Why do oilfields take damage when production is paused?

[NickW + 2,714]

4 hours ago, wrs said:

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.

When I was there in 2010 -12 drilling and workover crews were telling me it was nearer 70%

Aramco where shutting  down old wells all the time. Leave them for a few years and then hold in reserve for when prices suited a restart. Id assume from that that damage was rwlatively small. More issues I understand from over working a well. 

[Douglas Buckland + 6,308]

We need a reservoir engineer or a production engineer to respond to this question. Everything mentioned so far are drilling/well design concerns.

PS: If you fracture/breakdown the rock during a leak-off test, you should start packing your bags...

Edited April 22, 2020 by Douglas Buckland
Hhh

[LANDMAN X + 181]

Doug, what is a leak off test?  How are you doing in that small shut down area in SE Asia?  Any word on getting out?  Still shut down here in Denver but looks like liberal gov is going to start opening things up in phases this week?  On shutting down wells, why can't they just do a little choking on the producing wells to keep older wells from destruction later?  Above my grade for never worked on the rigs.  Title only.  Wolves are going to start barking at the doors which causes love to fly out the window..hope economy gets going soon?  Enjoy your comments.      

[Douglas Buckland + 6,308]

14 minutes ago, LANDMAN X said:

Doug, what is a leak off test?  How are you doing in that small shut down area in SE Asia?  Any word on getting out?  Still shut down here in Denver but looks like liberal gov is going to start opening things up in phases this week?  On shutting down wells, why can't they just do a little choking on the producing wells to keep older wells from destruction later?  Above my grade for never worked on the rigs.  Title only.  Wolves are going to start barking at the doors which causes love to fly out the window..hope economy gets going soon?  Enjoy your comments.      

When you finish drilling a section of the well, then run casing and cement it in place, you need to know the strength of the rock at this ‘casing shoe’ (theoretically the weakest spot in the well as you drill ahead). You need this information for well control purposes, to determine how far you can drill ahead, and to know the maximum mud weight you can use while drilling (among other things).

To do this you drill out the casing shoe, then about 3m of new rock. You then circulate the hole clean and ensure that you have a uniform mud weight all the way around. At this point you shut in the well and slowly, using the cement pump, pressure up on the well, recording volume pumped vs pressure.

You should see a linear line of constant slope until the formation (the 3m of new rock) starts to take fluid. At this point the graph will ‘break tangent’ and begin to flatten. You stop pumping NOW, not when the curve breaks over and the rock fractures (thereby weakening the rock).

Knowing the true vertical depth at the shoe, the mud weight in the hole and the pressure in the drillpipe when you stopped pumping, you can calculate the strength of the rock in pound per gallon equivalent or whatever units that rig is using.

Hope that explains a leak-off test for you.

[Ward Smith + 6,615]

2 hours ago, Douglas Buckland said:

We need a reservoir engineer or a production engineer to respond to this question. Everything mentioned so far are drilling/well design concerns.

PS: If you fracture/breakdown the rock during a leak-off test, you should start packing your bags...

Doug, don't you want to play one on TV? 

I agree about the drilling and design. And yes, as we've discussed, in many ways a frac job is just an over pressured well. 

In lieu of being reservoir engineers, we can pretend a bit, based on first principles. I've talked with Chief scientist reservoir engineers in the past. Have three really good ones in my contacts. Haven't called them yet because ilike to I figure out as much as I can first so they don't get too annoyed with me for saying dumb things. I'll be honest, I'm using you guys to not sound too dumb when the time comes.

[Douglas Buckland + 6,308]

7 minutes ago, Ward Smith said:

Doug, don't you want to play one on TV? 

I agree about the drilling and design. And yes, as we've discussed, in many ways a frac job is just an over pressured well. 

In lieu of being reservoir engineers, we can pretend a bit, based on first principles. I've talked with Chief scientist reservoir engineers in the past. Have three really good ones in my contacts. Haven't called them yet because ilike to I figure out as much as I can first so they don't get too annoyed with me for saying dumb things. I'll be honest, I'm using you guys to not sound too dumb when the time comes.

