Getting Weight to the Bit in a Long Lateral

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14 minutes ago, James Regan said:

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 running 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

James, thanks for this.

This article is addressing the friction factor input into torque & drag models, and as the article states, they are generally ‘fudge factors’ as there are simply too many factors to consider and rarely any applicable empirical data to determine a realistic factor.

If you look at the torque & drag graphical presentations, depending on what friction factor you input, at some point the torque or drag will exceed the limitations of the rig...theoretically.

From the recent responses, it appears that the pipe is ‘crammed’ into the hole, intentionally inducing buckling, and the stored energy in the buckled pipe is utilized to provide force to the bit to drive the cutting structure into new rock.

Furthermore, it seems the technology of choice is the Rotary Steerable System (RSS). This system allows you to rotate the pipe while maintaining directional control and since the pipe is rotating in the hole, reduces drag.

But it is imperative to keep in mind that you are rotating intentionally bucked pipe! This pipe would be ‘flapping around’ in the hole. Portions of the pipe would be continually alternating between compression and tension fatiguing the pipe and running the risk of drill string failure.

The whole idea of drilling with intentionally buckled pipe goes against basic ‘good drilling practices’....but as I said, I may be missing something.

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(edited)

24 minutes ago, Douglas Buckland said:

From the recent responses, it appears that the pipe is ‘crammed’ into the hole, intentionally inducing buckling, and the stored energy in the buckled pipe is utilized to provide force to the bit to drive the cutting structure into new rock.

All info so far seems to point in this direction, your spring analogy i think hits the spot, potential energy store in the spring (buckled pipe) slowly adds WOB or moves the pipe along the flat section. Risky indeed.

24 minutes ago, Douglas Buckland said:

But it is imperative to keep in mind that you are rotating intentionally bucked pipe! This pipe would be ‘flapping around’ in the hole. Portions of the pipe would be continually alternating between compression and tension fatiguing the pipe and running the risk of drill string failure.

Again it appears that these factors are considered by the software and delicate BHAs, its as if the aggressive risk is being taken into consideration and as the aggressive forces are transmitted slowly through the string from the buckling area to a smooth lateral push through the horizontal section to add the desired WOB, this could not be managed by a mere human, not the "humans" I've seen working the break some time. - Baby Sitter being called as we speak-

24 minutes ago, Douglas Buckland said:

The whole idea of drilling with intentionally buckled pipe goes against basic ‘good drilling practices’....but as I said, I may be missing something

Someone mentioned before that Tractor driven systems were being designed as we speak, this is the most logical answer, I guess we are still pushing boundaries of the rig floor mentality of "just out a bit more weight on the bit and lets see" (but with the addition of logarithms and Poly Ci etc) - The Industry has changed a lot but the fundamentals of drilling a hole haven't, we still turn to the right and pump.

As an Engineer your brain won't let you accept it until its been proven or seen- We are mechanical agnostics...

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

All info so far seems to point in this direction, your spring analogy i think hits the spot, potential energy store in the spring (buckled pipe) slowly adds WOB or moves the pipe along the flat section. Risky indeed.

Again it appears that these factors are considered by the software and delicate BHAs, its as if the aggressive risk is being taken into consideration and as the aggressive forces are transmitted slowly through the string from the buckling area to a smooth lateral push through the horizontal section to add the desired WOB, this could not be managed by a mere human, not the "humans" I've seen working the break some time. - Baby Sitter being called as we speak-

Someone mentioned before that Tractor driven systems were being designed as we speak, this is the most logical answer, I guess we are still pushing boundaries of the rig floor mentality of "just out a bit more weight on the bit and lets see" (but with the addition of logarithms and Poly Ci etc) - The Industry has changed a lot but the fundamentals of drilling a hole haven't, we still turn to the right and pump.

As an Engineer your brain won't let you accept it until its been proven or seen- We are mechanical agnostics...

My ‘engineer brain’ also will go to the ends of the earth to avoid twist-offs and fishing jobs!

