Why do oilfields take damage when production is paused?

[Fracguy30 + 7]

Shutting in horizontal oil wells can result in significant production loss. Put simply, the lateral can fill up with oil and water during a extended shut in. There may not be sufficient reservoir pressure to push the fluid from the longer sections of lateral.

 

This affect can be mitigated with costly repair operations. These typically will not be done in a low priced environment.

Net result, a lot of productive capacity will be lost/deferred after things return to a more normal status

[BradleyPNW + 282]

I'm enjoying this thread. One main problem and two secondary issues. Main problem is getting the oil up. Secondary issues are water and contaminants interfering with the main problem. That makes me wonder if the oil could be brought up and then dumped into the Saudi Arabian desert then dug up later and separated like Canadian tar sands. At least you have the oil on the surface. 

[D Coyne + 305]

Keep in mind that low output tight oil wells may be able to be shut in safely, if we assume tight oil wells with less than 100 bo/d of output in Dec 2019 can be shut in safely, then 1850 kb/d of 8000 kb/d of Dec 2019 tight oil output can be shut in.  If wells up to 200 bo/d of output can be safely shut in then the number expands to 3100 kb/d (about 39% of tight oil output).  In addition if the completion rate falls to zero, the natural decline if the producing tight oil wells (which is especially steep for the higher producing wells, generally the newer wells) is roughly 51% over 12 months, so with the 3100 bo/d shut in, plus natural decline over 12 months (assuming zero tight oil completions over those 12 months) we would have about 5600 kb/d lower tight oil output in March 2021 (from about 7800 kb/d in March 2020), so approximately 2200 kb/d of tight oil output down from roughly 8000 kb/d in Dec 2019.  That is assuming all tight oil wells producing less  than 200 kb/d are shut in.

Data from https://shaleprofile.com/blog/us-monthly-update/us-update-through-december-2019/

use show production by production level.

A second case with tight oil wells producing less than 100 bo/d being shut in would lead to about 2900 kb/d of output in March 2021 (again assumes no tight oil completions from April 2020 to March 2021).

A third case with no tight oil wells shut in, but the same no tight oil completion assumption results in about 3800 kb/d of tight oil output in March 2021.  Output falls by 2000 kb/d by August in this scenario form 7800 kb/d in March 2020 to 5800 kb/d 5 months later.  It may be that few shut ins are necessary as tight oil output drops very quickly when the completion rate goes to zero.

At current oil price level, about $10.25 for WTI posted at Plains all american for April 22, 2020, I would expect the completion rate to fall to zero and low volume wells will be shut in.  See link below for posted crude oil price bulletin from plains.

https://www.plainsallamerican.com/getattachment/6bfc16c0-860f-4925-8d0c-4ec8b3496568/2020-077-April-22-2020.pdf?lang=en-us&ext=.pdf

Edited April 23, 2020 by D Coyne

[Refman + 207]

So hypothetically if you had 10 wells and wanted to reduce production by 30%, would it be better to choke all 10 down by 30% rather than shut down 3 and leave the other 7 going full rate?

Edited April 23, 2020 by Refman
grammer

[James Regan + 1,776]

2 hours ago, D Coyne said:

Keep in mind that low output tight oil wells may be able to be shut in safely, if we assume tight oil wells with less than 100 bo/d of output in Dec 2019 can be shut in safely, then 1850 kb/d of 8000 kb/d of Dec 2019 tight oil output can be shut in.  If wells up to 200 bo/d of output can be safely shut in then the number expands to 3100 kb/d (about 39% of tight oil output).  In addition if the completion rate falls to zero, the natural decline if the producing tight oil wells (which is especially steep for the higher producing wells, generally the newer wells) is roughly 51% over 12 months, so with the 3100 bo/d shut in, plus natural decline over 12 months (assuming zero tight oil completions over those 12 months) we would have about 5600 kb/d lower tight oil output in March 2021 (from about 7800 kb/d in March 2020), so approximately 2200 kb/d of tight oil output down from roughly 8000 kb/d in Dec 2019.  That is assuming all tight oil wells producing less  than 200 kb/d are shut in.

Data from https://shaleprofile.com/blog/us-monthly-update/us-update-through-december-2019/

use show production by production level.

