Why do oilfields take damage when production is paused?

[Walter Faber + 48]

I have read repeatedly in articles that some types of oil reserves and some of the equipment used for extraction can take damage when production has to be stopped, implying that you cannot simply pause production and restart once demand bounces back. Could you please help me out with explanations and links to understand why this is the case? 
I am aware of economic damage which can endanger the company, I am asking explicitly for technological/gelological/chemical/physical factors here. 

Regards and thanks in advance

 

[Walter Faber + 48]

No one? Just asked the question on Quora as well: https://www.quora.com/unanswered/Is-it-true-that-pausing-oil-production-can-cause-damage-to-extraction-sites-and-oil-fields-If-yes-why-I-have-seen-this-problem-mentioned-in-several-news-reports-about-the-oil-glut

Edited April 21, 2020 by Walter Faber

[El Nikko + 2,145]

This is a total guess as it's not my area of expertise at all but if there is no flow from the reservoir I imagine the well could start to 'silt up' reducing the permiability of the rock (how easily fluid moves through the pore spaces) so when you restart production the flow rate will be much lower.

If you are asking about shale in particular I believe wells drilled in the last year can be shut in and when restarted they will over produce for a period of time and it takes something like 45-60 days to make up what has been lost during the shut in...just something I've read.

Edited April 21, 2020 by El Nikko

[El Nikko + 2,145]

Also I imagine that some wells in some conventional reservoirs might increase in pressure during a shut in so produce at a better rate when opened back up.

 

[Walter Faber + 48]

Thank you!

[Ward Smith + 6,615]

I did some research on this last week but was too busy to create a discussion. Thanks for doing it @Walter Faber

This paper had some interesting points

Generally speaking, after looking at a half dozen papers on the subject my feeling is it's not well researched vis a vis shut in versus abandoned. The mechanics are the same, roughly, with the exception that if there's still a lot of oil present the source rock contains more pressure than if it were mostly produced (which would be the case with abandonment) and therefore could repel the onslaught of water that generally causes problems with abandoned wells.  The same issues could apply to gas, or gassy oil, which is what LTO really is. 

[El Nikko + 2,145]

18 minutes ago, Ward Smith said:

I did some research on this last week but was too busy to create a discussion. Thanks for doing it @Walter Faber

This paper had some interesting points

Generally speaking, after looking at a half dozen papers on the subject my feeling is it's not well researched vis a vis shut in versus abandoned. The mechanics are the same, roughly, with the exception that if there's still a lot of oil present the source rock contains more pressure than if it were mostly produced (which would be the case with abandonment) and therefore could repel the onslaught of water that generally causes problems with abandoned wells.  The same issues could apply to gas, or gassy oil, which is what LTO really is. 

I was just thinking back to some articles about how the Iraqi reservoirs were also damaged due to sanctions/war etc and think excess water production was the problem as well.

 

[El Nikko + 2,145]

Just pondering but if you have a conventional reservoir with loads of wells drilled in it and you over produce from some and don't produce from others (due to what ever cause) I imagine it would cause production issues for nearby wells as the oil/water contact moves and some would end up producing loads of water.

 

[El Nikko + 2,145]

Some info on formation damage not really related to shut in production but interesting all the same

https://www.researchgate.net/publication/287511067_Reservoir_formation_damage_during_various_phases_of_oil_and_gas_recovery-_an_overview

[Ward Smith + 6,615]

1 hour ago, El Nikko said:

Just pondering but if you have a conventional reservoir with loads of wells drilled in it and you over produce from some and don't produce from others (due to what ever cause) I imagine it would cause production issues for nearby wells as the oil/water contact moves and some would end up producing loads of water.

IIRC you got a degree in mining? My understanding is the bane of every mine is water. At some point the cost of dealing with the water exceeds the value of the remaining ore.  I'm talking hard rock not coal. Even rock quarries usually fail when they hit water, then you end up with all these interesting skinny dip locations off the beaten path for teenage keggers, or so I've been told…

[BradleyPNW + 282]

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. 

[wrs + 893]

18 minutes ago, 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's a great quesion.  I don't think the comparison is even possible for example on Ghawar.  It's water flooded from the edges and I think there are only a couple of thousand really big wells that produce over 1kbbl/day.  I believe that the water cut used to be around 35% back in 2004 or so when it was last reported.  I assume it's much higher today.  When Abquiq was blown up they had to shut them in for a few days and they flared all the gas but I don't know what they did with the rest.  You could see the GOSP flares on the satellite images.

This could turn out to be a bigger problem if their storage backs up.  I wonder if that's not the real reason they chartered all those VLCCs.  Would serve them right if Ghawar dies as a result of this.

 

With shale it's a decision on a per well basis.  I think that most should restart after swabbing but they would have to work on getting the flow stable again.  It's not free.

Edited April 21, 2020 by wrs

[Ward Smith + 6,615]

20 minutes ago, 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. 

