Mark Dykstra, Chris Beuershausen
Salt Lake City
Baker Hughes Inteq
Baker Hughes Inteq
The formation of ledges, as shown here, are a common occurrence of short-gauge, aggressive PDC bits. Such ledges can hang up bottom-hole assemblies, resulting in increased friction and mechanical slip-stick movements (Fig. 6).
- This PDC bit uses long-gauge pads to promote steerability. Although short gauge bits can kick off much quicker, long-gauge bits help eliminate ledges across the course of a directional well (Fig. 10). [12,026 bytes]
This balancing act introduces design elements that may contradict conventional wisdom; in particular, the counteracting effects that aggressive gauge designs have on instantaneous build rates and borehole quality.
Defining aggressivenessThe steerable performance of a PDC bit is primarily governed by the interacting forces of a drill-bit's face and gauge aggressiveness. Laboratory tests, field experiments, and case studies support the following conclusions:
- Face aggressiveness determines the relationship between bit weight and bit torque. The more sensitive this relationship, the more difficult it is to control tool face in the presence of fluctuating WOB.
- Gauge aggressiveness has a pronounced effect on side-cutting ability and hole quality. Some side-cutting ability is necessary to kick off or change direction; however, too much side cutting may create ledges, spiraling, and hourglass features along the borehole.
- PDC bits that include a secondary gauge with reaming features provide the best borehole quality in two ways. First, the additional gauge area limits ledge development during the hole-making process. Second, its reaming capabilities continuously remove ledges and smooth out the well-bore throughout the drilling process.
Steerable assembly reviewTraditional steerable systems utilize a positive displacement motor (PDM), stabilization, and a bending mechanism such as a bent sub positioned near the bit ( Fig. 1 [71,988 bytes]). The bent sub allows tilt and bit offset and further defines the design geometry of the motor system and the resulting build rate.
The system is considered steerable if the motor can be used in both the slide and rotational modes. In the slide mode, the bit is turned by the motor alone. Because there is no drillstring rotation, the tool face, defined by the orientation of the bend, is held constant and allows a deviated path to be drilled in the desired direction.
In the rotational mode, however, the entire drillstring is rotated, allowing for a relatively straight hole to be drilled.
As inclination and horizontal departures increase, the frictional drag on the drillstring becomes larger. Eventually, the transfer of weight to the bit face becomes inefficient, especially when drilling in the slide mode.
Because there is no rotation in the slide mode, all of the frictional forces oppose the axial progression of the drillstring. This leads to axial "stick-slip" movements, resulting in the sudden application of thousands of pounds on the bit.
Depending on the face aggressiveness of the bit, a sudden increase in bit load can result in a substantial increase in bit torque. As shown in Fig. 2 [65,490 bytes], large changes in bit weight produce only slight increases in torque for roller-cone bits. For PDC bits, however, the same variation in bit weight can more than double the torque. This makes tool-face control extremely difficult and can cause motor stalling.
Furthermore, mechanical sticking of the BHA in rugose, ledged well bores compounds the negative effects of friction. Bit vibration and the interaction between the drilling fluid and formation cause some well-bore imperfections but most result from the characteristics of steerable assemblies in the slide and rotational modes.
LedgesA steerable assembly must deform to fit into a straight section of a gauge hole. The adjustable kick-off (AKO) sub setting and component geometry determine the side forces created on the bit and stabilizers. Typical side loads on assemblies of various sizes are shown in Table 1 [37,330 bytes].
Once circulation starts and the bit begins to rotate, the side load is typically "drilled off." If the assembly moves ahead at a suitable rate in slide mode while this is occurring, then the well path will be deviated in a smooth manner. However, if the aggressiveness of side cutting becomes excessive, then a ledge is created.
As the bearing-housing stabilizer contacts the ledge, it shifts the assembly centerline and changes the side load on the bit, creating another ledge. The same tendency is present to a lesser extent when the stabilizer on top of the motor contacts a ledge. Borehole imperfections tend to propagate in this manner in the slide mode.
When drillstring rotation begins, drilling an enlarged hole relieves the side force on the bit. This condition continues as the assembly moves ahead until the lowest stabilizer encounters the enlarged portion of hole.
At that point, there is clearance at the stabilizer, so it shifts laterally and reduces the side load on the bit. The bit then drills a diameter closer to gauge until the stabilizer once again reaches the gauge section of the hole. Because the clearance is reduced, the side load at the bit increases, and the hole is once again enlarged.
