Douglas Buckland

Getting Weight to the Bit in a Long Lateral

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(edited)

5 hours ago, Tom Kirkman said:

@Jason Lavis  to the white courtesy phone please.

Directional Drilling: Everything You Ever Wanted To Know

@Douglas Buckland you can also try to contact Jason on LinkedIn if he doesn't see the Bat Signal here.

 

/ edit ... I messaged Jason over on LinkedIn about your question.

 

Hi Tom, thanks for reaching out. I wrote that article after researching, not practical engineering experience. I'm definitely not an expert! For any high level technical drilling questions, the best place to go is the SPREAD forum:

https://my-spread.com/

It's free to register, and @Douglas Buckland can post the question which will get emailed to more than 2000 people who have registered specifically for drilling collaboration. The forum is owned by Dave Taylor (the DWOP king).

My initial answer is that on the longer laterals, they rely less on transferring weight from the vertical, and more from the actions at the drill head. For example, the mud motors can create a lot of pressure on one side, so that the drill bit can bite into the formation and pull itself forward. I've sent a couple of emails to experts and will be interested to hear a proper answer. I'll post it here when I get it.

Cheers, Jason

 

PS: (EDIT) I just got a quick reply from a manager of a company who solves this exact problem. They've asked the resident experts to craft a response. Will post it here when I get it!

Edited by Jason Lavis
An additional PS
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1 hour ago, Jan van Eck said:

Yup, all true, Douglas.  It is more of an "art" than a "science"!  And that is why you have to hire really sharp guys to do that sort of work.  Cheers. 

That’s what I’m trying to do...find one of those ‘really sharp guys’ to help me out here!!!😂

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56 minutes ago, Jason Lavis said:

Hi Tom, thanks for reaching out. I wrote that article after researching, not practical engineering experience. I'm definitely not an expert! For any high level technical drilling questions, the best place to go is the SPREAD forum:

https://my-spread.com/

It's free to register, and @Douglas Buckland can post the question which will get emailed to more than 2000 people who have registered specifically for drilling collaboration. The forum is owned by Dave Taylor (the DWOP king).

My initial answer is that on the longer laterals, they rely less on transferring weight from the vertical, and more from the actions at the drill head. For example, the mud motors can create a lot of pressure on one side, so that the drill bit can bite into the formation and pull itself forward. I've sent a couple of emails to experts and will be interested to hear a proper answer. I'll post it here when I get it.

Cheers, Jason

 

PS: (EDIT) I just got a quick reply from a manager of a company who solves this exact problem. They've asked the resident experts to craft a response. Will post it here when I get it!

Much appreciated Jason!

Is that Dave Taylor from RP Squared?

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1 minute ago, Douglas Buckland said:

Much appreciated Jason!

Is that Dave Taylor from RP Squared?

Yes, thats him.

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(edited)

1 hour ago, Douglas Buckland said:

You can play with the lubricity of the drilling mud to some extent, but keep in mind that it is a balancing act. Drilling mud must also prevent influx into the hole (hydrostatic pressure is your primary defense against a kick or blowout), must combat reactive formations and provide the yield point and plastic viscosity to remove cuttings from the wellbore. It is actually a finely blended chemical mixture.

If the pipe is lying on the bottom of the hole, then you are not getting any circulation UNDER the pipe so lowering the coefficient of friction does not reduce the drag.

 

Just to make this a bit more complicated, where will you put the JARS I have seen studies where they require a set of Jars for the horizontal section and the bendy (loose term) sections (while both sections are still uncased), I'm sure these BHAs are quite complicated in design.

Taking into consideration while the BHA is lying on the bottom of the hole there has to be mud circulating to free the cuttings, and maintain the mud weight at bit which is based on TVD (well control) plus the mud pressure required to steer and drive the mud motor, the risk of differential sticking would be great.

The smaller the quantity of drill collars, the higher the impact force. Conversely the larger the number of drill collars the greater the impulse force. A compromise has to be reached where both impact and impulse are working together to free the pipe.

A conundrum indeed.

