returns from offshore plays leaves tight oil a thing of child’s play , it only suits the current lobbyists and political agenda once it’s gone it’s gone.

Being big into shale is not the same ball park.

Total respect to your position and I agree that  diversity is the key, spread the work and wealth for the whole oilfield.

I keep reading about new natural gas finds and production competition. What do you think is the future of offshore natural gas? Is it just too cheap to deal with considering the quantity? Australia is doing well selling in Asia due to proximity. Europe wants it to balance trade with Russia.China has plenty of nations wanting to ship it to them. America just wants to export LNG rather than use it here. We would rather flare it and use up our oil. We can, of course, pipe our natgas but we still flare it rather than use it onsite. 

 

Edited by ronwagn

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27 minutes ago, ronwagn said:

Maybe, I think I will be in heaven before methane hydrates are actually used much. There is virtually an infinite supply of natural gas without them anyway. It comes from every living thing that dies. Peat bogs, lakes, oceans, feces from all species. Hey that rhymes! Trash heaps, etc etc!

I think the "new" methane from recent plant and animal deaths is rather difficult to collect.  The natural gas the is typically produced as an energy resource is not unlimited.  If natural gas output continues to grow at 2.5% per year and the Mohr et al 2015 best guess estimate (excluding methane hydrates) is correct then natural gas peaks in 2051, if there is extensive switching to natural gas for road transport, electric power generation, etc then the growth rate in natural gas output could accelerate.  Let's say it doubles to 5% per year, then the peak occurs in 2044 in that case.  For the high estimate for natural gas the peak would be 2065 at 2.5% growth and 2053 at 5% growth.  Best guess is 24,000 TCF and high estimate is 34,800 TCF, the low estimate is 14,000 TCF.  The resource is very large, on that we agree.

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14 minutes ago, D Coyne said:

I think the "new" methane from recent plant and animal deaths is rather difficult to collect.  The natural gas the is typically produced as an energy resource is not unlimited.  If natural gas output continues to grow at 2.5% per year and the Mohr et al 2015 best guess estimate (excluding methane hydrates) is correct then natural gas peaks in 2051, if there is extensive switching to natural gas for road transport, electric power generation, etc then the growth rate in natural gas output could accelerate.  Let's say it doubles to 5% per year, then the peak occurs in 2044 in that case.  For the high estimate for natural gas the peak would be 2065 at 2.5% growth and 2053 at 5% growth.  Best guess is 24,000 TCF and high estimate is 34,800 TCF, the low estimate is 14,000 TCF.  The resource is very large, on that we agree.

Your best guess with lots of statistics to back it up never includes biogas, methane hydrates, peat bog emissions etc. 

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31 minutes ago, D Coyne said:

I think the "new" methane from recent plant and animal deaths is rather difficult to collect. 

You actually believe the worlds NG/oil comes from plant/animals.......🤣   

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2 hours ago, ronwagn said:

I keep reading about new natural gas finds and production competition. What do you think is the future of offshore natural gas? Is it just too cheap to deal with considering the quantity? Australia is doing well selling in Asia due to proximity. Europe wants it to balance trade with Russia.China has plenty of nations wanting to ship it to them. America just wants to export LNG rather than use it here. We would rather flare it and use up our oil. We can, of course, pipe our natgas but we still flare it rather than use it onsite. 

 

@ronwagn For ease I have found a dated report in English regarding GNV and Brasil. 

Brasil currently uses 6mm/m3 a day on cars but a total close to 100mm/m3 per day is used from generation of electricity etc.

Gas flaring is permitted by the ANP but each case is taken on a case by case basis which is heavily policed by IBAMA (Ambiental Protectors of the Government)

its expected that Argentina would be big players circa 2011 since then the huge Brasilian pre-salt basins were discovered and the Libra field which at last info will produce 1.4mm/Bbl/day with expected reserves of 15Billion Bbls , this is just one field of the numerous pre-salt plays. As you can see by the diagram the pre-salt basin is fairly big and Libra is one of the first to come on line, over 30 FPSOs planned in the near future.

some interesting reading below.

 

https://www.export.gov/article?id=Brazil-Natural-Gas-Market-Potential

https://thebrazilbusiness.com/article/natural-gas-industry-in-brazil

https://content.next.westlaw.com/Document/Id4af1a3c1cb511e38578f7ccc38dcbee/View/FullText.html?contextData=(sc.Default)&transitionType=Default&firstPage=true&bhcp=1

933ED5D8-94C8-464F-B2F2-830E9AC1ACD1.jpeg

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I would say a break even is when they stop producing and prices go up. 

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(edited)

18 hours ago, ronwagn said:

Your best guess with lots of statistics to back it up never includes biogas, methane hydrates, peat bog emissions etc. 

The high case includes methane hydrates and is 44,500 TCF.  It also depends on the assumption that technology will be developed to make it profitable to extract those resources in large quantities.

From page 127 (section 5.2.2)

The projection is heavily dependent on the rapid growth in kerogen oil in the USA. Historically kerogen minerals were exploited for synthetic oil production such as in Australia, and kerogen is currently exploited in Estonia as an energy source for power stations. However, kerogen is only being exploited as a source of liquid fuel in small quantities in countries such as China, Brazil and Estonia [109]. Given the limited current production in kerogen, any projection of future kerogen oil production needs to be taken with considerable caution. Production from kerogen oil could easily fail to materialise due to delays in technological advances needed to reduce the cost of the oil, or due to scarcity in fresh water needed to process the kerogen into a synthetic crude oil.

From p 127 section 5.2.3

After conventional gas peaks, gas hydrates are anticipated have strong growth before peaking in the latter half of the 22nd century. The hydrates projection needs to be treated with considerable caution, as methods of extracting natural gas hydrates are still being researched. It is uncertain when or even if, technological advances will make gas hydrates extraction technically and economically feasible.

The Best case for natural gas  has the comment below.

p. 128 Section 5.3.3

As with the High case, projection of hydrates needs to be taken with considerable caution. Hydrates could be delayed if technical advances are slow in developing or unfavourable economically; alternatively the recent shale gas boom in North America highlights that technical advances could happen suddenly if a technical breakthrough occurs.

 

In my opinion, the recent shale gas boom was due to high natural gas prices leading to the combination of fracking and horizontal wells, which was not a technological breakthrough.  So citing this as being the reason that a methane hydrate technological might be imminent seems dubious.  Also the assumption that high enough natural gas prices can be maintained to allow profitable gas hydrate exploitation is doubtful in my view.  I also doubt that large scale exploitation will be profitable even over the long term.

I did a post about this paper at link below:

http://peakoilbarrel.com/projection-of-world-fossil-fuel-urr/

Edited by D Coyne

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