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(edited)

21 minutes ago, Douglas Buckland said:

My ‘engineer brain’ also will go to the ends of the earth to avoid twist-offs and fishing jobs!

Twists offs, stuck pipe, increased torque, drag, swabbing, surging, wash outs, top drive on fire, drill pipe fatigue, key seating in the well bore or BOP (worse case don't want to think about it) etc etc, still we haven't really gone down the road of stuck pipe and jar positioning (maybe we just uncoil the spring and the pipe jumps out of the hole in stands....... You need to ask the Camp Boss, he knows everything 🤣

It appears that rocket science is easier to explain, wheres a rocket scientist with some rig floor know how, this is whats required.

Edited by James Regan
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(edited)

Yup, no question you will run out of ability to run in hole and drill for the reasons you mention but if you do the analysis, you might get a surprise as to how far you can go....The world's longest well, O5-RD in Sakhalin got out to a whisker below 50k ft measured depth with a 46.4k step-out. Reservoir was around 8500ft TVD. I don't believe they ran out of weight at that stage, more likely drill pipe 🙂

The key is reducing the axial drag - once you start rotating the string, it's much easier to overcome this and as long as you have some weight in the low angle part of the well (which will generate a downward force greater than the drag force), you'll be able to run in hole and apply weight on bit, up to some limit above which you will initiate buckling. 

Edit: 

I ran out of time yesterday to post this and I've seen some comments subsequently about "cramming" pipe in the hole and springs and so on forcing the bit against the rock to initiate cutting - that's not correct. Hope the above explanation is enough.

Edited by Stewart McGregor
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36 minutes ago, Stewart McGregor said:

Yup, no question you will run out of ability to run in hole and drill for the reasons you mention but if you do the analysis, you might get a surprise as to how far you can go....The world's longest well, O5-RD in Sakhalin got out to a whisker below 50k ft measured depth with a 46.4k step-out. Reservoir was around 8500ft TVD. I don't believe they ran out of weight at that stage, more likely drill pipe 🙂

The key is reducing the axial drag - once you start rotating the string, it's much easier to overcome this and as long as you have some weight in the low angle part of the well (which will generate a downward force greater than the drag force), you'll be able to run in hole and apply weight on bit, up to some limit above which you will initiate buckling. 

Edit: 

I ran out of time yesterday to post this and I've seen some comments subsequently about "cramming" pipe in the hole and springs and so on forcing the bit against the rock to initiate cutting - that's not correct. Hope the above explanation is enough.

Hello again Stewart,

So from what you are saying, as I understand it, is that the weight that you are drilling with comes from the drill pipe/heavy weight drill pipe/ collars which you have judiciously placed in the vertical and build sections of the well. Only these components would be able to impart a portion of their weight axially along the drill string towards the bit (assuming a 2D well. 3D gets even squirrelier). This weight component derived in the vertical and build section MUST overcome the drag forces or you cannot proceed with the drilling operation.

Rotating the pipe, lubricity in the mud, specialized drill pipe centralizers all work to reduce the axial drag.

Am I getting this correct so far?

If so, in any given well there is a limit to the buoyed weight available in the vertical and build section which would be directly proportional, ultimately, on the measured depth from the rotary table to the end of the build section (as this is the only pipe contributing an axial force towards the bit).

If the previous paragraph is correct, then there is a limiting drag force which would counteract the force being supplied by the pipe in the vertical and build sections. Once this limiting drag is reached the pipe then buckles.

If this is true, then there is a maximum length of horizontal section that can be drilled based solely on the configuration of the well and the axial drag, which in the design stage is a wild arsed guess as the actual friction factor is not known.

If everything I have assumed to this point is correct, then successfully drilling a well such as the O5-RD relies alot on faith and I would assume that they only stopped drilling, as you said, because they ran out of weight or ran out of drill pipe...not because they intersected any intended target. The logistics and costs on this well would have been a nightmare, let alone mast and pit management.

