Drilling & Production

Leonard LeBlanc Houston A survey on drilling horizontal and extended reach sections among 13 operators in Europe (representing 80% of wells) and 14 operators in North America (representing 20% of wells) indicated a number of common situations, difficulties, and solutions. The survey was conducted by Japan National Oil Company, Japan Drilling Co. and Philip Crouse & Associates. The most common challenges include: Radius:

Leonard LeBlanc
Houston

Horizontal, extended reach section tendencies outlined

A survey on drilling horizontal and extended reach sections among 13 operators in Europe (representing 80% of wells) and 14 operators in North America (representing 20% of wells) indicated a number of common situations, difficulties, and solutions. The survey was conducted by Japan National Oil Company, Japan Drilling Co. and Philip Crouse & Associates. The most common challenges include:

  • Radius: Build rates in North America averaged about 16-20/100 ft (medium radius) to minimize pipe fatigue and wear, versus 3/100 ft in Europe, where short and medium radius builds are rarely needed. Europe is using more designer wells with multiple azimuth changes. The preferred extended reach well path in Europe and North America is catenary shaped.

  • Curve building: Most operators preferred to be on or ahead of the curved well path, in order to deal with formation targets that come earlier than planned. Many drilling and completion problems arose when drilling fell behind the curve (insufficient build rate).

  • Reach limitation: Reach limits were governed largely by efficiency of hole cleaning, followed by the curve radius and large changes in trajectory. Too tight a curve or trajectory change imposes severe drag restrictions.

  • Hole cleaning: The most important factor in hole cleaning was increased flow rates. Cuttings removal problems in lateral sections must be addressed immediately. If one mud pump goes down, it is better to halt drilling than risk insufficient flow rates.

  • Trajectory: Trajectory changes in horizontal sections should be made very slowly. Two preferred methods of drilling horizontal sections include geosteering in the larger hole sizes, and drilling of a pilot hole combined with the use of a less sophisticated bottom-hole assembly in smaller or lower budget wells.

  • Torque reduction: Torque and drag simulation helps improve drilling of horizontal and extended reach sections. Errors are averaging only 10%. Also, operators are reporting a torque reductions up to 25% by using non-rotating drillpipe protectors.

  • Wellbore stability: Not as significant a problem as formerly suspected.

  • Learning curve: Early horizontal wells for most operators were very expensive, but dropped quite rapidly as experience was gained. However, as the rock environment changed, operators had to start over. The critical factor in reducing section costs is assembling complete data on every well.

  • MWD/LWD failure: Measurement and logging while drilling deployment resulted in better pay zone penetration. The most common causes of MWD failure are increases in temperature or pressure.

  • Sidetracking:The most important reason for sidetracking, particularly in the North Sea, is fishing. Rig time is too costly to fish for dropped components. Other reasons for sidetracking in lateral sections were premature setting of the whipstock and poor integrity of the cement plug.

  • Drillstring vibration: A major culprit here is drillstring contact with the low side of the casing and open hole.

Reference:

Ikeda, S., Takeuchi, T., Crouse, P., "An Investigative Study on Horizontal Well and Extended Reach Technologies with Reported Problem Areas and Operational Practice in North America and Europe, IADC/SPE 35054, New Orleans, March, 1996.

The case for not cementing casing

The goal of obtaining complete cement coverage in cementing casing-in-casing is so difficult that operators need to consider whether annuli should be left unfilled. The case was made by Thomas O'Brien of O'Brien Goins Simpson at the IADC/SPE Drilling Conference in March.

Most drillers believe this type of cementing is most reliable and improves the burst rating, but that is not the case, and failures often have major consequences. The problems are as follows:

  • Large temperature changes create longitudinal expansion and contraction, resulting in loading on well foundations and other types of failure-inducing problems.

  • Gaps near the top of the casing are filled from the top, but cementers cannot determine the size of the fill volume or whether, uniformity of the fill, and whether channeling or air traps have been left.

  • Bond logs of tie-back casing show frequent lack of continuity in cementing and no means of pressure relief are available. Pressure is trapped, removing any benefit to burst strength.

  • Bending due to hole deviation in the outer string can be repeated through all the inner strings, and likewise, wear, also occurring at that point, affects the inner strings. With cement, pressure in this area cannot be relieved in the annulus, and may exist the outer casing string.

  • When weak points occur in a cemented inner casing, a tie-back string must be run to cover the weak areas. If the inner casing was uncemented, then it could be removed and replaced.

  • When well pressures are higher than planned, lower-rated burst casing strings can be replaced with those of higher strengths, if the string has not be cemented.

  • It is more difficult to cement in liners than casing, and liner overlap leaks are common.

  • Cement prohibits expansion of casing strings, particularly the outer string. Changes in temperature result in higher pressures than if the casing were not cement-constrained.

Until complete cement coverage of annuli is more certain, O'Brien recommends leaving annuli open in some cases, thereby retaining the option of replacement of worn sections and eliminating trapped pressure.

Maintaining a gauge borehole

Right behind rock bit bearing longevity and rate of penetration in terms of importance for drill bit manufacturers comes maintaining a gauge hole. A gauge hole is important for bit clearance during tripping as well as casing installation. Increasingly, drillers are casing hole with smaller annulus space, making gauge a crucial issue.

Roller reamers in the drillstring provide gauge assurance above the drill bit, but they represent moving parts in the borehole that can wear and tear away. To keep the reamers intact and working, equipment developers have built more reliability into the reamer bearings as well as the locks that keep them in place. Great strides have been made in both areas, but many drillers are reticent about putting more moving parts in the borehole.

In order to provide a gauge borehole that will readily accept a casing string, manufacturers are paying more attention to providing a smooth gauge wall behind the drill bit. Roller cone bits, used to drill most very hard formations, often leave an irregular wall behind. The gauge row of teeth on the cones produce a sliding and scraping action, rather than the crushing and chipping action.

The bit design process is now focusing on the shape and makeup of gauge and heel row bit tooth inserts, including the addition of trimming elements, as well as the spacing of row teeth to obtain maximum penetration of medium to hard formations.

Copyright 1996 Offshore. All Rights Reserved.

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