HORIZONTAL/EXTENDED REACH DRILLING Drillers push toward 10 km extended reach drilling goal

Feb. 1, 1996
Leonard Le Blanc Editor Drilling contractors and equipment developers are pushing the limits of yield and drillpipe lockup as they push the envelope of extended reach drilling. The record horizontal offset currently stands at 8 km, but many operators feel the 10 km mark can be exceeded by the year 2000. That 10 km (six miles) of offset distance opens up a substantial number of exploration and field development opportunities:

Pushing, sliding, and pulling drillstring down
inclined wellbore requiring new tools, techniques

Leonard Le Blanc

Drilling contractors and equipment developers are pushing the limits of yield and drillpipe lockup as they push the envelope of extended reach drilling. The record horizontal offset currently stands at 8 km, but many operators feel the 10 km mark can be exceeded by the year 2000. That 10 km (six miles) of offset distance opens up a substantial number of exploration and field development opportunities:

  • Reservoirs sometimes extend over three-four km radially. Long-reach wells enable operators to drain outlying flanks and pursue a larger number of adjacent non-connected reservoirs from existing facilities.
  • Lease blocks offshore the US are a little over five km square on average, making it possible to underdrill or tap as many as 12 surrounding blocks from a central lease.
  • Reservoir recovery programs frequently require placement of gas and water injectors at some distance from production structures, often necessitating deployment of subsea wells or compromise of recovery. Ten-km offset injector wells can alleviate that problem.
  • Long lateral sections expose much more reservoir, allowing single wells to produce two-three times the volume of short lateral sections and reducing the outlay for development drilling and surface facilities.

An extended reach well is one in which the ratio of the measured distance over the true vertical depth of the well is at least 2.0. The world record horizontal offset, currently held on a Wytch Farm (UK) well, carries a ratio of 5.0.

Extended reach wells are expensive. An extended reach well will typically cost 70-90% of a subsea completed well. A series of extended reach wells can cost 50-70% of a new platform or production system. Rarely can an extended reach well be drilled in under 60 days. However costly, the savings frequently alter field development decisions and are one of the reasons why non-OPEC production is soaring.

Enabling technologies

The critical limitation in extending wells laterally is inability to push, slide, or pull the drill bit and drillstring. As the economies of extended reach drilling have proven worth the effort, a growing array of technologies and techniques have been and are being developed to support the drilling effort.:

  • Tandem/long motors: Two power sections coupled together or longer downhole motors increase torque at the bit without reducing rotational speed. This power is critically important in the sliding mode where bit RPM drops off significantly. Rate of penetration performance gains ranging up to 50% have resulted.
  • Drillstring rotation: When compression of the drillstring in steeply inclined and horizontal wells reaches high levels, rotation at rates of 100-140 rpm pushes up the threshhold at which buckling begins.
  • Adjustable stabilizers: Variable guage stabilizer blade assemblies that can be deployed, controlled, and monitored with mud flow pulsing have been developed to prevent drillstring sliding and poor blade deployment downhole, and allow for drillstring rotation at high angles. Adjustable stabilizers set by weight are not workable at high borehole angles because string weight cannot be effectively transmitted to the stabilizers.
  • Agitation tools: Newly developed agitators can be positioned along the drillstring to direct fluid flow radially in order to agitate cuttings beds, a frequent problem in high angle and horizontal holes, and eliminate some back-reaming operations.
  • Hole cleaning: After the selection of proper drilling fluids for hole cleaning, the next most important elements are the periodic use of high-viscosity pills pumped down the well and back-reaming at connection times.
  • Performance stabilizers: At high borehole inclination, a rotating stabilizer inserted between the bit and motor assembly assists in building and turning operations, and redistribution of the load. Penetration improvements up to 19% have been recorded.
  • Longer casing runs: Casing installation is more difficult in inclined or horizontal wells. Packers that allow for circulation of drilling fluid in the borehole during casing runs and rotation of the casing and liner strings are critically important to installation of long casing and liner strings.
  • Location correction: Improvements in magnetic instruments aboard measurement-while-drilling tools and development of better correction routines are currently underway. Location correction is critical in 10-km offset wells because of the high incidence of significant bottom hole inclination and azimuth errors. At present, only gyro surveys provide certainty of bottom hole location.
  • Friction reducer: The addition of friction reducers to drilling fluid when running any kind of tubulars downhole can increase the depth of runs by as much as 12%.
Compression and torsion As long as all parts of the drillstring operate in tension, the drill bit will make hole. When the wellbore is contorted, turns through several angles, or begins to curve laterally, drillstring tension gives way rapidly to compression. With compression comes increasing contact with annular walls, friction, drag, rotating torque, and eventually sinusoidal (S-shaped) and helical buckling, with lockup as the last step. Drillpipe buckling is the stage at which extended reach and horizontal drilling comes to a halt.

Simple compression results in sinusoidal buckling, but the addition of torsion, resulting from the drillpipe being turned at the surface or the torquing of a coiled tubing string by the downhole mud motor, generally results in helical

  • Torsion as a result of downhole torque increases wall contact, which further increases torsional loading.
  • Torsional loading modestly diminishes the compression level at which buckling occurs, but generally will result in pipe yield before buckling occurs.
  • Compression loading will buckle a tubular before the yield level is reached.
  • As well curvature increases, lower levels of compression and torsion will buckle a tubular.
  • As rotational speed increases, higher levels of compression and torsion are needed to buckle a tubular.

