Source: {"pile_set_name": "USPTO Backgrounds"}

The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes drilling equipment situated at surface, and a drill string extending from the surface equipment to a below-surface formation or subterranean zone of interest. The terminal end of the drill string includes a drill bit for drilling (or extending) the wellbore. The process also involves a drilling fluid system, which in most cases uses a drilling fluid (“mud”) that is pumped through the inside of piping of the drill string to cool and lubricate the drill bit. The mud exits the drill string via the drill bit and returns to surface carrying rock cuttings produced by the drilling operation. The mud also helps control bottom hole pressure and prevent hydrocarbon influx from the formation into the wellbore, which can potentially cause a blow out at surface.
Directional drilling is the process of steering the drilling of a well from vertical to intersect a target endpoint or follow a prescribed path. At the terminal end of the drill string is a bottom-hole-assembly (“BHA”) which comprises 1) the drill bit; 2) a steerable downhole mud motor of a rotary steerable system; 3) sensors of survey equipment used in logging-while-drilling (“LWD”) and/or measurement-while-drilling (“MWD”) to evaluate downhole conditions as drilling progresses; 4) means for telemetering data to surface; and 5) other control equipment such as stabilizers or heavy weight drill collars. The BHA is conveyed into the wellbore by a string of metallic tubulars (i.e. drill pipe). MWD equipment is used to provide downhole sensor and status information to surface while drilling in a near real-time mode. This information is used by a rig crew to make decisions about controlling and steering the well to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, and hydrocarbon size and location. The rig crew can make intentional deviations from the planned wellbore path as necessary based on the information gathered from the downhole sensors during the drilling process. The ability to obtain real-time MWD data allows for a relatively more economical and more efficient drilling operation.
One type of downhole telemetry known as mud pulse telemetry involves creating pressure waves (“pulses”) in the mud circulating through the drill string. Mud is circulated from surface to downhole using positive displacement pumps. The pressure pulses are created by a fluid pressure pulse generator in a downhole telemetry tool, which controllably changes the flow area and/or path of the mud as it passes through the pulse generator in a timed, coded sequence, thereby creating pressure differentials in the mud. The changes in flow area can be effected by a valve mechanism in the pulse generator. One such valve mechanism is a rotor and stator combination, wherein the rotor is coupled to a motor which is controlled to rotate the rotor relative to the stator between an opened position where there is no restriction of mud flowing through the valve and no pulse is generated, and a restricted flow position where there is restriction of mud flowing through the valve and a pressure pulse is generated.
The position of the rotor at any given time is conventionally determined by position sensors typically located on an output side of the motor. Such sensors can be prone to failure, and impose an expense and complexity to the downhole tool. However, determining the rotor position is important in order to ensure that the telemetry signal is corrected encoded; a misaligned rotor can cause errors in the encoded telemetry signal, or make it difficult or impossible to decode the telemetry signal at surface. Therefore, it is desirable to provide a new and useful method or apparatus for determining the rotor position in a fluid pressure pulse generator.