Practical Drilling Technology New bits, motors improve economics of slim hole horizontal wells

Scott McDonald
Hughes Christensen Co.
New Orleans

Floyd Felderhoff
Hughes Christensen Co.
Midland,

Tex.

Keith Fisher
Baker Hughes Inteq
New Orleans

The latest generation of small-diameter bits, combined with a new extended power section positive displacement motor (PDM), has improved the economics of slim hole drilling programs.

Collectively, these improvements in bits and motors (commonly referred to as the drilling system), also have extended the physical drilling condition limits for this technology.

Advancements in small-diameter roller cone and fixed cutter bits have increased penetration rates and operational life, and the new PDMs are more durable and create more power than prior models. In the past, the inability to drill with acceptable penetration rates and to stay on bottom was significant enough to prevent many marginal reentry projects from reaching fruition.

The drilling system has been acknowledged as one area that can most impact slim hole well costs, with some estimates putting the possible cost savings around 40-60%.1

Furthermore, projects that were once beyond the equipment limits of earlier drilling systems are now being given serious consideration.

Cost benefits envisioned for previous-generation slim hole drilling systems were never realized, primarily because of equipment limitations and reliability. Isolated cost savings up to 70% were realized in slim hole wells drilled in the late 1950s and 1960s; however, the composite trend never improved significantly. The principal shortcoming was the continued use of roller cone bits, which at the time had unacceptably low penetration rates.1-3

Although the advent of polycrystalline diamond compact (PDC) drill bits held promise for radical increases in penetration rates, the high reactive torque of these bits created erratic toolface problems during drilling of constantly changing formations of varying shear resistance, like the sand/shale sequences in the Gulf of Mexico and in some onshore areas.

These toolface fluctuations made directional control a serious problem, especially in the more aggressive build rates now being required of horizontal well profiles. High drag forces for these more difficult well profiles made it difficult to keep a constant weight on bit, thus creating torque spikes beyond the power limit of the motors. The surging popularity of horizontal reentry wells forced a speedy resolution of this issue.4

Reserves extensions

As costs are driven down, redevelopment reserves are generated in the older, more established fields. New reserves result from increases in the ultimate recovery and accelerated production rates from the implementation of horizontal wells in reentry programs.

This logic stimulated an entire development program for a Gulf of Mexico platform, which was performed without significant compromises in well bore geometry.

Well bore profiles with a radius as short as 40 ft have recently been drilled in the Gulf of Mexico. This radius equates to a dogleg severity of 1.2/1 ft of hole drilled, as calculated by the following expression:

DLS = arccos[sin I1 sin I2 cos A2-1 + cos I1 cos I2]

where: DLS is the dogleg severity (/100 ft), I is the inclination in degrees, and A is the azimuth in degrees. The subscripts 1 and 2 indicate the first and second data points.

These advancements in technology allow the use of smaller, less expensive rigs for drilling and completing the typical geopressured wells in the Gulf Coast.

The savings from this new-generation drilling system come from reducing the total number of trips required during the drilling phase. For example, a typical rig and support cost for the Gulf of Mexico is about $60,000/day. Eliminating just one trip at a depth of 10,000 ft would save more than $20,000.

Well bore geometry

The latest-generation drilling system enables operators to experiment with smaller well bores. In West Texas, for example, more than 60% of the horizontal/directional wells drilled during the past 5 years have been in hole diameters of 43/4 in. or less, using International Association of Drilling Contractors (IADC) 547 and 537 class rock bits. Most recently, some wells in that area have been drilled with 37/8-in. IADC Class 537 roller cone bits, which were developed to coincide with the introduction of a 31/8-in. PDM.

In the Yates field of the Permian basin, the thin zone between the gas/oil contact and the oil/water contact forces operators to use short-radius profiles. Outside the Yates, however, improved bits and downhole motors have enabled Permian basin operators to experiment with various well profiles.

