Why do oilfields take damage when production is paused?

[wrs + 893]

14 hours ago, D Coyne said:

wrs,

Interesting chart. Note that after 6 months output fell back to rate of one month before shut down for fracking the child well in September 2019, so the bump in output is short lived, this is perhaps the so called "halo effect".  Thanks.

Great well, the average 2018 Permian well would have about 294 kb of oil output and 1.1 BCF of natural gas of cumulative output at 66 months.  The Average 2014 well has cumulative output at 66 months of about 151 kbo and about 595 million CF of cumulative gas.  So your well was probably a top 3% well of all Permian horizontal wells completed in 2014, not a typical well.

Do you have an idea of full cycle costs for that well (land, pad cost, storage tanks, gathering lines, abandonment cost as well ad D+C)?

Dennis,

I think the success of the well is due to the expertise of the operator.  He has worked hard to find out what the best flow and choke settings are.  He was never one to have a high IP because he didn't want to lose formation pressure too quickly.  So he told me they call him the choke whisperer.  He is in a position to take a personal interest in his wells because he has less of them than a public company.  If the public companies put as much personal interest into their wells as he has, they would probably do better but that's part of the weakness of the public company. 

I am sure that the "expert" here manages his wells in much the same way that my indpendent does, with a lot of care and concern for managing the resource and getting the most out of his investments of labor and money.  That is what every mineral owner wants in an operator but unfortunately it's not what you get in the majority, particularly in a boom.  The mineral owners who have the "expert" as their operator are in good hands.  It's just too bad he can't acknowledge that there are others like him in the shale business.  

I can't give you the full costs over the lifetime. I just know it cost about $15m to drill and complete.  However, he ran into some drilling problems and had to side track the well at 8000 feet so that increased the cost.  He has since drilled and completed the 4 others on my section for about $5m each.  Those are all 4500 foot laterals.  This first well was a learning experience so that's part of why it was so expensive.

 

Edited April 28, 2020 by wrs

[D Coyne + 305]

41 minutes ago, wrs said:

Dennis,

I think the success of the well is due to the expertise of the operator.  He has worked hard to find out what the best flow and choke settings are.  He was never one to have a high IP because he didn't want to lose formation pressure too quickly.  So he told me they call him the choke whisperer.  He is in a position to take a personal interest in his wells because he has less of them than a public company.  If the public companies put as much personal interest into their wells as he has, they would probably do better but that's part of the weakness of the public company. 

I am sure that the "expert" here manages his wells in much the same way that my indpendent does, with a lot of care and concern for managing the resource and getting the most out of his investments of labor and money.  That is what every mineral owner wants in an operator but unfortunately it's not what you get in the majority, particularly in a boom.  The mineral owners who have the "expert" as their operator are in good hands.  It's just too bad he can't acknowledge that there are others like him in the shale business.  

I can't give you the full costs over the lifetime. I just know it cost about $15m to drill and complete.  However, he ran into some drilling problems and had to side track the well at 8000 feet so that increased the cost.  He has since drilled and completed the 4 others on my section for about $5m each.  Those are all 4500 foot laterals.  This first well was a learning experience so that's part of why it was so expensive.

 

WRS,

Thanks. I think Mr Shellman's does not like the way some of the public companies are run.  Heck he may know your expert, having been in the business for 50 years, though I suppose their are a lot of oil professionals in Texas and everyone does not not everyone, it is a big state, but in some ways a small world.

You have told me this before, but I forget now, what roughly is the 36 month cumulative oil and cumulative natural gas for all the tight oil wells on your leases that have produced for at least 36 months (average per well).  

I believe that 2014 well had roughly 400 kb of output after 66 months (the well behind that excellent chart above), for all Permian horizontal oil wells completed in the Permian basin in 2014 (1747 wells) only 25 wells had cumulative output at 66 months of more than 400 kbo or 1.4% of all wells completed.  So your well is exceptional indeed.  Congrats.  If you don't have the 36 month cumulative for the other three wells (they may be younger than 3 years), could you give me their 12 month or 24 month cumulative output average (or for each well whatever you prefer), interested to see how they compare to the rest of the Permian basin for similar vintage well.