A second case with tight oil wells producing less than 100 bo/d being shut in would lead to about 2900 kb/d of output in March 2021 (again assumes no tight oil completions from April 2020 to March 2021).

A third case with no tight oil wells shut in, but the same no tight oil completion assumption results in about 3800 kb/d of tight oil output in March 2021.  Output falls by 2000 kb/d by August in this scenario form 7800 kb/d in March 2020 to 5800 kb/d 5 months later.  It may be that few shut ins are necessary as tight oil output drops very quickly when the completion rate goes to zero.

At current oil price level, about $10.25 for WTI posted at Plains all american for April 22, 2020, I would expect the completion rate to fall to zero and low volume wells will be shut in.  See link below for posted crude oil price bulletin from plains.

https://www.plainsallamerican.com/getattachment/6bfc16c0-860f-4925-8d0c-4ec8b3496568/2020-077-April-22-2020.pdf?lang=en-us&ext=.pdf

100Bbs/day or 200Bbls/day produced is this the average well performance? If so I find this astonishing and also now makes sense why the unconventional sector is hocked up to the eyeballs.

How much does it cost to drill and complete an average well?

What are the costs before spudding, ie leasing paperwork, royalty discussions, lawyer fees etc?

How much are you in the hole before you hit pay dirt?

Transport costs or is the producer paid at the wellhead?

Many questions I know, would be nice to understand in basic terms if possible.

Cheers

James

[Ward Smith + 6,615]

58 minutes ago, James Regan said:

100Bbs/day or 200Bbls/day produced is this the average well performance? If so I find this astonishing and also now makes sense why the unconventional sector is hocked up to the eyeballs.

How much does it cost to drill and complete an average well?

What are the costs before spudding, ie leasing paperwork, royalty discussions, lawyer fees etc?

How much are you in the hole before you hit pay dirt?

Transport costs or is the producer paid at the wellhead?

Many questions I know, would be nice to understand in basic terms if possible.

Cheers

James

James, we've talked about this before. Of course every well is different but fair numbers are: 

Drilling $5 million

Fracking $3 million

Misc $1 million

First year production 600 bbls/day

Second year 180 bbls/d

Third year 60 bbls

Thereafter, about 40/d

Steep decline curve after the first year, but at $50/bbl the costs were recovered that first year, so the rest is (mostly) profits. Compare to offshore where it might take ten years to recover costs. 

[D Coyne + 305]

4 hours ago, James Regan said:

100Bbs/day or 200Bbls/day produced is this the average well performance? If so I find this astonishing and also now makes sense why the unconventional sector is hocked up to the eyeballs.

How much does it cost to drill and complete an average well?

What are the costs before spudding, ie leasing paperwork, royalty discussions, lawyer fees etc?

How much are you in the hole before you hit pay dirt?

Transport costs or is the producer paid at the wellhead?

Many questions I know, would be nice to understand in basic terms if possible.

Cheers

James

James,

No it is not average well performance, it is the output of all the older wells that have decline in output. Transport costs depend on location, they are fairly cheap for Eagle Ford and quite expensive for North Dakota, so for Eagle Ford there might be a $4/bo transport cost and for Bakken maybe $11/bo (roughly), the wellhead price would be WTI minus transport cost.  Permian wells for all costs (drilling, fracking, pads, gathering lines, storage tanks, land, and other overhead cost,, along with plugging the well at end of life) are about $10.5 million, total output over the life of the average well is about 385 kbo.  To break even (where total cost is equal to the discounted net revenue over the life of the well at a 10% annual discount rate requires about $65/bo at the wellhead.

For Permian basin royalties and taxes are about 30% of wellhead revenue, operating expenses are roughly $13/bo produced.  Transport cost about $5/bo.

Chart below shows output by production level for the US tight oil horizontal wells from

https://shaleprofile.com/blog/us-monthly-update/us-update-through-december-2019/

 

Edited April 23, 2020 by D Coyne

[D Coyne + 305]

3 hours ago, Ward Smith said:

James, we've talked about this before. Of course every well is different but fair numbers are: 

Drilling $5 million

Fracking $3 million

Misc $1 million

First year production 600 bbls/day

Second year 180 bbls/d

Third year 60 bbls

Thereafter, about 40/d

Steep decline curve after the first year, but at $50/bbl the costs were recovered that first year, so the rest is (mostly) profits. Compare to offshore where it might take ten years to recover costs. 