Man, I’d take ANY gig at this point in time! Playing an engineer on TV might be fun!😂

I found some good technical papers online, but you have to pay for them.

[Douglas Buckland + 6,308]

https://www.onepetro.org/conference-paper/SPE-165705-MS

[martin.rylance@bp.com + 23]

"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/geological/chemical/physical factors here. "

It is a huge question, from a Petroleum Engineering perspective equivalent to how long is a piece of string, but I am going to take a shot at it anyway as a 34 Year PE how could I resist.   Please accept that these are broad brush strokes, there will always be exceptions, the range of reservoir and fluid types that we work with and produce is vast; but I will lay out some 'rules-of-thumb' that will demonstrate the majority of cases that would result.

•  In the majority of cases, shutting in a well will result in increased production post shut-in, for a variety of reasons but mostly due to the increased pore-pressure as the draw-down into the reservoir is eliminated and the average near wellbore pressure equates with the average reservoir pressure.

1.  Increased pore-pressure due to the elimination of draw-down, this means that when the well is started up, as the drawdown into the reservoir is redeveloped that there is more available pore-pressure for the Productivity Index (PI) to work with, assuming not on a fixed choke at the surface.
2.  Increased pore-pressure, will have multiple effects on solution-gas (e.g. if the Pressure Build-Up PBU crosses the bubble-point), condensate environments (or the dew-point), other depositional environments (some other phase envelope), again resulting in improved flow before the lower-pressures re-establish themselves.
3. Increased pore-pressure, will reduce the effective stress (Terzhagi), which will result in less stress on the proppant pack in a hydraulically fractured well and unpropped or natural fractures retaining more conductivity; this is the reason why some parties carefully manage post-frac flowback for example (to minimize stress on a proppant pack).
4. Gravity segregation, depending upon duration, certainly within proppant-packs (several 1,000 Darcy) this would be a real effect and water/gas/oil would separate, that could have a positive or potentially slightly negative effect on well restart, though in time the balance would likely be restored.
5.  ...

•   In some cases, shutting in a well will potentially result in reduced productivity, for a variety of reasons some of the biggest culprits of which I will summarise here

1.  Cross-flow, with more than one reservoir open in a vertical (or multiple fracs in a horizontal), variation in near-wellbore pressure will result in crossflow taking place during shut-in, debris, solids, water and unwanted material can cross-flow into these zones, this is particularly bad with cased/cemented/perforated as perforations can plug (surging on start up with the additional pore-pressure available can help).
2.  Waxes, Paraffins, Hydrates and other depositions in the Tubing/Wellbore, some wells are so paraffin/wax prone that to shut them in without thoughtful suspension can make start-up a difficult operation, wells like this should be circulated and soaked to a sympathetic fluid, note this is also an opportunity to soak a stimulation in these wells.
3.  ...

This list is not exhaustive, every cup of tea I have I am sure I could add another 2 or 3 items, but some of the major effects noted here, on the whole I would say that there would be little detrimental behavior.

I have also noted that Waterflood has come up a few times, and I believe that the misperception is that the water is sloshing around in the reservoir like water in a tank.  The reality is that the velocities of the streamlines are very low indeed, and in fact I would go as far as to say that there is as much evidence that stopping and starting a waterflood could be beneficial as there is indicating that it could be damaging.

Interestingly not  great deal of work in the published arena in this area, but i expect there will be some pretty eager MSc students right now.

Edited April 22, 2020 by martin.rylance@bp.com

[Ward Smith + 6,615]

2 hours ago, Douglas Buckland said:

https://www.onepetro.org/conference-paper/SPE-165705-MS

Found This paper on shale,but it's gas not oil. On the other hand, first principles still apply and gas is just another fluid with special properties. 

On the other hand the authors warn against treating wet wells and dry (gas) wells the same. 