Edited by James Regan
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18 minutes ago, James Regan said:

Just to make this a bit more complicated, where will you put the JARS I have seen studies where they require a set of Jars for the horizontal section and the bendy (loose term) sections (while both sections are still uncased), I'm sure these BHAs are quite complicated in design.

The smaller the quantity of drill collars, the higher the impact force. Conversely the larger the number of drill collars the greater the impulse force. A compromise has to be reached where both impact and impulse are working together to free the pipe.

A conundrum indeed.

You run into the exact same situation! If you can’t get weight to the jars, how are you going to cock/fire them?

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(edited)

1 hour ago, Douglas Buckland said:

You run into the exact same situation! If you can’t get weight to the jars, how are you going to cock/fire them?

Quoting from a BHA design paper for horizontal sections - DC Length = DC Length Vertical / Cos I (Well Inclination) For Horizontal wells Drill Collars are NOT normally used and BHA design is entirely based on the prevention of buckling.

So if thats true then there has to be some kind of traction device built into the mud motor which not only steers the bit but drives the mud motor through traction, ie dragging the BHA to increase WOB or as there are no collars WOB would be achieved by traditional weight increased by driller based on weight of BHA (without DCs) ??

(Scratching Head)

https://www.academia.edu/23705646/._Drill_String_Design_BHA_Design

Edited by James Regan
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(edited)

Quote

Slide Drilling Challenges
To initiate a slide, the driller must first orient the bit to drill in alignment with the trajectory proposed in the well plan. This requires the driller to stop drilling, pull the bit off-bottom and reciprocate the drillpipe to release any torque that has built up within the drillstring. The driller then orients the downhole mud motor using real-time MWD toolface measurements to ensure the specified wellbore deviation is obtained. Following this time-consuming orientation process, the driller sets the topdrive brake to prevent further rotation from the surface. The slide begins as the driller eases off the drawworks brake to control the hook load, which, in turn, affects the mag- nitude of weight imposed at the bit. Minor right and left torque adjustments are applied manually to steer the bit as needed to keep the trajectory on course...

The capability to transfer weight to the bit affects several aspects of directional drilling. The driller transfers weight to the bit by easing, or slacking off, the brake; this transfers some of the hook load, or drillstring weight, to the bit.2 The difference between the weight imposed at the bit and the amount of weight made available by eas- ing the brake at the surface is primarily caused by drag. As the horizontal departure of a wellbore increases, so does the longitudinal drag of the drillpipe along the wellbore.
Controlling weight at the bit throughout the sliding mode is made even more difficult by drillstring elasticity, which permits the pipe to move nonproportionally. This elasticity can cause one segment of drillstring to move while other segments remain stationary or move at different velocities.3
Poor hole cleaning may also affect weight transfer. In sliding mode, hole cleaning is less efficient because there is no pipe rotation to facilitate turbulent flow; this condition reduces the drilling fluid’s ability to carry solids.

@Douglas Buckland from the paper I linked. Somewhat old, but well written in my opinion. Hope you've had a chance to read it on a bigger screen. I skimmed it on my phone, then read more carefully on an iPad, but nothing like reading on my 34" desktop monitor. ;)

Edited by Ward Smith
Removed hyphens from quote

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I received a response from Stewart McGregor who's the Senior ERD Engineer and Technical Development Manager at Merlin ERD:

Hi Jason,

Hope this is what your poster is looking for. Let me know if there’s follow up required. It’s more high level, rather than an explanation on torque, drag and hydraulics.

There’s no magic bullet to the drilling of the really long wells and no downhole tractors for drilling (yet – but they are in development), only a process of detailed data analysis, optimization and close management during operations.