 

Thanks, great stuff.

Edited April 28, 2020 by D Coyne

[D Coyne + 305]

16 hours ago, Mike Shellman said:

@Dennis Coyne you asked me for an opinion and I gave you one. Don't now chide me for it because you don't agree with it and stop putting damn words in my mouth. I have never referred to myself as an "expert" on anything. Now, once again, I am forced to endure more dung heap from the Wolfcamp Ferrari owner, the recipient of millions in free royalty money and all the unlimited oil knowledge that goes with that. I suddenly feel like I need to be wire brushed, head to toe. 

If you children of shale believe in it so much, put your money where your mouth is: don't go buy a few shares in Pioneer, or FANG...that's for girls. Get you some working interest in a $10MM well and wait 4 years to get your money back, if ever. Pay an AFE, pay cost overruns, draw down on your personal checking account to facilitate a side track, pay your share of fishing a $250K ESP...loose some sleep over it; get an ulcer. You'll change your mind about all the stupid, self serving dribble you read on the internet, trust me. 

Shale oil is a financial disaster funded by socialized capital, now asking for socialized bailouts. All royalty owners believe in because its free money to them. If it was a healthy sector of my industry it could withstand whatever OPEC, or Russia, or a little bug that looks like a dog toy, threw at it. It can't. That's exactly why its now whining for help, for a bailout, for negative interest rates, more sanctions, tariffs, the right to flare at will. Its desperate. In the way you have all observed it in the past, its a goner. 

Cimerex, by the way, has $2B of long term debt and a debt to equity ratio of 0.73, which is horrible. It once traded at $146 a share and is now down to $22. While shareholder equity was being destroyed indeed its leader was making lots of bucks: https://www1.salary.com/Thomas-E-Jorden-Salary-Bonus-Stock-Options-for-CIMAREX-ENERGY-CO.html  His parachute is very Whitting like. 

Mr Shellman,

I apologize for calling you an expert, not considered an insult where I come from, from my perspective you are an expert in what it takes to be a successful oil producer for 5 decades in a very tough business.

I apologize for misinterpreting what you are trying to convey.  I took your meaning of burying money in the back yard as a better investment than tight oil at $70/bo as a suggestion that it was not a particularly good investment.  Generally the bury in the back yard approach gets you a long term real return of about  negative 2% per year, so seems pretty bad investment strategy to me. 

If tight oil investment is worse than that it suggests little investment would take place by any rational businessmen in the future, so I make the leap that perhaps there will be little tight oil produced in the future as a consequence.

To me that seems unfortunate, the US is likely to need that oil in the future. 

I would think there might be some future oil price where tight oil can be done right (little to no debt) and be profitable.

My guess is that you would strongly disagree, but you have not said so specifically, just my impression.

Part of this may be that my expectation is that scarce oil after the peak may lead to oil prices higher than $90/bo in 2020$, you perhaps have a very different expectation of future oil prices and/or when World oil output might reach its final peak.

Edited April 28, 2020 by D Coyne

[Ding Ray Chung + 8]

Thanks for sharing this chart!

Going back to our "pretend" game, if such well was on a BK auction I would not bid on it. People are prone on visual biases, and this chart makes the well look good, so I would be bidding against people who find it attractive. However, my concerns would be:

1. During the first shut-in, the well looks like it lost productivity. The decline trend post re-opening looks to me like a continuation of the curve, meaning that the production lost during the shutdown cannot be recouped ( I assume pressure loss in the formation continued even without production). Now what happens if we have to wait 4-6 months for prices to come back? 12 months? 

2. The second shut-in was happening during stimulation nearby (halo effect?). However, the decline post the initial bump was steeper then the natural decline before the shut-in.  If the wells were communicating, then when both are fully open the pressure dissipation is shared. That doesn't look good for the production/economics.

