HORIZONTAL WELLS-3 UNUSUAL STRESSES REQUIRE ATTENTION TO BIT SELECTION
Warren Jones
Hughes Tool Co.
Houston
The unique stresses imposed on a rock bit during horizontal drilling can often have detrimental effects if operating parameters are not addressed thoroughly and a bit program developed accordingly.
A number of phenomena either acting collectively or singularly can severely hamper the overall success of the program. These phenomena can be a function of the deviated well path, the formations encountered, or the increased use of downhole steerable motors and topdrive systems.
While bits may be a small portion of overall well costs, improper selection can have an adverse effect on the outcome of a horizontal program.
This third of an eight-part series deals with many of the considerations for selecting bits for horizontal drilling. Bit selection criteria that do not drastically vary from conventional drilling are not discussed.
Regardless of the types or sizes of bits chosen for a particular horizontal well plan, key objectives must be kept in mind. The bits must include features that will assist operators in meeting the directional targets while simultaneously maximizing the penetration rate capability. Furthermore, the bits selected must have sufficient life spans to minimize the need for early trips.
Selecting the least expensive bits capable of meeting all these objectives will, in turn, minimize overall bit costs, which is an important consideration in any well program.
BIT SIZE AND TYPE
Similar to vertical and standard directional wells, bit size is based upon the completion needs, or re-entry hole size. However, the completion objectives of horizontal wells may require a hole size different from the typical choice for a vertically drilled well.
Rolling cone and fixed cutter are the two categories of oil field rock bits established by the International Association of Drilling Contractors (IADC).
Both rolling cone and fixedcutter bits have applications in the drilling of a horizontal well, and the characteristics of each should be thoroughly measured against all operational and cost considerations.
The cutting structures of rolling-cone bits can either be tungsten carbide or steel tooth. Fixed-cutter bits are either classified as polycrystalline-diamond compact (PDC), thermally stable polycrystalline (TSP), natural diamond, a combination of the three, or other if no diamond material of any kind is used in the cutting structure.
Many horizontal wells use fixed cutter and rolling-cone bits in concert to take advantage of the unique operational and subsequent cost-effective features incorporated into each respective design. No universal rule-of-thumb exists to oversee the use of either.
As horizontal drilling technology advances, a rollingcone bit, for example, may be used in applications traditionally reserved for a PDC bit and vice versa.
However, exceptions do exist. Rolling cones are the preferred choice when the targeted well bore path contains chert, pyrite, or other hard structures. Conversely drilling slim horizontal holes, mandates the use of fixedcutter bits because of their greater durability in the smaller sizes and their ability to withstand very high rotational speeds.
In a Canadian horizontal program, it was learned that when geared to the proper formations, PDC bits drilled longer sections, which eliminated numerous trips.1 Conversely, in the same program, instances were encountered where formation type and rig hydraulics limited bit selection to rolling cones.
During drilling of the Helder field wells offshore The Netherlands, tungsten-carbide insert and PDC bits were used in the build and lateral sections, respectively. The TCI bits experienced fewer hang up problems affecting build rate in the former, while PDC bits lasted longer in the latter.2
ROTARY SPEED
With top-drive systems, particularly offshore, and downhole steerable motors becoming constants in the horizontal drilling arena, a rock bit is called upon to contend with much higher rotary speeds than those encountered in the average vertical program.
It was demonstrated in a South Texas test well that even onshore, top drives used in conjunction with steerable motors are cost effective in dealing with anticipated directional drilling conditions, especially tight hole problems.3
By using a top drive, two of three connections were eliminated, which made backreaming while circulating 90-ft sections possible. To maximize torque available at the bit, a torque/drag simulator was used to design the well bore profile and drillstring configuration.
This enabled the operator to gain valuable experience in high-angle directional drilling using steerable mud motors and conventional rotary assemblies.
Because top drive and downhole steerable systems increase the rpm delivered to the bit, the chances of wear increase correspondingly. In rolling-cone bits, high rpm can accelerate bearing and seal failure, while fixed-cutter bits may suffer from hastened cutting structure and gauge wear. It is generally accepted that speeds over 150 rpm are considered high.
In most cases, fixed-cutter bits are preferred for drilling long intervals (more than 40-50 hr, depending on the formation and rpm) at high rotary speeds. Their cutting structures and gauge areas can be readily redesigned to increase durability and wear resistance. Optimizing these features can be quickly and somewhat easily achieved on subsequent bits, perhaps even on the same well.
Contrasted to rolling cones, the absence of moving parts, such as cones, bearings, and seals, increases bit reliability in high rotary speed applications.