Some bullet points on specifics. You’ll need:

  • a thorough understanding of the surface loads (torque, drag and hydraulics) which will be imposed before drilling starts and the knowledge your equipment can handle them (and where the risks lie),
  • a wellbore stability model that gives a detailed understanding of the mud weights required (according to the trajectory) to avoid problems with hole collapse and losses,
  • a lithology column which can support the difference between static mud weight and ECD,
  • a high pressure mud circulating systems (7500psi) - probably,
  • rotary steerable systems and optimized drill bits - probably,
  • drill pipe sized for connection torque requirements, buckling, ECD and hydraulics management,
  • light weight BHA’s to reduce drag as much as possible,
  • mud systems with additives to improve lubricity,
  • a process to understand how clean your hole is while drilling so you can proactively manage hole conditions to avoid drilling and tripping problems in the first place.

Stu.

The problem that Douglas posed, is actually a cornerstone of the business for MerlinERD who design, deliver horizontal, extended reach, and complex high angle wells. They also run courses to teach others to do the same. You can probably guess what the ERD stands for, but to find out about the Merlin bit, you'd have to hire them or attend a seminar 😉 

https://www.merlinerd.com/

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6 hours ago, Ward Smith said:

@Douglas Buckland from the paper I linked. Somewhat old, but well written in my opinion. Hope you've had a chance to read it on a bigger screen. I skimmed it on my phone, then read more carefully on an iPad, but nothing like reading on my 34" desktop monitor. ;)

This tells you that you need to transfer weight to the bit and tells you the action the driller takes to do so, but does not indicate mechanically how this is accomplished.

Ye, the driller raises the brake to slack off and add weight on the bit. In a vertical or deviated well this is fairly straight forward, but in a long horizontal well it is a much different story.

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6 hours ago, Jason Lavis said:

I received a response from Stewart McGregor who's the Senior ERD Engineer and Technical Development Manager at Merlin ERD:

Hi Jason,

Hope this is what your poster is looking for. Let me know if there’s follow up required. It’s more high level, rather than an explanation on torque, drag and hydraulics.

There’s no magic bullet to the drilling of the really long wells and no downhole tractors for drilling (yet – but they are in development), only a process of detailed data analysis, optimization and close management during operations.

Some bullet points on specifics. You’ll need:

  • a thorough understanding of the surface loads (torque, drag and hydraulics) which will be imposed before drilling starts and the knowledge your equipment can handle them (and where the risks lie),
  • a wellbore stability model that gives a detailed understanding of the mud weights required (according to the trajectory) to avoid problems with hole collapse and losses,
  • a lithology column which can support the difference between static mud weight and ECD,
  • a high pressure mud circulating systems (7500psi) - probably,
  • rotary steerable systems and optimized drill bits - probably,
  • drill pipe sized for connection torque requirements, buckling, ECD and hydraulics management,
  • light weight BHA’s to reduce drag as much as possible,
  • mud systems with additives to improve lubricity,
  • a process to understand how clean your hole is while drilling so you can proactively manage hole conditions to avoid drilling and tripping problems in the first place.

Stu.

The problem that Douglas posed, is actually a cornerstone of the business for MerlinERD who design, deliver horizontal, extended reach, and complex high angle wells. They also run courses to teach others to do the same. You can probably guess what the ERD stands for, but to find out about the Merlin bit, you'd have to hire them or attend a seminar 😉 

https://www.merlinerd.com/

Bullet Item No. 7 is what I am actually after!

I wonder if Stewart could provide a link to diagrams showing these lightweight BHA’s?

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7 hours ago, Douglas Buckland said:

Bullet Item No. 7 is what I am actually after!

I wonder if Stewart could provide a link to diagrams showing these lightweight BHA’s?

Doug I think the question is answered in point 7, I have written to a couple of Directional hands and requested a typical long reach horizontal section BHA design, lets see what comes back, but you can bet your house the it will be specialised  DC  and roller reamers or stabilisers to avoid  contact with formation while sitting on the low side and management of buckling forces while adding weight in the conventional fashion.

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(edited)

On 9/6/2019 at 4:03 PM, Douglas Buckland said:

This tells you that you need to transfer weight to the bit and tells you the action the driller takes to do so, but does not indicate mechanically how this is accomplished.

Ye, the driller raises the brake to slack off and add weight on the bit. In a vertical or deviated well this is fairly straight forward, but in a long horizontal well it is a much different story.