By changing from short-radius to medium-radius profiles, which allowed pipe rotation, some Permian basin operators saw penetration rates jump from an average of 8.6 ft/hr to 36 ft/hr, with aggregate cost reductions of $360/ft for three medium-radius wells cited.

Worldwide, the trend in slim hole drilling has been moving more towards short-radius profiles. The trend is now increasing in the Gulf of Mexico, where the first short-radius well was drilled last year. Formerly, the majority of Gulf of Mexico horizontal wells were long radius, because earlier-generation steerable systems could only rotate through the laminated and fluctuating sand/shale sequences at buildup rates in the 0-8/100 ft range.

No system was available to rotate through buildup rates in the 25-47/100 ft range, which is the generally accepted range for short-radius wells. With completion technology now in place, the drilling of short-radius profiles is described as the next step in the evolution of slim hole drilling in the Gulf of Mexico.

Long-radius horizontal reentries require an average of 750 ft of drilling to complete the curve. Conversely, the average footage through the curves of short-radius wells is 290 ft; therefore, 460 ft less drilling is required to achieve the same objective. Fig. 1 [66212 bytes] compares long, medium, and short-radius profiles.

The latest-generation slim hole drilling system resulted from a concurrent bit/motor joint research program aimed at developing a high-speed, reduced-torque configuration with acceptable steerability, penetration rates, and overall operational life.

Roller cone bits

The inability of earlier versions of small-diameter roller cone bits to achieve satisfactory penetration rates and drilling hours severely limited the economics of slim hole programs. Earlier versions of small-diameter roller cone bits were pulled routinely after relatively short operating hours, because impending bearing failures could not be detected at the surface, creating a low level of confidence.

Because of improvements in the bearing geometry/metallurgy and cutting structures, 43/4-in. roller cone bits that previously drilled an average of 350-400 ft are recording footage in the 800-900 ft range. Recently, one 43/4-in. IADC Class 427 bit drilled 1,112 ft in a Gulf of Mexico well.

From a bit standpoint, the majority of stresses and potential problems in horizontal and directional programs arise from either the hole angle or the methods employed to reach the target.5 The stresses are magnified in smaller-diameter bits run on motors, because the higher rpm delivered to the bit can accelerate the wear rate of the seal, bearing surface, and cutting structure.

The ratio of rotary rpm to cone rpm is 1 to 1.3. The bearing surface speed is given by the following equation:

S = (rpm x 1.3 x p x d) 60

In this equation, S is the cone bearing speed (in./sec), rpm is the total bit revolutions per minute, and d is the bearing diameter (in.).

The latest generation of small-diameter steel tooth and tungsten carbide insert (TCI) roller cone bits incorporates a ball lock cone retention system, which provides higher retention capability and the capacity for higher rpm.

Early in the slim hole roller cone bit development program, instances of cone shell erosion were prevalent because the cutting structure was buried so deeply that the cone shell was literally riding on the formation. The problem was successfully addressed with a thicker cone shell and a smaller bearing pin diameter. This enabled compact projection to be increased 20% on IADC 427 TCI bits.

Shortening the bit body by 5.75 in. for a 43/4-in. bit enhanced its ability to turn on the curve-drilling assembly and decreased the possibility of shirt-tail damage as the bottom hole assembly turns or builds angle, especially in abrasive formations. Both TCI and steel tooth bits in the 37/8-in. to 61/8-in. range employ tungsten carbide shirt-tail compacts for leg protection, which is particularly critical in horizontal and directional programs.

Cutting structure durability was addressed by coating steel tooth bits with a proprietary hardfacing material, while TCI bits employ improved carbide grades. Fig. 2 [38147 bytes] is a 61/2-in. TCI bit incorporating the latest design features.

The economic impact of new small diameter roller cone bits on high-cost and low-cost slim hole drilling programs has been significant.

A new design 43/4-in. IADC Class 427 TCI roller cone bit used in the Gulf of Mexico saved $176/ft over the average of the best average offsets, for an overall savings in excess of $180,000. This bit drilled at a cost per foot of $71/ft, compared to $110/ft for the best offset and an average offset of $247/ft.