Please let me know if I have the basics correct. Also, if you’d happen to have a link to what was run in the hole on this well it would be appreciated.

Thanks for your time and consideration on this topic.

 

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10 hours ago, footeab@yahoo.com said:

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

I wonder. Given chip power, it would be easier and less coding to calculate it on the fly. 

Example, I've got a digital oscilloscope and an old analogue one. The digital does indeed do integrals on the fly, while the analog has a circuit equivalent of your "look-up tables". But to be honest I've met only a couple of EE's in the oil patch and neither of them were using their degrees. I don't have any idea if an NOV outsourced their HMI design or hired a bunch of EE's and software geeks and rolled their own. 

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10 hours 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?

My understanding is that the RSS typically is spinning while the full drill string is NOT, and vice versa. So they're taking turns, running the drill motor for a bit, then running the drillstring. The article James linked was pretty thorough IMHO. 

For the lurkers, this picture is worth a thousand words: 

1-s2.0-S1110062116300150-gr2_lrg.jpg

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For oil and gas operators today, remaining competitive means drilling longer laterals with less downtime, while creating the best possible balance of cost efficiencies. Casing flotation devices can help operators achieve these goals as they are engineered to reduce costs and increase efficiencies by ensuring casing reaches the bottom.

In the Appalachian Basin, Northeast Natural Energy (NNE) was challenged to land 17,000 feet of casing in a horizontal gas well with a 9,000-foot lateral while maximizing operational and cost efficiencies.

Running casing to depth in long lateral sections is complex due to excessive drag forces. While conventional casing flotation can reduce drag by creating an air chamber above the float collar that reduces sliding friction by approximately 50 percent, they shatter in large pieces. This creates debris which results in losing a significant portion of pay zone at the toe of the well.

However, by utilizing Nine Energy Service’s Breakthru™ casing flotation device, NNE eliminated the need for a debris trap and shortened the shoe track of the well. NNE gained an additional 20 feet of pay zone without extending lateral length, translating to an estimated incremental gas recovery of $120,000 in addition to improved drilling and completion cost efficiencies.

 

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Nine’s Breakthru casing flotation device uses an engineered material barrier that disintegrates into small sand-like particles after activation that are then easily circulated out through sleeves, toe valves and float equipment. This effectively eliminates the need for a debris trap, fluid flushes or extra trips to retrieve device pieces, reducing cost and maximizing recovery.

The device also greatly reduces the weight of the casing, which enables the string to reach total depth every time. And, eliminating the two premium thread connections required for conventional flotation subs lowers costs and further improves well economics.

image.png.4e88284f5869fcb957cc028fb9e2d6c2.png

https://nineenergyservice.com/cementing-drilling-solutions/breakthru-casing-flotation-device?utm_source=E%26P&utm_medium=Paid Advertisement&utm_campaign=BreakThru&utm_content=SeptemberOnlineArticle

 

 

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Just confused on what this jas to do with getting weight to the bit while drilling?

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8 hours ago, Ward Smith said:

My understanding is that the RSS typically is spinning while the full drill string is NOT, and vice versa. So they're taking turns, running the drill motor for a bit, then running the drillstring. The article James linked was pretty thorough IMHO. 

For the lurkers, this picture is worth a thousand words: 

1-s2.0-S1110062116300150-gr2_lrg.jpg

Now take that same drawing, orient it so that the well is horizontal and tell me what direction the ‘Weight of pipe’ is acting and where the ‘Axial load’ is coming from?

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57 minutes ago, Douglas Buckland said:

Now take that same drawing, orient it so that the well is horizontal and tell me what direction the ‘Weight of pipe’ is acting and where the ‘Axial load’ is coming from?

It's already in the drawing (which came from the link James posted). Upper right they show the horizontal and the drawing focus on the inset. I agree with you, and I like the "Buckland" phenomenon. I think there's an unwinding "kick" to the toe that helps (maybe) make more hole. Remember our prior discussion about the Alaskan well and your disbelief about changing out drillstring? I'm more convinced than ever that the strings have gone through hell. The software surely helps but it's still a guessing game. 

