Directional Drilling

Directional drilling is the intentional deviation of a wellbore from a vertical path, following a planned trajectory that curves away from vertical to reach a subsurface target that cannot be accessed by a straight vertical well. The wellbore may be deviated to reach a reservoir beneath a surface obstruction (a lake, a town, a protected area), to produce from multiple zones from a single surface location, or to drill a long horizontal section through a reservoir to maximize exposure to the pay zone. Most oil and gas wells drilled today in unconventional plays (Montney, Duvernay, Permian Basin, Marcellus) are horizontal wells that begin vertical, curve through a build section, and travel horizontally through the reservoir for 1,000 to 3,000 metres. These wells would be impossible without modern directional drilling tools and techniques.

Key Takeaways

A directional well is described by its inclination (the angle from vertical, in degrees) and azimuth (the compass direction of the wellbore path, in degrees from north). A vertical well has 0 degrees inclination. A horizontal well has 90 degrees inclination. A deviated well is anything in between. The planned sequence of inclination and azimuth values with depth is the well plan or directional plan, and it is the blueprint the directional driller follows.
Steerable mud motors and rotary steerable systems (RSS) are the two main tools for controlling wellbore direction. A mud motor is a positive displacement motor powered by drilling fluid flow that rotates the bit without rotating the drill string. By tilting the motor housing slightly (a bent housing or bent sub), the bit is pointed slightly off-center. Sliding (not rotating the string, only the bit turns) causes the well to curve. Rotating the string causes the well to go straight. The directional driller alternates between sliding to build inclination or azimuth and rotating to maintain it.
Rotary steerable systems (RSS) replace the slide-rotate technique with a fully rotating directional system. The RSS automatically applies a directional bias (via pads pushing on the borehole wall or by pointing the bit in the desired direction) while the entire string rotates continuously. This produces a smoother, more circular wellbore than slide-and-rotate drilling and allows faster, longer lateral sections with less torque and drag.
Measurement while drilling (MWD) provides real-time wellbore position data to the surface. Magnetometers and accelerometers in the MWD tool measure the wellbore inclination and azimuth at each survey point. These surveys are transmitted to surface via mud pulse telemetry (pressure pulses in the drilling mud) and plotted to track the actual well path versus the plan. Corrective actions are taken if the well deviates from the planned trajectory.
Extended-reach drilling (ERD) pushes directional drilling to extremes: wells that travel horizontally for distances of 6 to 12 kilometres from the platform or surface location. ERD wells are used on offshore platforms to access reservoir areas too far from the platform for conventional wells, avoiding the need for subsea tiebacks or additional platforms. The current world record for ERD is held by a well drilled from the Sakhalin Island platform off Russia, reaching a measured depth of over 15 kilometres.

Why Directional Drilling Changed the Industry

Imagine a town sits directly above a large oil reservoir. You cannot put a vertical well in the middle of town. Before directional drilling, that oil was effectively off limits. With directional drilling, a wellbore can start at a safe distance from town, angle underground at 30 to 45 degrees, and reach the reservoir directly below the buildings. The surface location has no footprint in the town but the well accesses everything below it.

Now take that principle and apply it to the horizontal plane. Instead of reaching a reservoir under an obstruction, extend the well horizontally through the reservoir for 2,000 metres. Instead of the wellbore intersecting the reservoir over a length of maybe 10 metres (as a vertical well does in a 10-metre-thick formation), the horizontal well is in contact with 2,000 metres of reservoir. The drainage area is 200 times larger. In a tight, low-permeability formation like the Montney or Duvernay in Alberta, where the formation only flows well very close to the wellbore, a 2,000-metre horizontal leg unlocks gas production that would be uneconomic from a vertical well.

The horizontal well revolution, enabled by directional drilling, transformed the oil and gas industry beginning in the early 2000s. The Bakken play in North Dakota and Saskatchewan, the Marcellus in Pennsylvania, the Montney in northeast British Columbia: all of these became major producing plays because horizontal wells combined with hydraulic fracturing made previously uneconomic tight formations productive at scale.

Fast Facts

The first intentionally deviated well is generally attributed to John Eastman and Roman Hines, who in 1934 used a whipstock (a wedge tool placed in the wellbore to deflect the bit sideways) to deflect a wellbore in Huntington Beach, California, and drain oil from under a pier. Commercial directional drilling services using more controllable downhole motors became widely available in the 1960s. The steerable motor, which allowed drilling both curved and straight sections without tripping, was developed in the 1980s. Rotary steerable systems became commercial in the late 1990s. In Canada, Precision Drilling (founded in Calgary in 1951) and Nabors Industries are among the leading directional drilling contractors serving the Western Canadian Sedimentary Basin.

