O&G Crew: Well Swabbing

[davidI]

Can anyone explain to me the purpose of well swabbing and when in a well's life one would choose to do it?

I'm working on a commercial arrangement for swabbing services and there is a lot of disagreement between our technical / field guys so I'm just trying to get a better understanding of when and why swabbing operations would be conducted for myself.

[ExtraSlow]

At the most basic, swabbing is used to remove fluid from a wellbore when the energy of the reservior is not sufficient to do so.

Often used after a completion or workover when a large amount of fluid has been introduced into the well (i.e. large water frac). The pressure exerted by the fluid is greater than reservior pressure (overbalance). Swabbing a portion of that fluid out will be enough to allow the well to flow on it's own, and carry of the remaining load fluid out over a period of time.


Also occasionally used on depleted producing wells to remove fluids, although if that's a regular occurance, some kind of arificial lift solution like a pump of plunger is probably more economical long-term.

That make sense?

[davidI]

Makes sense. If you're already running ESPs would you do it? If so, why?

[Feruk]

More details. Is it a horizontal well? An ESP typically implies your well has a strong drive mechanism (high bottom hole pressures, you won't pump it off). In this situation, I can only think of two one situations that would involve swabbing and they're both for testing purposes and the objective is to locate a high water cut part of the horizontal and plug it off.

[mr2mike]

I've worked somewhere that instead of swabbing, the reservoir had enough pressure that if the well started to show fluid via pressure and rate SCADA, we would shut the well in for a few hours, get a good build up and then rip the well back on, lifting fluids to surface.
Doesn't always happen this way and I'm with ExtraSlow, if it's a consistent issue, a plunger is better off in an economic sense.

Late or later on in a well's life if it's nearing the critical rate of lift, a plunger is best.

http://www.shaletec.com/faq/when-should-a-well-be-moved-to-plunger-lift/

[realazy]

There's applications in low rate gas wells that go down due to a facility upset that causes a slow pressure build up allowing the fluid column to kill the well.

If the well cannot unload by a blowdown, a swab could be considered as an option if the well can normally produce and lift the liquids. Ecnomics play a huge factor here as low rate gas wells can't pay for much.

I don't see many applications in swabing if the well already has artifical lift installed. Maybe if sand/debris is causing frequent pump failures?

[Feruk]

DavidI said It's an ESP (electrical submersible pump) application... nothing to do with either gas or low rates or low deliverability. You don't run an ESP unless you have (a) production in the ~400-10,000bbl/d+ of fluid, (b) a sustained fluid level (costly exceptions apply).

I've run plenty of plunger lifts and done more swabbing operations than I care to count, but this is not the application DavidI is asking about.

In a HZ with a very high water cut, they sometimes go back in to plug off part of the wellbore. To figure out what water cut is coming from what part of the well, they will isolate individual parts of the well and conduct "selective swabbing." This is the only thing that makes sense when you're dealing with the rates an ESP can lift.

[davidI]

They are vertical oil wells with a high water cut so I think you're on the right track Feruk.

Can you give me a bit more explanation on what the swabbing is meant to accomplish? How do they identify the areas flowing high water and consequently plug it?

[Feruk]

How big is your perfed interval approximately? Is there water injection into the zone in offsetting wells? Could be two different things depending if you have injection.

[davidI]

I'm not aware of the perfed intervals. We have a few water injection wells but the majority are not.

I deal with the commercial side and am more just interested to satisfy my own curiousity...

[Feruk]

Ok let's say you have a 10m interval. Two potential operations:
1) Your field is under waterflood. Let's say that 2m is significantly more permeable than the remaining 8m, and so water has broken through from injector to producer in that 2m and is now cycling, causing high water cuts. The other 8m is still sweeping oil, but would do so a lot more efficiently if the 2m was no longer active.
2) You have a strong bottom water drive. So under your reservoir, you have a water aquifer that supplies limitless pressure. Over time, the water moves up as you deplete pressure and sweeps the oil in (let's say) the bottom 5m and you water cuts are crazy high now. Only the top 5m is now really contributing oil, so time to seal off the bottom 5m.

You'll go in and isolate your 10m zone in (say) 2m intervals. This can be done mechanically or chemically. You'll let one 2m zone produce at a time and swab fluid from each (for super simplicity, it's like running a bucket down there and taking all the fluid from bottom of tubing to surface up). Based on your water cut, you'll know which zones are producing very high water cuts and little oil; hence which ones to shut off. You'll go back in and shut them off either mechanically (a plug), chemically (something that eliminates permeability), or physically (cement). When your well comes back on, you'll have a lot less water inflow, and likely more oil inflow (preferential flow).

[ExtraSlow]

I'm not lucky enough to work on any oil wells that require ESP.
I'm more a tight gas/shale gas guy these days.

[davidI]

Originally posted by Feruk
Ok let's say you have a 10m interval. Two potential operations:
1) Your field is under waterflood. Let's say that 2m is significantly more permeable than the remaining 8m, and so water has broken through from injector to producer in that 2m and is now cycling, causing high water cuts. The other 8m is still sweeping oil, but would do so a lot more efficiently if the 2m was no longer active.
2) You have a strong bottom water drive. So under your reservoir, you have a water aquifer that supplies limitless pressure. Over time, the water moves up as you deplete pressure and sweeps the oil in (let's say) the bottom 5m and you water cuts are crazy high now. Only the top 5m is now really contributing oil, so time to seal off the bottom 5m.

You'll go in and isolate your 10m zone in (say) 2m intervals. This can be done mechanically or chemically. You'll let one 2m zone produce at a time and swab fluid from each (for super simplicity, it's like running a bucket down there and taking all the fluid from bottom of tubing to surface up). Based on your water cut, you'll know which zones are producing very high water cuts and little oil; hence which ones to shut off. You'll go back in and shut them off either mechanically (a plug), chemically (something that eliminates permeability), or physically (cement). When your well comes back on, you'll have a lot less water inflow, and likely more oil inflow (preferential flow).

Thanks! Great explanation for my knowledge level.

I'm going to press our guys for a bit more explanation here as I have little faith in a lot of their technical abilities...

[ExtraSlow]

You still working those carbonate formations of the middle-east? Those are a world apart in geology from anything found in Alberta.