Why do oilfields take damage when production is paused?

[carbonates + 22]

Douglas,

I have steered and drilled horizontal wells with zero dogleg, and part of the motivation for that was to eliminate any problems setting casing. However, where I did this we were in an underpressured formation and I wanted to be certain that my wells flowed with gravity towards the heel where I was positioning an ESP. These wells did not produce any water and minimal gas. That said, I have seen wells drilled in the Permian where the doglegs were so severe the completion twisted off the casing and the well had to be side-tracked with a new lateral.  

It requires more expensive tools to drill a zero dogleg well and may slow down the drilling. Many operators today use only MWD gamma ray tools that are often 30 to 60 feet behind the bit. More expensive azimuthal LWD tools with at-bit inclination can be within 3 feet of the bit, but many operators will not pay the extra cost to use them (and some service companies don't like to provide them due to risk).  I have seen drillers running so fast in the lateral that the MWD tool could not even send the signal to the surface while they were drilling and there would be gaps in the logs. With tools placed 30 or even 60 feet behind the bit it is very difficult to drill a straight lateral with zero dogleg. The drillers often look for the fastest drilling rock, and may steer up or down trying to find it. Fifty foot up and down porpoising is often the normal tolerance that I see in the Permian Basin and it is not that rare for a well to go out of zone for part of the wellbore. I have seen wells that had to be plugged back because part of the lateral went into a different regulatory production pool. Eagle Ford wells I have worked were much the same. Niobrara wells often have to be steered up or down as they cross faults. I have no doubt that the money the drillers save with speed is lost in future production in many of those wells. It may be justified with the time value of money because the loss of production is not going to show up until many months later, but total EUR for the well with lots of dogleg will likely be lower (and there is plenty of published material to support this).  

Edited May 8, 2020 by carbonates

[Eric Gagen + 713]

5 hours ago, Douglas Buckland said:

@carbonates

“Most horizontal wells are not that straight because the extra time and cost to drill a perfectly straight wellbore.”

Thank you for your detailed explanation concerning damage to a shut-in well.

I am somewhat confused by your comment above. Any horizontal or directional well will be drilled to a ‘target’. As ‘time is money’ they are usually drilled as direct as possible towards that target. Doglegs are to be avoided (dogleg severity being tracked while drilling). The reason is not so much to prevent gas on the high side/sand on the low side, but to avoid issues later while running casing or tools into the well.

Micro doglegs are created while steering the bit, and also simply from the bit turning to the right, reactive torque and drilling through different formations or non-homogenous rock within the same formation.

Carbonates gave a pretty complete answer to your comment here, but I'll just add to reiterate that 'straight' from the POV of a driller isn't even vaguely good enough from the POV of maximum well productivity.  A deviation of as little as 2-3 ft up or down is enough to start causing ponding/pooling of water or other produced liquids at low flow rates.  Initially this isn't a problem, because the bottomhole pressure of the well is so high that everything is moving up the hole no matter what.  However as reservoir pressure decreases, and depletion sets in,  the different parts of the well tend to deplete at different rates.  In particular the heel tends to draw down first, and the toe tends to deplete later if only because of the frictional losses in pressure that fluids moving from the toe to the heel have to overcome.  Add to this a few low spots where liquids can accumulate and create further impediments to flow, and you eventually reach a point where serious production impairment sets in.

The only real way to prevent this is to drill the well slightly toe up, or toe down (there are reasons for both) and never let the well cross the 90 degrees mark.  so (for example) if you are toe up,  the well should ALWAYS be at an angle of 90 degrees or more, and if it's toe down it should ALWAYS be at 90 degrees or less.  In real life this isn't always possible - the formation might not be thick enough to support this well profile, or it might be impossible to achieve with the directional tools selected, but it's the only way to prevent this sort of impairment.

I have seen MANY wells that porpoise up and down 2 or 3 times 50 or even 100 ft in the vertical axis (usually just below the heel where they were turning so fast they couldn't reorient the tools before they overshot horizontal badly) and as a professional involved in wellbore repair and remediation they ensure that I will have a busy career for many years to come. The ultimate recovery, profitability and production on these wells is going to be just awful without some really clever and expensive production enhancement ideas.  In some really excessive cases the only way to get reasonable recovery from the rock towards the toe end of long laterals that were drilled quick and sloppy will be to redevelop the area with some sort of infill program.  

[Douglas Buckland + 6,308]

@Eric Gagen
 

I am not meaning to argue with either yourself or @carbonates, but I seem to be coming from a drilling perspective as opposed to a production or completion perspective.