Conversely, when formation type and cost considerations warrant, rolling cones also offer performance and steerability advantages and can be successfully applied at high rotary speeds. However, shortened seal/bearing life usually will limit run duration. Therefore, it is important to be conservative in forecasting expected drilling hours.
The effectiveness of a rock bit bearing is controlled by the seal, the lubrication system and the bearing itself with deterioration of any of these elements constituting a bearing failure. Such a failure can cause a cutter loss, resulting in a premature trip, along with an expensive and time-consuming fishing job.
Several styles of rollingcone bit bearing packages are available, including journal bearing and roller-bearing bits with either metal-face seals, conventional O-ring seals, or Belleville-type seals.
Metal-face seals have proven to be the most reliable at high rotary speeds and temperatures.
In a horizontal well in Malaysia, the higher confidence level in 8 1/2-in. metal-face sealed rolling-cone bits enabled an operator to drill 17% more footage than that drilled with the best of 11 0-ring journal-bearing bits used on two similar wells. All the bits were run on a 6 3/4-in. motor with a combined surface and motor speed of 208 rpm.
Journal bearings are used in most premium rolling-cone bits, except in the case of large-diameter bits (greater than 12 1/4 in.). Large bits usually use roller bearings. Most traditional horizontal applications do not employ bits in the build angle or lateral sections having a diameter greater than 12 1/4 in.
Journals with O-ring seals are frequently used with bearing/seal packages in today's horizontal wells. Their life is affected by the rate at which heat is generated at their highly loaded internal sliding surfaces.
High heat-generation rates result in high temperatures (200-300 F.) that can be detrimental. The rubber O-ring seal material undergoes a loss of abrasion resistance and wears more rapidly. The radial-bearing clearances are reduced if the inner journal expands more than the cone journal due to the cone's ability to better transfer heat into the surrounding drilling fluid. This can lead to increased bearing friction and momentary seizures.
Shearing of the bearing grease can generate significant heat at a rate that is proportional to the bearing cubed and the bit rotary speed squared.4 Larger-diameter bits have proportionately larger diameter bearings and consequently their bearing life is more sensitive to increases in rotary speed.
The rate of heat generation is also influenced by the contact pressures at the loaded sliding surfaces which are a function of weight on bit.
Another determinant of seal/bearing life is the total number of bit revolutions. An O-ring sealed journal will have a certain wear rate for a given combination of weight on bit and rotary speed. This implies that there is a fixed amount of seal and bearing wear per bit revolution.
Therefore, changes in rotary speed will directly affect seal/bearing life by changing the time required to achieve a given amount of wear or number of bit revolutions.
Heat generation rates and total number of revolutions must be considered together when evaluating the effects of altering rotary speed and weight on bit. Their combined effect is significant.
For high rotary speed applications, a thin coat of silver plating on the cone-bearing surfaces of journal-bearing bits is desirable. Cone plating essentially incorporates a solid lubricant and heat conductor into the bearing package, which is shown to offer significant increases in bearing performance at higher rotary speeds.
On the other hand, cone plating does not appear to improve bearing performance in high weight/low rotary speed applications.
WEIGHT ON BIT
As build rates, hole angles, and departure distances increase, string torque and drag often limit significantly the weight transmitted to the bit. When this occurs, penetration rates are reduced severely and could even lead to termination of the drilling program if weight on bit becomes insufficient to overcome rock strength.
Proper bit selection is the key to improving drilling rates in weight-limited applications. Fixed-cutter bits usually require less weight to continue drilling than do rolling-cone bits.
Common characteristics of those rolling-cone bits which will drill successfully at lower weights are high cone offset and low tooth quantities. Fixed-cutter bits with light-density cutting structures and high cutting-element exposures may be used to maximize the unit loads per cutter and result in greater depth of cut. Weights as low as 2,000-10,000 lb are used if penetration rate is adequate.
The high rotary speeds provided by motors, which are routinely used in build angle and lateral sections, help compensate for the decrease in the available weight on bit. One manufacturer's line of positive displacement motors includes units that will turn as slow as 80 rpm and others that will run as fast as 2,100 rpm. However, in many horizontal applications, motor speeds average between 150 and 250 rpm.
IMPACT LOADING
Because many horizontal wells target vertically fractured reservoirs, impact loading is an important consideration.
Impact loading can be caused by vugs, voids, broken formations, fractures, and formation changes. Each of these situations, either individually or in combination, makes it difficult to maintain a constant bottom hole pattern.
The frequent results are vibrations, bit bouncing, and unequal loading of the bearings and cutting structures, all of which lead to unpredictable drilling rates and reduced bit life.
Journal bearings, as opposed to roller bearings, normally are better suited to handling impact-loading conditions at the bit face, because of the better load distribution they afford.
