Dogleg Severity (DLS) is the angular rate of change of the wellbore path between two survey stations, expressed in degrees per 100 feet (deg/100ft) or degrees per 30 meters. It captures the total three-dimensional curvature of the wellbore, accounting for changes in both inclination and azimuth simultaneously. DLS is the fundamental parameter for evaluating whether a wellbore will support casing and completion operations, whether drill string fatigue limits are being respected, and whether the trajectory is following the planned well path. Typical DLS limits range from 2 to 3 deg/100ft in cased-hole sections to 8 to 15 deg/100ft in build sections of unconventional wells.
How It Works
Calculation
DLS is calculated from consecutive survey stations using the minimum curvature method:
DLS = arccos[cos(I2 - I1) - sin(I1) x sin(I2) x (1 - cos(A2 - A1))] x (100 / delta-MD)
Where:
- I1, I2 = Inclination at stations 1 and 2
- A1, A2 = Azimuth at stations 1 and 2
- delta-MD = Measured depth difference between stations
DLS can be decomposed into two components:
- Build Rate (BR) — The rate of inclination change in the vertical plane (deg/100ft). Positive = building angle, negative = dropping angle.
- Turn Rate (TR) — The rate of azimuth change in the horizontal plane (deg/100ft). Positive = turning right, negative = turning left.
DLS Limits by Application
| Application | Typical DLS Limit |
|---|---|
| Vertical / tangent sections | 1 - 2 deg/100ft |
| Intermediate casing point | 3 - 5 deg/100ft |
| Build section (curve) | 6 - 15 deg/100ft |
| Lateral section | 1 - 3 deg/100ft |
| Production casing / liner | 5 - 8 deg/100ft (depends on casing size) |
| Coiled tubing intervention | 8 - 12 deg/100ft max |
Why It Matters in Oil & Gas Operations
Excessive DLS creates compounding problems throughout the well's lifecycle:
- Casing Wear — High DLS concentrates drill string contact forces on the casing wall, causing wear that reduces burst and collapse ratings. A single high-DLS zone can reduce casing life from decades to years.
- Drill String Fatigue — Pipe rotating through a dogleg experiences cyclic bending stress. API and manufacturer fatigue curves define the maximum allowable DLS for a given pipe size, grade, and tension. Exceeding these limits causes drill pipe twist-offs and connection failures.
- Running and Pulling Difficulties — Casing, liners, and completion assemblies may not pass through high-DLS zones. A casing string that cannot reach bottom due to excessive friction in a dogleg can force a costly sidetrack or well redesign.
- Production Losses — In rod-pumped wells, high DLS causes rod-on-tubing wear, leading to failures and deferred production. Even ESP cables can be damaged in high-DLS zones.
How Netora Handles DLS
Netora Drilling Intelligence computes dogleg severity automatically from MWD survey data at each station, decomposing the total DLS into build rate and turn rate components. DLS is displayed in the survey table, plotted on trajectory charts, and flagged when values exceed planned limits, giving directional drillers and drilling engineers immediate visibility into wellbore quality. Learn more about Netora Drilling Intelligence.