From the same paper: 

Quote

The Slider automated surface rotation control
system was developed to help operators regain some of the drilling performance of a conventionally rotating drillstring. The Slider interface interacts with the topdrive control system to rotate the drillstring back and forth. This torque rocking technique reduces longitudinal drag along part of the drillstring while slide drilling. Rocking back and forth subjects the upper drillstring to near-constant tangential motion, pro- ducing a dynamic friction coefficient, which is lower than a static friction coefficient created by nonrotating pipe. Rocking can also help reduce axial friction along the drillstring. However, this motion is not necessarily transmitted all the way to the bit—other processes are at work.

So I'm guessing they rock and roll ;)

Edited by Ward Smith
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(edited)

Alright team! Stu from Merlin here.

With regards to bottom hole assemblies (BHA's) - again, no magic solutions. When I mean light, I mean keeping the amount of drill collars to the bare minimum, so starting at the bottom of the string you'd have.

Bit / Rotary Steerable System (RSS) / MWD / LWD / heavy weight drill pipe (HWDP) + Jars + drill pipe (DP) to surface.

We would expect to run only around 50m/150ft of "drill collars" (i.e. RSS/MWD/LWD) close to the bit, then into the HWDP (as little as possible - 3 - 5 joints, sometimes more depending on the application) then DP to surface.

You usually don't need lots of "weight on bit" to drill effectively and the neutral point can often be way up the drill string, closer to surface than the bottom of the hole. Also, under normal circumstances, no need for roller reamers or special stabilisers. Exxon put out some good guidance on what makes a good stabiliser (SPE-189649-MS, 2018) based on their work in Sakhalin. 

Douglas mentioned jars - a good observation. There is always plenty of discussion on jar placement and usefulness in long lateral/ERD wells. You may not be able to cock/fire them depending on the situation you're in, but then again you might. Zero to hero in short order if you have them in the string.....

Stu

Edited by Stewart McGregor
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Thanks for that Stu.

I don’t mean to harp on the issue, but I am still somewhat confused.

Okay, you may not need ‘lots’ of weight on bit to drill, but you definitely need some! If you are running a ‘light’ BHA as described, with your neutral point way back in the string, in a long horizontal lateral, you will have two issues working against you getting ANY weight to the bit.

First, you will have the drag of your HWDP/DP laying on the bottom of the lateral (cuttings beds due to inefficient hole cleaning will only exasperate this situation) and drag along one or more kilometers of horizontal hole will eat up any available weight to the bit rapidly.

Secondly, with your neutral point way back in the string, likely in the vertical section, any available weight not consumed by drag will be consumed by buckling.

The light BHA is not designed to provide weight on bit, it looks more like a ‘tool carrier’ for RSS/LWD/MWD.

Even if you run collars in the vertical section, drag and buckling will eat up this weight early in the horizontal section.

I am not intending to come across as confrontation in the least, I am simply trying to understand how any appreciable weight is transfered to the bit to allow you to drill at all!

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No worries. When Jason sent me the note on the question, I wrote out another response that was more biased towards torque and drag, but after a "sense check", I was persuaded to go a bit higher level....

Try this - I hope it's not too basic but I thought it was worth starting from square one..

The key is friction (or drag). Tripping pipe in the hole (or sliding whilst drilling) causes an interaction between the hole and drill pipe (obviously). The amount of drag is related to a number of factors, such as:

  • The mechanical interaction between the steel of the drill pipe and the rock itself.
  • The contact area of the steel and rock.
  • The properties of the drilling fluid
  • The stiffness of the string
  • The shape of the hole (ledges, wash outs, “undergage” patterning).
  • Amount of cuttings sitting on the low side of the hole.
  • Other stuff I haven’t thought of right now.
  • Oh, and trajectory, inclination & tortuosity.

We account for all of these measureable and non-measureable factors through the use of a Friction Factor (not the same as a co-efficient of friction). 

When tripping in, we are sliding the drill string down hole and the sum of all of these interactions acts in opposition to the direction of motion, hence it decreases the measured weight of the drill string, relative to the measured off bottom rotating weight.