Steel-tooth (mill tooth) cutting structures are more resistant to the breakage and chipping caused by multidirectional impact and are recommended if the formation is not too hard or abrasive.
Otherwise, tungsten-carbide insert (TCI) bits with lowcone offset, low-tooth projection, and high-tooth quantities are preferable. In fixed-cutter bits, higher cutter density and lower cutting-element exposure will more effectively resist breakage.
Generally, shock tools are not run in horizontal drilling applications because they cannot be positioned effectively in the drillstring. With the critical placement of the motor, bent subs, measurement-while-drilling (MWD) tools, and the like, a shock tool would have to be placed up the drillstring in a relatively ineffective location.
Therefore, shock tools normally do not provide a practical method for reducing the impact loading associated with horizontal drilling applications.
CUTTINGS
Hydraulic operating parameters for horizontal drilling are selected in the same manner as those for vertical holes. A major difference in horizontal wells, which must be strongly considered, is the cuttings accumulation on the low side of the hole.
This condition aggravates wear on the bit exterior and on the bearing seals in rolling-cone bits. Also, seal and bearing life can be reduced because of less efficient cooling.
Cuttings accumulation around the bit can be minimized by maximizing turbulence and selecting a bit structure or jet arrangement that promotes cross flow. Cross flow is obtained with asymmetric nozzle configurations, such as dual nozzles and a blank on a rolling-cone bit.
Turbulence is made more effective by agitation, which can be promoted with the addition of leg pads to the OD of rolling-cone bits, by the use of bladed PDC bit structures, and by increased circulation. Leg pads should not be used if they interfere with the proper operation of the bottom hole assembly.
Martin, et al., determined that when an inclination increased from 0 to 45, the minimum mud velocity that ensured transfer of the cuttings up the borehole increased quickly.5 This velocity may reach between two and three times the minimum value required for vertical holes.
Employing backreaming to clean the borehole wall when there is low-side cuttings accumulation can often intensify the problems associated with wear on the bit exterior. Leg wear pads and hardfacing (Fig. 1) help protect the legs of a rolling-cone bit.
In fixed-cutter bits, wrapping the diamonds around the top of the gauge onto the bevel will help maintain gauge by providing protection from the reverse direction (Fig. 2).
STEERABILITY AND SIDELOADING
Steerability, which is defined as the ease with which the course or direction of a well can be altered, has reached a new plateau of expectation with the advent of medium, short, and ultrashort-radius drilling techniques.
In the past, common drilling applications directed the industry to develop bits incorporating features that limited lateral drilling flexibility. New design features are now being applied to not only permit, but enhance, steerability.
Fixed-cutter gauge pads have been redesigned dramatically. Both PDC and TSP cutters are being placed along the entire gauge lengths, which are now being shortened and profiles flattened to increase sidecutting aggressiveness.
When necessary, diamond density in these short gauge lengths can be greatly increased to achieve additional life when necessary.
By reducing the overall bit lengths, steerability is increased proportionately. Shortening the shanks of fixed-cutter bits is one method of reducing makeup shoulder to nose distance. This, in turn, allows the steerable system to drill a smallercurve radius (create a higher angle build rate) with any given system's bend angle.
The shorter shank maximizes the ability of the curve-drilling assembly to build angle by placing the stabilizers in closer proximity to the bit face.6 A shank of normal length would subsequently decrease the build rate, which in turn would increase the curve radius.
The system's bend angle can be reduced if an increased build rate is not desired. As depicted in Fig. 3, a reduction in the system bend angle will reduce bit offset, thereby decreasing the severity of impact loading at the bit gauge. Fig. 4 shows a PDC bit having shortened gauge pads, a flatter profile, and a shorter shank. Adjacent is a PDC bit without these features.
WALK RATE
Subjecting a rock bit to a side load causes it to pivot about its point of engagement with the wall of the hole. This combination of events causes the hole to follow a path dictated by the magnitude and direction of the side load as well as the direction of the bit rotation.
Thus, a bit rotated clockwise with its cutting elements forced against the low side of the hole will tend to drill down and to the right. With clockwise rotation and the cutting elements forced against the high side of the hole, the trajectory will be up and to the left. Such tendencies are referred to as bit walk.
The isolated walk tendencies vary with the type of bits used. Usually, rolling-cone bits are more predictable than fixed-cutter bits. A primary reason is that fixed-cutter bits have more variation in cutter arrangements, profiles, and gauge lengths and configurations.
Developing a plan to achieve the desired well-bore trajectory should be based on the available information regarding walk tendency for a bit and the bottom hole assembly in a given drilling environment. After starting the well, corrections can be made to compensate for unexpected deviations.
