Shale Oil Fiasco

[ceo_energemsier + 1,818]

EIA: Bone Spring will drive Permian production growth

The U.S. Energy Information Administration (EIA) has released new maps and geologic information for the Bone Spring play in the Delaware Basin, which spans from southeastern New Mexico to western Texas. The updated information includes formation geology, deposition history, and regional tectonic features. The Delaware Basin is in the western part of the larger Permian Basin, one of the most prolific areas for oil and natural gas production in the United States.

The Bone Spring formation lies directly under the Delaware Mountain Group and over the Wolfcamp formation. The Bone Spring formation consists of interbedded

 

settled between existing layers) siliciclastic, carbonate, and shale rocks up to 4,000 feet thick and is divided into four intervals. These intervals are named, from top to bottom, the First, Second, and Third Bone Spring. The Avalon shale is within the First Bone Spring carbonate. 

Each interval has very low permeability, which means that oil and natural gas cannot flow easily. Recent advances in completion techniques have increased oil recovery factors to as high as 34%, meaning 34% of the estimated resource base in an area is produced. 

With the introduction of hydraulic fracturing and horizontal drilling, hydrocarbon production has increased considerably in the Bone Spring. The number of producing wells in Bone Spring grew from 436 wells in January 2005 to 4,338 wells in mid-2019. These wells have become more productive over time: average initial daily crude oil production per well for the first six months of operation increased from 67 barrels per day (b/d) in 2005 to 770 b/d in 2019. In that same period, average natural gas production per well for the first six months of operation grew from 0.1 million cubic feet per day (MMcf/d) to 1.6 MMcf/d. 

In August 2019, average monthly production from Bone Spring reached 0.6 million barrels of crude oil and 1.7 billion cubic feet of natural gas per day. EIA expects Bone Spring production to continue to drive production growth in the Permian Basin. Additional pipeline takeaway capacity is coming online through 2020 to accommodate the production increase.

 

 

https://www.eia.gov/maps/pdf/Wolfcamp_BoneSpring_EIA_Report_July2019_v2.pdf

 

[Old-Ruffneck + 1,246]

6 hours ago, ceo_energemsier said:

The updated information includes formation geology, deposition history, and regional tectonic features. The Delaware Basin is in the western part of the larger Permian Basin, one of the most prolific areas for oil and natural gas production in the United States.

They are already hammering that whole area as we speak. The only real guarantee of hitting oil. The science is totally different than when I was in Lea County. We drilled down 14 to 15k feet and you would have thought going thru the shale layers we would have seen something in the pit. Mostly gas kicks (some would push pipe up little ways). Drilled to measured point and case it and wireline comes in. Different world in the tech. Somewhere there is a post with all the wells drilled in the Delaware up to November. The formation is huge and has a lot to give. 

[PE Scott + 563]

7 minutes ago, Old-Ruffneck said:

They are already hammering that whole area as we speak. The only real guarantee of hitting oil. The science is totally different than when I was in Lea County. We drilled down 14 to 15k feet and you would have thought going thru the shale layers we would have seen something in the pit. Mostly gas kicks (some would push pipe up little ways). Drilled to measured point and case it and wireline comes in. Different world in the tech. Somewhere there is a post with all the wells drilled in the Delaware up to November. The formation is huge and has a lot to give. 

Almost every pad I've worked in SE New Mexico had at least 1 of the wells in the third bone springs. They're pretty low pressure by comparison to other reservoirs in the area. Very easy to frac, I think I've run as high as 4.5 ppg slurry at 100bpm using slickwater down 5.5" casing and not seen more than 8k psi at the wellhead. It's like watching paint dry. 

 

Then again, I remember a few that surprised us. 

[Douglas Buckland + 6,308]

On 1/2/2020 at 8:07 PM, Papillon said:

''Back to'' sir?

That exists here does it?  ... / sarc

Says the man who will not answer a direct question... / no sarc

[D Coyne + 305]

On 1/6/2020 at 6:24 PM, 0R0 said:

 

"The 20% revision to official US reserves, on the other hand, is due to higher reserves reported by the operators and is based on more stringent rules from the US Security Exchange Commission,” says Per Magnus Nysveen, Head of Analysis at Rystad Energy."

We are still at the reserve delineation stage for shale. So the predictions based on proven reserves are premature and provide an early peak point and too high a price estimate. While a doubling of resource from here is not a geological probability since the geological survey is close to complete and has had little onshore expansion that I am aware of the last decade, a double of proven reserves over the next decade in shale is very likely, as only 10% of the resource has been delineated to the point of a drilling plan by specific operators, vs. 25% in Russia, 20% in Iran 33% in Saudi. Just by changing the proven reserve definition up from 5 year's planned production to 10 years, as industry is pressing the FASB to allow, would more than double it. 

