Summary Small-scale wellbore tortuosity—variations in attitude on a length scale smaller than standard survey intervals of 30 m (100 ft)—is generally neglected because of its small effect on the final position of the well and its unclear relation to traditional dogleg severity (DLS). However, it is well-known that such tortuosity may have significant influence on the drilling process and on drilling efficiency. Furthermore, it is a crucial factor for the design and installation of completions and production equipment, because a highly tortuous wellbore section, depending on borehole diameter and tortuosity amplitude and along-hole distribution, may exert strong bending forces on such equipment, or high friction on moving parts. This paper describes a novel methodology for analyzing the tortuosity of openhole wellbores, casing, drillstring, and production tubing. Several related tortuosity parameters are described, and examples of application to field data are included. The methods use high-resolution survey data [measured depth (MD), inclination, and azimuth], which may, in principle, originate from any surveying tool or service capable of providing such data. The methodology requires input data from a single survey only. On the basis of a user-defined length as single external parameter, tortuosity can be analyzed on any length scale greater than approximately 10 times the input survey-data interval, and with a maximum resolution equaling twice the data interval. The processed parameters include relative elongation of a tortuous section compared with a straight-line section, transverse displacements from the straight line, and maximum available diameter for a downhole device caused by the small-scale bendings of the section. The results can be displayed as graphs vs. MD, or as 3D-rendered views of the actual wellbore or tubing shape. Results from various field cases are included, in which the tortuosity analysis was applied to high-resolution continuous gyro survey data collected in cased wellbores. In all the field cases, the novel methods revealed sections of considerable tortuosity that were either unnoticed, or located with unacceptably low accuracy, by conventional methods. These results led to re-evaluation of the planned locations for completion and production equipment. The characterization of the wellbore in terms of tortuosity on various length scales may be of crucial importance for the functionality and lifetime of permanently installed equipment. For example, identification of highly tortuous sections will aid the placement of rod-guide wear sleeves, increasing the rod and casing life and reducing the workover frequency. Another application is the identification of low-tortuosity sections in which downhole pumps or other equipment will not be subject to excess bending. In addition, the tortuosity results may help evaluate the drilling equipment and the drilling process.
Small scale wellbore tortuosity – variations in attitude on a length scale smaller than standard survey intervals of 30 m (100 feet) – is generally neglected due to its small effect on the final position of the well and its unclear relation to traditional dogleg severity. However, it is well known that such tortuosity may have significant influence on the drilling process and the drilling efficiency. Furthermore, it is a crucial factor for the design and installation of completions and production equipment, since a highly tortuous wellbore section may exert strong bending forces on such equipment, or high friction on moving parts. This paper describes a novel methodology for analysing the wellbore tortuosity, and shows examples of application to field data. The methods utilise high resolution continuous gyroscopic survey data (inclination and azimuth), and an analytical definition of tortuosity. Based on a user-defined length as single external parameter, the methods have the robustness and flexibility to analyse tortuosity at any length scale greater than the input survey data interval. In one method, a tortuosity parameter is defined over a pre-defined wellbore section as the ratio between the along-hole length and the length of the straight line between the end points. The tortuosity parameter can be displayed as a graph versus measured depth. In another method, the transverse deviations of a set of survey points from an established reference line are calculated. These transverse deviations describe how the wellbore bends on a small scale over the analysed section, causing restrictions to the maximum diameter of a device that shall pass through the section, or be permanently placed at this depth. The results can be displayed as a graph of maximum allowed diameter as a function of measured depth, or as a 3D view of the actual wellbore shape. Results from various field case examples are included, in which the tortuosity analysis has been applied to field survey data. In all the field cases, the novel methods revealed sections of considerable tortuosity that were either unnoticed, or located with unacceptably low accuracy, by the conventional methods. Although verification of the methods is still needed, some of these field results have already led to re-evaluation of the planned locations for completion and production equipment. The characterization of the wellbore in terms of tortuosity on various length scales may be of crucial importance for the functionality and lifetime of permanently installed equipment. For example, identification of highly tortuous sections will aid the placement of rod guide wear sleeves, increasing the rod and casing life and reducing the workover frequency. Another application is identification of low tortuosity sections where downhole pumps or other equipment will not be subject to excess bending. In addition, the tortuosity results may help in evaluating the drilling equipment and the drilling process. The tortuosity analysis has the potential to contribute to technical and procedural improvements and cost savings in areas ranging from drilling operations to the completion phase and initial and long term production.
In rod-pumped systems, the locations to install rod guides along the rod are determined through the analysis of calculated side forces exerted on/by the rod string. The side forces are computed from axial forces in combination with information about the trajectory of the rod string in the well. Traditionally, the trajectory of the rod string is estimated from directional survey data, obtained by magnetic or gyroscopic surveys at typically 100ft reporting intervals. However, because the surveys are run in open hole, in casing, or in tubing, it is the trajectory of these structures that are described by the directional data. None of them are accurate representations of the actual trajectory of the rod string, implying that the resulting side forces may suffer from reduced accuracy, and therefore are not optimal for decisions on rod guide placement. Additionally, due to the low resolution survey data, local variations in the wellbore trajectory within the survey intervals, which may affect the forces on the rods, may be undetected. In a previous paper we developed a method for analyzing the small-scale tortuosity of a wellbore from high-resolution (1ft) survey data. One important outcome of this analysis is the finding that high small-scale tortuosity substantially narrows the free passage through a wellbore or tubing. The narrowing is quantified in terms of the reduction in the effective diameter of a device that can be placed in the wellbore. In this paper, the technique has been extended for the calculation of points along the wellbore where the rod string is expected to make contact with the tubing. This is an important result by itself, indicating where rod guides may be needed along the rod string. With these points of contact, the trajectory, or shape of the rod within the production tubing is estimated. The use of this estimate instead of the traditional directional survey data in the calculations of side forces is expected to improve the accuracy of the results. The technique has been applied to a number of field cases, and two are presented in this paper. The results show that the forces on the rod calculated from the proposed technique are similar to, and exhibit the same general trend as the forces calculated with conventional methods. However, there are some differences, due primarily to the use of the estimated shape of the rod string in the proposed method. The forces on the rod at the estimated points of contact of the rod and the tubing can be extracted and used for rod guide placement decisions. By providing improved estimates of contact point locations and the forces acting between the rod and the tubing, the method may help to optimize the rod pumping system for producing wells. It may help to explain occurrences of pump failures, erosion of the production tubing by the rods, and other issues that are not fully understood. This may result in reduced failure rates, energy savings, and cost savings resulting from reduced workovers and production losses.
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