Is it worth it? Definitely. Being able to lateral out offshore from a nice cozy beach can save hundreds of millions. It's also the reason the Baker Hughes rig counts no longer help us determine future production numbers. One big lateral well can surely out produce a dozen vertical wells into the same formation. 

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1 minute ago, Ward Smith said:

It's already in the drawing (which came from the link James posted). Upper right they show the horizontal and the drawing focus on the inset. I agree with you, and I like the "Buckland" phenomenon. I think there's an unwinding "kick" to the toe that helps (maybe) make more hole. Remember our prior discussion about the Alaskan well and your disbelief about changing out drillstring? I'm more convinced than ever that the strings have gone through hell. The software surely helps but it's still a guessing game. 

Is it worth it? Definitely. Being able to lateral out offshore from a nice cozy beach can save hundreds of millions. It's also the reason the Baker Hughes rig counts no longer help us determine future production numbers. One big lateral well can surely out produce a dozen vertical wells into the same formation. 

That drawing shows the bottomhole assembly while it is in the bend or build up section of the well, where you still have a certain amount of inclination and therefore a component of the weight acting along the drill string. Once you are horizontal this component disappears.

Look back on this thread to the latest comments by Stewart McGregor. He is with Merlin ERD which consults on these tupe of wells.

Buckling is to be avoided.

I never questioned “Is it worth it?”, I was simply trying to ascertain how it was accomplished.

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(edited)

On 9/4/2019 at 9:52 PM, Douglas Buckland said:

This is addressed to the technical drilling types on the forum:

A few days ago there was a post concerning a well drilled in Alaska with a 'world record' horizontal lateral section. I would like to know how do you get weight on bit (WOB) in one of these exceptionally long laterals?

In laterals which I have been involved in you simply place the drill collars plus heavy weight drill pipe in the VERTICAL section of the drill string and let the weight transfer (push) to the bit. This will work for awhile, but you have the issue of the pipe buckling below the collars and derrick management becomes a pain in the backside while tripping. In a very long lateral, regardless of how much weight you stack in the vertical section, eventually the drag along the bottom of the hole will eat it up and you will have no weight at the bit to drill ahead.

Perhaps there is now something like a BHA tractor to push the BHA/Mud motor towards the 'bottom' of the hole (it's been awhile since I was involved with drilling one of these wells).

Anyhow, if anyone out there can tell me how it is done these days, or point me in the right direction with a link, it woud be greatly appreciated.

Douglas,

 

I hope this isn't too late. I've done quite a bit of drilling in both the long reach 3D wells you speak about, as well as long hz wells. 

For long Hz wells:

1) when utilizing RSS tools, getting weight to bit isn't that much of a problem. When rotary drilling, the friction vector is pointing somewhere between axially (drag) and rotationally (TQ). Depending on the ratio of the speeds of axial and rotary motion, often low axial/rotary sped ratios, there is little drag while rotating. I've seen this measured, via DH WOB subs with Wired Drill Pipe, and typically DH WOB is 70-75% of the Surface Applied weight. A similar case applies with conventional motors, with just a little difference in the friction vector, as rotary RPM is usually lower with the ABH/FBH motor (of course, that depends on the setting, which varies)

2) Conventional Tools (Sliding): this one gets a little more hairy. Luckily, buckling limits of the drillstring are higher when non-rotating. Some of the tricks I've seen employed (haven't seen DH WOB data to corroborate, but the ROP certainly does). The following are on top of the typical things done (HWDP to +/- 45 deg inc, DCs if necessary):

- larger drill pipe: depending on the trade off with increased string weight (assuming the same grade), increases buckling resistance of the overall string

- Lo-Tad subs inside casing: with large BURs in many of the long shale wells, a large % of friction (50 - 65%, depending on well profile, build length, Hz length ,and Buckling regime) is actually in the build section

