PROPER BIT SELECTION IMPROVES ROP IN COILED TUBING DRILLING

William W. King
Security Division, Dresser Industries Inc.
Houston

Using the correct type of bit can improve the rate of penetration (ROP) and therefore the economics of coiled tubing drilling operations.

Key factors, based on studies of the coiled tubing jobs to date, are that the drilling system must be analyzed as a whole system and that both the drill bit type and the formation compressive strength are critical components in this analysis.

Many tools and components designed for conventional rotary drilling have been modified and used in coiled tubing drilling, some successfully and some not. Special tools, including bits, designed specifically for coiled tubing drilling are also under development and have been used with varying degrees of success.

Much of the literature on coiled tubing drilling has covered the advantages and disadvantages of this drilling technique. Many of these factors affect bit selection and performance. Box 1 lists some of the advantages, and Box 2 lists some of the disadvantages of using coiled tubing for drilling.

In a recent survey (by Resource Marketing International in Kingwood, Tex.), experienced slim hole drilling personnel worldwide indicated the need for increased availability and performance of small-diameter bits for coiled tubing drilling.

Once a candidate job has been qualified technically for drilling with coiled tubing, the job will have to be justified economically compared to conventional drilling. A key part of the economic analysis is predicting the ROP in each formation to be drilled to establish a drilling time curve. This prediction should be based on the key components of the system, including the following: hydraulics, motor capabilities, weight on bit (WOB), rock compressive strength, and bit type.

This analysis should not base expected ROPs on offset wells drilled with conventional rigs and equipment. Furthermore, a small-diameter bit should not be selected simply by using the International Association of Drilling Contractor (IADC) codes of large-diameter bits used in offset wells.

COILED TUBING DRILLING

Because coiled tubing cannot be rotated, downhole motors must be used to rotate the bit. Drilling occurs in a sliding mode similar to locked-rotary runs in conventional directional drilling.

Directional work requires a bent sub or bent housing on the motor and a special orienting tool to align the bend properly for course corrections.

The rotational speed capabilities of the bit selected should be analyzed considering the rotational rate of the specific motor at the expected flow rate. Medium-speed, medium-torque (MSMT) and high-speed, low-torque (HSLT) motors are commonly used in coiled tubing drilling operations.

A rule of thumb is not to use roller cone bits on HSLT motors. Rather, roller cone bits are better suited to MSMT motors.

In directional coiled tubing drilling, constant sliding makes knowing the precise downhole WOB difficult. Drag reduces the force delivered to the bit. Friction reducers, such as copolymer beads in the drilling fluid, can alleviate some of the detrimental effects of drag. The constant sliding mode is advantageous because the bit does not experience extensive side loading as in conventional directional drilling. Rotating a string with a bent sub can create high side loads on the bit and can cause an oversized hole to be drilled. This problem can occur in conventional directional drilling when rotating ahead begins after a correction run.

In directional coiled tubing drilling, steering occurs constantly. A straight hole is not possible because the bend in the bottom hole assembly always turns the hole path. The normal approach to this situation is to turn the tool face after a certain section length is drilled. Ultimately, this procedure produces a helical well path.

Two types of orienting tools are typically used in coiled tubing drilling: one weight actuated and the other hydraulically activated. Each type allows for adjustment of the tool-face angle downhole.

• The weight-actuated tool requires repeated on bottom and off bottom weight cycles to ratchet it around. This cycling applies repeated axial loading to the bit. Once adjusted, this tool requires 250 psi to hold the adjustment.

• The hydraulically activated tool uses a series of pump pressure changes to alter its adjustment.

In addition, an electrically adjustable tool, which uses a hard wire inside the coiled tubing, is being developed.

WOB

The weight the system can deliver to the bit is a significant consideration in coiled tubing drilling. Drill collars provide WOB in vertical coiled tubing jobs. Because of the fatigue life of the tubing and handling time considerations at surface, the bottom hole assembly design includes the minimum number of drill collars to deliver acceptable WOB.

Drill collars are not used with coiled tubing in directional or horizontal wells. The injector head and the weight of the coiled tubing above the lateral section apply the force to the bit. Much of the force applied at the surface and the available tubing weight is lost from buckling of the tubing and drag friction on the borehole wall, especially along the turn in the well path.