People here say, the "wells will likely be fine after shut-in". But what does "fine" mean? Does it mean they'll produce? Or does it mean that they'll pick up production from where they were left before the shut-in. These differ enormously economically.

21 hours ago, wrs said:

Here is the production report through Feb 2020 for one of the older producing Wolfcamp wells out in the Permian.  Not the oldest but it's one of the ones that first used slick water fracks with a lot of sand instead of a lot of gel.  The well had to be shut in for two longer periods twice in it's life.  The first time was the month of December 2015 after a gas plant explosion which had some kind of back pressure effect so they kept it shut in until that was fixed.  The second time was last summer when they were drilling and completing three new wells. Two were deeper and in different locations on the lease but one was a child well of this one.  Apparently the completion of the child well and the shutin period allowed this well to have triple the previous production.  This isn't the only well I have seen this happen with.  The oldest XTO well experienced the same kind of increase in output after completing a child well and a shut in period.  I don't know what the explanation would be but this is the data.  This well contradicts a lot of the typical claims made against shale.  The total production is about 400kbbl oil and 3Bcf of gas, so far.  This well other than lifting costs, taxes and royalty is FCF to it's operator.

 

 

 

[wrs + 893]

48 minutes ago, Ding Ray Chung said:

Thanks for sharing this chart!

Going back to our "pretend" game, if such well was on a BK auction I would not bid on it. People are prone on visual biases, and this chart makes the well look good, so I would be bidding against people who find it attractive. However, my concerns would be:

1. During the first shut-in, the well looks like it lost productivity. The decline trend post re-opening looks to me like a continuation of the curve, meaning that the production lost during the shutdown cannot be recouped ( I assume pressure loss in the formation continued even without production). Now what happens if we have to wait 4-6 months for prices to come back? 12 months? 

2. The second shut-in was happening during stimulation nearby (halo effect?). However, the decline post the initial bump was steeper then the natural decline before the shut-in.  If the wells were communicating, then when both are fully open the pressure dissipation is shared. That doesn't look good for the production/economics.

People here say, the "wells will likely be fine after shut-in". But what does "fine" mean? Does it mean they'll produce? Or does it mean that they'll pick up production from where they were left before the shut-in. These differ enormously economically.

 

I actually mislabeled the shutin period in the first case.  It was 45 days and thus, the production in January was only a partial month.  The November data was for a full month and then the well was shut in right at the start of December for some kind of maintenance and the gas plant blew up two days later.  So they had to wait until the pipeline was available before they could finish the maintenance.  The whole process was about 45 days.  At thetime I was getting daily production reports so I was able to track the number of days in the shut in.  

So I agree that the first shut in is more like what we sould see.  You don't probably get more out than before but with the halo effect you do.  I think if most wells come back and behave as in the first shut-in that would be acceptable or "fine".

Edited April 28, 2020 by wrs

[Ding Ray Chung + 8]

I am looking at Feb 2016. If you fit the natural decline curve, Feb. 2016 production seems to be exactly where you would expect it, if no shut-ins have taken place. No big deal in this case. But what if the shutdown was 6-12 months? If the reservoir is decaying even without production (oil re-adsorbtion in the rock? loss of pressure?), then that's a problem, IMO...

34 minutes ago, wrs said:

I actually mislabeled the shutin period in the first case.  It was 45 days and thus, the production in January was only a partial month.  The November data was for a full month and then the well was shut in right at the start of December for some kind of maintenance and the gas plant blew up two days later.  So they had to wait until the pipeline was available before they could finish the maintenance.  The whole process was about 45 days.  At thetime I was getting daily production reports so I was able to track the number of days in the shut in.  

So I agree that the first shut in is more like what we sould see.  You don't probably get more out than before but with the halo effect you do.  I think if most wells come back and behave as in the first shut-in that would be acceptable or "fine".