Here is the average production profile for Permian wells from 2016 to 2019.

Average output for first year is 387 bo/d.

year 2 average output is 159 bo/d.

year 3 average output is 100 bo/d.

Chart with production profile from

https://shaleprofile.com/blog/permian-monthly-update/permian-update-through-january-2020/

[Ward Smith + 6,615]

@D Coyne I'm not accustomed to your site but look here

I selected "Productivity over time" then set 12 months. I grabbed the most recent two years. The question your site isn't answering in your post is which wells. If I knew specific well names I guess I could get better numbers. Looking at these and dividing by 12 shows more than 1000 bbls per day. 

The second picture clearly shows more than one thousand bbls per day when I select "First production year" and the available 2017 & 2018. No averaging legerdemain, just Your site

 

Edited April 23, 2020 by Ward Smith
Wanted to make sure screen shot worked before adding text

[D Coyne + 305]

10 minutes ago, Ward Smith said:

@D Coyne I'm not accustomed to your site but look here

 

Ward,

The productivity has increased a bit for permian basin since 2016, but only because the average lateral length has increased over the 2016 to 2019 period, when we look at output per 1000 feet of lateral, productivity has actually decreased a bit.

Not my web site, but the information is very good, he uses Texas RRC well data and New Mexico State well data as the basis for his information.

Based on your chart the average cumulative output for a 2018 well is about 144549 barrels and 144549/365= 396 bo/d, I used 2016 through 2019 so the average was a bit less. In 2017 the average well had 359 bo/d in first 12 months, and in 2016 it was 343 bo/d.  In any case your 600 bo/d estimate is not an average first year output for any tight oil basin in the United States (Permian and Bakken are highest).

Edited April 23, 2020 by D Coyne

[Ward Smith + 6,615]

3 minutes ago, D Coyne said:

Ward,

The productivity has increased a bit for permian basin since 2016, but only because the average lateral length has increased over the 2016 to 2019 period, when we look at output per 1000 feet of lateral, productivity has actually decreased a bit.

Not my web site, but the information is very good, he uses Texas RRC well data and New Mexico State well data as the basis for his information.

D. I was still editing above when you replied. Bottom line I don't care about production per foot, we're looking for economic viability (or not). My information came from the horse's mouth but for the Bakken. Costs to drill and frack have fallen by 50% over the last decade, but the quality has likely gone down by 10-20% per job. 

So, to summarize, you spend around $10 million to drill and complete a well and on these numbers, you'd recover that in about 7 months at $40/bbl into your pocket. Gross numbers, not counting interest expenses, royalties, management bonuses, hookers and coke… 

[D Coyne + 305]

1 minute ago, Ward Smith said:

D. I was still editing above when you replied. Bottom line I don't care about production per foot, we're looking for economic viability (or not). My information came from the horse's mouth but for the Bakken. Costs to drill and frack have fallen by 50% over the last decade, but the quality has likely gone down by 10-20% per job. 

So, to summarize, you spend around $10 million to drill and complete a well and on these numbers, you'd recover that in about 7 months at $40/bbl into your pocket. Gross numbers, not counting interest expenses, royalties, management bonuses, hookers and coke… 

No oil with all of that.  Got it, I did n ot realize you were talking Bakken, about $9 million sound right for well cost.

For the average 2016 Bakken well average first year output is about 350 bo/d, second year 152 bo/d, and year 3 about 90 bo/d.

The 2018 average well has higher first year output, but looks to decline more quickly than 2016 wells.

The economics of the average well does not work when operating expense, transport cost ($10/bo), royalties and taxes (30% combined), and LOE at $10/bo are included for a $9 million well cost, needs $60 to $70/bo for a decent ROI.

See https://runelikvern.online/2020/01/09/bakken-something-about-eurs-pdp-reserves-and-r-over-p-ratio/

for excellent analysis by Rune Likvern.

