Can a cemented well casing really take 15000 psi ? 4

[docellen]

Seems to me that the casing would break loose from the cement.

Young's modulus for steel is about 29 x 10**6 psi. If the cross-sectional area of the steel is about 10% of the entire pipe, 15,000 psi in the pipe will produce about 150,000 psi in the steel, which will stretch it about 0.5% ( 1mm for every 200mm of pipe length).

Now assume the pipe is embedded in rigid cement and rock. The cement will shear long before the pipe moves even 1mm, probably at the smooth interface between the steel and the cement. The action will start in a thin band at the edge of the cement near the top of the pipe, and move down quickly.

Am I missing something?

 

[waross]

A rule of thumb from my fathers day was;
A rebar buried to 40 times its diameter in concrete will break before pulling out.
Is there a similar ratio for casing?

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[BigInch]

Problem. In a casing you have
longitudinal stress, Pressure * Area Flow / Area Steel
and
hoop stress Press * Diam / 2 / Wall thickness

On the 21" x 1" wall casing, if pressured to 15000 psia
at 5000 ft depth there's 2000 psi external pressure = 13000 psig.

Longitudinal stress is about 68 ksi
Hoop stress is about 158 ksi

I'll assume 80 ksi steel (no idea if that's right)
Combined stress limit of 90% = 72 ksi
The longitudinal stress is almost at that limit by itself, and you have to add the 158 ksi, which is already 2 times the pipe yield stress.

So, pipe doesn't stretch, it already split before that.

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"Being GREEN isn't easy." Kermit

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[waross]

Thanks BigInch.
Yours
Bill

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[docellen]

The hoop stress will push against cement and rock, but if there are voids in the cement, it could certainly burst in this mode. I'm assuming an ideal cement job. I think we still have a problem with shear forces at the steel to cement interface. Even if the pipe doesn't pop out, the cracked cement could open a path for the blowout.

 

[BigInch]

Yes there will be some confining pressure on the well casing from the cement, soil and rock, passive pressure; bascially figured as an equivalent hydrostatic load from a certain percentage of the weight of the soil above any given soil depth that acts laterally and at shallow soil depths would be a relatively small pressure in relation to the internal pressure of 15000 psi(a assumed, or is it g?), especially near the mud line, so it wouldn't contribute much to restraining the casing. Farther down it could be significant, but right at the mud line (and above, which is where the problem is) there is only hydrostatic pressure of some 5000 ft of seawater + atmos, roughly 2237 psia; a net internal pressure would really be 13864 psi"g" at that depth of water. Still looks pretty high for that 21" diameter casing, but again, not sure what its yield strength is.

"We have a leadership style that is too directive and doesn't listen sufficiently well. The top of the organisation doesn't listen sufficiently to what the bottom is saying." Tony Hayward CEO BP
"Being GREEN isn't easy." Kermit

http://www.youtube.com/watch?v=hpiIWMWWVco

http://virtualpipeline.spaces.liv

 

[docellen]

There is a diagram "Well Configuration Data" at

http://energy.gov/open/oilspilldata.htm,

but I don't think we need to consider the specifics of this one well, which has nested pipes near the top.

Maybe Bill's rebar analogy is the best we can do. Pull on a rebar, and the cement bond near the surface will crack, but if the depth into the concrete is 40 times the diameter, it will hold.

I wonder if repeated pressurization will make a difference. Maybe each time the sheared zone moves down a little further. Maybe there is a limit to this process, where the expansion of the pipe, even in what must be loose powdered cement will still provide enough grip to keep the pipe from pulling out.

Has anyone seen a BOP under high pressure? Does the wellhead come up out of the ground a few inches?

 

[waross]

My analogy was meant as a question rather than an anal;ogy. I think that BigInch answered the question. Re-bar doesn't have internal pressure trying to rupture it. As I understand the answer, the casing will probably burst at a lower than the pressure needed to break it like an over stressed re-bar. Did I get that right?

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[BigInch]

I wouldn't think the rebar analogy is applicable. There are three methods of failure there, stretching the bar and rupturing contact stress between concrete and steel (250 psi or so) causing the bar to pull out, outright failure of the bar in tension when pull force > yield stress * x-sectional area and lastly the rebar is strong enough for the pullout force and the contact area is large, but the concrete slab is thin and you fracture the slab with shear stress, ie. the bar remains intact and takes a big chunk of concrete along with it.

In a well casing, any upward force from internal pressure on an "endcap" effect of a closed ram or valve would be resisted by the steel pipe immediately below it pulling down with longitudinal stress set up in the casing steel. There would be no net pullout force on the casing itself.

Laterally, internal pressure expands the steel, perhaps increasing contact stress against the cement and soil somewhat, perhaps also cracking the cement around it making contact stress with the soil ineffective, but there's no net lateral forces from internal or external pressures acting left or right, up, or down on the casing anyway. Effectively you have a can of Coke embedded in the sand. Yes it has internal pressure on the lid, on the inside walls and sand pressure on the outside walls, but the can isn't going anywhere until the internal pressure increases and either splits it or blows the lid off.