 

[wrs + 893]

8 minutes ago, Ding Ray Chung said:

I am looking at Feb 2016. If you fit the natural decline curve, Feb. 2016 production seems to be exactly where you would expect it, if no shut-ins have taken place. No big deal in this case. But what if the shutdown was 6-12 months? If the reservoir is decaying even without production (oil re-adsorbtion in the rock? loss of pressure?), then that's a problem, IMO...

 

It's always looked like that to me too.  I don't know what a 6-12 month shutin would look like but I doubt anyone can go that long without income unless they want to just give the well up.  I know the operator is planning to wait for prices over $35 for 60 days so that could be 6 months.  It's a risk but really there is no option if you can't sell the oil.  That well has 12000 barrels of oil and water storage capability in it's tank battery so they could easily keep it open for that long and just pump the oil into the tanks to be sold later.

He added tanks for the new wells and there was also another tank battery of the same size for the second well he drilled in 2017. He may have enough storage for two or three months of lower production on site.  I haven't been out to see how much he added this summer but I would expect the same per well so probably there is at least 60kbbl of tank battery storage on site.  Half of the battery was used for water storage when he didn't have his own disposal wells but in 2018 he got both wells on a water pipeline to his disposal wells.  He may not have built the water storage into the new tank batteries but I bet he did because he likes the cookie cutter designs.

[Ward Smith + 6,615]

2 hours ago, Ding Ray Chung said:

the production lost during the shutdown cannot be recouped ( I assume pressure loss in the formation continued even without production)

I'm curious why you believe pressure loss would continue in a shut in well? If the wellhead isn't leaking where is that pressure going? I think it will equalize to a prior value. I'm not a reservoir engineer by any means

[nsdp + 449]

5 hours ago, Ward Smith said:

I'm curious why you believe pressure loss would continue in a shut in well? If the well head isn't leaking where is that pressure going? I think it will equalize to a prior value. I'm not a reservoir engineer by any means

My question would be does your operator have enough cash and equity to stand a long shut in and rework the well if necessary.  In 2012 KSA tested the old Dammam field which they shutin in  1983. Field appears to be capable of 350,000 b/d if reworked. KSA took DAMMAM off line because of Ghwar was starting production and heavy oil was worthless.

[Ding Ray Chung + 8]

It may have to do with imbibition into the rock, away from the frac face, there is some literature on that. But I really don't know, I was just observing that Feb 2016 was what you would expect/extrapolate from normal decline with production, meaning that the shut-in resulted in production loss. 45 days is tolerable, but if you bid on a producing well, then keep it shut-in for 6-9-12 months, and then when you open the valve production is significantly less than pre-shut-in levels... well that makes it not a very sound investment.

For this well, wrs mentioned that it was carefully drawn with choked flow. My understanding is that this prolongs the productive period as more associated gas is kept in to assist with lift, so I get the benefit... However, choked flow keeps more pressure in the rock pores for imbibition. I wonder if wells that are drawn more aggressively, will actually perform better during shut in. The reason is that they will have steeper pressure gradient from the rock towards the well bore, and less imbibition. So during shut-in the pressure will equalize a bit, elevating the well-bore pressure, and maybe even get a bit of a spike in production, post opening...

In any case, a lot of unknowns. I read people say, "the wells may need to be re-worked, but will be fine"... Well, if re-work is needed, economically that's more like a DUC then, rather than an operating well. So going back to our discussion: I'd be careful with operating wells that will be bid higher than DUCs, but maybe no  more valuable than DUCs economically, in fact maybe even less. I'd say if values are to be found, it will be in the DUCs clearance bin.