Argentine shale is not yet incorporated completely into resource estimates for the country, but the geological formation is potentially more than double the size of the Permian as the shale is reported as 250 ft thick vs. 170 for the Permian, and covers perhaps double the area. Instead of wondering where the substantial increase in international rig counts earlier in 2019 was coming from I looked it up and it is from Europe. I guess because of the weaker Euro or Krone FX rates making oil drilling in Europe more attractive. 

https://stockcharts.com/freecharts/gallery.html?$BRENT:$nokUSD

Rig counts

https://bakerhughesrigcount.gcs-web.com/intl-rig-count?c=79687&p=irol-rigcountsintl

Another issue is that of recoveries we should expect as some new techniques apparently will increase those potentially to 20% in some lithographies, but perhaps not in others. Jury is still out. If it is closer to 20% than to historical 5% or current reported 7-8% then the reserves will grow dramatically. 

Then comes the issue of lowering drill and frac costs. Some are claiming $600/ft or even lower with thin water and lower sand loadings of finer sand (100 mesh), using waste NG to power equipment, and using water from the wells themselves and drill guide technology. To the degree this is true, the cost side would allow production at even lower prices even with the existing debt load and bad lease costs. AR are talking $5M all in on a 10k ft well. Don't know if that will be possible elsewhere. But a useful benchmark as to the bottom end of cost levels.  

Finally, the accounting from PWC of the stats of shale drills shows no difference between the different tier wells. Not clear whether that is because of initial misclassification or because first run output is pretty much the same for tier 2 and 3 wells, so we would only see the difference in future refracs. Seems outlandish, but those are the stats so far.  If the stats hold, then there is no real high grading possible and no reason to expect a fall in well recoveries over time. 

So I don't see how a sharp oil spike happens and sticks for any substantial length of time. 

The argument for a cash cost breakeven at well below $50 is likely going to be correct soon enough in the rather near future. So for companies with renegotiated leases and less debt, the operation out of cash flow may still provide growing production despite financial markets being closed to energy production funding for quite a while now. 

 

 

The Rystad estimates for World oil are too high by about 500 Gb.

There are definitely different well productivities, so the idea that this doesn't matter for profitability is nonsense.

See advanced insights and slide the tabs to the left to click on productivity distubution, then change to 12 months on production (from default of 24), choose under year of first flow all years 2010 to 2018, and under basins choose ND Bakken, Niobrara (CO and WY), Eagle Ford, and Permian (TX and NM), link follows

https://shaleprofile.com/2020/01/07/us-update-through-september-2019/

mean 12 month cumulative output is 91544 barrels, median is 77366 barrels, 64% of all wells have cumulative output of 100,000 barrels or less and 37% of wells have 12 month cumulative of 70,000 barrels or less, only 19% of wells have 12 month cumulative of 140,000 barrels or more.  Now you may think oil operators just drill wherever, but my guess is they try to pick the spots where output is highest, eventually the "sweet spots" run out of room and oil operators must move their drilling to less prospective areas.  The oil field has always operated this way and it always will.

Or that is my impression from listening to those who know how to produce oil.  I am not an oil man.

Chart with productivity distribution attached.  Thank you Enno Peters for your excellent website at https://shaleprofile.com

Edited January 8, 2020 by D Coyne

[D Coyne + 305]

On 1/7/2020 at 1:45 AM, Old-Ruffneck said:

I hope so, but I am just alittle bit skeptical...money drying up fairly fast.

Only a little?

Have you seen the frac spread counts from primary vision and the drilling rig counts?  the y might rebound with higher oil prices, but for the next 4 to 6 months, I imagine the tight oil well completion rate might struggle to remain at the November 2019 level.

[PE Scott + 563]

7 minutes ago, D Coyne said:

Only a little?

Have you seen the frac spread counts from primary vision and the drilling rig counts?  the y might rebound with higher oil prices, but for the next 4 to 6 months, I imagine the tight oil well completion rate might struggle to remain at the November 2019 level.

From my narrow perspective:

The bigger company I sometimes work for cut their project in the EF down to 7 wells from 21 wells planned previously. 

On the flip side, smaller private operators working with cash seem to have mostly doubled their planned completion rates this year - from say 3 wells to 6 wells. Some of their first zippers. Exciting times for those guys that aren't up to their ears in debt.

