Douglas Buckland

Getting Weight to the Bit in a Long Lateral

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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.

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(edited)

Doug just off the top of my head.

The theoretical BUR (Build Up Rate) capability of the motor could be calculated using the simple geometric model by adjusting the length between the bit gauge and the bearing housing stabilizer in the calculation. However, in the application planned for the LGSM (Latest Gen Steerable Motors), the operator would require the steerable motor assembly to be run slick. The uncertainty in the contact points between the BHA and the borehole wall for the slick motor necessitates  another method to calculate the BUR capability of the LGSM.

A proprietary engineering software package can be employed to calculate the BUR capability of the modified motor. The software analyzes the static and dynamic behavior of a complex drill string in a wellbore. The individual components of the drill string and BHA (Bottom Hole Assembly) are broken into discrete elements. These elements then undergo finite-element analysis to determine the internal loads and borehole wall contact forces acting on the drill string and BHA for a specific wellbore profile and BHA design.

Using the resolved contact forces and loading, the modeling software predicts the BUR capability of the system. This provides a more complete and sophisticated analysis of BUR capability, compared with the geometric model.

https://www.aogr.com/magazine/sneak-peek-preview/new-techniques-building-better-wells

Edited by James Regan
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BUR is not the issue, as long as you keep the bending strength ratios of your tool joints within limits and don’t get too aggressive.

My issue is how do you get weight to the bit in a 2km (for example) horizontal lateral? The pipe will be dragging on the low side of the hole, in rotation or not, which would eventually negate any available weight you had in the vertical section of the well.

I may be missing something here, but damned if I know what it is!🤨

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It shows acceptable accuracy for vertical wells, but for horizontal wells, it cannot be used because of low accuracy due to wellbore friction.

For horizontal wells, the inclination for the entire well is 0°. For the buildup sections and horizontal sections of horizontal wells, the inclination is not equal to 0°. For buildup sections, the inclinations increase from 0° to 90° and in the horizontal sections the inclination equals or is close to 90°. Since there are inclination changes, the bottomhole assembly (BHA) and drillstring will contact the wellbore by gravity or due to buckling while rotating. Because of the existence of friction between drillstring and wellbore, torque and drag will occur and accumulate from bottom hole to surface. The additional drag will partially offset WOB believed to set at surface. This is also the reason why the WOB on surface panel is inaccurate for horizontal wells. Generally, the WOB on surface is greater than the downhole WOB.

Check out the link it appears that the BHAs are very small 50meters including Mud Motors, MWD etc, it looks like minimal drill collars with HWDP staggered between DP and so on see diagram.

https://prism.ucalgary.ca/bitstream/handle/11023/1717/ucalgary_2014_lei_lingyun.pdf;jsessionid=357D5D7A4AD853B66C0E7FEECB99CE48?sequence=2

Screen Shot 2019-09-05 at 12.04.13.png

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I learning here also Doug, excellent discussion to bring up, maybe a rocket scientist will join in and show us some new iPhone App that does it, its interesting as the basic well mechanics of the Drillstring in your thread doesnt make sense at all, at some point you would be just bucking the DP as the collars sit on the low side, which would also bring into the equation differential sticking risks.

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(edited)

For longer laterals, two main systems usually employed. In very general terms, if you're simply rotating away...not much of an issue. There will obviously come a point where torque & drag, hole cleaning, etc... comes in to play. But, well profiles are generally limited to a "window" that the directional driller needs to stay in....therefore needs to "slide" the assembly in the direction you want to travel. Sliding involves keeping the drill string static while you point the mud motor in the direction you want to go. So, again...this is where torque & drag...buckling...etc...becomes a problem. Old school method was to manually "wobble" the pipe at surface ie: put 5 turns clock-wise into the pipe on surface, put 10 turns counter clock-wise into pipe, put 10 turns clockwise into pipe, etc.... This helps to break the drag & allows your weight to transfer down the pipe (WOB). Nowadays, most deep drilling rigs use an automatic rocker system. For companies that want to spend the money on fancier tools, they can always put a rotary steerable motor down-hole. Instead of the rotate / slide / rotate method of drilling, rotary steerable assemblies are always rotating thereby cutting down on the WOB issues. Mud systems are also very important. The better your "slickery sauce" the farther you can drill ;)

Edited by Hamish
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Hi Doug, missed your message. I'm not the expert but have worked with some. One is on a job right now going out further than the Alaskan well. Can't say where it is, it is under NDA. 