When tripping out, these drag forces act in same direction as the motion of the drill string, hence your measured pick up weights are higher than the measured rotating off bottom weight. Rotating the string breaks the axial friction of the string/hole system but that translates into another drag force, this time rotational, which we measure as torque. Because there is no axial friction while rotating, the weight we measure at surface when rotating is the “true” weight of the string in hole.

So, to answer the question. When we rotate the drill string, we’re breaking the axial friction (drag) which means we can run the string in hole with less affect due to these forces. The string will run in hole as long as there is enough string weight to overcome whatever residual drag remains. When it comes to weight on bit, applying a force at the end of the string effectively increases the axial friction, which could put the drill string into a buckling condition, which we clearly want to avoid.

So, as long as:

  • there is enough string weight in the hole (depending on the trajectory and drill string) to allow for a net downward force compared to the remaining axial forces (either when rotating or sliding), and
  • there is enough buckling resistance in the string to apply some weight on bit to allow the cutting action to occur,

 You will be able to make some hole, hand!

There are loads of commercially available software programs that allow you to plug in the drill string and BHA properties, hole geometry and trajectory, mud properties which will then generate slack off, rotating off bottom and pick up weights against various friction factors. You can then check these against a buckling analysis at various weight on bit values to ensure that you avoid surprises whilst drilling. On one recent job, one of our client was running out sliding capability around ~16.5k ft MD on a ~6.5kft lateral. If you want to go further, you can look at using Agitators, or use an RSS which avoids slide drilling altogether.

Make sense?

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I understand all that you have said as I have a drilling engineering background. But at some point there must be a limit as to even running in the hole. At some point, while running in the hole, where you do not even have enough weight in the string to overcome the drag in a horizontal well and you will essentially be 'pushing' the pipe in the hole...theoretically.

Assuming that you can push the bit to the end of the hole so that the toolface contacts new formation, it appears to me that the weight you are now drilling with is actually the force of the drill string 'unbuckling', like a spring.

RSS has a different issue, as you are rotating the pipe AND using a mud motor, at some point, again theoretically, you should stall out your topdrive due to torque.

I am not doubting what you are saying, and I know Merlins reputation. That said, I have been involved in many extended reach well and wells with very complex paths. As long as you have SOME angle, and therefore weight acting at the bit, you can usually get to TD. That said, when you are drilling long horizontal laterals, with no angle and no weight actually acting on the toolface - the game is entirely different.

As I said, this is not harping on the subject, I am just trying to get my head around how you actually get weight to transfer out a few kilometers in a horizontal well.....

 

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15 hours ago, Douglas Buckland said:

Assuming that you can push the bit to the end of the hole so that the toolface contacts new formation, it appears to me that the weight you are now drilling with is actually the force of the drill string 'unbuckling', like a spring.

This is it, exactly! 

My days of throwing chain are long gone, as are the days of the driller riding the brake handle. The NOV rigs have video displays and joysticks and might as well be a video game. The driller isn't watching a scale, but a whole bunch of data pre analyzed and fed to her/him as a "keep it in the circle" game. You might find one out of a hundred drillers who actually know and understand what's going on Downhole, but it doesn't matter because software doth make geniuses of us all. 

It's kind of like flying a plane with great instruments versus seat of the pants on the stick. I've done it both ways and while I can fly the stick, I vastly prefer the electronic cockpit because it takes all the "stupid" out of the game. Sure you have things like the 737 Max fiasco, but even that is just cocky pilot behavior. Fly Southwest and notice the angle of attack on takeoff. They don't NEED to take off at 60 degrees, they just LIKE to. Add the bigger engines on the Max, and bored pilots who don't get to have much fun and it was a recipe for disaster. Boeing just needed to say, "Don't exceed 45 degrees on takeoff" and all would have been fine. But instead they implemented "secret code" called MCAS and neglected to tell anyone about it. Excellent In depth article here in IEEE spectrum.