Also in the Gulf of Mexico, a 61/8-in. steel tooth bit reduced the cost per foot from an average of $83/ft for the best available offsets to $46/ft.

Overall, roller cone bit life, expressed as drilling hours, has increased 30-40%, while total footage has doubled and in some cases tripled with the introduction of the new design features.

PDC bits

The highest potential cost savings in slim hole drilling programs are with PDC bits. With their lack of moving parts, PDC bits have a big advantage over their roller cone counterparts because of the concern of lost cones.

The development of the latest generation of slim hole fixed-cutter bits has focused to a large degree on PDC bits. However, a thermally stable diamond (TSD) bit with new coating technology increased penetration rates some 28% in a high-speed PDM vertical program in the Prentice field in West Texas.6

The primary focus of the small-diameter PDC bit development program was improving steerability and rates of penetration. Critical to the success of this endeavor was addressing the torque response of PDC bits. The shearing cutting action of PDC bits can require rotational torque three to five times greater than that exhibited on roller cone bits to achieve their penetration rate potential.7

Historically, this significantly higher reactive torque prevented the running of PDC bits on steerable assemblies in the build section. The coefficient of friction, , for PDC bits is in the 0.6-2 range, whereas the reactive torque of roller cone bits falls between 0.10 and 0.15.

Reactive torque for drilling bits is calculated with the following equation:

= 36 x Tq/(WOB x BD)

In this equation, is the coefficient of friction, WOB is the weight on bit (lb), BD is the bit diameter (in.), Tq is torque (ft-lb).

The torque response of aggressive PDC bits tends to be very sensitive to changes in weight on bit. A reduction in this weight sensitivity was accomplished by increasing the cutter backrake, which is defined as the angle at which the cutter contacts the formation. The increased backrake lessened the aggressiveness of the bit, thereby reducing torque variability.

Furthermore, a significantly shorter bit profile, in conjunction with an antiwhirl gauge, has dramatically improved steerability.

The newest slim hole PDC bits have carbide supported edge cutters designed specifically to alleviate premature fracturing, which in the past severely limited the life of PDC bits.8 Basically, these cutters have an extended chamfer edge that reinforces the diamond table against the detrimental blows experienced during the drilling process (Fig. 3 [59517 bytes]).

Polished cutters, another recent development, can lower the frictional forces that cause formation buildup at the cutter face, which can result in cutter balling. Polished cutters, which have the frictional coefficient of ice sliding on ice, have been shown to facilitate cuttings removal, thereby improving penetration rates.9 Cuttings removal is also enhanced by undercutting the shank to maximize the junkslot cross-sectional area at the transition from the gauge to shank annulus, especially on PDC bits 43/4 in. and smaller.

Although it was previously believed that a uniform stress exists downhole, subsequent investigations revealed that certain areas of the borehole exhibited more stress, and hence the rock was stronger. Therefore, the cutters on the latest generation (0.323-in. cutters for 57/8-in. bits and smaller; 0.529-in. cutters for bits up to 61/8 in.) are designed to withstand specific downhole stresses.

Cutters can be strategically placed to match specific borehole rock strengths. To contend with the high tangential stresses encountered on the flank and shoulder areas of the bit, cutters with thicker diamond middle sections are employed to better resist torque-related loads and abrasive wear. The high axial stresses in the center of the bit are addressed by using cutters with a modified diamond-to-carbide interface that strengthens the area most susceptible to axial loads.

Fig. 4 [29424 bytes] shows a 61/8-in. M232 PDC bit incorporating these new design features. This type of PDC bit recently drilled a well in the Gulf of Mexico at a cost of $70/ft, compared to the average offset cost of $123/ft.

New generation PDM

Positive displacement motors (PDMs), once considered suitable only for initial directional kick offs and short directional corrective runs, have now evolved into tools capable of extended runs in a variety of configurations.10 The latest in the evolution of the downhole motor, which resulted from more than 1.5 million operating hr of experience, is a PDM with an extended length power section.