This article is fairly basic but the ones that were better at SPE were behind pay walls. Bottom line they use mud motor drills so the whole string isn't rotating, only the bit at the BHA. I wrote a patent for an electric motor version but I'm unsure if it will ever get built. I designed it for a brushless DC motor, which has essentially unlimited torque. 

Here's a Good video describing all the components. You'd mentioned before that laterals were being drilled back in the 80's,  but they were using the techniques you've mentioned and hit the failure points you've identified. I think of laterals since they took pumps like these and ran them backwards with a drill bit in the end. Fairly ingenious no? The string doesn't rotate but it does drag and they do try to rotate a bit to even out the wear and tear. 

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Guys, thanks for all your responses, but perhaps I am not making myself clear.

I understand direction drilling and how it works. I have used mud motors and rotary steerable systems in the past. But my experience was with highly deviated, complex well-paths and not long, horizontal layerals.

Regardless if you are using mud motors, rotary steerable systems, sliding or rotating, you MUST be able to get weight to the bit or it simply cannot drill.

My question only relates to how weight is provided to the bit in a long horizontal lateral and not any directional control issues....HELP!😂

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22 minutes ago, Douglas Buckland said:

My question only relates to how weight is provided to the bit in a long horizontal lateral and not any directional control issues....HELP!😂

@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.

 

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I have absolutely no idea what anyone is talking about here.

On to the next discussion for me... 

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No problem! That whole trading thing baffles me...😂

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12 hours ago, Douglas Buckland said:

BUR is not the issue, as long as you keep the bending strength ratios of your tool joints within limits and don’t get too aggressive.

My issue is how do you get weight to the bit in a 2km (for example) horizontal lateral? The pipe will be dragging on the low side of the hole, in rotation or not, which would eventually negate any available weight you had in the vertical section of the well.

I may be missing something here, but damned if I know what it is!🤨

Found This paper that wasn't behind the SPE paywall. Pretty complete explanation from Schlumberger. Cheers 

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25 minutes ago, Ward Smith said:

Found This paper that wasn't behind the SPE paywall. Pretty complete explanation from Schlumberger. Cheers 

Thanks for that Will.  Looks like you nailed it.

04-slide-drilling-english.pdf

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1 hour ago, DayTrader said:

I have absolutely no idea what anyone is talking about here.

On to the next discussion for me... 

Oh, come on, not that hard to grasp.  You want to pound a fence-post into the ground, you have to get the weight (the hammer) on the top end.  Same idea with the drill;  nothing (no weight) pushing on the drill bit, it does not move further into the ground  (or rock).  SO the whole issue is:  how do you get it to keep on going?  In pole pounding, it gets to what the engineers call the "point of refusal," where that post, or pylon, will not move farther.  In drilling, the roustabouts want to keep that bit moving forward  (and making a longer hole) so that they can capture more oil - thus moving that "point of refusal" farther down the line, for a longer hole. .  

The above discussion was a bit technical on overcoming side hole drag and bottom collar friction, but taking the words out, it is still that you need to be able to get some "push" at the end or the drill stops drilling.  What they want to do is lower the overall sidewall coefficient of friction, kinda like running that Zamboni machine over the ice-hockey rink surface to let the players skate faster.  So there you go!

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(edited)

Thanks  @Jan van Eck ;) 

F**k**g smart arse   :)

Edited by DayTrader
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1 hour ago, Ward Smith said:

Found This paper that wasn't behind the SPE paywall. Pretty complete explanation from Schlumberger. Cheers 

Thanks for this. Need to get home and bring it up, difficult to read on the phone...

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21 minutes ago, Jan van Eck said:

Oh, come on, not that hard to grasp.  You want to pound a fence-post into the ground, you have to get the weight (the hammer) on the top end.  Same idea with the drill;  nothing (no weight) pushing on the drill bit, it does not move further into the ground  (or rock).  SO the whole issue is:  how do you get it to keep on going?  In pole pounding, it gets to what the engineers call the "point of refusal," where that post, or pylon, will not move farther.  In drilling, the roustabouts want to keep that bit moving forward  (and making a longer hole) so that they can capture more oil - thus moving that "point of refusal" farther down the line, for a longer hole. .  

