Abstract

Rod and tubing failures due to wear are persistent problems in many rod pumped wells. Historically, guidelines for deviations while drilling have been issued, and followed, and still, some wells have rod on tubing wear problems. Clearly, the criteria governing rod on tubing wear is not described adequately by maximum deviation guidelines for drilling.

In order that rod on tubing wear problem; can be properly addressed, avoided where possible, and ameliorated when not avoidable, the factors contributing to rod on tubing wear have to be identified and analyzed for significance.

This paper addresses the problem by identifying the variables, numerically quantifying their contribution to rod on tubing wear where possible, and identify those variables which are not quantified and require additional research. A method for combining the quantifiable variables into formulae useful for analysis is presented.

Variables in rod design are investigated and evaluated using these numerical methods and, in some cases, bench marked against measured field conditions.

Historical Methods

As a preventative step in minimizing rod on tubing wear, drilling contracts almost always include provisions for wellbore surveying. Drilling contractors are required to take measurements of the direction of the borehole at specified intervals and if deviations exceed some specified minimum, remedial action is usually required at the expense of the drilling contractor.

It has been common practice to use these measurements taken at the time of drilling to calculate dog leg severity (DLS), expressed as degrees per 30 meters. DLS calculations can be based on many relationships, but the most common relationship is the minimum curvature method, wherein adjacent survey points are assumed to be on the circumference of a circle and DLS quantities are the degrees of arc projected by the survey points, and scaled to an arc length of 30 meters.

It has also been common practice to use the DLS calculations to estimate the location and seriousness of anticipated rod on tubing wear problems. At locations of the highest DLS, the most severe wear problems might be expected.

Unfortunately, rod breaks and tubing leaks due to wear often occur at other locations in the wellbore. Many operators have taken more detailed wellbore surveys after wear problems have occurred only to learn that the surveys taken while drilling do not adequately describe the geometry of the wellbore and many severe doglegs were skipped. Figure 1 shows DLS profiles for a deviated Alberta well based on surveys taken while drilling and a survey taken later at 10 meter intervals. Because the data used for Figure 1 is taken from a deviated well survey points taken while drilling are relatively numerous. In vertical wells, the number of survey points taken while drilling would be expected to be fewer, and consequently, more doglegs would be missed.

In many cases, though, even the detailed survey fails to identify the reason for rod on tubing wear. Clearly, other significant factors are involved in addition to DLS.

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