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Collapse – When You Can’t Take the Pressure

Casing collapse can occur when external pressure or load exceeds the collapse resistance of the casing.  

Factors that can influence the collapse resistance of the casing include:

  • Pipe ovality – the initial ovality of the pipe from the manufacturing process or due to damage during installation such as bending, or crushing, can reduce the collapse resistance
  • Axial loading – loads induced in the casing during operation due to temperature changes, subsidence and improper pre-tensioning can affect the collapse resistance. Increased axial tension can reduce the collapse resistance and axial compression can increase it.
  • Wall loss – corrosion, erosion and wear can reduce the casing wall thickness and the corresponding collapse resistance.
  • Confinement – filling the annulus around the casing with cement can increase the collapse resistance by making it more difficult to ovalize the casing
  • Temperature – at elevated temperatures that are encountered in HPHT and thermal wells, the degradation in the mechanical properties of the casing material can reduce the collapse resistance
  • Loading mechanism – point or line loads on the casing caused by formation squeeze or formation movement can cause collapse to occur well below the collapse resistance predicted for hydrostatic pressure

In many cases, more than one of these factors can occur at the same time. This makes it difficult to predict the collapse resistance accurately.  The changes in the well environment that can cause casing collapse include:

  • Heating of trapped annular fluid
  • Salt/shale squeeze
  • Fluid migration behind casing during well operations

Collapse caused by heating of trapped annular fluid

Fluid trapped in the annulus between casing strings or in intervals with very low permeability formations will expand when it is heated by warmer fluids flowing up the well from lower formations. Generally, the heating rate of any fluid trapped in the annulus is slow enough that the pressure will bleed off through the cement or surrounding formations.

The increased fluid pressure may also fracture the formation as the formation breakdown pressure is usually lower than the collapse pressure of the casing. These collapse events may occur suddenly but may not cause a large ovalization of the casing. As soon as the casing collapses, the pressure in the trapped fluid will drop and prevent the collapse from propagating.

Collapse caused by salt/shale squeeze

The well casing can be subjected to high external loads due to closure of the wellbore in mobile formations such as shale and salt.  Stress concentrations are created in the formation around the wellbore when the hole is drilled.

Some formation materials like salt (halite, sylvite and anhydrite) and some shales have a viscoplastic behavior that causes the material to deform or creep over time. This viscoplastic behavior relieves the stress concentrations and returns the formation to the isostatic stress state that existed before drilling.

This formation creep results in closure or squeezing of the wellbore If the casing is not cemented.

If only partially cemented, the borehole will ovalize and eventually contact the casing. The contact with the casing is not uniformly distributed around the casing but results in forces that can push on opposite sides of the casing. The casing will ovalize in the same orientation as the direction of formation squeeze.

This concentrated loading on the casing can cause it to collapse more easily than if the load is evenly distributed around the pipe as occurs with external fluid pressure.  

If the casing is fully cemented to the formation, the loading caused by formation squeeze is more uniformly distributed around the casing and the casing is constrained from ovalizing. The collapse resistance is higher than where there is no cement. Partial, or low strength cement in the casing-formation annulus can improve collapse resistance.

However, it is difficult to predict how much benefit is gained due to the uncertainties in the properties and distribution of the cement.

Casing collapse due to formation squeeze occurs over timeframes ranging from days to years. The formation generally closes slowly. The initiation of collapse might be observed from detailed casing inspections before the deformation is large enough to impair well operations or compromise the integrity of the casing. This could allow operators to perform necessary well operations below the collapsed interval before the casing ovalizes to the point that these operations are no longer possible.

Collapse caused by fluid migration behind casing during well operations

Overpressure can occur when there is a breakdown in the well cement or formation that allows pressure from lower, higher pressure zones, or from zones that have been overpressured by injection operations, to contact uphole cased intervals.
This is only critical if the pressure inside the casing is not balanced with the external pressure. This might occur if a packer is seated below the top of a formation that is being pressurized.

Overpressure can also occur by reducing the internal casing pressure to the point where the pressure differential acting on the casing exceeds the collapse resistance.  Rapid upward tool movement can “swab” the well, causing a significant, localized transient reduction in the wellbore pressure.  This pressure drop can occur at any point in the fluid column of the well.

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