Merlin provides expertise to clients around the world in the field of casing wear. During discussions with clients we find several myths and misunderstandings about casing wear are common. Some of these misunderstandings can be costly to operators and add risk to projects, as they move the focus to solutions that can be costly and ineffective, while the simplest and most effective measures are omitted.
It is hoped that the points below will shed some light on this matter and provide guidance at the planning stage of a project for recognition and assessment of casing wear.
Figure 1: Casing burst due to excessive wear
When should we be worried about the casing wear?
Typically casing wear is assessed as a part of the feasibility study or an engineering review of a drilling programme. A side force check is run for drilling, rotating off-bottom and backreaming cases. The Typically casing wear is assessed as a part of the feasibility study or an engineering review of a drilling programme. A side force check is run for drilling, rotating off-bottom and backreaming cases.
Casing wear occurs only while drilling
False: any operation that requires string rotation will result in casing wear. Side force, time and RPM will increase the amount of wear. Wireline logging can cause a spot-wear when the high tension of the cable is causing high side force concentrated over short distance.
Casing wear is higher while drilling than rotating off-bottom
It depends: usually when drilling, WOB will decrease the tension along the string and will reduce side force and thus wear. However, in some instances, WOB can cause buckling in the string and therefore high side forces across the lower part of the drill string. If the buckled part of the string is still in the cased hole, casing wear will increase.
The friction factor plays a huge role in casing wear
False: Casing wear happens while rotating. During drilling and rotating off-bottom, the friction factor does not increase tension significantly to be the main or even secondary driver behind the casing wear. While backreaming, if the pipe pulling speed is high enough, the friction factor starts playing a role in the value of axial drag and thus in the casing wear. However, pulling too fast while backreaming will have other consequences, more imminent, and casing wear is the last thing to be worried about in this scenario.
Casing wear is significantly lower in oil-based muds than in water-based muds
Partially true: Multiple sources, (Bol, 1986) (Mitchell & Xiang, 2012) mention lower wear factors for oil-based mud compared to water-based mud. The differences are associated with the high lubricity of the oil-based muds which reduces friction between casing and tool joint surfaces. Another source (White & Dawson, 1987) records higher wear efficiency for oil-based mud than water-based mud for the same side force applied. The authors explain the phenomenon of galling inhibition in oil-based mud. In water-based muds, galling is significant which prevents direct removal of casing material thus more time is spent wearing the casing than in oil-based muds where the material is removed quicker. A note should be made that experiments made in the laboratory apply direct side force to the rotating tool joint. Therefore, lubricity on the entire wellbore/drill string system is not considered. Actual casing wear results presented in other sources show a reduction in casing wear when oil-based mud is used. This is explained by slight T&D reduction and the direct reduction in side-loading.
Lubricants help reduce casing wear
Partially true: According to (Bol, 1986) Lubricants in weighted mud above 1.5 SG have no effect on friction because weighting agents in the mud penetrate the film formed by the lubricant on the tool joint and take over a function of lubricant forming a “bearing”. In 1.3 to 1.5 SG muds lubricant effect is low and in muds below 1.3 SG, the addition of lubricants is significant in terms of friction reduction for concentrations higher than 2% by vol. Bol also mentions that in clay weighted muds (drilled solids) forming of high lubricity film was prevented. Therefore, LGS levels must be kept low for the lubricants to be effective. Bol measured friction reduction rather than wear reduction when adding lubricants. Therefore, the effect of lubricants on casing wear is rather indirect i.e. these will reduce cased and open hole friction and therefore side loads which will then slightly reduce overall wear.
Low gravity solids should be kept at a minimum to reduce casing wear
False: In their paper, Kumar & Samuel (2015) say that casing wear increases with sand content. Another source (White & Dawson, 1987) sees higher wear for 0% than for 2% sand content. This counterintuitive result is attributed to a re-worked (rounded) sand forming a bearing layer between the tool joint and casing, preventing direct contact. Bol in his paper (1986) also mentions that a layer of solids reduces casing wear while investigating wear in weighted muds. A general conclusion can be drawn from these observations that, while some solid content can reduce wear, it will negatively affect other wear-reducing measures (lubricants in water-based muds). Bol also notes that the smaller the particles are, the smaller the effect will be on reducing casing wear. At all times, abrasive solids content (hematite, coarse sand) will worsen the casing wear. The bearing forming effect will have diminishing results for low abrasive tool joints which already cause reduced adhesive wear.