The g-damned hackers screwed up my response I'd meticulously typed up. Damn

Shorter version, proppant sands will get pulverized by the formation pressure of about 4000 psi or so. Said more but I'm too pissed to reenter 

[Geo B + 15]

There are really 2 separate issues for conventional and unconventional shale fields.

Most conventional fields are quite old, and have been using waterfloods for decades to keep the reservoirs pressurized and fluids moving. In a waterflood, you inject high pressure water on 1 end of the field and expect to recuperate that water + oil + gas on another end of the field. By continuously injecting water, you keep things moving underground through the rock pores. Now, if you shut in wells, you also need to stop injecting water, because the reservoir can only take so much. Once you stop injecting water, everything stops moving underground, the rock can swell, effectively closing the pores making impossible to restart the reservoir... or the oil can stick to the rock rather than flow through the water... there are many mechanics that would simply cause the oil to get trapped underground if we shut in these old conventional fields, and would take billions of dollars to get them restarted. So it's just not worth, better to produce the field at a loss for a few months than lose it forever. 

 

I would argue that unconventional shale fields are a lot easier to shut in and restart but in many cases there is a huge cost associated with that. Once a shale well is producing, if you shut it in for some time, sand will slowly accumulate in the horizontal effectively clogging the well off completely and there is nothing you can do to get this well back online without incurring huge costs by getting a crew out on location to clean out the well and bring it back online. So again engineers need to carefully evaluate the economics in this scenario to make sure that shutting in a well wouldnt end of causing more economic damage than just keeping the well online even through it is currently uneconomic. 

 

all this is to say... turning wells on and off isnt just a simple ordeal... you can turn them off for a couple hours, maybe a day, and not cause long term damage but shutting in some wells for a long period of time is essentially abandoning the asset. 

[BillKidd + 139]

I am not up to speed on 2020 thinking regarding damage from shutting in and it can differ in regards to conventional reservoirs versus unconventional.

On a sidenote, decades ago, I studied all of the published articles on area oilfields in my area. These were written by geologists who intimately worked those fields or studied them. Fascinating info and even more fascinating, and sad, was I recall two wonderful fields that were damaged such that they were ruined forever. It had to do with salt water encroaching and being pulled over the top of the oil such that the oil would not move throughout the reservoir any longer. I don't recall the technical reasons but it all made sense. This damage was done in the 40s and 50s best to my recollection. Tough lessons to learn, leaving huge fortunes in the ground. I always dreamt of someone discovering a way to reverse the damage and get that oil out. It's still there. And not deep... only 2,500 feet. These were uber permeable sandstone reservoirs.

Another sidenote is back then, in another area, I drilled a shallow well to hope to hit gas and it was just as anticipated, a huge payzone at 3,700 feet. The electric log showed gas over water. A beautiful sandstone payzone about 30 feet thick, with 18 feet of gas saturated sand and the bottom 12 feet holding saltwater. It was highly permeable. I was very worried to pull it too hard. I hired a petroleum engineer to give me an opinion on that and he explained how there was no worry... perforate the top ten feet and pull it hard with no fear. There was a drainage issue. An operator next door had purposely sabotaged my pipeline hookup for a year and for that year, he drained hell out of my acreage, he drilled a well (that had a pipeline) 330 feet off my lease line and produced it like mad. When my engineer gave me the green light, I pulled my well as hard as it would go. Even put a compressor on it and pulled it harder. Never had a problem and it was a great well.

[Ward Smith + 6,615]

My lost post had a lot of stuff like this presentation talks about.

I was feeling really good, explaining my pet theory that frac wells fail due to proppant collapse. Turns out I was probably right. Too bad I didn't think of it until now. Might have livened up the many shale discussions here. 

[Gerry Maddoux + 3,627]

16 minutes ago, Ward Smith said:

I was feeling really good, explaining my pet theory that frac wells fail due to proppant collapse. Turns out I was probably right. Too bad I didn't think of it until now. Might have livened up the many shale discussions here. 

I can certify that old conventional wells mostly go downhill when shut in. That's going to put a terrific burden on producers because it's not cheap to plug a well.

As to fracked wells, it has been my experience that it totally depends on the rock and the reservoir pressure. If this is done when there is high pressure abounding in rock with great fissures as attested by massive flow rates, then not much happens during a month-long shut-in (that's as long as I know anything about). But if done when there is a pressure sump, particularly if gas-lifting is being utilized, then you can kiss those wells goodbye.

Bottom line is that some fraction--it's a guess--of the thousands of wells that are currently being shut in will never be productive again. Sad but true.  

[El Nikko + 2,145]

47 minutes ago, BillKidd said:

I am not up to speed on 2020 thinking regarding damage from shutting in and it can differ in regards to conventional reservoirs versus unconventional.