 

14 hours ago, Ward Smith said:

I'm curious why you believe pressure loss would continue in a shut in well? If the wellhead isn't leaking where is that pressure going? I think it will equalize to a prior value. I'm not a reservoir engineer by any means

 

 

[KH 2020 + 1]

I believe the biggest risk to shutting in wells will come from mature fields, since older wells fight depletion (low oil production) or high water cuts from waterflooding. Wells typically function better when they are continuously pumping, as it keeps fines/solids suspended in the liquid which makes them easier to transport to surface and you get more consistent coverage from your corrosion/scale inhibiting chemicals. 

I've worked a lot of water floods and can say that high water volume wells will more likely corrode and have scale issues. Water is cancer in the oilfield, as it's expensive to produce and dispose. If you leave a well shut in, you aren't spending money treating for corrosion and a warm, moist, static downhole environment will manifest itself to severe bacteria colonies, which will turn your equipment into swiss cheese. When and if you can retrieve the equipment, you'll have to spend extra money to replace the equipment or if your tubulars are stuck or parted due to corrosion, you'll need to consider fishing costs. 

Since 80-90% of the wells in the U.S. make 10 BOPD or less (see image below), this is why a lot of production could be at risk, especially if it's shut in for longer than a year. 

On the other hand, if you don't need to worry about corrosion/scale/solids, the well shouldn't have issues returning to production. In fact, as someone else mentioned, you should see better production temporarily as the well has had time to pressure back up. 

[Wombat + 1,028]

On 4/22/2020 at 3:55 AM, BradleyPNW said:

I'd be interested in the comparative risk of shut-in between types. Is shutting in a Russian well worse than a Saudi well? How does closing US shale wells compare to foreign competition? 

My hope is US shale is easier to restart compared to foreign oil industry. 

That is certainly what an OP article hinted at last week. Apparently, Russian, ME wells take massive damage from shut-ins due to porosity of the rock, which is higher, hence the cheap oil. Shale on the other hand, needs to be fracked, they don't call it "tight oil", for nothing, and therefore suffers less damage. Don't ask me if shut-in shale wells would need to be re-fracked, not an oil engineer. Maybe someone here can tell us?

[iron5 + 1]

On 4/21/2020 at 3:25 PM, Coffeeguyzz said:

Mr. Faber

Great question that will hopefully encourage multiple informed (and informative) responses.

The last link from Mr. Smith (Vincent's 2015 presentation) is especially enlightening on so many levels, not the least of which it provides an almost 'time capsule' perspective specific to the challenges of completions in general and proppant selection/use in particular.

(Many of the referenced sources from Vincent are 2013 studies or earlier).

Robust, pioneering efforts, certainly, but somewhat archaic when contrasted to 2020 completion approaches.

 

I'll weigh in a bit more later, but I will offer up this  data point from the most recent (4/14/20) release from North Dakota ... the Director's Cut showing results up to February, 2020.

With 16, 118 producing wells, there were  2,091 categorized as Inactive, that is, shut in for more than 3 months and less than 12 months.  (Abandoned are now included in this category, but I have not kept up with how much this 'real world' abandonment is administrative labelling for various reasons versus actual permant plug and abandonment).

(January's report had 16,014 Producers with 2,607 Inactive, which might imply several older, heretofore underperformers were tweaked and brought 'up to speed').

 

My general understanding is that 'shale' wells can remain offline for extended periods with minimal permanent damage, although rejuvenation activities might be needed/desired.

I have seen a handful of Marcellus wells that remained dormant for 3 to 4 years after fracturing before finally being turned inline.

There are temporary abandonments versus permanent abandonments.  I also know that wells will be drilled and not completed if the economy disallows it.  They will then be reopened and completed once the economics are sensical.

[Wombat + 1,028]

On 4/22/2020 at 6:11 PM, James Regan said:

Looking for info on what seems like a simple question, no-one really wants to take on the subject, most info dances around the idea.

https://www.spglobal.com/marketintelligence/en/news-insights/latest-news-headlines/no-place-to-go-oil-storage-filling-up-amid-collapsing-demand-excess-production-57865154

This one goes into the complexities of gas hydrates and water injection etc, there is obviously a lot of reasons to keep an oil or gas well flowing. (Good luck understanding this one if you do then you should probably not on this forum lol)

https://petrowiki.org/PEH:Well_Production_Problems#Introduction

More reasons to keep the well producing.

https://www.arab-oil-naturalgas.com/natural-gas-well-production-problems/

This statement alone shows the complexities and damage that can arise with just shutting a well in.