When the drilling engineers are handed the proposed well parameters from the asset manager, that package will define a surface location and a target, or a series of targets.

The drilling team will then PLAN the most efficient, cost effective well to intersect these targets. On paper, the well looks like an unwavering series of curved and straight lines.

Then reality sets in. Drilling contractors strive to deliver the best well possible, but they are limited, like the rest of us, by physics and the equipment and technology available.

Simply by requesting them to drill a directional or horizontal well, even specifying rotary steerable tools, you, by definition, expect some changes in direction, and therefore doglegs. This cannot be avoided.

If you are geosteering and watching for micro fossils in the cuttings, by default you have a lag in your information stream (you have to pump bottoms up to get a sample). If you decide that you are in the wrong spot, then you must reorient the toolface and head in a new direction...instant dogleg.

Drilling is not an exact science, there are simply too many variables. To expect a perfectly smooth well, with no doglegs or porpoising in the horizontal section is simply unrealistic.

Edited May 8, 2020 by Douglas Buckland
Iii

[El Nikko + 2,145]

Talking of geosteering here's something cool from a few years ago

Geosteering a channel sand deposit using deep reading azimuthal resistivity + RSS + neutron density + GR. The sands would pinch out and vanish sometimes.

 

 

[Douglas Buckland + 6,308]

In geosteering, you only know you are out of the formation of interest when the targeted fossils disappear in the cuttings. This requires a toolface reorientation. Unless you have a crystal ball, it is what it is....

[El Nikko + 2,145]

4 minutes ago, Douglas Buckland said:

In geosteering, you only know you are out of the formation of interest when the targeted fossils disappear in the cuttings. This requires a toolface reorientation. Unless you have a crystal ball, it is what it is....

That's just one type of geosteering, I imagine it's because the formation is otherwise homogenous and maybe the LWD data doesn't differentiate between carbonate layers. I know it's still done but it's a very old way of geosteering and I've never geosteered that way myself although many years ago I did work on jobs where we had biostratigraphers.

It's much more common these days to do the geosteering using LWD data. We model the expected tool response before the job and that helps us understand where in zone we are and allows us to make corrections before we go out of zone, thats called proactive geosteering. Reactive geosteering is where you make changes after you see something that tells you you're out of zone but either way it's very unusual to not have to make changed to the tool face orientation or downlink to the RSS for an inclination change.

Some formations like the one above are sand and aren't full of microfossils etc so we couldn't use that technique even if we wanted to and on top of that the ROP was way too fast to wait for cuttings etc. Some of the wells I drilled last year were 400+ ft/hr we had GR and a GR image but the data density was very low. On top of that we had XRF data ( X-ray fluorescence spectrometer) which gives you the mineral composition of the rock and that was a first for me and quite interesting but it's the same problem as using cuttings, by the time we got the latest data it was several hundred feet behind the bit.

The dark art of geosteering 😂

I have loads of interesting examples I could show people, I'm just cautious about sharing things publically in case there are legal implications.

[Eric Gagen + 713]

2 hours ago, Douglas Buckland said:

@Eric Gagen
 

I am not meaning to argue with either yourself or @carbonates, but I seem to be coming from a drilling perspective as opposed to a production or completion perspective.

When the drilling engineers are handed the proposed well parameters from the asset manager, that package will define a surface location and a target, or a series of targets.

The drilling team will then PLAN the most efficient, cost effective well to intersect these targets. On paper, the well looks like an unwavering series of curved and straight lines.

Then reality sets in. Drilling contractors strive to deliver the best well possible, but they are limited, like the rest of us, by physics and the equipment and technology available.

Simply by requesting them to drill a directional or horizontal well, even specifying rotary steerable tools, you, by definition, expect some changes in direction, and therefore doglegs. This cannot be avoided.

If you are geosteering and watching for micro fossils in the cuttings, by default you have a lag in your information stream (you have to pump bottoms up to get a sample). If you decide that you are in the wrong spot, then you must reorient the toolface and head in a new direction...instant dogleg.

Drilling is not an exact science, there are simply too many variables. To expect a perfectly smooth well, with no doglegs or porpoising in the horizontal section is simply unrealistic.

