During well planning, the directional driller must consider several factors to determine the required trajectory, particularly dogleg severity (DLS)—the rate of change in wellbore trajectory, measured in degrees per 30 m [100 ft]—as well as the capabilities of the BHA, drillstring, logging tools and casing to pass through the doglegs. Drilling limitations include rig specifications such as maximum torque and pressure available from surface systems. Geologic features such as faults or formation changes need to be carefully considered; for example, very soft formations may limit build rates, and formation dip may cause a bit to walk, or drift laterally. Local knowledge of drilling behavior enables the directional driller to derive the correct lead angle needed to intercept the target.
The skill of the directional driller lies in projecting ahead, estimating the spatial position of the bit and, based on the specific circumstances, deciding what course to take to intercept the target or targets. In the early days of directional drilling, a manual slide rule device was used to calculate the toolface angle required to drill from the last survey station to a target. Today, computer programs perform the same function.
Directional Drilling Operations
To steer a well to its target, directional drillers employ the following techniques:
Jetting—A jetting assembly provides directional capability while drilling through loose or unconsolidated formations. Jetting bits are roller cone bits with either a large extended nozzle in place of one of the cones, or with one large nozzle and two small nozzles. The large nozzle provides the “high side” reference, and the well path is deflected by alternately sliding or rotating the drillstring.
Nudging—This technique is often used in tophole sections, where several wellbores in close proximity to one another can pose magnetic interference issues and increase the risk of collision with other wellbores. The well path is nudged, or deflected, from vertical to pass the hazard—then steered back to vertical when the hazard has been passed.
Kicking off—Diverting a well path from one trajectory to another is called kicking off. The number of KOPs in a single well path depends on the complexity of the planned trajectory.
Sidetracking—Deflecting a well path from an existing wellbore, or sidetracking, is performed for a variety of reasons such as avoiding a well collapse, a zone of instability or a section of previously drilled wellbore containing unretrieved fish (junk or tools left in the well). This technique is also used to initiate multilateral drilling operations. Operators also drill vertical pilot holes to confirm reservoir true vertical depth (TVD), then sidetrack horizontally to maximize reservoir exposure. They sometimes sidetrack wells when expected targets are not encountered.
Whipstock operations—A whipstock is a wedge-shaped steel tool deployed downhole to mechanically alter the well path. The whipstock is oriented to deflect the bit from the original borehole at a slight angle and in the direction of the desired azimuth for the sidetrack. It can be used in cased or open holes.
Geosteering—Geosteering uses formation evaluation data obtained while drilling—primarily through measurements-while-drilling (MWD) or logging-while-drilling (LWD) sensors—to provide real-time input for steering decisions in horizontal and high-angle wells. Recent improvements in telemetry allow MWD and LWD data to be transmitted faster and with greater data density than in the past, greatly increasing the accuracy with which the well trajectory can be controlled.