I can fly my Cessna using artificial horizon and instruments that let me "fly the envelope" with no concern about what's really going on outside the window. All well and good, assuming my instruments and sensors are up to snuff. Absolutely great when it's pure IFR flight rules outside and I'm only looking at clouds anyway. 

At some point, drilling transitioned from "VFR" (Visual Flight Rules) to IFR (Instrument Flight Rules). Any old timer still recognizes what's going on, and I've even laughed at the "artist's conception" on the screen of the old drill string weight analog gauge. But while the old gauge had actually been "weighing" the string, the new "software" gauge is getting it from derivatives and integrals under the hood. Technology marches on…

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13 minutes ago, Ward Smith said:

the new "software" gauge is getting it from derivatives and integrals under the hood. Technology marches on…

NIT: there is not one single integral or derivative being done, not even in the INS.  Look up tables and numeric computation. 

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I shudder to think that drillers do not have a clue what is going on downhole anymore.

So you are telling me that in long horizontal laterals we are simply introducing buckling and using that stored energy to ‘push’ the bit into new formation?

And that doing so while running RSS (for example), rotating with buckled pipe, is not an issue?

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(edited)

1 hour ago, Douglas Buckland said:

I shudder to think that drillers do not have a clue what is going on downhole anymore.

So you are telling me that in long horizontal laterals we are simply introducing buckling and using that stored energy to ‘push’ the bit into new formation?

And that doing so while running RSS (for example), rotating with buckled pipe, is not an issue?

Doug- I have looked at the info and systems available and indeed it looks like you hit the nail on the head with the "buckling"issue, now being nicely referred to as the "Buckland" phenomenon. It appears to be that the buckling of the string in the vertical, slant and horizontal sections are managed by these fly by wire systems, ie enough buckling is managed to push the BHA (which as I stated earlier in the thread indeed do not use DC- not blowing trumpets), but use HWDP to avoid friction.

As far as the weight indicator or Martin Decker is still visible in both analogue and digital formats on cyber chair systems, so the driller still has to be aware of whats going on, yes they will engage the auto drill for some tediously hard sections but they still require to be aware of whats going on, lots of alarms etc but just in the fact well control courses haven't changed to a cyber system tells us the fundamentals of turning to the right and drilling a hole are still the same.

The buzz phrase is "Managed Friction Factor" - The link shows various scenarios including long horizontal sections. Buckling of the drillstring is a nightmare and causes havoc with torque etc and eventually a lost BHA, wake up the fishing hand, directional hand goes to bed.

Im still trying to get my head around a long horizontal section and the pipe being pushed by a spring load managed by the hook weight and driller etc, seems too risky, but it does look like its managed by numerous factors, mud properties, fancy BHAs and a lot of tech.

JMHO

https://www.sciencedirect.com/science/article/pii/S1110062116300150

Edited by James Regan
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@Jan van Eck

''Easy to grasp''   #stillgoing  ;) 

On 9/6/2019 at 4:47 AM, Jan van Eck said:

What they want to do is lower the overall sidewall coefficient of friction

Yep, come on guys. Pretty obvious. Jeez. 

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(edited)

17 minutes ago, DayTrader said:

@Jan van Eck

''Easy to grasp''   #stillgoing  ;) 

Yep, come on guys. Pretty obvious. Jeez. 

Its basic stuff really, put your straw in you coke bottle it pokes out the top, you blow or suck (normally), now put the lid back on and the straw is forced into the bottle  and either breaks or buckles you can't use the straw any more efficiently, we just need a really long coke bottle to explain it better and L shaped... 😉

https://blog.odfjellwellservices.com/what-is-drill-pipe-buckling-and-how-to-prevent-it-from-happening

Thats only buckling 101, now we need to fill the L shaped coke bottle with rocks, and get the straw to the end of the bottle and still be able to use it to blow bubbles and remove the rock and the residue after  drilling out the rock with none or little force at the pointy end......god forbid you jam the straw as we now need to discuss how to free the straw without damaging it......

Worth remembering that the bottle is highly charged with gas that wants to erupt on your new white T-shirt which takes us into well control or Fizz Control....

Edited by James Regan
more info added
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