Buckling and drillpipe lockup are the two major responses to pushing drillstrings through extended wells, but fatigue and wear of drilling tubulars also takes place, resulting in premature failure of the string in the hole.

In general, drillstrings in tension tend to produce more fatigue-related problems (poor pin-box shoulder contact, etc), while those drillstrings in compression tend to buckle and lockup before fatigue becomes a serious factor. Protection of the drillpipe and annulus in the curved sections of the borehole will postpone wear, generally.

Today, the high cost and difficulties surrounding extended reach drilling ensure that drillers select drillstrings that are in best condition to withstand the long working periods associated with extended reach drilling.

Coiled tubing ERD

Coiled tubing use in extended reach wells faces many of the same problems as rotary drillpipe, excepting that compression and torsion produce buckling at much lower threshholds. Rarely can extended reach wells using coiled tubing exceed lateral offsets of more than 1,300 meters before lockup. Coiled tubing (CT) is used more often for drilling short laterals kicked off from existing vertical wellbores, which can qualify as extended reach wells in shallow formations, and for servicing and working over horizontal and extended reach wells. A number of methods and technologies assist coiled tubing in overcoming the tendency to buckle. They are:
  • Buoyancy reduction: Buoyancy in CT forces the tubing against the top of extended reach casing and hole sections, creating friction. By using heavywall tubing or injecting nitrogen into the string, the CT takes on a more neutral position in the wellbore.
  • Friction reducers: A low-friction film can be introduced to the CT and casing surfaces through the drilling fluid, reducing the drag force. Friction reducer is used on Wytch Farm CT operations near the point of lockup.
  • Optimal taper: CTs with larger wall thicknesses should be deployed in areas of greatest compression, increasing the forces needed to buckle the tubing.
  • Straightening CT: The CT well injector provides a reverse bending as it comes off the reel, but leaves a residual bend. Removing that residual bend with a bending device will diminish the CT fatigue life by 15-23%, but will allow for greater reach in lateral sections.
  • Downhole tractors: A number of wireline and coiled tubing providers are testing electric and hydraulically powered downhole tractors to pull CT strings down long horizontal or extended reach sections. While applications are being considered for servicing wellheads experiencing CT helical lockup, there is no reason why CT drilling with a downhole tractor could not be undertaken. Also, if yield is critical when pulling CT out of the hole, then a tractor could also be used to push tubing uphole.
  • Annulus pressure: Sometimes known as pumpdown when the CT is run inside production tubing, this method involves the pressurization of the annulus outside the coiled tubing through a packoff point. The external pressure boosts tension on the CT, reducing buckling tendencies.
  • Torque reactor: Torque induced by drill bit rotation and acting on the drill string enhances helical buckling substantially, especially if the CT is in a pre-buckling or high wall contact mode. A torque reactor separating the bottom hole assembly from the tubing diminishes torque transfer.

Formation borehole

Unintended well tortuosity is not only a problem in reaching the target formation in extended reach wells. Intentional alteration of borehole trajectory within the formation to detect boundaries and keep the borehole ideally positioned within the pay adds to tortuosity, often limiting the length of formation exposure in extended wells. Part of the problem of trajectory change within the reservoir is preventable with some of the new technologies available. Typically, when formation thicknesses of two meters or less are encountered, inclination trajectory changes are slight. When the formation exceeds three-four meters in thickness, trajectory changes must be sufficient to permit contact with the upper and lower reservoir boundaries.

This establishes formation dip or run. Such relatively large trajectory changes are needed because propagation resistivity measurement loses resolution outside a radius of two-three meters. Formation boundary detection can be achieved in two ways:

  • Bit resistivity: Real time resistivity sensors set up at or immediately behind the bit allow the driller to correct bit course early, before actually encountering the boundary or plane. The closer to the bit, the faster the course change, especially important when the detection margin is only two meters.
  • Acoustic tools: Acoustic referencing systems, although still in trial, appear to be able to spot and measure reflecting boundaries at a radius of 10-15 meters away. Resolution is weaker than resistivity measurement, and acoustic power and processing of backscatter noise remain a problem.
Drillers need information that will allow them to drill the straightest hole possible that will follow the pay and avoid gas and water contact intervals. Both optimize reservoir exposure and optimize recovery, at minimum cost. The major benefit of extended reach and horizontal drilling is to produce long exposures in thin, low-porosity, or vertically fractured formations, at long distances from surface drilling facilities. The race is on now to ensure that future offset distance threshholds will be economic, rather than technological.


Ryan, G., Reynolds, J., Raitt, F., "Advances in Extended Reach Drilling - An Eye to 10 km Stepout," SPE 30451, Dallas, October, 1995.

Bhalla, K., "Coiled Tubing Extended Reach Technology," SPE 30404, Aberdeen, September, 1995.

Nakken, E., Mjaaland, S., Solstad, A., "A New MWD Concept for Geological Positioning of Horizontal Wells," SPE 30454, Dallas, October, 1995.

Odell, A., Payne, M., Cocking, D., "Application of a Highly Variable Gauge Stabilizer at Wytch Farm to Extend the ERD Envelope," SPE 30462, Dallas, October, 1995.

Andresen, S., Hovda, S. Olsen, T., "Experience with Drilling C-26A, a World Record Extended Reach Horizontal Well in the Oseberg Field," SPE 30463, Dallas, October, 1995.

He, X., Halsey, G., Kyyllingstad, A., "Interactions between Torque and Helical Buckling in Drilling," SPE 30521, Dallas, October, 1995.

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