Directional and horizontal wells are now being drilled using a new surface technology called Slider, which greatly enhances the efficiency of conventional downhole motor/measurement-while-drilling (MWD) systems without introducing any new downhole equipment. The system works by imposing an alternating right and left "rocking" motion from the top drive while continuously measuring surface torque during sliding operations. Using the rocking action to break friction, longitudinal drag can be reduced from the surface down to the point where borehole frictional forces and imposed torque are in balance.

Similarly, reactive torque propagates back uphole from the motor to break friction over the bottom section of the drillstring up to a point where it, also, is balanced by frictional forces. Thus, the drillstring can be thought of as having three discrete sections: the upper section that is gently rocking back and forth driven by the top drive, the bottom section that is rocking due to varying reactive torque from the motor, and a middle section that is not turning at all. By continuously measuring torque, weight-on-bit and penetration rate while sliding, the driller can minimize the length of the middle section, thus minimizing longitudinal drag. Obviously, calculating all of this by hand in a dynamic drilling situation is impractical, so the Slider system computer does it automatically.

Because the system is constantly making torque and drag computations, it can orient the tool face in any direction while slide drilling without having to come off bottom (this is not possible in conventional sliding, according to Slider) and is able to greatly enhance the weight transfer to the bit, thus delivering many benefits.

Defining the benefits

In four example wells where the technology has been used, the cost-savings and production value realized is compared with conventional manual sliding. Savings benefits are identified as: Sliding rate of penetration (ROP) increase, faster orientation, fewer trips and use of less mud additives for lubricity control.

The sliding ROP increase is realized from the smoother transfer of weight to the bit and the ease of increasing the weight on bit while simultaneously adjusting the tool face while drilling. Faster orientation is realized from the system's ability to adjust the tool face while drilling without having to come off bottom (for the longer horizontals these savings could be of the order of a half hour or more per orientation attempt). Fewer trips are realized by eliminating motor stalling that in deeper sections of the well can be quite significant. Multiple stalls during manual slides were common for this data set. Fewer stalls increase motor life, and because there is smoother weight transfer to the bit, this increases bit life (both motor and bit life increase translate into fewer trips, although this benefit wasn't quite evident in most cases discussed here since the wells were very fast to drill). Mud additive savings are realized by reducing or sometimes completely eliminating lubricity enhancement products by using surface rocking torque to overcome friction. This can be done when the left-hand torque requirements aren't at critical levels for pipe connection integrity.

The increase in production value is realized by being able to increase the horizontal section beyond what could be achieved with conventional motor drilling. In one specific well presented here, there was an additional benefit that came from producing a horizontal section of reduced tortuosity that allowed the final casing to be run without problems.

Case histories

Some case histories will demonstrate the value of the benefits as shown in Table 1. Wells 1 through 3 were land wells (horizontals) and the fourth well was an offshore directional well. Of the many wells drilled using the Slider system, these four are quite representative and have good data to support the economic analysis.

Well 1 kicked off at 150 ft (45.8 m) and ended with a true vertical depth (TVD) of 1,300 ft (396.5 m) and horizontal displacement of 8,500 ft (2,592.5 m). It was drilled with an 81/2-in. polycrystalline diamond compact (PDC) bit using a 5-in. drillpipe.

Well 2 kicked off at 6,730 ft (2,052 m) and ended with a TVD of 6,880 ft (2,098 m) and horizontal displacement of 5,500 ft (1,677.5 m). It was drilled with a 43/4-in. PDC bit using 27/8-in. drillpipe.

Well 3 is a horizontal well drilled in Canada with a measured depth of 7,976 ft (2,431 m). Ade Adeleye, senior drilling analysis engineer with Anadarko Canada Corp., said, "The Slider tool was used in a horizontal well in North East British Columbia, Canada, to deliver cost-effective performance. Sliding ROP was 30% to 40% higher than conventional in the section of interest; better still, we drilled 25% more horizontal footage than originally anticipated," he said. "The drilling team is encouraged to drill more horizontals and extended reach wells using this technique. It could stand as an excellent alternative where cost structure prohibits the use of steerable systems," he concluded.

Well 4 is an offshore 58? inclination well dropping to vertical with a 122?turn in a 61/2-in. hole. Alvin Golden, directional drilling coordinator with Sperry Drilling Services, said, "Well 4 is in an area where sliding has been a problem because inconsistent weight transfer to the bit causes uncontrollable toolface orientation. The system seemed to solve the problems, but just to be sure, it was turned off to verify that the observed results could be attributed to the tool," he said. "Previously, sliding in the shale sections and many of the sand sections was problematic if not impossible, but after introducing Slider technology, sliding success was achieved in the lower sand packages," he continued. "There are a great many applications for tools of this type in the Gulf of Mexico, and rig time savings can pay for their cost."

Scott Jones, with Integrated Directional Drilling Services, working on wells in the Gulf of Mexico, said, "As the system is deployed more frequently, drilling efficiency has improved. As our people become used to the new system, they are able to increase the drilling speed and accuracy during directional control operations," he said. "This leads to faster penetration rates and corresponding cost savings. The full cost advantage of the system is still becoming apparent and will result in even larger savings when the system is incorporated into the well planning process," he continued. "As drilling engineers realize the potential of the system to assist in drilling more complex wells at a reduced risk factor, more marginal wells can be added to the drilling program, increasing production and proven reserves."

Analysis of the benefits shows that they vary between 12% and 28% of total well costs. If production benefits are not considered in the analysis, the value would vary between 10% and 24% - still very significant according to Slider. The production benefit alone for wells 2 and 3 produced a value between 13% and 14% of the total well cost.

Besides the quantification of value above, there are other benefits that have been harder to quantify but nevertheless have been shown to be important. In the offshore well, for instance, the drilling contractor liked the fact that Slider significantly reduced the wall sticking problem they were having and thus avoided jarring, known to be detrimental to the contractor's equipment. On all wells, the automatic rocking feature alone allowed directional drillers to focus on the data trends as opposed to trying to manually control the rocking motion.

In addition to the above, the benefits quantified in Table 1 came from directional drillers using this equipment for the first time. According to Slider, it is logical to expect greater benefits once drillers start mastering the use of the equipment.

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