The above discussion was a bit technical on overcoming side hole drag and bottom collar friction, but taking the words out, it is still that you need to be able to get some "push" at the end or the drill stops drilling.  What they want to do is lower the overall sidewall coefficient of friction, kinda like running that Zamboni machine over the ice-hockey rink surface to let the players skate faster.  So there you go!

Not necessarily Jan. When ‘pounding a post’ or driving the conductor casing, you are correct, you are simply beating it into the dirt. All you are really worried about is the rigidity of the pipe and it’s ability to maintain it’s shape while it is ‘driven to refusal’.

When drilling a vertical well, the drillpipe is in tension. At some point in the collars (bottomhole assembly) you reach a neutral point and below this the collars are in compression. This is the weight available to the bit and this is varied by adjusting the tension in the pipe by raising or lowering the drillstring at the drill floor.

Once you make the bend and are drilling horizontally, this configuration does not work well as the weight of the drill collars is now acting on the low side of the hole and is no longer pushing the bit into new rock.

You can get around this for awhile by reconfiguring the drill string so that the collars are back in the vertical section of the hole and continue drilling until they are back at the bend, then reconfigure and repeat, but this comes with derrick management headaches and buckling issues below the collars in the drillpipe.

Eventually there is so much drag from the drillpipe laying on the low side of the horizontal section that the drill collar weight in the vertical section cannot overcome the drag in the horizontal section.

Hence my query.

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20 minutes ago, DayTrader said:

F**k**g smart arse   :)

You are promoted to the Head of the Class for recognizing raw talent.  Congratulations!

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1 minute ago, Douglas Buckland said:

Not necessarily Jan.

C'mon Jan, pretty easy to grasp buddy  ;) 

It's just banging in a post / ice hockey / ''Derrick management''

 

15 hours ago, James Regan said:

The uncertainty in the contact points between the BHA and the borehole wall for the slick motor necessitates  another method to calculate the BUR capability of the LGSM.

Well obviously. Duh. 

 

13 hours ago, James Regan said:

it looks like minimal drill collars with HWDP staggered between DP and so on

Agreed. 

 

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2 minutes ago, Douglas Buckland said:

Eventually there is so much drag from the drillpipe laying on the low side of the horizontal section that the drill collar weight in the vertical section cannot overcome the drag in the horizontal section.

I was attempting, albeit imperfectly, to make a very simple analogy.  

That said, you will agree that it is all a matter of friction.  That "drag" that you are attempting to overcome is a frictional drag  (the various pieces of pipe resting on the hole-bore bottom).  You can overcome that frictional drag by either reducing the total surface area, which is what a shaft in say a paper mill accomplishes by installing pillow-block bearings, and you can reduce the drag by lowering the coefficient of friction, by putting oil in the pillow block bearing surfaces, or "mud" under pressure along that drill pipe in the bore hole.  Once you lower the overall resistance, you can then transmit more "push" to that drill head.   Now, if I have this analysis screwed up, I am going to open a bottle and get roaring drunk, as I will be facing the hard fact that my brains no longer work. OK, hit me with the bad news... 

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8 minutes ago, Jan van Eck said:

Now, if I have this analysis screwed up, I am going to open a bottle and get roaring drunk, as I will be facing the hard fact that my brains no longer work.

I say open it either way.

Your brains don't work or you're a legend (potentially both). Both deserve a drink. 

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28 minutes ago, DayTrader said:

Well obviously. Duh. 

10 points for hilarious sarcasm.

< ducks >

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1 hour ago, Jan van Eck said:

I was attempting, albeit imperfectly, to make a very simple analogy.  

That said, you will agree that it is all a matter of friction.  That "drag" that you are attempting to overcome is a frictional drag  (the various pieces of pipe resting on the hole-bore bottom).  You can overcome that frictional drag by either reducing the total surface area, which is what a shaft in say a paper mill accomplishes by installing pillow-block bearings, and you can reduce the drag by lowering the coefficient of friction, by putting oil in the pillow block bearing surfaces, or "mud" under pressure along that drill pipe in the bore hole.  Once you lower the overall resistance, you can then transmit more "push" to that drill head.   Now, if I have this analysis screwed up, I am going to open a bottle and get roaring drunk, as I will be facing the hard fact that my brains no longer work. OK, hit me with the bad news... 

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.

 

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4 minutes 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.

 

PS: If you have inadequate hole cleaning you get cuttings beds building up on the bottom of the hole. The pipe lays in these beds effectively increasing the surface area of the pipe dragging.

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5 minutes 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.

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. 

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