- mud lubricants: a good 1.5 - 2% Radiagreen EBL (or eME for high pH drilling fluids) if using a WBM. For OBM, there are lubriglide beads, with the requisite recovery unit

- Slide Enhancers: the most common/famous would be the NOV/Andergauge Agitator. When first used, were placed entirely too close to the bit to be effective. The tool transfers rotary motion (basically a mud motor power section) through to axial vibration, via a shock tool. The vibration reduces normal force/friction/drag when sliding. In recent years, as people have gotten better at understanding where/how friction is generated, they've began to place them in the build section, or use multiple tools (one either above or in build, one further in the Hz section).

Not exhaustive but I hope that this helps, clarifies, or spurs some conversation. 

Edited by Ian Austin
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25 minutes ago, Ian Austin said:

Douglas,

 

I hope this isn't too late. I've done quite a bit of drilling in both the long reach 3D wells you speak about, as well as long hz wells. 

For long Hz wells:

1) when utilizing RSS tools, getting weight to bit isn't that much of a problem. When rotary drilling, the friction vector is pointing somewhere between axially (drag) and rotationally (TQ). Depending on the ratio of the speeds of axial and rotary motion, often low axial/rotary sped ratios, there is little drag while rotating. I've seen this measured, via DH WOB subs with Wired Drill Pipe, and typically DH WOB is 70-75% of the Surface Applied weight. A similar case applies with conventional motors, with just a little difference in the friction vector, as rotary RPM is usually lower with the ABH/FBH motor (of course, that depends on the setting, which varies)

2) Conventional Tools (Sliding): this one gets a little more hairy. Luckily, buckling limits of the drillstring are higher when non-rotating. Some of the tricks I've seen employed (haven't seen DH WOB data to corroborate, but the ROP certainly does). The following are on top of the typical things done (HWDP to +/- 45 deg inc, DCs if necessary):

- larger drill pipe: depending on the trade off with increased string weight (assuming the same grade), increases buckling resistance of the overall string

- Lo-Tad subs inside casing: with large BURs in many of the long shale wells, a large % of friction (50 - 65%, depending on well profile, build length, Hz length ,and Buckling regime) is actually in the build section

- mud lubricants: a good 1.5 - 2% Radiagreen EBL (or eME for high pH drilling fluids) if using a WBM. For OBM, there are lubriglide beads, with the requisite recovery unit

- Slide Enhancers: the most common/famous would be the NOV/Andergauge Agitator. When first used, were placed entirely too close to the bit to be effective. The tool transfers rotary motion (basically a mud motor power section) through to axial vibration, via a shock tool. The vibration reduces normal force/friction/drag when sliding. In recent years, as people have gotten better at understanding where/how friction is generated, they've began to place them in the build section, or use multiple tools (one either above or in build, one further in the Hz section).

Not exhaustive but I hope that this helps, clarifies, or spurs some conversation. 

Thanks for that! Much appreciated.

I’ve been involved in the planning and execution of several ERD wells and wells with complex 3D profiles, but it seemed to me that things would get incredibly difficult once you approached 90 degrees...therefore this thread.

Thanks again!

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(edited)

3 hours ago, Douglas Buckland said:

Thanks for that! Much appreciated.

I’ve been involved in the planning and execution of several ERD wells and wells with complex 3D profiles, but it seemed to me that things would get incredibly difficult once you approached 90 degrees...therefore this thread.

Thanks again!

Now with a horizontal view (excuse the rough design) we can see the weight of pipe would have a much greater affect on BHA, which would affect the bending moment considerably based on whats being ran of course but gravity is a bitch, stabilisers or tools with larger fishing necks will reduce the friction.

After rotating the view by Ward its clear that the forces and loads would increase ie friction and axial loading, higher velocity would be required to overcome the friction, its probably marginal depending on the pipe size being used to support the motor?

slick hole and ram it in, and keep turning the bit....

Screen Shot 2019-09-11 at 03.33.16.png

Edited by James Regan
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