Deviation

Key Takeaways

• Unintentional deviation in wells drilled to be vertical creates operational and regulatory problems that require correction during drilling — most jurisdictions and well programs specify a maximum allowable deviation for nominally vertical wells, typically 3-5 degrees from vertical, beyond which the well is classified as directional and must be surveyed and reported as such; unintentional deviation causes casing wear (the drill string contacts the low side of the deviated wellbore more aggressively), increases torque and drag (the deviated wellbore creates additional side forces on the drill string), and in extreme cases causes key seating (the drill string cuts a slot in the formation wall that can trap tool joints); BHA design is the primary tool for controlling unintentional deviation — pendulum BHAs (drill collars hanging below a stabilizer, creating a pendulum effect that tends to return the bit toward vertical) are standard for drilling nominally vertical wells in formations with known deviation tendencies; when unintentional deviation develops despite the pendulum BHA, a packed-hole assembly or a motor with a slight bend can be used to bring the well back toward the planned trajectory before the deviation exceeds the allowable tolerance.
• Deviation surveys are the measurement system that tells the directional driller whether the wellbore is on plan, and their frequency and accuracy determine how closely the actual well path can be controlled to the design trajectory — a single-shot survey takes one inclination and azimuth measurement at a single depth using a tool dropped or pumped down the drill string to a survey point; a multi-shot survey records inclination and azimuth at multiple depths from a single tool run; continuous measurement while drilling (MWD) records inclination and azimuth in real time while drilling, enabling immediate correction of trajectory deviations rather than waiting for a survey run; the accuracy of the survey tool determines the position uncertainty of the wellbore at depth — a well drilled to 10,000 feet with standard MWD tools has a positional uncertainty ellipse of approximately 50-100 feet in three dimensions, which must be considered when planning well spacing and anti-collision for adjacent wells; high-accuracy inertial navigation systems (gyro-while-drilling tools) reduce position uncertainty to 10-30 feet in the same well, which is required for close-approach operations like relief well drilling and cluster well anti-collision management.
• Dogleg severity is the rate of change of wellbore deviation (both inclination and azimuth) with depth, and excessive dogleg severity causes drill string fatigue, casing wear, and difficulty running completion equipment — dogleg severity is measured in degrees per 100 feet (or degrees per 30 meters) and represents the total angular change of the wellbore direction over that depth interval; a planned directional well typically builds inclination at 3-6 degrees per 100 feet in the build section and maintains 0-1 degree per 100 feet in the tangent section; unplanned doglegs from formation kicks, direction corrections, and BHA orientation changes can reach 5-15 degrees per 100 feet, which creates high bending stresses on the drill string passing through the dogleg, accelerating fatigue damage; after a significant dogleg is drilled, the string rotation at that point during subsequent drilling creates cyclic bending that can crack drill pipe tool joints; operators specify maximum allowable dogleg severity for each well based on the planned completion equipment (casing, liner, tubing, and downhole tools all have maximum bend specifications), the drill string capacity (heavy-weight drill pipe has lower fatigue resistance than standard drill pipe in a dogleg), and the artificial lift design (ESP pump strings and coiled tubing have particularly low dogleg tolerance).
• Wellbore deviation affects log quality and interpretation because most logging tools are calibrated for vertical wells and their measurements change character in deviated and horizontal boreholes — density and neutron porosity tools measure formation properties perpendicular to the tool axis, and in a deviated well this measurement direction is no longer perpendicular to the formation bedding; gamma ray logs read apparent bed thickness rather than true bed thickness in deviated wells, requiring a dip correction; resistivity tools in a deviated well crossing dipping beds show a characteristic polarization horn that must be recognized and corrected in interpretation; in horizontal wells, the tool rides on the low side of the borehole under gravity, reducing its standoff from the formation and biasing its readings; modern petrophysical interpretation routinely applies true vertical depth (TVD) and dip corrections to deviated well logs, but the corrections require knowledge of the wellbore trajectory (from the deviation survey) and the formation dip (from image logs or regional geology) to be applied correctly.
• Anti-collision management uses deviation survey data to calculate the minimum separation distance between all wells on a multi-well pad or field and prevent wellbore collisions during drilling — as well pads have become denser (10, 20, or more wells drilled from a single surface location to reach different subsurface targets), the risk of one wellbore intersecting another has grown from theoretical to practical; wellbore collision during drilling can be catastrophic — the drill bit of one well breaking into the casing or open hole of another; anti-collision monitoring computes the closest approach distance between every pair of wells in real time as each new survey station is recorded, comparing the nominal trajectory plus its positional uncertainty ellipse to all other well trajectories plus their uncertainty ellipses; when the separation factor (the ratio of closest approach to the combined uncertainty ellipse radius) drops below a threshold (typically 1.5-2.0), the operator must pause drilling and either correct the trajectory or accept the risk with specific management controls; anti-collision planning is now standard practice on all multi-well pads and is required by regulation in most jurisdictions for offshore platforms and onshore pad drilling programs.