 

Edit: clarity

Edited January 8, 2020 by PE Scott

[D Coyne + 305]

4 minutes ago, PE Scott said:

From my narrow perspective:

The bigger company I sometimes work for cut their project in the EF down to 7 wells from 21 wells planned previously. 

On the flip side, smaller private operators working with cash seem to have mostly doubled their planned completion rates this year - from say 3 wells to 6 wells. Some of their first zippers. Exciting times for those guys that aren't up to their ears in debt.

 

Edit: clarity

PE Scott,

Thanks for the information.

On balance in your area (TX and NM I think) do you think the completion rate is likely to rise, fall, or remain the same?

Edited January 8, 2020 by D Coyne

[PE Scott + 563]

As a side note, I think maybe you guys misinterpret "sweet spots" in tight shale. What you have to remember, from a physical standpoint, is that oil and gas are mostly immobile in tight shale. So, the lithology doesn't support the same kinds of traps and such that you see in conventional reservoirs. Granted, there are thicker parts of formations and many many sandstone lenses etc. 

Again, narrow perspective, but a sweet spot in shale for me is more likely to reflect on operation and development cost based on its physical proximity to critical infrastructure. In that sense, the low hanging fruit is being picked quickly.

[PE Scott + 563]

3 minutes ago, D Coyne said:

PE Scott,

Thanks for the information.

On balance in your area (TX and NM I think) do you think the completion rate is likely to rise, fall, or remain the same?

I think it will plateau mostly, perhaps fall a little during the first 6 months.....but nothing dramatic imo.

[0R0 + 6,251]

4 hours ago, D Coyne said:

The Rystad estimates for World oil are too high by about 500 Gb.

There are definitely different well productivities, so the idea that this doesn't matter for profitability is nonsense.

See advanced insights and slide the tabs to the left to click on productivity distubution, then change to 12 months on production (from default of 24), choose under year of first flow all years 2010 to 2018, and under basins choose ND Bakken, Niobrara (CO and WY), Eagle Ford, and Permian (TX and NM), link follows

https://shaleprofile.com/2020/01/07/us-update-through-september-2019/

mean 12 month cumulative output is 91544 barrels, median is 77366 barrels, 64% of all wells have cumulative output of 100,000 barrels or less and 37% of wells have 12 month cumulative of 70,000 barrels or less, only 19% of wells have 12 month cumulative of 140,000 barrels or more.  Now you may think oil operators just drill wherever, but my guess is they try to pick the spots where output is highest, eventually the "sweet spots" run out of room and oil operators must move their drilling to less prospective areas.  The oil field has always operated this way and it always will.

Or that is my impression from listening to those who know how to produce oil.  I am not an oil man.

Chart with productivity distribution attached.  Thank you Enno Peters for your excellent website at https://shaleprofile.com

That is really great insight into the distribution of productivity. But the question of high grading and sweet spot hunting is assuming that it is a matter of applying one technology suite to all the prospective sites. We are still at the point of optimizing the match of techniques to the lithography etc. The rising initial recoveries charts that Gautreau keeps pointing to as indicators of faster declines, still show a consistent improvement every year, so we are not yet hitting the lower quality deposits. Since recoveries started out as low as 4% and improved to 8-10% recently, and claims are out for 20% by Conoco at least for some lithographies, we may not be as far along as we thought we were in depleting the shales.. Another stat that grabs me is that fewer rigs are producing more output. Not wanting to be a shaleprofile database jockey, let me ask you if you are seeing a decline of well initial production over recent completions. So long as there isn't, then high grading (or rather ongoing optimization of techniques to stone) has not ended and the proven reserves and production are not yet approaching a finite definition where the 90 Gb probable reserve is a useful estimate of a cap to ultimate recoveries. 

How would you apply your modeling to a wave of refracking of the cumulative depleted wells starting next year? I am guessing it would look like an added wave of output behaving like a new reserve of higher cost production delayed a decade or so from the initial wave of production. 

As PE Scott is indicating, there is a sweet spot focus and those are depleting. But he is also indicating that everyone is waiting for gas pipelines to reach their fields. Which makes so much more sense financially, as it provides revenue from NG rather than flaring it. The majors operating in the gassy shales like the Permian are saying outright that they are waiting for pipelines to reach their fields before they frac or even drill. Something you can do if you haven't placed yourself in front of a debt canon.- like PE Scott's cash flow based small drillers that are doubling their activity. 