"We have a leadership style that is too directive and doesn't listen sufficiently well. The top of the organisation doesn't listen sufficiently to what the bottom is saying." Tony Hayward CEO BP
"Being GREEN isn't easy." Kermit

http://www.youtube.com/watch?v=hpiIWMWWVco

http://virtualpipeline.spaces.liv

 

[BigInch]

I guess it's not quite a Coke can, since a well casing is actually open on the bottom, but after a 2000 feet of soil cohesion on the surrounding cement, where it is cemented, or on the casing itself, you'll get enough pullout resistance for most any longitudinal force set up from internal pressure.

My whole point being that hoop stresses from internal pressure are usually going to control the situation, not longitudinal tensions from end cap effects.

Actually axial tension, according to Mohr's circle analysis, helps the combined stress, as it reduces shear stress; the real mode of failure stress. Axial compression combined with hoop stress increases shear stress, so is the more dangerous of the two.

"We have a leadership style that is too directive and doesn't listen sufficiently well. The top of the organisation doesn't listen sufficiently to what the bottom is saying." Tony Hayward CEO BP
"Being GREEN isn't easy." Kermit

http://www.youtube.com/watch?v=hpiIWMWWVco

http://virtualpipeline.spaces.liv

 

[waross]

Thanks again BigInch.
Yours
Bill

Bill
--------------------
"Why not the best?"
Jimmy Carter

 

[DrillerNic]

Docellen- let's do a short casing stress design for a 9-5/8, Q125, 62.8ppf one with a maximum internal pressure at the wellhead of 15000psi.

Lets do the maximum burst load case: internal pressure is 15,000psi, external hydrostatic at the wellhead is 2236psi, so resultant stress in casing at wellhead is 15000- 2236 = 12764psi.
Burst rating of 9-5/8" 62.8ppf Q125 casing is 13851psi. we're OK (just).

Tensile stress.... thermal effects: thermal gradient of 1°/ 100ft (a bit high perhaps?), mudline temperature at 5000ft of 40°: reservoir temperature at 18,000ft of about 220°f. Assume casing temperature about 70° when cemented (ie close to surface temperrature) so differential temp of 150°.
F = EaT(OD area - ID area)

E = Youngs mod = 29x10^6,
a = coeff of expansion = 6.9x10^-9
OD area = 3.142 * 0.25 * 9.625 * 9.625 = 72.77
ID area = 3.142 * 0.25 * 8.625 * 8.625 = 58.43
T= 150

Thermal stress = 428,100lbs force

Tensile stress... pressure effects.

F = 2u(ID area* Internal pressure change - OD area* external pressure change)

u= Poisson's ratio = 0.3
No change in external pressure
let's assume the worst case and the change in pressure is 15000psi (ie we're ignoring the pressure due to the mud in the casing when it was run).

F = 2 * 0.3 * (15000 * 58.43 ) = 525,870lbs force

Tensile stress is additive, so total tensile stress form teh as cemented case to the blowout case is 428,100 + 525,870 = 956,970lbs force


Tensile yield of 9-5/8" 62.8ppf Q125 casing is 2,270,000lbs force, so OK.

I can't be bothered to work out triaxial stress using Von Misens, but I think the production casing is string enough to cope with 15000psi!

 

[BigInch]

DrillerNic, Thanks for showing us how to do that. Please forgive my further questions.

I ignored thermal stress and ... I thought zdas said the casing was 21" diam x 1" wt. No wonder those hoop stresses were so high. That's a relief.

Is the temperature expansion coefficient alpha that low? I thought it might have been 100 times that.

I also thought that a pipe in contact with sufficient soil (typically anything over 250 m long) would develop enough skin friction to not allow low temperature axial expansion, eassentially making longitudinal thermal stress compressive, and also making the axial component of the pressure stress tension, thereby subtracting those axial stresses, not adding.

You don't seem to consider end cap stress either. Wouldn't you have that with a closed off valve?

"We have a leadership style that is too directive and doesn't listen sufficiently well. The top of the organisation doesn't listen sufficiently to what the bottom is saying." Tony Hayward CEO BP
"Being GREEN isn't easy." Kermit

http://www.youtube.com/watch?v=hpiIWMWWVco

http://virtualpipeline.spaces.liv

 

[docellen]

DrillerNic, Thanks for the design example. I hadn't considered thermal stress, but it looks like that could be a significant factor. Anyway, it looks like they have plenty of steel down that hole, so the real issue is the quality of the cement job.

 

[DrillerNic]

Big Inch- it's been along time since I did casing stress by hand too (that's what computers are for!)

Thermal stress can be ignored if the casing is free to move as it just expands. So, for example tubing with expansion devices (PBRs). If the casing is restrained (by cement, or by friction with the soils) the stress due to thermal effects has to be considerd. In the case of the Macondo well, we could actually argue that the production casing was unrestrained for most of it's length and so would expand slightly and actually buckle into the annuli provided by the earlier casing strings. Provided you don't reach critical buckling, the production casing is fine, and the actual stress in the casing is relieved slightly.

I know some pipelines use this strain based (rather than stress based) design methodolgy, but I don't think it's penetrated to casing design (and most drilling engineers probably wouldn't understand it, ha ha!).