Absolutely agreed.  Merely pointing out that there are consequences and tradeoffs to the choices made.  In my experience analyzing wellbore trajectories for friction modelling however it's very common to run across incredibly badly drilled wells.  In most cases, it isn't a technology problem, or even a matter of a huge amount of money, but of priorities.  One of the supermajors I was doing modelling for working in the Delaware section of the Permian started a plan to drill some unusually complex trajectories, and asked their directional drilling contractors about what would be possible for them to do.  The DD's were, to put it bluntly amused, and explained to the oil company that it would not be difficult to drill the wells if they simply used the 'standard' practices that were in place with the average operator, and that the supermajor got had of the worst drilled wells in the basin (they had data to prove it too). The supermajor guys were shocked, and wondering why they weren't getting 'good' quality wellbores for production already, and the answer of course was cost and priorities.  It would cost extra (somewhere along the lines of $25,000 per well) to take the time required to get a much better trajectory, and the supermajor's drilling department got bonuses strictly based on speed, and cost.  They literally had zero incentive to get good trajectories, and a large one to cut corners, so they cut the corners.  On a sample of ~ 100 wells or so which we analyzed, the drillers saved ~ $2.5 million on directional drilling costs, and that netted them a solid $25 million in excessive costs due to wellbores that were so tortuous that they couldn't reliably pump plugs down between frac stages.  Even if they onlysuccessfully resolved 1/2 the tortuosity problems via more careful directional control they still would have been dramatically better off. This is before even getting into the long term lost production due to the bad trajectories.  

I have seen differences in 'standard' practices between different operators in the same part of the same basin which are enormously large.  Operator A might have trouble getting good quality completions TD'ed in 7,500' laterals, while operator B might routinely complete 12,000' laterals for roughly the same overall cost from spud to production. 

Edited May 8, 2020 by Eric Gagen

[Douglas Buckland + 6,308]

This is why I hate working for the large operators. No common sense or thinking out of the box. If it isn’t in the manual, you will not do it. Everything is process driven.

The small or mid-sized outfits must save money wisely, and they function more as a team. A much better working environment all around. They also try to work WITH the third party services as opposed to dictating to them.

Edited May 8, 2020 by Douglas Buckland
Nnn

[Coffeeguyzz + 454]

Mr. Buckland

Your last comment hits squarely on the head of why much of this 'unconventional' development has evolved - and may continue - in the manner that has unfolded.

The sheer variety of factors from foot by foot geology changes, exposure to new processes, marketplace adaption (micro and macro), time-dependent circumstances such as this thread has exposed regarding hitherto unforeseen conditions of possibly long term shut ins.

On and on.

"No ... thinking out of the box"  brings to mind the response years ago from a pioneering 'shale' operator. To wit "What's a box?"

Your comment highlights a fundamental challenge this very day ... how will the very large companies effectively succeed in such a dizzyingly heterogeneous, ever changing environment?

Shell is virtually giving away outstanding assets in Tioga county for peanuts.

Chevron is on deck to do the same.

The Irving headquarters of Exxon literally sits atop the Barnett  Shale, a formation they shunned completely in the early years.

This current squeeze will pass, and the methods that the survivors adopt should be fodder for business school studies for decades to come.

Your comments provide the crux of the explanation.

[John Bohan 0]

Tubing and rods corrode and fall apart when you try to pull it later.  Casing and liners can also corrode at the air oil contact.  Steam chests can collapse from lack of support and turn to warm water.  Wells are shut in for being marginally economic, with the additional damage they are unlikely to be economic at slightly higher prices.  

[Douglas Buckland + 6,308]

2 hours ago, John Bohan said:

Tubing and rods corrode and fall apart when you try to pull it later.  Casing and liners can also corrode at the air oil contact.  Steam chests can collapse from lack of support and turn to warm water.  Wells are shut in for being marginally economic, with the additional damage they are unlikely to be economic at slightly higher prices.  

Corrosion of the tubing, rods and casing should have been addressed in the original well design life and material specification and the well maintenance program.

[Walter Faber + 48]

New article from oilprice.com about problems of stopping production: https://oilprice.com/Energy/Energy-General/The-Major-Problem-With-Shutting-Down-Oil-Wells.html

[martin.rylance@bp.com + 23]

I think I would rather go with evidence based reality, than theoretical (academic assessment of petrophysics) and the early data appears to agree, nothing to see here move along please ....

https://www.hartenergy.com/exclusives/experts-no-reservoir-damage-production-shut-shale-wells-188112?mkt_tok=eyJpIjoiWlRaa01UVmtaVEkyWVdJMSIsInQiOiJlREJZRE1xbWExWG5MQlNocnBcL2hDM2l6d1JjYmhEZHF1OEFJcEtCR1ZZc3RFZlEyMlRFaHlaUG1BQzJoUEFZTFdreG9uakVFeG9EbVh3eXNMWFdyYjBncVpGZlYxbDMwSHRzMktsYzdvRlptdE85Yyt5S2dWNG1MWEZqdFhoSkoifQ%3D%3D

Edited June 18, 2020 by martin.rylance@bp.com