[0R0 + 6,251]

6 hours ago, PE Scott said:

As a side note, I think maybe you guys misinterpret "sweet spots" in tight shale. What you have to remember, from a physical standpoint, is that oil and gas are mostly immobile in tight shale. So, the lithology doesn't support the same kinds of traps and such that you see in conventional reservoirs. Granted, there are thicker parts of formations and many many sandstone lenses etc. 

Again, narrow perspective, but a sweet spot in shale for me is more likely to reflect on operation and development cost based on its physical proximity to critical infrastructure. In that sense, the low hanging fruit is being picked quickly.

I think you have it in that the main constraint is the ability to get infrastructure to the fields, particularly gas pipelines to add an NG revenue.to the oil. How do you see the progress of pipeline expansion around you? There are so many announced completion targets for 2020. How much production do you think it is holding back?

[PE Scott + 563]

14 minutes ago, 0R0 said:

I think you have it in that the main constraint is the ability to get infrastructure to the fields, particularly gas pipelines to add an NG revenue.to the oil. How do you see the progress of pipeline expansion around you? There are so many announced completion targets for 2020. How much production do you think it is holding back?

Oh gosh, that's a hard number to call. I think it would be easier to say that any pipeline capacity that becomes available will be filled quickly. In fact, my guess is a lot of the capacity is already contracted. 

I cant really say how much is being held back in lieu of flaring because I don't work on the production and midstream side of things. My instinct is they are just flaring the gas and still producing the oil most places. I think the real important part, that you pointed out, is that the prospect of revenue for NG vs flaring it will influence the well economics in such a way as to incentivize completions in areas that are currently struggling to prove profitable.

 

[ceo_energemsier + 1,818]

2 minutes ago, PE Scott said:

Oh gosh, that's a hard number to call. I think it would be easier to say that any pipeline capacity that becomes available will be filled quickly. In fact, my guess is a lot of the capacity is already contracted. 

I cant really say how much is being held back in lieu of flaring because I don't work on the production and midstream side of things. My instinct is they are just flaring the gas and still producing the oil most places. I think the real important part, that you pointed out, is that the prospect of revenue for NG vs flaring it will influence the well economics in such a way as to incentivize completions in areas that are currently struggling to prove profitable.

 

As more LNG trains come online, more pipelines will be built and the price of gas will go back up. Also dont forget that shale gas has become a fav. as a petchem feedstock along the USGC and elsewhere particularly in Asia and Europe. We have taken up as much pipeline throughput capacity and or arranged for some of our JV producers as possible. Flaring will end mostly with new pipelines being built in addition to use for local power gen plants, local regional small , mid size GTL's among other activities but the export demand for NG is going to go up with time. Japan is switching fast from burning heavy crude, heavy fuel oil to LNG. They have billions of $$$ of investments going into NG fired power plants to replace and or cut down the use of the heavy crude and heavy fuel oils.

There are discussions and negotiations among several companies to build crude pipelines to the WC of Mexico and build a deep water port. The pipeline throughput capacity could range between 750,000bpd-1mil. Another pipeline is being discussed for 800,000bpd. I know this because I have been involved in the negotiations and arranging equity funding and other participation.

[PE Scott + 563]

2 minutes ago, ceo_energemsier said:

The pipeline throughput capacity could range between 750,000bpd-1mil. Another pipeline is being discussed for 800,000bpd.

Am I right to assume the full capacity will be utilized almost immediatly with existing production?

[ceo_energemsier + 1,818]

Just now, PE Scott said:

Am I right to assume the full capacity will be utilized almost immediatly with existing production?

Yes and there will be immediate need for more throughput capacity.

[PE Scott + 563]

I've spoken with people in the OCD here in New Mexico and they've hinted at developing/enforcing rules on flaring, requiring a plan to spell out how gas will be processed, transported, or sequestered, and generally trying to discourage wasting the NG. Not from an environmental standpoint, but because the state is concerned with the wastefulness of flaring....... and the lost tax dollars, no doubt. 

Because it's the state, it will take a year or two for them to formalize anything, but I'm sure its coming.

[ceo_energemsier + 1,818]

5 minutes ago, PE Scott said:

I've spoken with people in the OCD here in New Mexico and they've hinted at developing/enforcing rules on flaring, requiring a plan to spell out how gas will be processed, transported, or sequestered, and generally trying to discourage wasting the NG. Not from an environmental standpoint, but because the state is concerned with the wastefulness of flaring....... and the lost tax dollars, no doubt. 