Some producers will prefer to take the hit of negative prices -- paying someone to take the oil off their hands -- to the long-term costs of shutting down a well. In the aftermath of the last major downturn, a North Dakota sour crude went to a negative 50 cents.

https://www.worldoil.com/news/2020/3/27/oil-at-historic-lows-beginning-to-force-shut-in-of-wells

So based on some short surfing, there are many reasons to not wanting to shut in a producing well, all of the come back to cost and fiscal viability ie start up costs after shutting in a well, many od which in the unconventional sector are already at balance point in relation to cost and return, if the balance point is so finite that working over a well is a major factor determining the viability of said wells life span then it is probably a low producing well with a short expected life span.

IMO and Googles.... Keep it pumping the cost and risk of start up outweigh shutting the well in, so the previous information that unconventional wells were close the tap and then open it is not the case, mass shutdown of unconventional wells will probably crater most companies....

There is no need for mass shutdown of LTO, just a quarter, coz natural field decline so rapid anyway. Add this to collapse in rig count and completion of DUC's, production falls 50% in 7-8 months. Then there is collapse in Canadian production, plus OPEC etc, deepwater, and production will quickly fall to meet demand. Real problem is that once demand = production, massive inventory overhang will persist for years, suppressing prices and activity. Not the death of the industry, but a major body blow that will take considerable time to heal from. 

[Wombat + 1,028]

On 4/25/2020 at 3:10 AM, D Coyne said:

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/

That's interesting, here in Australia, our LNG plants are far more profitable if they rich in NGL's coz the Asians pay a fortune for the stuff.

[D Coyne + 305]

2 minutes ago, Wombat said:

That's interesting, here in Australia, our LNG plants are far more profitable if they rich in NGL's coz the Asians pay a fortune for the stuff.

Wombat,

What is the price for a barrel of NGL vs crude?  Note that in the US there is an excess supply of NGL so only worth about 25% of a barrel of crude on average.  The Natural gas is also over supplied so dry natural gas gets only about $1 per thousand cubic feet at the wellhead.  

[D Coyne + 305]

42 minutes ago, Wombat said:

There is no need for mass shutdown of LTO, just a quarter, coz natural field decline so rapid anyway. Add this to collapse in rig count and completion of DUC's, production falls 50% in 7-8 months. Then there is collapse in Canadian production, plus OPEC etc, deepwater, and production will quickly fall to meet demand. Real problem is that once demand = production, massive inventory overhang will persist for years, suppressing prices and activity. Not the death of the industry, but a major body blow that will take considerable time to heal from. 

Wombat,

My models suggest about 15 to 18 months for US LTO to fall from 8 Mb/d to 4 Mb/d with a zero tight oil completion rate.  This does not take into account potential shut ins for tight oil wells that were producing at the end of February 2020, if 2 Mb/d of low output tight oil wells are shut in immediately (about 25% of current tight oil output), then we could see 3900 kb/d after 5 months (August 2020) and 2800 kb/d by Jan 2021 (this assumes zero new tight oil wells start flowing from April 2020 to Jan 2021 or 10 months).

In short, your estimates are quite reasonable.

[Wombat + 1,028]

1 hour ago, D Coyne said:

Wombat,

What is the price for a barrel of NGL vs crude?  Note that in the US there is an excess supply of NGL so only worth about 25% of a barrel of crude on average.  The Natural gas is also over supplied so dry natural gas gets only about $1 per thousand cubic feet at the wellhead.  

Propane currently gets you US$500/tonne. I don't know how much a barrel of oil weighs but propane weighs 0.5g/cm cubed. I hope that helps?

