The recovery of hydrocarbons from subterranean zones relies on the process of drilling wellbores. The process includes using drilling equipment situated at surface and a drill string extending from equipment on the surface to a subterranean zone of interest such as a formation. The drill string can extend thousands of meters below the surface. The downhole terminal end of the drill string includes a drill bit for drilling the wellbore. Drilling wellbores also typically involves using some sort of drilling fluid system to pump a drilling fluid (“mud”) through the inside of the drill string, which cools and lubricates the drill bit and then exits out of the drill bit and carries rock cuttings back to the surface. The mud also helps control bottom hole pressure and prevents hydrocarbon influx from the formation into the wellbore and potential blow out at the surface.
Directional drilling is the process of steering a well from vertical to intersect a target endpoint or to follow a prescribed path. At the downhole terminal end of the drill string is a bottom-hole-assembly (“BHA”) that includes 1) the drill bit; 2) a steerable downhole mud motor; 3) sensors including survey equipment (e.g. one or both of logging-while-drilling (“LWD”) and measurement-while-drilling (“MWD”) tools (both “LWD” and “MWD” are hereinafter collectively referred to as “MWD” for simplicity)) to evaluate downhole conditions as drilling progresses; 4) telemetry equipment to transmit 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 known as drill pipe. The MWD equipment is used to provide in a near real-time mode downhole sensor and status information to the surface while drilling. This information is used by the rig operator to make decisions about controlling and steering the drill string to optimize the drilling speed and trajectory based on numerous factors, including lease boundaries, existing wells, formation properties, hydrocarbon size and location, etc. This can include making 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 data allows for a relatively more economical and more efficient drilling operation.
MWD is performed using MWD tools, each of which contains a sensor package to survey the wellbore and to send data back to the surface by various telemetry methods. Such telemetry methods include, but are not limited to telemetry via a hardwired drill pipe, acoustic telemetry, telemetry via a fiber optic cable, mud pulse (“MP”) telemetry and electromagnetic (“EM”) telemetry.
A typical arrangement for EM telemetry uses parts of the drill string as an antenna. The drill string is divided into two conductive sections by including an electrically insulating joint or connector (a “gap sub”) in the drill string. The gap sub is typically placed within the BHA such that metallic drill pipe in the drill string above the gap sub serves as one antenna element and metallic sections below the gap sub serve as another antenna element. EM telemetry signals can then be transmitted by applying electrical signals across the two antenna elements. The signals typically include very low frequency signals applied in a manner that codes information for transmission to the surface. The electromagnetic signals may be detected at the surface, for example by measuring electrical potential differences between the drill string and one or more ground rods spaced from the drill string.
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