Because it's the state, it will take a year or two for them to formalize anything, but I'm sure its coming.

Private companies will be ,could be much much faster in implementing procedures and methodologies and using technologies for various projects to end flaring if they have an incentive and from the looks of it, there are plenty of incentives. But permitting process and times need to be streamlined. It is a resource that should not e wasted the way it has been wasted and is being wasted.

[0R0 + 6,251]

The power is already there. Flaring is done by TRRC permits. Those are supposed to be tightening already. 

[0R0 + 6,251]

4 minutes ago, ceo_energemsier said:

Private companies will be ,could be much much faster in implementing procedures and methodologies and using technologies for various projects to end flaring if they have an incentive and from the looks of it, there are plenty of incentives. But permitting process and times need to be streamlined. It is a resource that should not e wasted the way it has been wasted and is being wasted.

So it is a financially viable proposition already to do reinjection or field compression to bring the NG to market? Meaning that the equipment is commercially available and not more costly than the market value of the gas? 

[PE Scott + 563]

4 minutes ago, ceo_energemsier said:

Private companies will be ,could be much much faster in implementing procedures and methodologies and using technologies for various projects to end flaring if they have an incentive and from the looks of it, there are plenty of incentives. But permitting process and times need to be streamlined. It is a resource that should not e wasted the way it has been wasted and is being 

They staffed up in santa fe, added 5 petroleum engineers with previous industry experience I think. Hopefully application process times will come down. A good friend of mine is working there and has given me some insight into their struggles. They have a serious backlog of applications and had a mass exodus of retirees last year. 

[ceo_energemsier + 1,818]

1 minute ago, 0R0 said:

So it is a financially viable proposition already to do reinjection or field compression to bring the NG to market? Meaning that the equipment is commercially available and not more costly than the market value of the gas? 

For some companies it is a financially viable avenue to re-inject the gas to pump more oil and or re-inject the gas in depleted formations. For some they are able to make use of the infrastructure and technologies to bring the NG to market via pipelines and or other means such as LNG trucking. Lot of NG is being shipped to Mexico via use of LNG trucks and also being brought to LNG plants along the USGC. It is the individual company's capability in marketing their gas via different means whereby they can get a better value for their NG by shipping it via different means and also how and if they can structure some form of agreements with marketers/exporters/processors and earn higher market value than the cost and or let one of those parties carry the cost of transport. Certain there is a lot of $$$ to be made in sale of NG as petchem feedstock as well as LNG export.

[Coffeeguyzz + 454]

When you all are discussinhg Permian natgas, you might not want to overlook the 2 proposed LNG plants for the west coast of Mexico ... one at Puerto Libertad and - especially - Sempra's Costa Azul project.

Sempra is hoping to quickly pop in a 2.4 mtpa train (~300 MM cubic feet/day) and be exporting by 2023 using existing infrastructure.

Existing pipelines are being upgraded (Sierrita and North Baja XPress) to accommodate expected huge uptick in demand.

Both Energie Costa Azul and the Puerto Libertad projects are ultimately expected to have 12 to 14 modular trains each.

As of this moment, it is not improbable to forsee delivered LNG to Asia at the $4/mmbtu HH price point.

This, obviously, would be amongst the lowest cost LNG  anywhere.

[D Coyne + 305]

4 hours ago, 0R0 said:

That is really great insight into the distribution of productivity. But the question of high grading and sweet spot hunting is assuming that it is a matter of applying one technology suite to all the prospective sites. We are still at the point of optimizing the match of techniques to the lithography etc. The rising initial recoveries charts that Gautreau keeps pointing to as indicators of faster declines, still show a consistent improvement every year, so we are not yet hitting the lower quality deposits. Since recoveries started out as low as 4% and improved to 8-10% recently, and claims are out for 20% by Conoco at least for some lithographies, we may not be as far along as we thought we were in depleting the shales.. Another stat that grabs me is that fewer rigs are producing more output. Not wanting to be a shaleprofile database jockey, let me ask you if you are seeing a decline of well initial production over recent completions. So long as there isn't, then high grading (or rather ongoing optimization of techniques to stone) has not ended and the proven reserves and production are not yet approaching a finite definition where the 90 Gb probable reserve is a useful estimate of a cap to ultimate recoveries. 

How would you apply your modeling to a wave of refracking of the cumulative depleted wells starting next year? I am guessing it would look like an added wave of output behaving like a new reserve of higher cost production delayed a decade or so from the initial wave of production. 