[jason dinges + 6]

Yes, if the formation is a sand formation the sand can tighten up and restrict flow when turned on. Years ago, I had a friend with a new well making 200 a day. Back then the State allocated the amount of oil you could pump. After 30 days thee state ran its test and required him to slow it down to 50 a day.  6 months later I was with him and he wanted to speed it up for a few days just to see what it would still do. It just stayed at 50 s the sand had collapsed and tightened up when flow was restricted. Could certainly be an issue with frac wells also. Other thing come into play if you shut down wells, you can violate your lease terms by not producing, the chemical programs can break down and you suffer iron damage and pump damage. If it is and extended shut down as this one may well be a shut down for several years before break even is again seen, you have to lay of daily pumpers, getting them back may be difficult. Starting with new people can be challenging and costly. With non use, packers and tubing anchors and things like that can freeze up and become impossible to remove with major expense when the time comes to work on the wells. Electric motors and above ground pumps can experience rodent damage as they set idle. In order to hold a lease in Kansas, you must produce and sell oil at least once a year or be subject to losing your lease in a legal battle. In order to run them once in a while, you would need to rehire pumpers and then lay them off again after a week or two.  Property taxes, Insurance, and State compliance still goes on even if you do not have revenue.  Good help can only sweep shop floors so many times. If you lay off good help, you may well lose them. Unattended wells can develop undetected leaks and spill which adds to the grief. 

[Wombat + 1,028]

1 hour ago, D Coyne said:

Wombat,

My models suggest about 15 to 18 months for US LTO to fall from 8 Mb/d to 4 Mb/d with a zero tight oil completion rate.  This does not take into account potential shut ins for tight oil wells that were producing at the end of February 2020, if 2 Mb/d of low output tight oil wells are shut in immediately (about 25% of current tight oil output), then we could see 3900 kb/d after 5 months (August 2020) and 2800 kb/d by Jan 2021 (this assumes zero new tight oil wells start flowing from April 2020 to Jan 2021 or 10 months).

In short, your estimates are quite reasonable.

Thankyou, all that maths I did during my Physics degree was useful after all

[Wombat + 1,028]

16 minutes ago, Wombat said:

Propane currently gets you US$500/tonne. I don't know how much a barrel of oil weighs but propane weighs 0.5g/cm cubed. I hope that helps?

Best I can come up with is about $30/barrel, which is half what it was last few years. Apparently, there is a looming glut of the stuff on its way, not just from USA, but SA, Qatar, and others, so I am glad you asked! Changes my expectations for how our local LNG companies will perform in the future, not gonna buy back in till the share prices drop again later in the year

[Dan Clemmensen + 1,011]

2 hours ago, Wombat said:

There is no need for mass shutdown of LTO, just a quarter, coz natural field decline so rapid anyway. Add this to collapse in rig count and completion of DUC's, production falls 50% in 7-8 months. Then there is collapse in Canadian production, plus OPEC etc, deepwater, and production will quickly fall to meet demand. Real problem is that once demand = production, massive inventory overhang will persist for years, suppressing prices and activity. Not the death of the industry, but a major body blow that will take considerable time to heal from. 

In the immediate short term (weeks) there will be a need for some sort of production slowdown due to storage shortage in addition to normal decline. In the mid-term, your analysis of "natural" production decline probably holds (I have no expertise so I just believe you). After we get to where "natural" decline has balanced production to consumption, the market kicks back in, in a three-way dance between production, consumption, and storage. The storage overhang must be (roughly) the difference between "maxed out" and "reasonable". What's that? maybe 1 billion bbl? The time taken to drain that amount will be the time needed and used by producers to get back to "normal(?!)", whatever that will be. This process will be a complex dance with different parts of the industry reacting very differently. You have a reasonable model for natural decline, but you need models for consumption recovery and production recovery before you can evaluate storage overhang drain. And of course the three models interact with each other. This makes my head hurt. In any event, it's unlikely that storage drawdown will be less than 1 million bbl/day or more than 10 million bbl/day, so it will take more than three months and less than three years. the highest-cost producers will not make a profit until the end of that time. Note that this gross oversimplification does not account for the different types of crude and the potential changes in refinery input mix.