Quote

Our study shows that with an increment in water saturation in the matrix blocks due to shut-in, causes permeability reduction, and hence reduction in well productivity. The duration of shut-in and the time of the well life in which shut-in occurs plays an important role. The initial flowback is critical to unload the water. Shut in later in well life have lesser impact than initial shut-in.
The wells can suffer a productivity loss from 17% to 64% depending on the water imbibed in the reservoir and the corresponding increase in water saturation in the matrix blocks for "soak-in" case. For extended shut-in case, the EUR loss in our case is 13.33%, but we expect it to decrease if the shut-in happens later in well life.
 

Found another paper right in your backyard Doug You should request the full text from the authors

Edited April 22, 2020 by Ward Smith
Added Malay paper

[Douglas Buckland + 6,308]

@martin.rylance@bp.com
 

1. “ Increased pore-pressure due to the elimination of draw-down, this means that when the well is started up, as the drawdown into the reservoir is redeveloped that there is more available pore-pressure for the Productivity Index (PI) to work with, assuming not on a fixed choke at the surface.”

Correct me if I am wrong, but once a well is shut in, depending on duration, the pore pressure will only build back up to what it was at the time of shut-in, not the original reservoir pressure, due to any pressure depletion due to previous production.

Once the pressure equalizes throughout the reservoir, after opening the well back up, production SHOULD return to pre-shut in levels IF no wellbore/fracture damage occurred and the fractures did not close and embed the proppant.

Also, if the relative permeabilities changed during shut-in, you may see different percentages of oil/water/gas than you saw prior to shut-in?

Is that correct? I am a drilling hand not a reservoir engineer...😂

[James Regan + 1,776]

5 hours ago, Douglas Buckland said:

We need a reservoir engineer or a production engineer to respond to this question. Everything mentioned so far are drilling/well design concerns.

PS: If you fracture/breakdown the rock during a leak-off test, you should start packing your bags...

Bags are packed, see that's the difference between and Engineer and a roughneck, my explanation was designed for eejits  such as myself, wrong choice of words, but hey I tried to explain it a very general way that most could imagine, its very hard to try and explain basic ops on a rig, you lose people after the first sentence some times. We take it for granted at times how complicated is is to wake up and put your boots on...

Hangon unpacking my bags, there are a few trains of thought on this.

 

[Douglas Buckland + 6,308]

Geez he’s long winded! For drilling you just need that first inflection point. After that you can create problems for yourself!

[James Regan + 1,776]

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....

Edited April 22, 2020 by James Regan

[martin.rylance@bp.com + 23]

1. “ Increased pore-pressure due to the elimination of draw-down, this means that when the well is started up, as the drawdown into the reservoir is redeveloped that there is more available pore-pressure for the Productivity Index (PI) to work with, assuming not on a fixed choke at the surface.”

Correct me if I am wrong, but once a well is shut in, depending on duration, the pore pressure will only build back up to what it was at the time of shut-in, not the original reservoir pressure, due to any pressure depletion due to previous production.

Once the pressure equalizes throughout the reservoir, after opening the well back up, production SHOULD return to pre-shut in levels IF no wellbore/fracture damage occurred and the fractures did not close and embed the proppant.

Also, if the relative permeabilities changed during shut-in, you may see different percentages of oil/water/gas than you saw prior to shut-in?

Is that correct? I am a drilling hand not a reservoir engineer...😂

 

As the well is shut in the pore-pressure builds from the initial PBHFP up to the Average reservoir P* which will not be the original PR unless EOR has been taking place and water injection has been injected at a VRR of 1.0.  The P* (or PBU pressure) will be well in excess of the immediate PBHFP at shut-in.  So when the well is opened the initial drawdown available is much higher than previously, over time the drawdown will develop into the reservoir and the well will return to previous values.  Other than during initial flowback (post frac) i.e. soaking/imbibition which is a very specific case (as noted by someone above), there is no real reason that relative-perm values should be changed (note this soak/imbibition ONLY occurs post completion) and not during shut-in of a long-term producing well.

