A variety of magnetic ranging methods are used to determine distance and direction between a magnetic field sensor and a magnetic field source. If the sensor is in a near vertical hole, it may be difficult to orient the sensor's axes relative to known world coordinates, since no gravity high side is available. This can create difficulties calculating and applying ranging results. A magnetic azimuthal toolface may also be impaired due to magnetic interference.
To address this problem, we combine and align ranging and gyro systems in one tool-string and use simultaneous gyro attitude measurements to define the orientation of a ranging system with respect to True North. We apply this technique to two distinct magnetic ranging methods. The first method consists of a solenoid based ranging system. The example shows how this method was used to drill a precisely parallel wellbore in a close proximity to a previously drilled vertical well. The second described method consists of an at-bit-while-drilling ranging system that was used to safely pass by a vertical well while drilling a horizontal well in a close proximity.
The paper compares the results of alternative north orientation techniques for magnetic ranging versus the simultaneous gyro attitude referencing. The alternative techniques include a magnetic north orientation and the north orientation derived from a prior downhole survey and gravity high side tool face. The results show that the described technique can improve magnetic ranging accuracy by up to 10-fold over the previous methods. The paper provides 2D and 3D visualization and numerical analysis of the listed north orientation techniques applied to the magnetic ranging methods.
Simultaneous gyro measurements can significantly improve magnetic ranging accuracy. The applications for the described technique include relief well drilling, plug and abandonment, collision avoidance/risk mitigation, civil and mining projects.
Deviated wells pose an inherent risk to down-hole tubulars via increased bending and contact loads. Deviation is a "necessary evil" when it comes to directional wells as periodic well path corrections are often needed to stay on course for a planned trajectory. These intrinsic deviations generate bends and kinks in the wellbore, effectively reducing the "pass through" diameter of a given well section and making it more difficult to move a tool string through the well. Understanding this tortuosity limitation is instrumental in helping engineers to better place completion components for mitigating risks associated with high stress environments; such as fatigue, premature wear, and difficulty running-in-hole.
A new analysis software has been developed that analyzes the geometry of the wellbore and its effect on the mechanical loading of down-hole tools by utilizing a combination of gyro-based high-density surveys and ID measurements from multi-finger caliper logs. Using a specified tool length, (i.e. the length of a pump) this methodology allows for a determination of an effective tool OD or length that can be run so as to avoid any bending in the tool. This approach also allows for a quick comparison of multiple tool assembly lengths in order to aid in the tool selection and decision process. The results are supported with enhanced 3D visualizations, which help to effectively describe the tortuosity present in a wellbore and estimate the allowable pass-through ID ("Effective ID") for a specified tool length.
Some real-world applications of this technology are presented in detail. The OD and lengths of components placed in the wellbore can now be considered; determining if completion tools will experience bending while being run down-hole, if a holdup while running-in-hole is probable, or if operating at a certain setting depth is likely to result in premature failure. These results may then be used to optimize the completion string, artificial lift setting depth, or allowable tubular size for subsequent casing or tubing strings. Similarly, non productive time (NPT) associated with problems running other completion devices (perforation guns, plugs/packers, tubing, liners, etc.) in the well can be avoided by utilizing this analysis.
Now, completion and production engineers can have a better understanding of the tortuosity in the wellbore and its effects on the production or completion equipment to be run in the wellbore. This study provides insight into the practical application and utility of high-density surveying, caliper-logging, and estimating tortuosity while considering tool lengths and ODs. Comparing the results obtained with both standard measurement while drilling (MWD) surveys and short interval surveys, it is shown that standard dog-leg severity (DLS) measurements lack the required resolution to properly model the effective diameter of the wellbore. Utilizing the new approach has proven to be more valuable for artificial lift placement optimization, identifying wellbore access issues, and quantifying wellbore tortuosity.
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.