[D Coyne + 305]

39 minutes ago, Ward Smith said:

@D Coyne I'm not accustomed to your site but look here

I selected "Productivity over time" then set 12 months. I grabbed the most recent two years. The question your site isn't answering in your post is which wells. If I knew specific well names I guess I could get better numbers. Looking at these and dividing by 12 shows more than 1000 bbls per day. 

The second picture clearly shows more than one thousand bbls per day when I select "First production year" and the available 2017 & 2018. No averaging legerdemain, just Your site

 

Ward,

Those numbers are 140k barrels over 12 months to get bo/d you need to do 140000/365 (as there are 365 days in a 12 month period) that is 383 bo/d average output for first 12 months (or one year) of production.

Try the Well quality tab for well profile.

Edited April 23, 2020 by D Coyne

[Eric Gagen + 713]

On 4/22/2020 at 12:43 PM, Ward Smith said:

From your Quora discussion (but really from an SPE discussion). He outlined a case where water imbibed multiple producers. I guess something like 80% or more of wells worldwide come with water. Usually that's a good thing, water on bottom, oil on top and water pushes oil out. Bad if the water finds its way above the oil, or you get emulsion, or other problems I haven't thought about yet. 

But net net, will shutting in wells have positive benefits? I'm starting to get more optimistic, thanks to this discussion

I read a lot of the comments on Oilprice.com, but don't usually comment very often, but seeing my own comments in here as the voice of experience and reason is pretty interesting. 

It reminds me of an experience a guy I once worked with had:  He was an expert mechanic working on the diesel engines for a crew boat that HAD to get back in service ASAP in Louisiana.  The engine compartment was cramped, and hot and dirty, and the problem was complex, and the more he dug into it, the worse it was getting.  He called the base he was dispatched from, and let them know that he didn't think he could resolve the issues on his own, and that he needed help.  The supervisor told him to hang on,  and he would put him on the line in a conference call with the expert from Caterpillar who knew everything there was to know about this model of engine.  He waits on the line for a few minutes, and then his cell phone starts to ring.  He did sort it out eventually, but it took a long time.  Probably he was the first person to see this particular problem, because afterwards he called and did some research at Caterpillar and nobody had ever heard of it happening before.

Moral of the story.  I won't claim to be an expert on this particular problem,  but I know enough about some of it to ask the 'real experts' about what's dangerous in particular situations.  The situation with new or recently drilled wells is straightforward - you can close them in for extended periods and they are fine.  The situation with the old stripper wells is equally simple - they have troubles, but everyone knows what they are likely to be and what to do about them - they or wells like them have been shut in before.  What nobody has done however is closed in partially depleted horizontal oil and gas wells for long time periods yet, so nobody knows exactly what will happen to them. 

For horizontal oil wells:

There are reasons to be optimistic:

The near wellbore pressure could recharge from rock far away from the well leading to a 'flush' of production and associated pressure

As the pressure equalizes it may open or reorient fractures in the well creating more production

There are also reasons to be pessimistic:

As near wellbore pressures change dramatically there could be casing or cement failures leading to wellbore integrity issues (expensive to fix and you can't produce the well until they are repaired

Fracture networks that were open could close up

There are also some wild cards:

Most horizontal wells deplete in the heel first, then the toe later.  If you close a partially depleted well in for an extended period, does the pressure and hydrocarbons in the toe charge up the heel creating better production?  Or does water influx starting in the heel flow into the toe and prevent oil production in the future?   

 

Gas wells should be fine provided they don't have any considerable associated water production.  However if they do,  things could get really unpleasant.  

This has been a good discussion and I look forward to hearing more.  

Edited April 23, 2020 by Eric Gagen

[Ward Smith + 6,615]

2 hours ago, D Coyne said:

Ward,

Those numbers are 140k barrels over 12 months to get bo/d you need to do 140000/365 (as there are 365 days in a 12 month period) that is 383 bo/d average output for first 12 months (or one year) of production.

Try the Well quality tab for well profile.

Ugh, not even sure what I did now. Know I was screwing around with different views, found what I wanted but this site rejected the URL. Went back to take a pic but didn't capture what I was looking at previously. Thought I'd done the same thing, obviously didn't and neglected to double check. Sigh. 