The process is self-perpetuated, leading to hourglass (Fig. 3 [81,402 bytes]), corrugated, and spiral borehole patterns.
Modifying bit aggressivenessTool-face control may be improved by making the bit face less aggressive. The idea is that although instantaneous penetration rates may be sacrificed, overall net penetration rates will improve because motor stalling and tool face resets can be avoided.
The simplest approach is to change the orientation of the cutters in relation to the drilling surface (back rake). This is analogous to scraping the ground with a shovel as compared to actively digging in. Modifying this feature, however, may excessively slow the bit down.
Instead, the strategic placement of nonaggressive cutters on the bit profile can allow the optimal balance of steerability and penetration performance to be attained. Figs. 4 [68,880 bytes] and 5 show computed weight and torque contributions from individual cutters on bits with varying degrees of face aggressiveness.
Gauge lengthCommon industry perception is that side-cutting aggressiveness must be maximized to quickly deviate the well path. Generally, gauge length is minimized to provide this side-cutting ability.
However, previous experience with steerable turbines has shown that bits with long gauges-12 in. or more-can perform well at hole curvatures of at least 8°/100 ft.1 To resolve this conflict, the relationships between gauge length, side-cutting aggressiveness, and steerable performance were investigated.
As a first step, the relationship between side-cutting ability and gauge aggressiveness was established in the laboratory. In the experiments, various bit weight and side loads were simultaneously applied to compare axial and lateral penetration rates. Side loads of up to 2,000 lb were applied.
Table 1 suggests that these were very conservative compared to typical loads for 81/2-in. assemblies. Results from tests of roller cone and PDC bits of various gauge designs are shown in Table 2 [72,844 bytes]. To summarize, an 81/2-in. roller cone bit with 2,000 ft-lb of applied side load and 10,000 ft-lb of bit weight drilled laterally at about 6% of the rate at which it drilled ahead. PDC bits with very aggressive gauges drilled laterally 50% faster than the roller cones. Furthermore, PDC bits with nonaggressive gauge designs drilled laterally at about 33% the rate of a roller-cone bit.
While the effect on build rate was not certain at this point, the implications for borehole quality became clear upon examination of rock cores. The ledges shown in Fig. 6 were created by a PDC bit with an aggressive gauge. As previously stated, ledges and irregularities in an actual borehole can cause stabilizers to hang up, which makes steering extremely difficult.
Tool-face controlDrilling results for PDC bits with aggressive and nonaggressive face designs are shown in Fig. 7 [162,640 bytes]. The slide portions of each run are indicated by depths of 0-100 ft, and the rotational sections are shown from 100 to 200 ft.
As observed in the laboratory, the more aggressive face provided higher, but erratic, ROP values ranging from 50 to 400 ft/hr (150 ft/hr average). Because the WOB quickly drilled off, the bit was difficult to control. The penetration rate for the bit with the less-aggressive face was slightly lower, but much more consistent at 50-250 ft/hr (100 ft/hr average).
These results verify that PDC bits with nonaggressive cutters in the cone allow more weight to be absorbed with minimal changes in reactive torque. This makes the bit easier to control.
Build-up rateDrilling results for PDC bits with different gauge designs are shown in Fig. 8 [161,561 bytes], where the more-aggressive, shorter-gauge pad is shown on the left. Build rates achieved with PDC bits of varying gauge aggressiveness are shown in Fig. 9 [66,264 bytes], along with results obtained from a roller cone bit.
At the beginning of the slide, the build rate accumulated fastest for the PDC bit with the most aggressive gauge, followed by the roller cone bit and finally the PDC bit with the nonaggressive gauge.
The expected 8°/100 ft dogleg was reached in 8, 12, and 24 ft for these bits, respectively. Interestingly enough, the side-cutting ability measured in the laboratory correlates almost perfectly with these results.
Perhaps the most interesting aspect of the results concerns the profiles of build rate during the slides. The bits with more side-cutting ability produced much more erratic hole curvatures. In fact, the wild fluctuation in the dogleg severity (DLS) for the PDC bit with the aggressive gauge eventually made drilling in slide mode impossible.
While the PDC bit with a nonaggressive gauge took longer to attain the target build rate, it approached this value smoothly, providing the highest average dogleg (slightly more than expected) over the entire slide interval.
PerformanceThe advantages associated with this controlled gauge aggressiveness philosophy were recently demonstrated in several directional wells drilled by Amerada Hess in the South Arne field, Danish North Sea.