As PE Scott is indicating, there is a sweet spot focus and those are depleting. But he is also indicating that everyone is waiting for gas pipelines to reach their fields. Which makes so much more sense financially, as it provides revenue from NG rather than flaring it. The majors operating in the gassy shales like the Permian are saying outright that they are waiting for pipelines to reach their fields before they frac or even drill. Something you can do if you haven't placed yourself in front of a debt canon.- like PE Scott's cash flow based small drillers that are doubling their activity. 

Thanks.

Keep in mind the recovery factors will vary from place to place.  It may be possible that in the sweet spots the recovery factor has increased, but it is unlikely that this has occurred everywhere.  My guess is that higher recovery factors in some areas will not be matched everywhere, that it is a sweet spot phenomenon that will be very limited in area.  Difficult to say, but the Delaware and Midland basin USGS studies are fairly recent, my guess is the geophysicists mean estimate may be about right with perhaps an error of +/-10%.  PEScott would know better.

The refracs might work on 10% of older wells at high prices, but recent child wells will likely drain the area making the refrack a bust.  So I am far less confident of various investor presentation hype.  This stuff is to get people to buy the stock and drive up the stock price in my opinion.  So far only the Eagle Ford and Niobrara are seeing new well EUR falling when output is normalized by lateral length.  Much of the increased output in the Permian, Eagle Ford, and Niobrara has been a function of increased average lateral length.  That will not help overall basin URR as a longer lateral well uses more area, I am fairly sure nobody is making the basins any bigger.    The result of longer laterals is fewer potential wells overall.  For example if there are 200,000 potential well locations at 5000 feet laterals per well, a doubling of lateral length to 10,000 feet reduces the total wells to 100,000.  Not everyone gets this.  Probably a good metric would be EUR per acre, that number may not have changed much, though perhaps a bit due to heavier proppant use.

Agree more natural gas pipeline capacity will help, though in my models I assume they get $1.87/MCF at the well head (including NGL sales) so I am already assuming most producers are selling their gas rather than flaring it, in other words my model is optimistic in this regard.

Also mote the 90 Gb tight oil estimate is a resource estimate, it is not a 2P reserve number, tight oil reserves are only about 24 Gb, The USGS estimates are for undiscovered technically recoverable resources (UTRR), I add reserves and cumulative production at the time of the studies to the UTRR estimates to get a TRR than apply economic analysis to get the economically recoverable resources (ERR), that is where the 90 Gb estimate comes from.

Edited January 9, 2020 by D Coyne

[Boat + 1,324]

On 12/5/2019 at 9:29 PM, Douglas Buckland said:

People do not seem to realize that the root cause of the production problems associated with shale oil is the extremely low permeability or the ability for the rock to flow. There is only so much that you can do to mitigate this issue.

Let’s take a simplistic historical view. First a well is drilled vertically through a tight shale formation. This yields a certain surface area for hydrocarbons to enter the wellbore, which in turn gives a certain production rate for that surface area and permeability. The rate is uneconomical. How do we increase the permeability of the reservoir rock matrix? We can’t, so we must adjust the surface area. We now drill a lateral through the reservoir. Surface area of the wellbore increases and production goes up - for awhile. The near wellbore oil is recovered ‘easily’, but as the oil further from the wellbore is being recovered, the tortuous path between the shale grains becomes longer, friction becomes greater and it becomes more difficult for the oil to reach the wellbore. Eventually the production rate becomes uneconomical. We need even more surface area, so we hydraulically fracture the formation. Once again, more surface area yields higher production - until it doesn’t for exactly the same reasons described above. At some point the money runs out and you can neither increase the length of the laterals OR increase the number of stages in the frac program.

Okay, let’s just drill and frac a multitude of wells in the same area. This will yield a huge increase in the wellbore surface area (remember, you can’t really change the permeability of the actual reservoir rock) and production should skyrocket, and it does, right up to the point that it doesn’t and the parent/sibling well issue raises it’s ugly head.

At the end of the day, the shale oil boom will bust simply because you can not alter the deep reservoir permeability AND you’ve run out of money trying to do so.

That’s it in a nutshell.

Over to you Jabbar...

I think the large producers are doing exactly what you said except apparently your so called parent/sibling wells are a plus and not a minus. They are just getting more oil out of a smaller area. 
Adding more stages and explosions closer together increased production. Maybe an old tier 1 well didn’t produce as much as a tier 2 well does now because of these newer techniques. 
Even after today’s fracking most of the oil is still in the ground awaiting the engineering technology of tomorrow. Your betting on the rock and I would bet on the brains behind tech.