Non-rotating drill pipe protectors are the most effective way of casing wear reduction
Figure 2:Non-rotating drill pipe protector (WWT)
True: In their paper, Dai, Noel et al. (2018) present actual casing wear recorded in an ERD well where non-rotating drill pipe protectors (NRDPP) were used and compare these results to calculated wear and wear expected without the application of NRDPP. The significant effect of NRDPP on casing wear reduction (95% in the subject well) is due to these providing stand-off between tool joint and casing. The protector sleeve is stationary therefore casing wear at the contact point is zero. The resulting casing wear recorded in the subject well was due to pipe body contact with the casing. If the calculated casing wear without NRDPP is high and is of concern for the well integrity, despite other mitigations (casing friendly tool joint hardbanding material, optimized trajectory, OBM/SBM, no sand), then NRDPP should be introduced. It is also highly recommended to check increased ECD loads due to the NRDPP application.
Tool joints are the main source of casing wear
Figure 3: Tool joint hardbanding
True: Tool joints are mostly the points of contact between the drill string and the casing and the tool joint material and hardbanding are the main drivers behind casing wear. Table 1 shows experimentally defined casing wear factors for different tool joint types (lower is better). Note that rough tungsten carbide produces extremely high casing wear factors. This is due to high contact pressure between a hard-banding and casing, compared to smooth tungsten carbide which results in lower contact pressures. A wide range of WF in water-based mud can be attributed to a variation in mud properties (weighting additives, lubricity, sand content). A first check that must be done by the drilling engineer when trying to assess potential casing wear is: the hardbanding material and its condition. A new drill string with casing-friendly hardbanding may sometimes be the easiest way to avoid well integrity problems.
Table 1: Tool joint casing wear factors (Mitchell & Xiang, 2012)
Casing wear is a problem only in ERD wells
False: Casing wear is a result of a high side force between the drill string and the casing, coupled with rotation and time. In deepwater, vertical wells, often unwanted tortuosity can result in extremely high side forces driven by high tensile loads in the upper part of the hole. This in the end causes high casing wear.
Trajectory optimization can reduce casing wear
Partially true: At the planning stage, not much can be done to reduce side forces by optimizing the trajectory. In ERD and complex wells, the possibility of trajectory optimization is often restricted by the reservoir geometry, surface location constraints, anticollision and completion tools limitations. During the execution stage, however, the most important job during an execution phase is to keep the tortuosity to a minimum. Localized doglegs (tortuosity) will increase side loading due to bending, drag and therefore side forces and casing wear.
Soft-string T&D model is enough to simulate casing wear
It depends: for high risk, critical wells where casing wear is a persisting issue (re-entry in an existing, worn cased hole), a stiff string model will give a more accurate casing wear prediction. If the risk of well integrity issues is low (newly drilled wells, relatively low side forces, low pore pressures), a soft string model will be sufficient for assessing casing wear. It should also be noted that depending on an operation (drilling, backreaming, reaming-in) the contact points may be at different sides of a casing (see Figure 1). Therefore, the software that accounts for the radial distribution of the wear is recommended. Merlin can provide both soft- and stiff-string casing wear simulations.
Ditch magnets can help us assess casing wear on the fly
False: While the ditch magnets, if properly sized and positioned, can help reduce metal content in the mud, and thus prevent failures of surface equipment, they do not allow for an assessment of the casing wear severity. The amount of metal swarf on the magnets can be calculated into a volume of the steel worn by the drillstring. However, without proper modelling that worn-out volume cannot be translated into a wall thickness reduction if we don’t know the distance of the casing from which the swarf is produced. Applying the wear uniformly to the entire length of the casing can result in a false sense of security when in fact all the swarf could come from a localized high side force interval.
References
Aniket Kumar, R. S. (2015). Casing Wear Factors: How do they Improve Well Integrity Analyses? SPE-173053-MS.
Bol, G. (1986). Effect of Mud Composition on Wear And Friction of Casing and Tool Joints. SPE Drilling Engineering.
Dai, Noel et al. (2018). A Practical approach to Casing Wear Prediction, Modeling and Mitigation on Challenging ERD wells. SPE-191495-MS.
Fontenot, & Bradley. (1975). The prediction and control of casing wear, . J. Pet. Tech.
Mitchell, S., & Xiang, Y. (2012). Improving Casing Wear Prediction and Mitigations Using a Statistically Based Model. SPE 151448.
Schoenmakers. (1987). Casing wear during drilling: simulation prediction and control. . SPE.
White, J., & Dawson, R. (1987). Casing Wear: Laboratory Measurements and Field Predictions. SPE Drilling Engineering.
