WELL CONTROL-6 MINIMIZING LOADS DURING SNUBBING HELPS PREVENT PIPE FAILURE

L. William Abel
Wild Well Control Inc.
Spring, Tex.

Planning a snubbing operation during well control requires detailed analyses of pressure loads to limit workstring stress and avoid pipe failures.

Common rules of thumb and simplified methods may not be applicable for predicting string loads, and more detailed analyses are needed in most well control operations that use snubbing techniques.

Extreme and uncommon loads are sometimes encountered on workstrings in atypical snubbing operations. These loads occur during snubbing operations in post-blowout control jobs, reentry operations into underground flows, and work on high-pressure wells. These extreme load conditions must be understood so that snubbing workstrings can be properly designed.

Routine snubbing operations produce workstring loads that can be described by general guidelines. These general guidelines will adequately predict loading conditions and workstring stress, providing certain conditions remain stable and predictable. This routine approach ignores some important aspects for atypical operations, however. The following are some of the conditions that could cause extreme loading in the snubbing workstring:

Forces caused by obstructions from debris or mechanical damage
Sudden increases in pressure
Constraining ODs that are several times greater than the workstring OD, thereby allowing buckling
A pack-off condition that increases the effective seal area
Frictional forces generated from fluid movement
Differential sticking because of loss of circulation or art underground blowout
High wall-contact forces generated from helical buckling
Wall contact forces generated from the deviation of the well and string tension.

COMMON SNUBBING LOADS

Common snubbing loads are caused by pressure-area effects, frictional loads, the weight of the string, and obstructions in the well. String forces can be altered by applying external pressure. Examples are well stimulation (fracturing the well), bullheading to kill the well, and pressure testing.

It is common to use the Seal area where the well pressure is contained in the blowout preventer (BOP) to determine the pressure-area effect. In a vertical well, frictional loads can be up to 20% of the overall string weight, while the friction generated by stripping through the BOP is generally small and negligible (providing small workstrings are used). Obstructions, such as sand bridges, generate set-down (weight on the bit) forces which can be controlled by the snubbing unit operator. In addition, the pressure test can cause string forces that exceed those generated by the well, because the pressure test is normally greater than the well pressure.

These common snubbing loads can be predicted with simple calculation methods. In most routine snubbing operations, no additional consideration or analysis is needed or necessary.

Fig. 1 (44599 bytes) shows common snubbing loads, which can be described as follows:

A pressure-area force resulting from well pressure which is taken to act on a cross section of the snubbing string at the seal area
The gravitational force or weight of the string with consideration for buoyancy changes during the operation
Common frictional forces (such as wall contact) taken as simple multiple of the overall string weight
A force from obstructions in the well which are acted upon by applied force or set-down weight from the snubbing unit.1

The simplified rules are limited because much higher levels of stress can be produced in certain situations, which can result in string failures.

One key to successful snubbing is to recognize when conditions deviate from routine operations. In these cases, additional analyses and calculations are necessary, and sometimes special operational procedures are needed to avoid failures.

EXTREME SNUBBING LOADS

Extreme snubbing loads are simply the loads on the snubbing string that are beyond those expected in a typical snubbing operation.

HELICAL BUCKLING

Helical buckling can occur when the workstring is in compression, and insufficient lateral support or confinement is provided. The obvious condition for helical buckling is a small OD workstring snubbed into large OD casing or riser. For example, a 1.66-in. OD workstring may be quite susceptible to buckling inside an 11-in. riser or inside large through-bore (13 5/8-in.) BOP (Fig. 2 (66323 bytes)).

Helical buckling calculations are necessary if a small diameter snubbing workstring is used in large OD risers or BOPs. Equation 1 is a simplified method of calculation. This method assumes that the system is frictionless; therefore, the analysis indicates buckling at smaller values than if friction were considered.

Table 1 lists helical buckling values, along with the pressure that can produce these values, for a common workstring (1.66-in. OD tube). These data indicate that snubbing into an 11-in. bore with small diameter tubing is risky, even if small compression loads are expected.