Furthermore, design changes effectively avoid the negative side effects experienced with dual power section and dual power head motors employing conventional components.

While the extended length PDM operates at speeds similar to conventional motors, the horsepower output exceeds that obtained by current dual power section PDMs and turbine motors. Table 1 lists the specifications for 31/8-in. and 43/4-in. versions of the extended length motors.

Several design differences exist between the extended length PDM and earlier motors. The rotor/stator (power) section is about twice as long as earlier motors and incorporates a newly developed profile that is more durable and efficient. Additionally, the bearing assembly is more durable. Allowable bending moments for critical internal and external connections have increased up to 250% compared to earlier generations. Makeup torque on some of the connections has more than doubled.

Field trials during a 1-yr period involved more than 60 extended length motors of various sizes. These trials used a variety of drill bits in various types of formations worldwide. New marks were set in length of runs, rates of penetration, and cost savings in avoidance of trips to service motors and bits. No motors were left in the hole because of component failure.

On a recent run in the South Pass region of the Gulf of Mexico, a 43/4-in. PDM incorporating the extended power section and a 61/8-in. M232 PDC bit with the new design features drilled 56% more footage than other drilling systems on any single well in the area. The bit drilled from kick off at 4,247 ft to total depth at 10,022 ft, drilling a total of 5,775 ft in 124.75 hr for an average penetration rate of 46.3 ft/hr.

The bottom hole assembly was pulled twice, but only because the blowout preventers required testing.

These motors, in combination with new small-diameter bit designs, show promise for extending slim hole drilling capabilities.

References

1. C ohen, J.H., Maurer, W.C., and Leitko, C.E., "High-Power Slim Hole Drilling," Society of Petroleum Engineers paper No. 30485, presented at the SPE Annual Technical Conference Exhibition, Dallas, Oct. 22-25, 1995.

2. D upuis, D., and Fanuel, P., "Well Cost Systems Approach: Achieving Well Cost Reduction Through Slim Hole Drilling With a Purpose Built Drillstring and Rig," IADC/SPE paper No. 25721, presented at the IADC/SPE Drilling Conference, Amsterdam, Feb. 23-25, 1993.

3. W orrall, R.N., van Luijk, B.V., Hough, R.B., Rettberg, A.W., and Makohl, F., "An Evolutionary Approach to Slim-Hole Drilling, Evaluation and Completion," SPE paper No. 24965, presented at the European Petroleum Conference, Cannes, France, Nov. 16-18, 1992.

4. Cooney, M., and Fisher, K., "Horizontal Drilling Makes Re-Entries Attractive in the U.S. Gulf," Offshore, February 1995.

5. Felderhoff, F., "Design and Performance of Small Diameter Roller cone Bits in Short Radius Lateral Drilling Programs, presented at the Short Radius Horizontal Drilling Symposium, Midland, Tex., Jan. 23, 1992.

6. Felderhoff, F., Horton, R., Payton, R., and Bean, B., "New Coating for Slimhole TSD Bits Helps Cut Drilling Costs," Oil and Gas World, May 1995, pp. 46-48.

7. Pessier, R.C., and Fear, M.J., "Quantifying Common Drilling Problems With Mechanical Specific Energy and a Bit-Specific Coefficient of Sliding Friction," SPE paper No. 24584, presented at the SPE Technical Conference and Exhibition, Washington, D.C., Oct. 4-7, 1992.

8. Cooley, C.H., and Meany, N., "The Development of a Fracture-Resistant PDC Cutting Element," SPE paper No. 28312, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 25-28, 1994.

9. Smith, R.H., Lund, J.B., Anderson, M., and Baxter, R., "Drilling Plastic Formations Using Highly Polished PDC Cutters, SPE paper No. 30476, presented at the SPE Annual Technical Conference and Exhibition, Dallas, Oct. 22-25, 1995.

The Authors