Management Precise casing-wear prediction is important for improving well integrity and longevity, while simultaneously making casing designs more cost-effective. Currently, there are no known and commonly accepted guidelines available in the industry. Several studies have been presented in literature over the past couple of decades that proposed various methods for estimating the downhole wear in casings. However, the results of all such efforts have been mixed. Predicted values of casing wear using wear models failed to accurately match the wear logs from the wells when scaled up to the field level. This has led to a perception in the industry that existing casing-wear prediction methods lack the desired accuracy. Many of these suspicions are unwarranted and have emerged because of inconsistencies in accurately applying the casing-wear model. Kumar and Samuel (2015) have previously presented a comprehensive treatise on all the uncertainties involved in casing-wear analysis and the underlying modeling method and parameters. This article proposes a new modeling method for casing-wear prediction using stiff-string analysis, aiming to reduce the existing uncertainties in downhole wear estimation. In addition to estimating more accurate side forces, the stiff-string model also predicts the contact position of the drillstring at any given depth in the casing. These contact positions, at any given casing depth cross-section, are used to model the development of multiple wear grooves around the cross-section, as various wellbore operations are conducted through the casing. Further details of this modeling method have been presented in this study. The proposed model has been validated using measured wear-log data from an offshore well in the North Sea. The value of the maximum wear-groove depth, along with its respective azimuthal location at that casing cross-section measured using the wear logs, were compared with the simulated values for the entire logged-casing section. Casing-Wear Model This modeling approach has been slightly modified while being applied to address the different kinds of operations that are performed to successfully drill a well. Five major operations are considered in this analysis—drilling, backreaming, rotating off-bottom, sliding, and reciprocation. This study focuses on wear caused only by the above operations, which can be performed in different sequences to reach the target depth. Other possible reasons for downhole wear, such as erosion while fracturing, corrosion, or any other mechanical wear during production, are not considered in this analysis. For the drilling and backreaming operations, Eq. 1 has been applied for analysis. The drilling or backreaming operation starts from a given measured depth, and the drill bit progresses farther down (drilling) or up (backreaming) the hole to reach the target end depth for that operation. As a result, the tool-joint contact with the inner casing wall varies as the drillstring moves down or up the hole. The last factor in Eq. 1, the ratio of tool-joint length over drillpipe length, is applied to account for this contact resulting from tool joints only. The average side force supported by the tool joints is calculated using Eq. 2, assuming that the entire load is taken solely by the tool joints and there is no pipe-body contact.

On the Norwegian Continental Shelf there are many fields and wells in late life production. There are also many nearby drilling targets with limited volumes to add. This situation requires new mindset in order to optimize tie-ins of new reserves to existing infrastructure. Retrofit multilateral well solutions are regarded as one enabeler in this context since they enable tie-in to existing producers from nearby targets through deep sidetrack operations. There are many pre-requisites that must be in place for such solutions to be suitable. In addition, the risk of partial success involves loss of an existing producer. A few such wells have been constructed by the operator in the last couple of years. The requirements and challenges are discussed. The implementations show that it is technically feasible to use conventional multilateral technology in ways that enable installation in producing wells. Improvements to existing solutions are sought in order to facilitate future implementations and to improve robustness of this technology.

As more and more complex wells are being drilled, an important problem to be addressed relates to casing, liner, and tubing wear. Casing wear is one of the continuing challenges faced by the industry, and an accurate estimation of downhole wear remains a paradox. Several casing wear estimation techniques were applied to actual drilling situations in the past; however, the results of those efforts have not always provided the necessary level of accuracy of wear prediction. The effects of improper estimation of casing wear may not be felt owing to the general overdesign of the casings by largely applying excessive casing-wear safety factors. This paper addresses these concerns by providing a comprehensive solution to this long-standing casing-wear puzzle. The widely used conventional soft-string model is not applicable for all well paths for casing-wear modeling; it assumes that the drillstring continuously follows the exact wellbore curvature and cannot predict the different contact locations of the drillpipe with the inner casing wall. Consequently, a new modeling technique has been developed by applying the stiff-string model for casing-wear analysis. The stiff-string model calculates more accurate contact loads by accounting for the bending stiffness of the string and helps to estimate the contact position of the drillstring at any given casing depth. These contact points are used to model the development of multiple wear groove locations at any casing depth cross-section by accounting for the varying contact positions as various operations are performed through the casing. Estimates of multiple groove positions at each cross-section reduce the overestimation of casing wear, because the wear is now distributed across different grooves, thus providing a more realistic casing-wear estimate. This modeling approach was validated by using ultrasonic logs from complex directional wells that are the most susceptible to wear. Detailed operational steps and parameters for each well were modeled to predict the development of multiple wear grooves for each casing section. These models were compared with the 360° cross-sectional distribution of remaining wall thickness from image-based ultrasonic logs. The estimated groove depths and positions correlated with the peaks observed from wear logs that showed the worst wear locations. The results obtained from this exhaustive analysis are promising to establish a new, more thorough means of validating casing-wear predictions. By applying a new comprehensive modeling approach using stiff-string analysis to estimate multiple wear grooves, this study has helped to reduce long-unsolved casing-wear uncertainties. A novel method for validating the estimated groove positions using the full 360° spectrum of caliper or ultrasonic logs has been presented. Accurate wear prediction is important for well integrity and optimized well designs.

Despite advances in Measurement-While-Drilling / Logging-While-Drilling (MWD/LWD) technologies, the oil & gas industry has until recently lacked viable technologies and tools to measure wellbore geometry in large hole sizes (>12-1/4″) while drilling and subsequently the ability to visualize and describe the borehole shape and size in an intuitive way. A direct mechanical measurement solution such as used on wireline, e.g., multi-finger tools, is not feasible to implement on MWD/LWD tools due to the nature of the drilling operation. Conventional technologies and methods, including acoustic- and density-based measurement methods have been used with reasonable results in smaller hole sizes (≤12-1/4″) when combined with low mud weights. However, many commercially available tools within the industry have low vertical and azimuthal resolution due to sparse sampling or sparse storing in its internal downhole memory of such caliper measurements, resulting in limited use of such data for borehole shape and size purposes. Such conventional technologies and methods have not been, or very seldom used in large hole sizes, primarily due to lack of available technologies and tools, resulting from challenges related to the sensor to wellbore interface standoff distance. A novel Logging-While-Drilling Caliper tool based on impulse radar technology has been developed to overcome the challenges related to mud weight, sensor to wellbore standoff in oil-based muds and at the same time addressing challenges related to sparse datasets. This tool enables the oil and gas industry to accurately image borehole shape and size with both high vertical and azimuthal resolution, including within large hole sizes where there has not been any viable solution whilst drilling. The high sampling rate together with a large downhole memory (128 GB) allows the industry to evaluate the borehole shape and size as a function of time (timelapse). An Impulse Radar Caliper tool has been pilot tested in several wells on the Norwegian Continental Shelf (NCS), in borehole sections ranging from 12-1/4″ to 17-1/2″. During the pilot testing, the Impulse Radar Caliper tool acquired wellbore shape and size measurements while drilling, and some intervals while pulling out of hole. Several wellbore features, not previously imaged in such large hole sizes, have been identified and their time-dependent development studied in detail. The results from this pilot campaign are discussed in this paper together with the 3D/4D tunnel-view visualization used to assess the processed caliper measurements.