Edited April 22, 2020 by martin.rylance@bp.com

[El Nikko + 2,145]

8 hours ago, Douglas Buckland said:

When you finish drilling a section of the well, then run casing and cement it in place, you need to know the strength of the rock at this ‘casing shoe’ (theoretically the weakest spot in the well as you drill ahead). You need this information for well control purposes, to determine how far you can drill ahead, and to know the maximum mud weight you can use while drilling (among other things).

To do this you drill out the casing shoe, then about 3m of new rock. You then circulate the hole clean and ensure that you have a uniform mud weight all the way around. At this point you shut in the well and slowly, using the cement pump, pressure up on the well, recording volume pumped vs pressure.

You should see a linear line of constant slope until the formation (the 3m of new rock) starts to take fluid. At this point the graph will ‘break tangent’ and begin to flatten. You stop pumping NOW, not when the curve breaks over and the rock fractures (thereby weakening the rock).

Knowing the true vertical depth at the shoe, the mud weight in the hole and the pressure in the drillpipe when you stopped pumping, you can calculate the strength of the rock in pound per gallon equivalent or whatever units that rig is using.

Hope that explains a leak-off test for you.

I know you know this but just to add to the confusion for everyone else that should be called a formation integrity test (FIT) not a Leak off test even though it's still common for people to call it a leak off test lol.

 

[Douglas Buckland + 6,308]

5 minutes ago, El Nikko said:

I know you know this but just to add to the confusion for everyone else that should be called a formation integrity test (FIT) not a Leak off test even though it's still common for people to call it a leak off test lol.

 

Wrong!

A Formation Integrity Test (FIT) is a test taken to a known value that will allow you to drill the well regardless where the inflection point is. An FIT never sees the inflection point! FIT’s are usually performed in development wells where you have enough offset well data and do not need to confirm the rock strength.

Leak-Off Tests (LOT) are required in exploration or appraisal wells where YOU DO NOT HAVE DEFINITIVE OFFSET WELL INFORMATION.

[James Regan + 1,776]

16 minutes ago, Douglas Buckland said:

Wrong!

A Formation Integrity Test (FIT) is a test taken to a known value that will allow you to drill the well regardless where the inflection point is. An FIT never sees the inflection point! FIT’s are usually performed in development wells where you have enough offset well data and do not need to confirm the rock strength.

Leak-Off Tests (LOT) are required in exploration or appraisal wells where YOU DO NOT HAVE DEFINITIVE OFFSET WELL INFORMATION.

So based on that a Leak Off test will indeed fracture the formation? I agree with both of you by the way.....

[Douglas Buckland + 6,308]

6 minutes ago, James Regan said:

So based on that a Leak Off test will indeed fracture the formation? I agree with both of you by the way.....

No, no, no...!

A leak-off test should NEVER fracture the formation! This MAY weaken the formation at the point where theoretically it is already the weakest point!

Look at that graph you posted. The leak-off point is just that, the point where the formation starts to take fluid (the first inflection point where the line changes slope). The point where the rock actually fractures is the highest point on the graph where the line breaks over to the horizontal and starts heading south (the fracture initiation point).

[Douglas Buckland + 6,308]

[James Regan + 1,776]

12 minutes ago, Douglas Buckland said:

No question is a dumb question, I'm sure with this little back and forth between the three of us, we have managed to explain something, even if this does look like the Covid19 test data for Belgium....

[Izzie Farreal 0]

18 hours ago, Gerry Maddoux said:

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. 

Interesting!

[Walter Faber + 48]

Thanks to everyone who attempted to answer here, with special appreciation to @martin.rylance@bp.com for his write up. 
Also see the long comment-of-comment-of-comment reply by Michael Baker on Quora, which has information from an interview:
https://www.quora.com/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/all_comments/Cyrus-Farschi?comment_id=136887364&comment_type=2&__filter__=all&__nsrc__=1&__sncid__=4837738528&__snid3__=7787603805

[El Nikko + 2,145]

5 hours ago, Douglas Buckland said:

Wrong!

A Formation Integrity Test (FIT) is a test taken to a known value that will allow you to drill the well regardless where the inflection point is. An FIT never sees the inflection point! FIT’s are usually performed in development wells where you have enough offset well data and do not need to confirm the rock strength.