In both vertical and horizontal coiled tubing drilling operations, the bit will most likely not have enough weight to drill optimally. Because of these WOB constraints and hydraulic limitations, all the Rotational energy from the motor must be used by the bit. An optimum motor configuration must be coupled with the proper bit to achieve the best ROP.

HYDRAULICS

Coiled tubing makes safe underbalanced drilling possible. Underbalanced drilling can improve ROPs by reducing the confining pressure on the formation at the bit/rock interface.

Hydraulic capabilities are limited in coiled tubing drilling. The internal diameter of a coiled tubing string is relatively small, creating a large frictional pressure drop. The tubing has a maximum allowable working pressure, and the pump pressure must be kept well below this value to minimize tubing fatigue. After annular pressure drop, frictional pressure drop inside the tubing, and pressure drop in the bottom hole assembly are subtracted from the available system pressure, only a small amount of working pressure drop remains available to the bit.

SYSTEM DESIGN

Coiled tubing drilling is an inherently energy-limited system. Taking maximum advantage of the available energy requires in-depth analysis of the individual components and the drilling parameters for each section drilled.

Table 1 lists the coiled tubing and bit sizes for all the known coiled tubing drilling jobs through late 1993. These data were used as a guide in designing three typical coiled tubing drilling matched-component systems (Table 2).

Even though the use of 2.375-in. diameter coiled tubing and 6.250-in. bits has been limited thus far, they are presented here because both are seen as part of the future for coiled tubing drilling.

As with any well program, all the various types of bits available need to be considered for the job. None of the bit types should be dismissed outright, nor should any bit type be automatically planned without a proper review of the economics and the drilling task ahead.

ROLLER CONE BITS

Milled tooth and insert bits with sealed or non-sealed bearings are available in each of the bit sizes in Table 2. Nonsealed bits are generally designed for drilling out of cement and for workover applications; they are not suited for drilling with downhole motors.

Bits with sealed bearings have a potential application in coiled tubing drilling. Motor stalling is a negligible problem with roller cone bits, making them attractive if stalling has been a problem with fixed cutter bits.

There are several drawbacks to using roller cone bits in coiled tubing drilling, however. Coring of the central spear point or insert of the No. 1 cone can result from high-speed rotation at low WOB while the bottom hole pattern is broken in. In the small bits necessary for coiled tubing drilling, the small bearings lack the strength and the lubrication-reservoir capacity of larger roller cone bits.

The general approach taken with roller cone bits is to trip them in, drill, and then trip them out after a reasonable hour limit that provides a comfortable safety factor.

If a coiled tubing drilling job has an unusual hole size, then roller cone bits may not be an option. In unusual, very small, and some standard sizes, roller cone bit availability is limited. Unusual sizes may require extensive design and tool-up time for manufacturers to produce them.

Table 3 lists roller cone bit availability, by IADC code, for the bit sizes shown in Table 2. Table 3 was developed from various sources, including bit catalogs, bit records, and industry reports. This table should be used only as a general guide because new bit models are constantly under development and old models become obsolete. Even if a particular bit model has been used previously and is still actively used, its availability may be limited. If an operator has a drilling operation planned, he should check with local bit representatives to determine bit availability.

Fig. 1 shows a 4 3/4-in. roller cone insert bit specifically designed for downhole motor applications.

FIXED CUTTER BITS

Natural diamond, thermally stable polycrystalline (TSP), and polycrystalline diamond compact (PDC) bits are all fixed cutter-type bits. These three bit types are custom designed and built on a regular basis. Each of these fixed cutter-bit types can be fitted with reverse cutting structures to assist in backreaming when the bit is tripped out of the hole.

Table 4 provides a general ranking of the available bit types.

NATURAL DIAMOND

Natural diamond bits are still manufactured, but their popularity has decreased because of the wide range of TSP and PDC bits available. Bits built with uniformly produced synthetic diamonds have a far greater number of cutter layouts and designs than do bits built with natural diamonds.

Natural diamonds are not readily available in sizes greater than I carat. This cutter-size limitation is a barrier to high rates of penetration.

Despite these limitations, applications exist for natural diamond bits in coiled tubing drilling. For example, natural diamond bits are likely to be chosen to drill an angular, fight sand which would limit the life of other bits. The cutting action of natural diamond bits produces low amounts of torque, which lends to their application on downhole motors.

Fig. 2 shows a typical small-diameter natural diamond bit.