On a sidenote, decades ago, I studied all of the published articles on area oilfields in my area. These were written by geologists who intimately worked those fields or studied them. Fascinating info and even more fascinating, and sad, was I recall two wonderful fields that were damaged such that they were ruined forever. It had to do with salt water encroaching and being pulled over the top of the oil such that the oil would not move throughout the reservoir any longer. I don't recall the technical reasons but it all made sense. This damage was done in the 40s and 50s best to my recollection. Tough lessons to learn, leaving huge fortunes in the ground. I always dreamt of someone discovering a way to reverse the damage and get that oil out. It's still there. And not deep... only 2,500 feet. These were uber permeable sandstone reservoirs.

Another sidenote is back then, in another area, I drilled a shallow well to hope to hit gas and it was just as anticipated, a huge payzone at 3,700 feet. The electric log showed gas over water. A beautiful sandstone payzone about 30 feet thick, with 18 feet of gas saturated sand and the bottom 12 feet holding saltwater. It was highly permeable. I was very worried to pull it too hard. I hired a petroleum engineer to give me an opinion on that and he explained how there was no worry... perforate the top ten feet and pull it hard with no fear. There was a drainage issue. An operator next door had purposely sabotaged my pipeline hookup for a year and for that year, he drained hell out of my acreage, he drilled a well (that had a pipeline) 330 feet off my lease line and produced it like mad. When my engineer gave me the green light, I pulled my well as hard as it would go. Even put a compressor on it and pulled it harder. Never had a problem and it was a great well.

That could be what is described as water coning maybe?

[BillKidd + 139]

3 minutes ago, El Nikko said:

That could be what is described as water coning maybe?

Coning is more like what I described as my fear of that well I drilled. The two fields I described, it was more than that. It was something like the oil's molecular attraction to the grains of sand got changed somehow and it would never again move. I don't recall the details but it was interesting because it was such a tragic mistake to screw up fields like that which had dozens of great wells each. The fields had nothing to do with one another; the were just tapping into the same zone but different reservoirs. They were 30 miles apart, had nothing to do with one another.

[El Nikko + 2,145]

9 minutes ago, BillKidd said:

Coning is more like what I described as my fear of that well I drilled. The two fields I described, it was more than that. It was something like the oil's molecular attraction to the grains of sand got changed somehow and it would never again move. I don't recall the details but it was interesting because it was such a tragic mistake to screw up fields like that which had dozens of great wells each. The fields had nothing to do with one another; the were just tapping into the same zone but different reservoirs. They were 30 miles apart, had nothing to do with one another.

That could be an amazing project for a PHD student or reservoir engineer one day.

[Coffeeguyzz + 454]

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.

[Gerry Maddoux + 3,627]

^ Good info. Thanks. Vis a vis my point, those Marcellus wells enjoy enormous pressure heads.

[0R0 + 6,251]

3 hours ago, 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. 

 

1 hour ago, 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.

I think that more of the geologies are able to retain proppant structures as they are without clogging up the fissures or the well bore. In many situations the wells are shut for weeks while a child well is fracked. So we know it is a matter of routine to have them shut in without much change in performance for a few weeks. 

[Ward Smith + 6,615]

Found This link discussing well pressures

It's not geared for production but drilling, however the physics is essentially the same. 

@James Reganor @Douglas Buckland might be willing to jump in here? Can't remember what kind of engineer @Tom Kirkman is. 

[James Regan + 1,776]

22 minutes ago, Ward Smith said:

Found This link discussing well pressures

It's not geared for production but drilling, however the physics is essentially the same. 

@James Reganor @Douglas Buckland might be willing to jump in here? Can't remember what kind of engineer @Tom Kirkman is. 

Doug will definitely embellish not sure if this is relevant as I haven't read the whole thread, after running casing and cementing it in you run the new bit in to start the new section (smaller diameter) you drill out any cement and once you have circulated out new cuttings etc or are sure your into formation, you slowly pressure up with a known mud weight until it LEAKS OFF, ie the formation takes the pressure exerted, you basically fracture the new hole, now you know the Maximum allowable mud weight that you can use before you start drilling again. You have basically proved the max pressure your shoe will handle, as you drill ahead this will change as you will inevitably change mud properties. This data is very important should you get into a well kill situation.

Production wells are fragile and can become easily damaged due to lack of flow, the balance of pore pressure to maintain the desired choked flow is normally designed for longevity, ie if you have fractured or perforated a well, it has a high probability of becoming blocked up, especially if you stop the cycle. This is a science on its own, however its not the end of the world, if a know producers stops producing you, rig up and work over the well and normally replace all the production tools, very common but expensive especially if your well is marginal. Offshore wells are shut in all the time for work overs, not sure how often its done on land, but offshore your talking of wells producing 60,000Bbls a day and more bigger scale. Kind of makes sense whey would you drill wells in the middle of the ocean if they were not very productive this is the main difference between punching hundreds of holes on land to well positioned high producing wells offshore.

Hope this helped...

To be honest Ward, if we see oil while drilling and exploration well we are in deep shit, we never see the stuff unless we have a well test program, we get them with each of the end zone and then leave and let the production teams and normally a platform come in, it can be up to two years from when we drilled out the wells until the final package comes to drill out and start producing.

Edited April 21, 2020 by James Regan