Casing Wear Series – 1: Causes

During the drilling phase, the most costly component is the casing. On top of the expensive casing materials and the costs likely to be encountered in cutting, pulling and replacing a worn or damaged string, casing wear creates more serious problems for operators due to its potential catastrophic incidents such as oil spills, blow outs or loss of the well.

To analyze the forces behind casing wear, we need to study the torque and drag (T&D) of the drill pipe during drilling operations. The basic mathematical and physical model of T&D has not changed significantly since Johancsik et al. published their paper on T&D prediction. Pipe movements such as drilling ahead or tripping create drag, while rotation produces torque. The magnitude of T&D is determined by the combination of these two movements.

Since the so-called vertical well virtually does not exist (the whirring action of the bit always creates a micro-helical shape of the well path), the contact of the drill pipe and its tool joint with the casing ID is unavoidable. The gravitational force acting on the drill pipe is always trying to pull the pipe to the lower side of the wellbore, while the axial tension on the drill pipe (in a build-up section) tends to push the pipe to the upper side of the wellbore. Depending on the pipe weight, dogleg severity, and axial force along the pipe, the drill pipe either touches the upper or lower side of the wellbore.

Typical T&D analysis starts by dividing the pipe into small elements. Calculation begins from the bottom element of the pipe, where weight on bit (WOB) and torque on bit (TOB) are expected. For each element, force and torque are balanced and the T&D at the top of the element are calculated. From bottom to top, calculations are performed for each pipe element, until it reaches the rig floor. This step-by-step calculation also determines the direction and magnitude of the side force, which pushes the drill pipe against the wellbore as shown in Figure 1.

Figure 1. Snapshot of Side Force along a Drill Pipe

Figure 1. Snapshot of Side Force along a Drill Pipe

Under this side force, the rotating tool joint on the drill pipe against the casing inside, gradually removes steel from the casing wall and forms a crescent-shaped wear on the casing as shown in Figure 2.

Figure 2. Rotating Tool Joint Wears Crescent Grooves in Casing

Figure 2. Rotating Tool Joint Wears Crescent Grooves in Casing

The seriousness of friction between two contacting surfaces is dependent on the nature of the rubbing surfaces and the mud.

The tool joint coating plays a bigger role here compared to the casing wall. The industry has seen tool joint coating evolve from “casing killer” (rough tungsten carbide) to “casing friendly” as shown by many high-tech hardbanding materials.

Tungsten carbide is applied on the tool joint. While it is a very good protector of the tool joints, it aggressively wears the casing so much that the mud type and its additive will not help much in reducing casing wear if rough tungsten carbide is present.

Once a casing friendly tool joint coating has been selected, the mud type and its additives play an intermediate role in casing wear. Water-based mud causes twice as much casing wear as the oil-based alternative. Lubricant reduces friction and severity of the wear.

Generally speaking, high dogleg will create a high side force and severe casing wear. The wear profile resembles the shape of dogleg severity. Higher RPM and lower ROP make more rotation time between the tool joint and casing and will cause aggressive wear.

The following conditions contribute to casing wear:

  • Well path and dogleg
  • Drill pipe weight
  • Tool joint coating
  • Mud and additives
  • RPM and ROP

Casing Wear Series - 2: The Basics

When it became apparent that casing wear was going to be a matter to be reckoned with, several organizations initiated experimental studies of this phenomenon. Among these were (1) Shell Oil Company, (2) Exxon, (3) Texas A & M, and (4) Drilco. All these operators discovered that experimental casing wear studies were both time consuming and expensive.

All of the casings wear studies involved building a machine that would simulate field conditions as closely as possible in the laboratory. Figure 1 is a symbolic presentation of a casing wear test machine that incorporates all of the parameters needed to simulate casing wear as it would occur under field conditions.


Figure 1: Elements-of-a-casing-wear-test-machine

As shown in the Figure 1, the rotating tool joint sample is pressed against the inner wall of the casing sample with a constant force. The intersection of the casing and the tool joint is flooded with drilling fluid, which contains sand to simulate the drill cuttings which the mud transports to the surface in field operations.

In addition, the tool joint ( or the casing sample ) should be slowly reciprocated during the wear test to simulate drilling progress. Failure to include this reciprocation results in a significant reduction in the observed casing wear. It is believed that without reciprocation, the casing sample and the tool joint sample will `mate’ to each other, and the drilling fluid will then form a hydrodynamic lubricating layer between the two surfaces. This will greatly reduce the grinding effectiveness of the sand that is transported by the drilling fluid. Non-reciprocating wear tests may result in as little as 10% of the wear observed in tests where reciprocation is employed.

Such a casing wear test machine is pictured in Figure 2. This machine was built by Steve Williamson ( Drilco ) in the early 1980s, and was later purchased by Maurer Engineering for use in the Drilling Engineering Association ( DEA ) projects ( DEA – 8, DEA – 42, and DEA – 137 ). These projects covered the period from 1990 through 2002.

Drilco casing wear test machine

Figure 2: Drilco casing wear test machine

Most of the material presented in these articles was developed as a result of the work done using this machine.