Leak-Off Tests (LOT) are required in exploration or appraisal wells where YOU DO NOT HAVE DEFINITIVE OFFSET WELL INFORMATION.

Thats what happens when replying to a thread 5 minutes after waking up 😂

Must engage brain

[Gerry Maddoux + 3,627]

Jeez, you guys argue more than a bunch of doctors!

And you're almost as opinionated!

This is most disconcerting!

Try to repair this part of your personalities!

😂

[Ward Smith + 6,615]

2 hours ago, Walter Faber said:

Thanks to everyone who attempted to answer here, with special appreciation to @martin.rylance@bp.com for his write up. 
Also see the long comment-of-comment-of-comment reply by Michael Baker on Quora, which has information from an interview:
https://www.quora.com/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/all_comments/Cyrus-Farschi?comment_id=136887364&comment_type=2&__filter__=all&__nsrc__=1&__sncid__=4837738528&__snid3__=7787603805

Quote

Eric Gagen, SPE: “The damage comes when you have multiple zones producing in the same well, or a single large zone with limited vertical permeability. These are extremely common producing scenarios. During continuous production, the flowing bottomhole pressure of the different zones, or portions of a large zone are all the same. When you shut the well in, different zones and portions re-pressurize in different ways. Take for example a well with 3 oil producing zones. The uppermost one is a medium sized reservoir with a high solution GOR, and contributes 30% of production and reserves. the middle is a large reservoir with the lower GOR which contributes 50% of production and 55% of reserves (relative production is lower than the high GOR zone due to less gas expansion driving production in/towards the near wellbore zone). The lowermost is a small reservoir with the same GOR as the middle one and aquifer support and contributes 20% of production and 15% of reserves (production is higher due than would usually be expected due to the pressure support), They were all put on production at the same time. The well is naturally flowing - the large amounts of gas from the high GOR zone help to lift the low GOR zones, and the total flowrate and gas rates are sufficient to lift the water as it flows towards the well.

Now they are shut in for an extended period - say 6-9 months.

The Upper medium reservoir (or section of a laminated or partially connected thick zone)with the high GOR has intermediate depletion and a pressure lower than the large reservoir
The Middle large reservoir (or section of a laminated or partially connected thick zone) has the lowest depletion, and intermediate pressure when shut in and allowed to build up.

Due to the aquifer support, the Lower small reservoir (or section of a laminated or partially connected thick zone) has the highest depletion of reserves, but it's pressure in the near wellbore area rebounds to a level relatively close to the original bottomhole pressure when the well was completed within a month of being shut in.

The following crossflow occurs:

Water from the bottom small reservoir pours into the medium sized one, and some gets into the large one also. This continues until the well is put back on production, because the volume of water available is effectively infinite. . 
Oil from the middle large reservoir goes into the medium reservoir, displacing the high GOR oil with low GOR oil.

The medium reservoir now has 2 different kinds of oil in it, and an enormous load of water. 
The remaining oil in the lower reservoir was bypassed by the water.

Now the well is put on production and won't flow. A swabbing unit is put on the well, and it makes massive amounts of water. After a week of swabbing they give up. A month later a workover rig is put on the well and it's put on artificial lift (any kind, take your pick)

The relative permeability of the medium reservoir is messed up due to the massive influx of water and only mostly compatable oil - it eventually produces at 1/2 of it's old rate, and it's estimated that only 1/2 of it's previously calculated reserves will get produced.

The massive and sustained influx of water from the small reservoir has effectively bypassed all the remaining reserves that were in it, and it only ever produces water if it's not plugged back.

The large reservoir eventually produces it's load of water, and is restored to production.

Congratulations: Your well has permanently lost 35% of it's production and 30% of it's reserves after a well intervention a a couple of workovers. If you want to get the bypassed reserves back again, you are going to have to drill a new well to make a clean completion into the lower zone, and the upper zone, assuming that there is a good geologic location to access them”

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