Helical buckling is not limited to the through bore of the BOP stack. It can occur downhole where the confining diameters change, such as below a packer (Fig. 3 (39997 bytes)).

PRESSURE-AREA EFFECTS

The pressure-area effects are sometimes simplified to a calculation of pressure times area to determine the force. The area is generally taken as the cross sectional area of the tube at the seal area. (The seal in the BOP stack on the largest diameter in the seal is used, or the tool joint or tube body OD is used if the seal is around either.) This method works well if nothing downhole complicates the forces or contradicts the logic.

One must be aware of downhole conditions that would override this simplified approach. If the inner bore of the casing or tubing, that is entered via snubbing, packs off (such as with an inflatable packer or produced solids) the effective area can become the total cross section of the well bore (Fig. 4 (53012 bytes)).

If the casing diameter, rather than the workstring outer diameter, is used, the effective area is larger, for a larger force from the pressure. Because the area varies as the square of the diameter, the corresponding force will vary dramatically. For example, for a 1.66-in. workstring diameter compared to a 7 in. well bore casing, the area will increase more than 17 fold.

Thus, one must be very careful running inflatable packers and other tools that can pack off the full well bore diameter.

Post-blowout tasks often include washing out bridges that formed during the flowing period. Often there is pressure trapped below these bridges, and care must be taken to avoid workstring stress that approaches the helical buckling limits. Washing through bridges with pressure trapped below can create additional conditions that will increase the compression forces in a workstring:

The pressure increases suddenly from the release of the trapped pressure
The well bore packs off from the debris being washed out (Fig. 5 (58789 bytes)).

In Fig. 5 (58789 bytes), the well is bridged off and no pressure acts on the string. During the washout, the bridge holding pressure is penetrated, and the well bore pressure suddenly increases. The string becomes packed off by bridging material, allowing the full area of the well bore to be acted upon in the generation of upwards thrust on the workstring.

FRICTIONAL FORCES

Blowout wells at times generate tremendous frictional forces from the force of the flow. There have been many instances where the force of the flow has been sufficient to eject the string in the hole (Fig. 6 (57201 bytes)). Most of these cases involved a sudden change in the surface equipment (such as shooting off the wellhead or opening the BOP).

If the well is to be reentered with a snubbing string, these frictional pressures and the forces generated must be analyzed and accounted for in the design of the workstring and the snubbing operations. If the snubbing unit resists the pipe ejection forces, the string will be in compression and buckling must be accounted for in the workstring design.

High wall-contact forces can be generated when the string becomes helically buckled. When the string goes into the helical shape, high wall-contact forces are generated, and these forces can easily exceed the rule-of-thumb calculation method of assuming that frictional loads are limited to 10-20% of the string weight. Key seats or severe doglegs can also cause excessive tension as the snubbing string is pulled out of the well.

DIFFERENTIAL STICKING

Underground flows can be particularly challenging for snubbing operations because the workstring can become stuck from differential sticking. Fig. 7 (54275 bytes) shows differential sticking problems in both cased hole and open hole operations.

Many underground flows have been entered successfully with snubbing workstrings; however, substantial overpull and buckling capacities are required.

The force generated to cause an underground flow depends on the following:

The projected area of the tools run in the flow
Contact surface between the wall and the tool
The pressure generated by the flow at the exit point
Type of fluid being produced (rheology of produced fluid).

ACKNOWLEDGMENT

The author would like to thank Joe Dean Thompson, capping specialist with Wild Well Control Inc., and Ed Zwald, consultant, for their contributions to this article.

REFERENCES

Abel, L.W., Bowden, J.R. Sr., and Campbell, P. J., Firefighting and Blowout Control, Wild Well Control Inc., 1994, pp. 184-196.
Abel, L.W., et al., "Safer Snubbing Depends on Proper Pre-job, Calculations," World Oil, October 1988.
Abel, L.W., et al., "Well Control Factors to Consider When Snubbing," World Oil, November 1998.
Abel, L.W, et al., "Well Control Equipment for Safer Snubbing," World Oil, December 1988.
Abel, L.W, et al., "Guidelines for Safer Snubbing," World Oil, January 1981).