Pressure containment is always supposed to be done by the casing. The function of the cement in a casing string isn't to support the casing, but to seal the annulus between the borehole and the casing (and if necessary to seal the bottom of the casing). This seal then allows certain selected zones in the reservoir section to be accessed with perforating guns.

In this case it appears (although so far this is just the most likely scenario) that the cement job didn't seal the annulus completely (either at all, or during the cement job, before the cement set), allowing gas up the backside of the casing. As the top of the casing was sealed, the gas couldn't expand, so you arrive at the surface with the pressure it had from the reservoir, plus the bottom hole pressure (this concept is a standard part of well control theory), which might have caused the casing hanger seal to fail. Whether the flow path from the reservoir to surface is up the annulus (ie the cement sheath has failed) or something else then broke and it's now coming up the inside of the production casing I don't know.... but the flowrates to me suggest up the inside of the casing?

 

[BigInch]

If the casing is 21", then that's trouble.

"We have a leadership style that is too directive and doesn't listen sufficiently well. The top of the organisation doesn't listen sufficiently to what the bottom is saying." Tony Hayward CEO BP
"Being GREEN isn't easy." Kermit

http://www.youtube.com/watch?v=hpiIWMWWVco

http://virtualpipeline.spaces.liv

 

[DrillerNic]

Can you get 21" casing? It's not in my copy of API 5CT!

If we're talking about the 21" marine riser, under the requirements of API RP16Q, a riser analysis will have been done for BP for this well, which owuld consider a maximum pressure, bending load, fatigue and so on and combination loads, but I don't know what the design max pressure for this marine riser was. I can dig around and find some rig specs (maybe even the Deepwater Horizon's detailed rig specs) that might have some actual marine riser wall thickenesses, but probably not rated pressures...

 

[docellen]

The "Well Configuration" drawing at

http://energy.gov/open/oilspilldata.htm

shows a number of "adapters" between the sections of well casing, and a "crossover" between the two sections of inner production tubing. Are these welds, screw threads, or just loose hangers? Are these intended to isolate blowouts to just one section?

I see three "16-inch rupture/burst disks" inside the production tubing. I assume they are designed to take any conceivable pressure. It's hard to believe all three have failed.

It looks from this drawing that there is nothing to keep the oil from flowing up the space between the casing and the inner production tubing. How is that supposed to be sealed?

 

[DrillerNic]

doceelen- all the casing, and drill pipe and tubing, adapters and crossovers are threaded.

I'm not sure exactly, but the two adapters on the well schematic look to me like liner hangers- that is a piece of kit screwed into the top of a piece of casing that has seals and slips that are hydraulically energised bite into the previous casing to support the liner. I'm not sure why the hangers at the top of the 18" and 16" liners are called adapters. It could be that this well did use some expandable casing strings (run the casing, then run a mandrel through it to expand it slightly so the next section can be drilled with a slightly larger bit) which might also explain some of the weird casing sizes: 10-1/8" for example.

A well is drilled in stages- drill a section, case it off and then drill the next section, and each casing or liner has to be able to withstand any pressures it might see from lower down. This proabably explains why they ran the 16" casing all the way from 11585ft MDBRT to just below the wellhead instead of to just above the previous 18" casing shoe- I guess the calculations showed that either the 18" or the majority of the 22" casing couldn't cope with possible pressures coming from below the 16" shoe.

Finally, the skinny tubing in the middle of the pipe isn't a proper production tubing string- it is the drill pipe and cement stinger work string. If the well had been completed, it would have had a production tubing string run in (4-1/2" or 5" tubing to fit inside 7" casing) with a permanent production packer run and set in the 7" casing just above the top of the reservoir to seal the annulus between the production tubing and the prodcution casing. As the well was still being constructed (they were about to set a cement plug somewhere about 7000-8000ft MDBRT to form the second suspension barrier before removing the BOP, installing a wellhead corrosion cap and going home), you need an open annulus between the drill string and the casing to bring returns back to the surface. In an emergency, this annulus is supposed to be sealed with the BOP pipe rams and the annular preventer, and in extremis, the BOP blind/ shear ram.

 

[docellen]

DrillerNic, thanks for the clarifications on the well configuration diagram. If I understand you correctly, those "16-inch rupture/burst disks" are really just cement plugs 16 inches in length, and those inner pipes (9-7/8" to 12,487' and 7" to bottom) are not "production tubing" but just another layer of casing. Also, the 5-1/2" and 3-1/2" tubes are the drill pipe and cement injection tube, presumably drawn as they were at the time of the blowout.

In that case, the two upper cement plugs are not really there, and the drawing is just showing us where they were supposed to go.

The 7" pipe has a notation 14.0 SOMB. I assume that is 14 pounds-per-gallon mud. Also, there is a small number 14 just inside the top of the 16" casing. I assume that means the same. Should I assume all the white spaces in this drawing are supposed to be filled with 14ppg mud?

Why do they have seawater in the upper sections of the inner tubing? Wouldn't mud be a better balance with the mud just outside these tubes?

What are the "shoes" you are referring to? Are the casing sections suspended from above, or resting on these shoes prior to cementing?