Build Rate, Azimuth, and Wellbore Geometry

The rate at which a well builds inclination is measured in degrees per 30 metres (degrees per 100 feet in US conventions). A standard build rate for a long-reach horizontal well might be 3 to 6 degrees per 30 metres, which creates a smooth curve from vertical to horizontal over 450 to 900 metres of measured depth. A fast build rate (10 to 15 degrees per 30 metres) creates a tighter curve and is used when the target is shallow and the surface location must be close.

High build rates create wellbore sections with high curvature (called dogleg severity, measured in degrees per 30 metres). High dogleg severity sections are harder to run casing through, create higher fatigue stress in the drill pipe passing through the bend, and increase torque and drag in horizontal wells. Completion equipment (frac plugs, perforation guns) must also fit through the dogleg. For a multi-stage fracture completion in a Duvernay horizontal well, the dogleg severity in the build section is limited to less than 5 to 6 degrees per 30 metres so that completion tools can be pumped or coiled-tubed through without getting stuck.

Directional Drilling in Canadian Operations

Alberta and British Columbia are among the most active directional drilling markets in the world. The Montney play in northeast British Columbia has some of the longest horizontal laterals in North America, with operators regularly drilling 3,000 to 3,500-metre lateral sections from a single surface pad. Multi-well pads (8 to 16 wells drilled from a single pad) use directional drilling to fan out the horizontal laterals in different directions, minimizing the surface footprint while draining a large subsurface area.

The Foothills play of western Alberta requires directional drilling of a different kind: relief wells drilled to kill a blowout by intersecting the blowing well deep underground and pumping kill fluid to stop the blowout. Relief wells are some of the most precise directional drilling challenges in the industry, requiring the bit to intercept a 12 to 36 centimetre target (the casing of the blowing well) at depths of 2,000 to 4,000 metres, using magnetic ranging tools that can detect the steel casing of the target well from 10 to 20 metres away.

Directional drilling is also called deviated drilling or slant drilling. Horizontal drilling is a specific case of directional drilling where the target inclination is 90 degrees. Related terms include rotary steerable system (RSS, a directional drilling tool that steers the bit while the entire drill string rotates continuously, producing smoother wellbores and allowing faster lateral drilling than slide-and-rotate motors), measured depth (MD, the length of the wellbore measured along its actual curved path; greater than the true vertical depth in deviated wells; the depth reference used for all downhole tool positions), dogleg severity (the rate of change of inclination and azimuth in a directional well, measured in degrees per 30 metres; high dogleg severity limits casing running and completion tool passage), measurement while drilling (MWD, sensors in the drill string that measure inclination, azimuth, and formation properties in real time while drilling; the wellbore navigation system for directional wells), and horizontal well (a well drilled to 90 degrees inclination so the borehole travels laterally through the reservoir; combined with hydraulic fracturing, horizontal wells unlocked tight gas and oil shale production globally).

How a Directional Error Added CAD 4.2 Million to a Pembina Cardium Horizontal Well

A horizontal Cardium well was being drilled from a multi-well pad in the Pembina area of west-central Alberta. The well plan called for a 1,600-metre horizontal lateral landing at 1,715 metres true vertical depth (TVD) in the upper Cardium sand. The directional plan used a build rate of 4.5 degrees per 30 metres to reach horizontal in 600 metres of measured depth.

During the build section, the MWD tool experienced a temperature-related malfunction at 2,100 metres measured depth and transmitted incorrect inclination readings for approximately 120 metres of drilling. The directional driller, working from erroneous survey data, applied corrections that were opposite to what was actually needed. When the MWD tool recovered and transmitted accurate data, the wellbore was found to be 8.2 degrees low of the planned inclination and 14 metres low of the planned TVD. The bit had drilled below the Cardium target into the underlying Blackstone shale.

Correcting the trajectory required sidetracking: cementing off the wellbore below 2,100 metres, drilling a new directional path from that point, and rebuilding the inclination to land in the Cardium target. The sidetrack required an additional 340 metres of measured depth and 11 days of rig time. At a rig rate of CAD 28,000 per day plus directional services, materials, and cement, the error cost CAD 4.2 million. The well was ultimately completed and producing, but with 6 weeks added to the project schedule. MWD tool temperature rating for the Cardium bottomhole temperature (110°C) had been at the margin of the tool's rated operating range. Specifying a higher-temperature MWD tool for the build section would have prevented the malfunction at a cost of CAD 12,000 per day for the premium tool.