While drilling the 121/4-in. section of well SA-1, a short-gauged, aggressive PDC bit demonstrated steerability in rotary mode. However, it lost tool-face control in the slide mode. This pilot-hole portion of the wellbore was drilled at a 45° tangent.
When the operator plugged back to 2,436 m to begin the horizontal leg SA-1A, another short-gauge PDC bit was installed. This bit was pulled also short of TD because it lost directional control as the junk slots filled with soft shale. The well had to be finished with a milled-tooth tri-cone bit.
To increase hole quality and tool-face control, Amerada selected a 121/4-in. Hughes Christensen BlackTrax BX447 drill bit for well SA-2 (Fig. 10). After drilling the casing shoe, this PDC bit drilled from 1,739 m to 2,750 m measured depth (MD), achieving the first objective.
Across this interval, penetration rates reached levels of 150+ m/hr , averaging 41.2 m/hr. The bit weight was maintained between 1 and 4 tons for the rotary mode and 7-9 tons for the sliding mode. The BX447 reached TD in 58.6 hr and came out of the hole in excellent condition. In the last build section, tool-face control was a little sensitive, but as the BHA advanced along the curve, directional control improved greatly.
Lithology of the section was predominantly clean claystone, with limestone stringers encountered at approximately 2,800 m MD, with a 10-40 m section containing 15-20% dolomitic limestone. The limestone content was continuous from 2,920 to 3,060 m MD with values approaching 30%.
Because of the exceptional directional control and hole quality, the section was drilled in a single bit run for the first time. A wiper trip was made at 2,835 m MD, backreaming to the 133/8-in. shoe. No tight spots were logged and no obstructions were encountered as it was run back to bottom.
This smooth well bore enabled Amerada to easily run casing to the target depth. On the other hand, casing in the SA-1 had to be hammered to bottom. Subsequent wells, including the SA-3 and SA-4, were drilled with the BX447. On these jobs, the casing was run smoothly to the target depth.
- Stapel, G., Lucas, S., Illerhaus, R., and Doogan, P., "Innovative Steerable System, Combined With Block Set Impregnated Diamond Bit Design, Dramatically Improves Economics of Dutch Horizontal Well," paper 35112 presented at the SPE/IADC Drilling Conference, New Orleans, Mar. 12-15, 1996.
Mark Dykstra is responsible for drag and rolling cutter bit innovation, modeling and analysis of drilling system dynamic response, and the coordination of special research projects for Hughes Christensen. He has extensive experience with directional drilling, drilling system dynamics, and hole opening technology.
Dykstra has been with Hughes Christensen for 3 years. Prior to that, he worked for Amoco Production Research. He has authored several publications relating to directional drilling, reaming while drilling, and drilling system dynamics. He holds BS, MS, and PhD degrees in petroleum engineering from the University of Tulsa.
Chris Beuershausen is a senior engineer for Hughes Christensen based in The Woodlands, Tex. His current assignment is manager of product evaluation. His responsibilities include failure analysis of dull bits and identifying improvement opportunities based on failure analyses.
Prior to this position, Beuershausen was a design engineer in the diamond products engineering group. He led the technology development of a steerable PDC product line. He holds a BS in mechanical engineering from Texas A&M University.
Jim Norris was a research and development engineer for Hughes Christensen based in Salt Lake City, Utah. He started with Eastman Christensen in Salt Lake City in 1989. When he coauthored this article, he was a staff engineer. Norris received a BS in design engineering from Brigham Young University in 1984 and an MS in mechanical engineering from University of Utah in 1991.
Roger Fincher is currently a manager for Subsea Pumping Systems Development (Deepvision), a Baker Hughes and Transocean Inc. LLC. He is responsible for the development of riserless, reeled-pipe deepwater-drilling operations. Other the past 20 years, Fincher has held a variety of technical and managerial positions within the Baker Hughes companies. He has been directly involved in field deployment and operational support for horizontal drilling systems and steerable products. Fincher has a degree in civil engineering from the Georgia Institute of Technology and holds several patents for drilling devices.
Michael Ohanian is drilling systems manager for Baker Hughes Inteq, Cairo, Egypt. He is responsible for drilling and marketing operations throughout Egypt. Ohanian has 17 years' oil field operations, marketing, and management experience. His major focus since 1985 has involved planning, execution, coordination, or management of over 150 long and medium radius directional wells. Ohanian holds a BS in biology/geology/education from Stephen F. Austin State University in Texas.
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