You must log in to edit PetroWiki. Help with editing

Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. More information

Bottom hole assembly (BHA) design for directional control

Revision as of 12:49, 12 September 2013 by Glenda Smith (Glendasmith) (talk | contribs)
(diff) ← Older revision | Latest revision (diff) | Newer revision → (diff)
Jump to navigation Jump to search

The bottom hole assembly (BHA) is a portion of the drillstring that affects the trajectory of the bit and, consequently, of the wellbore.

Factors that determine drilling tendency of the bottom hole assembly (BHA)

In general, the factors that determine the drilling tendency of a BHA are:

  • Bit side force
  • Bit tilt
  • Hydraulics
  • Formation dip
  • Formation Rock Properties

The BHA design objective for directional control is to provide the directional tendency that will match the planned trajectory of the well.

Bit side force

The bit side force is the most important factor affecting the drilling tendency. The direction and magnitude of the bit side force determine the build, drop, and turn tendencies.

  • Drop assembly: When the bit side force acts toward the low side
  • Build assembly: When the bit side force acts toward the high side of the hole
  • Hold assembly: When the inclination side force at the bit is zero
  • Bit tilt angle: The angle between the bit axis and the hole axis and affects the drilling direction because a drill bit is designed to drill barllel to its axis

Rotary assemblies

Note: Rotary Steerable Assemblies are a notable exception to the comments below and are used as directional assemblies that can be steered and are used to build, drop, or hold angle and can be controlled from surface.

Rotary assemblies are designed to build, drop, or hold angle. The behavior of any rotary assembly is governed by the size and placement of stabilizers within the first 120 ft from the bit. Additional stabilizers run higher on the drillstring will have limited effect on the assembly’s performance.

Rotary assemblies are not “steerable”; first, the azimuth behavior (right/left turn) of a rotary assembly is nearly uncontrollable. Second, each rotary assembly has its own unique build/drop tendency that cannot be adjusted from the surface. Thus, tripping for the assembly change is required to correct the wellbore course.

Commonly used stabilizer types are:

  • Sleeve
  • Welded blade
  • Integral blade

For long wear life, geology is the most important consideration when selecting one type of stabilizer vs. another. Sleeve stabilizers are most economical, but ruggedness often is an issue. Welded-blade stabilizers are best suited to large holes in soft formations. Integral-blade stabilizers are the most expensive but very rugged, making them the ideal choice in hard and abrasive formations. Roller reamers are sometimes used with stabilizers to open the hole to full gauge, extend bit life, and prevent possible sticking problems.

Building assemblies: fulcrum principle

Building assemblies use the fulcrum principle—a near-bit stabilizer, closely placed above the bit, creates a pivot point wherein the bending drill collars force the near-bit stabilizer to the low side of the hole and create a lateral force at the bit to the high side of the hole. Experience has shown that the more limber the portion of the assembly just above the fulcrum, the faster the increase in angle.

A typical build assembly uses two to three stabilizers. The first (near-bit) stabilizer usually connects directly to the bit. If a direct connection is not possible, the distance between the bit and the first stabilizer should be less than 6 ft to ensure it remains an angle-building assembly. The second stabilizer is added to increase the control of side force and to alleviate other problems.

Build rates can be increased by increasing the distance between the first and second stabilizers. When the distance between the stabilizers increases enough to cause the drill collar sag to touch the low side of the hole, the bit side force and bit tilt reach their maximum build rate for the assembly. Generally, the drill collars will sag to touch the borehole wall when the distance between the stabilizers is greater than 60 ft. The amount of sag will also depend on the hole and collar sizes, inclination, stabilizer gauge, and weight on bit (WOB).

Other important factors for the fulcrum assemblies are:

  • Inclination
  • WOB
  • Rotary speed

The build rate of a fulcrum assembly increases as inclination increases because the larger component of the collar’s own weight causes them the bend. Increasing the WOB will bend the drill collars behind the near-bit stabilizer even more, increasing the build rate. A higher rotary speed tends to straighten out the drill collars, thus reducing the build rate. Therefore, low rotary speeds (70 to 100 rev/min) are generally used with fulcrum assemblies. Sometimes, in soft formations, a high flow rate can lead to formation washout, resulting in decreased stabilizer contacts and, thus, a reduced build tendency.

Holding assemblies: packed hole

The packed-hole assemblies contain three to five stabilizers properly spaced to maintain the angle. The increased stiffness on the BHA from the added stabilizers keeps the drillstring from bending or bowing and forces the bit to drill straight ahead. The assembly may be designed for slight build or drop tendency to counteract formation tendencies.

Dropping assemblies: pendulum principle

The pendulum effect is produced by removing the stabilizer just above the bit while retaining the upper ones. While the remaining stabilizers hold the bottom drill collar away from the low side of the wall, gravity acts on the bit and the bottom drill collar and tends to pull them to the low side of the hole, thus decreasing the hole angle. Pendulum assemblies sometimes can be run slick (without stabilizers). Although a slick assembly is simple and economical, it is difficult to control and maintain the drop tendency.

A dropping assembly usually contains two stabilizers. As the distance between the bit and the first stabilizer increases, gravity pulls the bit to the low side of the hole, increasing the downward bit tilt and bit side force. If the distance between the bit and the first stabilizer is too large, the bit will begin to tilt upward, and the drop rate will reach a maximum. With a higher WOB, the drop assembly could even start building angle. Generally, the distance between the bit and the first stabilizer will be approximately 30 ft. The second stabilizer is added to increase control of the side force.

Initially, low WOB should be used to avoid bending the pendulum toward the low side of the hole. Once a dropping trend has been established, moderate WOB can be used to achieve a higher penetration rate.


Noteworthy papers in OnePetro

External links

See also

Directional drilling

PEH:Directional Drilling