TSP

Thermally stable polycrystalline (TSP) diamond bits have achieved a strong following for coiled tubing drilling applications. TSP bits can drill faster than natural diamond bits but generally drill slower than comparable PDC or roller cone bits. TSP bits are sturdy downhole.

The biggest recommendation for TSP bits is torque consistency. These bits tend to have a less erratic torque cycle than conventional PDC bits. This torque consistency helps overcome both tool-face orientation difficulties and motor stalling. TSP bits are often used in the build section of a coiled tubing drilling directional well.

The use of TSP bits is usually a conservative approach in coiled tubing drilling bit programs. These bits have become a default selection because of their life expectancy and consistent torque.

The problem with this approach is that the higher rates of penetration possible with alternative selections are never achieved, ultimately handicapping the economic application of coiled tubing drilling.

Fig. 3 shows a TSP bit applicable to coiled tubing drilling.

PDC

Some companies have recommended polycrystalline diamond compact (PDC) bits for nonbuild work in coiled tubing drilling. For the most part, compared to TSP bits, conventional PDC bits have been regarded as too aggressive for the requirements of the system.

The primary drawbacks of conventional PDC bits have been related to difficulties from erratic and excessive torque. The erratic torque has contributed to tool-face orientation problems, motor wear, motor stalling, and reduced coiled tubing life.

Recent advances in PDC bit design have made possible small-diameter PDC bits that reduce torque-related problems. When properly selected and specified, these new technology PDC bits take maximum advantage of the limited energy available in a coiled tubing drilling operation.

The primary technological breakthrough in the development of new technology PDC bits is the recognition of axial and lateral vibrations occurring at the bit. These vibrations are responsible for much of the erratic torque during drilling. PDC bits remove rock by shearing, which causes the high torque. The high-amplitude torque cycle of conventional PDC bits results from a combination of bit whirl (lateral vibration) and bit bounce (axial vibration).

Bit whirl can be resisted by several bit design modifications, including less aggressive gauge sections, force balancing of the cutting structure, asymmetrical blade layouts, and tracking cutter deployments. PDC bits with these features are far less likely to whirl and therefore do not produce the erratic torque from lateral vibration.

Bit bounce can result when a conventional PDC bit overengages the formation and then releases. Blunt matrix protrusions and a properly engineered cutting structure can dampen the axial vibration cycle. Controlling bit bounce reduces the amplitude of torque variation. This type of PDC bit design can engage the rock more constantly and can reduce impact damage to the cutting structure.

These new technology bits have extended the application of PDC bits into harder rock and have significantly increased bit life in traditional PDC bit applications. By reducing downhole vibrations and smoothing out cyclical torque variations, these bits are well suited for use in coiled tubing drilling.

Fig. 4 shows a small-diameter new technology PDC bit designed for use on coiled tubing.

BIT SELECTION

The bit selection process often begins with trial and error and improves with experience. All the system components, drilling parameters, and formation compressive strength are considered in this process.

Trial bit types are run to determine ROPs within torque and weight limits at the selected motor's rotational speed and flow rate. If any of the basic resources available are not being used fully, then the bit type is changed.

Figs. 5 and 6 provide general representations of mean torque, torque cycle, and weight-on-bit relationships for various bit types within a coiled tubing drilling system.

• WOB. Weight on bit (WOB) is delivered in two ways in a coiled tubing drilling I application: In a vertical well, drill collars are used, and in a directional well, the downward force from the injector plus the weight of the tubing (reduced by drag and buckling) is transmitted to the bit.

In either case, the actual WOB is quite low compared to that in conventional drilling. Generally, 2,000 lb has been suggested as a working minimum WOB at total depth. WOBs of 3,500-4,000 lb are commonly planned for a 4 3/4-in. hole.

Although WOB is limited, it must still be considered as a key source of energy for formation failure during drilling.

• Hydraulics. The hydraulic energy available in a coiled tubing operation is constrained because of the small-diameter pipe used. Pressure losses in the tubing, annular pressure losses, and pressure losses in the bottom hole assembly should be calculated to determine the pressure and flow available to the motor and bit.

In coiled tubing drilling, the hydraulic horsepower per square inch developed at the bit will, in most cases, be less important than other hydraulic considerations. The flow rate should be set to allow the motor to operate in its peak power range. One suggestion for optimum performance is to set the flow rate at 80% of the motor's maximum rated flow rate.