Giving up on that, here's Rystad energy backing up my numbers.

Quote

With two additional months of production data now available, we confirm that our previous conclusion holds true, as seen in Figure 1. In fact, the average well each month is slightly more productive than average well drilled three to six months ago. It should be noted that the basin-wide average productivity of new wells has been observed above 1,000 barrels of oil equivalent per day (boepd) for five months in a row on a two-stream production basis.

[D Coyne + 305]

12 hours ago, Ward Smith said:

Ugh, not even sure what I did now. Know I was screwing around with different views, found what I wanted but this site rejected the URL. Went back to take a pic but didn't capture what I was looking at previously. Thought I'd done the same thing, obviously didn't and neglected to double check. Sigh. 

Giving up on that, here's Rystad energy backing up my numbers.

 

Ward,

The 1000 b/d is a two stream (I assume they mean oil and natural gas) basis.  The natural gas does not generate much cash flow and a lot of it cannot find a place to process it so it is simply flared (generates zero revenue) and the rest probably averages about $1/MCF at the wellhead because of the lack of pipe and natural gas processing in the area.

Go to https://shaleprofile.com/blog/bakken-monthly-update/north-dakota-update-through-february-2020/

click on well quality, then look at cumulative output chart, you can choose specific years in the first production year box at bottom left of chart.  Chart below the years chosen ar 2016, 2017, 2018, 2019, output is crude plus condensate only for North Dakota horizontal oil wells.  The average 2018 well has 175,715 barrels of cumulative output in the first year of production or 481 bopd.  After 24 months output is roughly at the level of the average 2016 well (about 120 bopd), by 36 months output has fallen to 73 bopd.  At 36 months cumulative output for the Average 2018 well would be about 280 kbo and EUR might be about 400 kbo at 20 years or so.  Such a well would at $40/bo at wellhead, have 280k*0.7=196k net barrels (30% for royaties and taxes assumed) after 3 years and perhaps net $30/bo after operating expenses so 196k*30=5.88 million in net income.  

A wise oil man with 5 decades of experience owning his own E&P company has taught me that a profitable well will pay out in 36 months.  This well would come up short by 9-5.88=$3.12 million at $40/bo at wellhead.  It would need at least $56/bo at wellhead to pay out and I have ignored the heavy debt burden carried by most North Dakota tight oil producers, so in reality if this were included it would be more than $56/bo at wellhead, perhaps $60/bo for a profitable average 2018 well.

Also keep in mind they are running out of room in the Bakken sweet spots and have been high grading (drilling only in the sweet spots) since March 2015.  Before long we will see the average new well EUR in North Dakota start to deteriorate which will drive breakeven oil prices higher.

[Alex8741 + 4]

From my experience as a Production Engineer and Reservoir Engineer on conv reservoirs, I would say that operators don't stop production until they have to (for workovers..) because they are simply afraid that production won't be back. One of my former boss told me: "If you have a good producing well, you never touch it". 

I restarted many wells and in most cases nothing really happened expect sand accumulation at the bottom of the well or artificial lift failure to restart.

I think operators do not want their process disturbed by these current circumstantial events, keep it the way it is until they really have to.

And one last thing, I want to point out is that every field is different and the strategy operator can adopt to reduce production is very different from one field to another. Mainly because it highly depends on the surface installation (minimal power generation, water injection pumps minimal flow, etc...)

Edited April 24, 2020 by Alex8741

[GasRat88 + 3]

Oil wells can be turned off with little damage to the reservoir. The reservoir is still under pressure if the well is shut in. The damage may come to the operation of the artificial lift equipment when the well is turned back on. Under normal rod lift operations a well is constantly being turned on and off. ESP operations are a bit more difficult. it is the equipment that does not like to be turned on and off. We are constantly shutting in wells for frac protect.