[Wombat + 1,028]

15 minutes ago, Dan Clemmensen said:

In the immediate short term (weeks) there will be a need for some sort of production slowdown due to storage shortage in addition to normal decline. In the mid-term, your analysis of "natural" production decline probably holds (I have no expertise so I just believe you). After we get to where "natural" decline has balanced production to consumption, the market kicks back in, in a three-way dance between production, consumption, and storage. The storage overhang must be (roughly) the difference between "maxed out" and "reasonable". What's that? maybe 1 billion bbl? The time taken to drain that amount will be the time needed and used by producers to get back to "normal(?!)", whatever that will be. This process will be a complex dance with different parts of the industry reacting very differently. You have a reasonable model for natural decline, but you need models for consumption recovery and production recovery before you can evaluate storage overhang drain. And of course the three models interact with each other. This makes my head hurt. In any event, it's unlikely that storage drawdown will be less than 1 million bbl/day or more than 10 million bbl/day, so it will take more than three months and less than three years. the highest-cost producers will not make a profit until the end of that time. Note that this gross oversimplification does not account for the different types of crude and the potential changes in refinery input mix.

Dan, in complex systems, it is better to take a "top-down" historical approach than a "bottom up" holistic approach. After the oil crash of 2014, the inventory overhang peaked at 300mb. It took until January this year to work off. Admittedly, the US was ramping up production rapidly, but global demand was rising rapidly, and it eventually took 3 years of OPEC cuts to do the job. Now there is about 600mb overhang, and even if all countries were to lift lockdown tomorrow, the global recession will knock 10% of prior covid demand for several years. In other words, if history is any guide, the inventories won't go back to "normal" for at least 6-7 years. Sure, there will be violent swings either way as countries compete for market share one moment, try to maximise price the next, but it all averages out over time and it much easier to make predictions based on historical fact than try to build an impossibly complex model that will always be wrong due to too many inputs with large "error bars". Same applies to climate modelling. They do the same silly thing coz they have never done a physics experiment and don't understand the concept of "cascading errors". Hope that helps:)

[D Coyne + 305]

53 minutes ago, Wombat said:

Best I can come up with is about $30/barrel, which is half what it was last few years. Apparently, there is a looming glut of the stuff on its way, not just from USA, but SA, Qatar, and others, so I am glad you asked! Changes my expectations for how our local LNG companies will perform in the future, not gonna buy back in till the share prices drop again later in the year

I get about $40/b for propane at $500/ metric tonne.  Using US units I have 1 US gallon propane=4.2 pounds, 1 metric tonne=2204 pounds and 1 barrel=42 US gallons, so 2204 pounds propane=2204/4.2=525 gallons propane, 525/42=12.5 barrels propane, and 500/12.5=$40/barrel propane.  In the US the price of propane is about $14/b, but this is only a portion of the NGL stream.  Not sure about prices of other products such as ethane and butane, etc.  Propane is about 37% of the US hydrocarbon gas liquid stream (this excludes pentanes plus). Ethane is about 43% of the HGL produced , the rest is butane and isobutane.

Thanks for the info.

[I. Thunkit + 2]

Interesting topic. I have been wondering why producers don't all get together and simply agree to create an artificial supply shortage by completely shutting down for a month or two. By that time demand will have recovered and the price could easily go sky high, $100 a barrel or more, and they will recoup any losses.
The way things stand right now, with production exceeding demand and storage  100% full, there can be only one consequence, forced shut downs.
If that causes many wells to be abandoned, as the current discussion would suggest, there will be one helluva shortage anyway when C19 disappears. Prices could easily be $150 a barrel in six months time.