At the outset of a drilling operation, drillers typically establish a drilling plan that includes a target location and a drilling path to the target location. Once drilling commences, the bottom hole assembly is directed or “steered” from a vertical drilling path in any number of directions, to follow the proposed drilling plan. For example, to recover an underground hydrocarbon deposit, a drilling plan might include a vertical well to a point above the reservoir, then a directional or horizontal well that penetrates the deposit. The operator may then steer the drill through both the vertical and horizontal aspects in accordance with the plan.
In some embodiments, such directional drilling requires accurate orientation of a bent segment of the downhole motor that drives the bit. In such embodiments, rotating the drill string changes the orientation of the bent segment and the toolface. To effectively steer the assembly, the operator must first determine the current toolface orientation, such as via a measurement-while-drilling (MWD) apparatus. Thereafter, if the drilling direction needs adjustment, the operator must rotate the drill string to change the toolface orientation. In other embodiments, such as rotary steerable systems, the operator still must determine the current toolface orientation.
During drilling, a “survey” identifying locational and directional data of a BHA in a well is obtained at various intervals or other times. Each survey yields a measurement of the inclination and azimuth (or compass heading) of a location in a well (typically the total depth at the time of measurement). In directional wellbores, particularly, the position of the wellbore must be known with reasonable accuracy to ensure the correct wellbore path. The measurements themselves include inclination from vertical and the azimuth of the wellbore. In addition to the toolface data, and inclination, and azimuth, the data obtained during each survey may also include hole depth data, pipe rotational data, hook load data, delta pressure data (across the downhole drilling motor), and modeled dogleg data, for example.
These measurements may be made at discrete points in the well, and the approximate path of the wellbore may be computed from these discrete points. Conventionally, a standard survey is conducted at each drill pipe connection to obtain an accurate measurement of inclination and azimuth for the new survey position. However, if directional drilling operations call for one or more transitions between sliding and rotating within the span of a single drill pipe joint or connection, the driller cannot rely on the most recent survey to accurately assess the progress or effectiveness of the operation. For example, the driller cannot utilize the most recent survey data to assess the effectiveness or accuracy of a “slide” that is initiated after the survey was obtained. The conventional use of surveys does not provide the directional driller with any feedback on the progress or effectiveness of operations that are performed after the most recent survey measurements are obtained.
When deviation from the planned drilling path occurs, drillers must consider the factors available to them to try to direct the drill back to the original path. This typically requires the operator to manipulate the drawworks brake, and rotate the rotary table or top drive quill to find the precise combinations of hook load, mud motor differential pressure, and drill string torque, to properly position the toolface. This can be difficult, time consuming, and complex. Each adjustment has different effects on the toolface orientation, and each must be considered in combination with other drilling requirements to drill the hole. Thus, reorienting the toolface in a bore is very complex, labor intensive, and often inaccurate. A more efficient, reliable method for steering a BHA is needed.
USPTO Backgrounds
USPTO Backgrounds