Edited April 24, 2020 by GasRat88

[Ward Smith + 6,615]

4 hours ago, D Coyne said:

The 1000 b/d is a two stream (I assume they mean oil and natural gas) basis

Rystad's exact words were "oil equivalent". Let's take them at their word shall we? Now, in point of fact pentanes plus are not oil, but they sold (especially in Canada) at a premium to WTI. We've discussed the "lightness" problems of shale oil many times here. WTI has an API of about 35 gravity. Shale "oil" routinely comes in at 60 API, then you have the "equivalent" that's lighter yet or perhaps some wells "Blend" to a 60 API number. Why separate? Might have to do with different taxes and royalties. Like I said, my numbers came directly from the chief scientist of a major Bakken producer.  I'm confident he was giving me the total "liquids" number. 

It would take me a while to work out the shale profile site. Unfortunately I'm doing this on a mobile device and the thumbnail graphs I get are a bit tough to read. I can click on them, just takes more time and I might have done something wrong. Maybe they never consider natural gas liquids at all. Even butane and propane sell for considerably more than methane. You'll notice the pure play gas operators are constantly searching for the "wet gas" reservoirs, more profit. 

[D Coyne + 305]

36 minutes ago, Ward Smith said:

Rystad's exact words were "oil equivalent". Let's take them at their word shall we? Now, in point of fact pentanes plus are not oil, but they sold (especially in Canada) at a premium to WTI. We've discussed the "lightness" problems of shale oil many times here. WTI has an API of about 35 gravity. Shale "oil" routinely comes in at 60 API, then you have the "equivalent" that's lighter yet or perhaps some wells "Blend" to a 60 API number. Why separate? Might have to do with different taxes and royalties. Like I said, my numbers came directly from the chief scientist of a major Bakken producer.  I'm confident he was giving me the total "liquids" number. 

It would take me a while to work out the shale profile site. Unfortunately I'm doing this on a mobile device and the thumbnail graphs I get are a bit tough to read. I can click on them, just takes more time and I might have done something wrong. Maybe they never consider natural gas liquids at all. Even butane and propane sell for considerably more than methane. You'll notice the pure play gas operators are constantly searching for the "wet gas" reservoirs, more profit. 

Ward,

Often they use barrels of oil equivalent, often for natural gas the conversion is 5800 CF=1 barrel oil equivalent, so from a profit perspective at $1/MCF a boe of natural gas would be $5.8/boe, in the US pentanes plus do not sell at a premium to WTI and natural gas liquids generally trade at about 25% of WTI in the US.  If we add the 90 kboe of natural gas for the average 2018 well to the total net revenue we only add another 0.4 million dollars.  We would also get about 50 kb of NGL from the natural gas  produced over first 36 months, at $40/bo this would be about $10/b of NGL and add another half million of revenue,  I had adjusted for this in my previous estimate by assuming only $10/bo for LOE assuming about $3/bo of income from natural gas abd NGL sales.

So recalculating we have about 196 net kbo over first 3 years at 40 minus 13= $27/bo net for a total of 5.292 million dollars, then add 0.4 million for natural gas sales and 0.5 million for NGL sales, we round to 1 million to make math easy and we get 6.3 million in net revenue over first 3 years, the well needs to get to $9 million in 3 years to be a successful (profitable) well and we are $2.7 million short, again I have ignored interest payments (which are substantial for most of these companies).  I would also suggest you consider Mr. Likvern's analysis which is top notch (far more detailed than my back of napkin analysis here).

https://runelikvern.online/

Edited April 24, 2020 by D Coyne

[Ding Ray Chung + 8]

2 hours ago, GasRat88 said:

Oil wells can be turned off with little damage to the reservoir. The reservoir is still under pressure if the well is shut in. The damage may come to the operation of the artificial lift equipment when the well is turned back on. Under normal rod lift operations a well is constantly being turned on and off. ESP operations are a bit more difficult. it is the equipment that does not like to be turned on and off. We are constantly shutting in wells for frac protect.

So in effect, a shut-in is like in-the-ground storage.... 

[Ravikumar KOC + 1]

More than 50% of oil production is through Artificial Lift systems like Gas lift, ESP and sucker rod pumps. Artificial lift system is used typically in sub hydro static wells. When you stop these wells due to to some reason for a period , the static fluid characteristics inside the well string changes. So when you restart these wells first it takes some time to revive the well production; secondly, it will take some more time to optimize the production by adjusting the lift parameters. Especially in a multiple completion wells( more predominantly in offshore) it takes more time to realize the same production obtained before closing the wells . This is one of the reason for oil field production damage when you pause the production. There are more other technical reasons. 