TORQUE AND TOOLFACE
Bit torque results from the interaction of the gauge and face-cutting elements with the formation and is primarily a function of cutting structure aggressiveness and weight on bit.
Compared to a rolling-cone bit, a PDC bit exhibits more torque variation with fluctuations in weight on bit. This is particularly apparent in the rough running conditions intrinsic with drilling through vertically fractured formations.
The variation in torque is intensified when aggressive PDC cutting structures or high-torque/slow-speed motors are employed. In the field, torque variation is an observed phenomenon, and while lab data are available, it is not representative of actual operating conditions, i.e., torsional vibration. However, solid field and laboratory evidence indicates fixed-cutter bits run much more roughly than do rolling-cone bits in an identical formation.
Toolface orientation is dependent on the amount of torque required to rotate the bit. This is the result of balancing bit torque with reactive drill stem torque. Therefore, increased variation in bit torque leads to greater variation in toolface orientation.
Consequently, depending on formation factors, it can be more difficult to maintain toolface orientation when drilling with aggressive fixed-cutter bits, which is why rolling cones can be preferred in build-angle sections.
To minimize torque fluctuations, it is wise to use PDC bits that possess less cutter exposure, a higher cutter density, and a higher cutter backrake angle.
On the other hand, Dech, et al., found in drilling the Austin chalk of South Texas that both PDC and steeltooth bits exhibited good directional stability.7 They did note that the lower reactive torque of the steel-tooth bits made controlling toolface orientation much easier.
BIT LIFE
As is the case with all downhole equipment, bit life is predicted based on previous experience and a working knowledge of the design features of the tool in question. The selection should be made to maximize the probability of successfully drilling the next targeted hole section.
Even though angle-build applications cause increased lateral loading at the bit, build sections normally are short in length relative to bit life. Therefore, unplanned trips are not always a function of bit life.
Bit life in horizontal hole sections is generally the same as it would be in a vertical well, providing that similar operating conditions of low weights and high rotary speeds are employed.
However, this assumes that gauge-holding ability is adequate for the horizontal application. Wilkerson, et al., found that in the final angle build section of a Prudhoe Bay well, rapid gauge and bearing wear reduced the life of journal-bearing, rollingcone bits.3 The short bit life was attributed to the increasing quantity of fine solids in the mud, high motor rotational speeds, and high sideloading.
In applications where gauge-holding capacity may limit bit life, various features are available to increase the life expectancy of the bit. Rolling-cone cutting structures can be altered to use less cone offset, or gauge designs with more wear resistant insert and hardfacing materials. Their legs can be protected as discussed earlier.
Fixed-cutter bits may use, individually or in combination, increased gauge lengths, increased diamond density, lengthened PDC contact area at gauge, and TSP materials.
Because the heart of a rolling cone is the bearing package, it should be a primary consideration when analyzing the expected life of such a bit. A reliability analysis has concluded that while drilling costs decline as bit life increases, the potential savings diminish when the risk of a bearing failure exceeds a calculated probability of survival.8
REFERENCES
- Gust, D., "Horizontal drilling evolving from art to science," OGJ, July 24, 1989, pp. 43-52.
- Stewart, C.D., and Williamson, D.R., "Horizontal Drilling Aspects of the Helder Field Redevelopment," 20th annual Offshore Technology Conference, Houston, May 2-5, 1988.
- Wilkerson, J.P., Smith, J.H., Stagg, T.O., and Walters, D.A., "Horizontal Drilling Techniques at Prudhoe Bay, Alaska," Journal of Petroleum Technology, November 1988, pp. 1445-51.
- Burr, A.H., Mechanical Analysis and Design, Elsevier Science Publishing Co., New York, 1981, p. 45.
- Martin, M., Georges C., Bisson, P., and Konirsch, O., "Transport of Cuttings in Directional Wells," Paper No. 16083, 1987 SPE/IADC Drilling Conference, New Orleans, Mar. 15-18, 1987.
- Parsons, R.S., and Fincher, R.W., "Short-Radius Lateral Drilling: A Completion Alternative," Paper No. 15943, SPE Eastern Regional Meeting, Columbus, Ohio, Nov. 12-14, 1986.
- Dech, J.A., Hearn, D.D., Schuh, F.J., and Lenhart, B., "New tools allow medium-radius horizontal drilling," OGJ, July 14, 1986, pp. 95-99.
- Kelly, J.L. Jr., "Forecasting the Life of Rock Bit Journal Bearings," Journal of Petroleum Technology, June 1990, pp. 165-70.
Copyright 1990 Oil & Gas Journal. All Rights Reserved.