[Eric Gagen + 713]

2 hours ago, Ward Smith said:

Rystad's exact words were "oil equivalent". Let's take them at their word shall we? Now, in point of fact pentanes plus are not oil, but they sold (especially in Canada) at a premium to WTI. We've discussed the "lightness" problems of shale oil many times here. WTI has an API of about 35 gravity. Shale "oil" routinely comes in at 60 API, then you have the "equivalent" that's lighter yet or perhaps some wells "Blend" to a 60 API number. Why separate? Might have to do with different taxes and royalties. Like I said, my numbers came directly from the chief scientist of a major Bakken producer.  I'm confident he was giving me the total "liquids" number. 

It would take me a while to work out the shale profile site. Unfortunately I'm doing this on a mobile device and the thumbnail graphs I get are a bit tough to read. I can click on them, just takes more time and I might have done something wrong. Maybe they never consider natural gas liquids at all. Even butane and propane sell for considerably more than methane. You'll notice the pure play gas operators are constantly searching for the "wet gas" reservoirs, more profit. 

When something is reported as 'oil equivalent' it's nearly always (99.5% of the time) the case that they have converted the gas into the equivalent energy value of oil.  pentanes + are rolled into the crude if they were liquid at the point where the oil was metered, or counted as gas if they were gaseous at that point (it can be either) They don't try to convert any of it into a cash figure, nor do they report it by gravity or chemistry - it's only a rough estimate of the total volume of usable energy coming out of the well. It's a very skewed # for use in calculating cash output values because gas is only ~ 1/5th as valuable as oil on a per energy unit basis. Two different wells, one with 90% oil and 10% gas and the other reversed could have the same BOE production and one of them could be 4 or 5 times as valuable as the other.  

[Coffeeguyzz + 454]

There have been some great contributions on this thread.

 

The following is from my decade long observations of this 'Shale Revolution' with a somewhat granular look at 3 recent Bakken wells from Kraken.

General cost to Drill and Complete (D&C) an 'unconventional' well can range from under $3 million for ~5,000 foot laterals in the Niobrara (mononbore drilling playing a big role) to well over $10 million for various Permian Basin efforts.

Several Bakken operators now state ~$5 million to D&C, with Marathon claiming a recent 4 well/pad operation coming in at ~$4.3 million per, IIRC.

To depict an "average" cost is both fruitless and counterproductive, I believe.

This stance - eschewing "averages" - has been but one of a long string of differences between Dennis and myself.

Basin by basin, formation by formation, operator by operator, well by well ... if these vast differences are not recognized and taken into account, false conclusions will be projected from fundamentally flawed originating premises.

 

In a nutshell, to address Mr. Faber's original post and incorporating several of the excellent contributions upthread, it would seem reasonable to me that operators will immediately  curtail production in the unconventional world. (Continental has just announced this).

Looking forward, operators may incorporate new well D&C with a sharp eye on maximizing the expected FUTURE production profiles of the now shut in wells.

Incorporating artificially induced formation pressure (might want to look again closely at Mr. martinrylance's second post) along with the several excellent - and accurate - comments regarding reworking/artificial lift conditions associated with re-opening shut-ins, I will post a follow on comment on what might be expected regarding the status of thousands of now - or soon to be - unconventional wells taken offline.

 

[Ward Smith + 6,615]

@Coffeeguyzz, I think you and I are in the same page and if D is Dennis I agree even further

Way back when I was in computer science in university I had a prof who said, "Never mistake data for information". This about 4 decades ago, and it's only gotten worse, not better. I just spoke with one of my experts, now retired who worked for one of the majors. We spent about an hour discussing all of these points. He reiterated that anything less than 600 bbls/day of oil was considered a dog well. I asked about shaleprofile's numbers and he said, "I can't comment if I don't know how and where they got their numbers". I agree with you coffee that once data gets normalized by averaging, all the information is probably lost. 

As for Continental Resources, we'll soon have real data on what massively shutting down active producers does in the real world, and hopefully from that data can suss out some information about whether it's a good or bad idea.