TURBODRILLS AND INNOVATIVE PDC BITS ECONOMICALLY DRILLED HARD FORMATIONS

Robert C. Boudreaux
Dresser Industries Inc., Security Division
Lafayette, La. Kenneth Massey
Neyrfor Turbodrilling Co. Inc.
Lafayette, La.

The use of turbodrills and polycrystalline diamond compact (PDC) bits with an innovative, tracking cutting structure has improved drilling economics in medium and hard formations in the Gulf of Mexico.

Turbodrills have improved drilling operations, compared to that from rotary drilling and the use of positive displacement motors, in a variety of drilling environments worldwide. In some applications, however, turbodrill use has been minimal because of the cost of turbodrills and because of inadequate bit performance associated with the high rotational speeds of turbodrills.

One problem with PDC bits, especially when used on high speed turbodrills, was their instability which has lead to bit whirl and inefficient drilling. A new PDC cutting structure minimizes some of these destructive tendencies by developing restoration forces at the onset of off center bit rotation. The PDC cutters cut grooves into the formation, forming a track for the bit to follow. This "trackset" cutting structure thereby stabilizes the bit.

Field results have confirmed that turbo-drilling with trackset PDC bits reduced drilling costs, compared to offset wells. The combination of turbodrills and trackset bits has been used successfully in a broad range of applications and with various drilling parameters. Formations ranging from medium shales to hard, abrasive sands have been successfully and economically drilled. The tools have been used in both water based and oil based muds.

Additionally the turbodrill and trackset PDC bit combination has been stable on directional drilling applications. The locking effect of the cutting structure helps keep the bit on course.

TURBODRILL USE

Turbodrilling with PDC bits along the Texas and Louisiana Gulf Coast began in the early 1980s. PDC bits were used with turbodrills to try, to improve drilling economics, similar to their success in other regions.

From 1981 to 1985, the Gulf Coast applications of PDC bits and turbodrills used bits that were successful in other world markets rather than new or experimental bit designs. The long, tapered profile bit designs were largely uneconomical because of low penetration rates and poor bit durability. Thus, operators were reluctant to chance additional runs. During this period, 15 standard PDC bits were run on turbodrills, drilling an average of 356 ft each.

From 1986 to 1991, parabolic profile PDC bits, used successfully in Alaska, were tried with turbodrills along the Gulf Coast. Turbodrilling use and performance increased significantly. Thirty-eight standard PDC bits, primarily parabolic design, were used with turbodrills during this period. The average footage per bit increased to 908 ft. Although the average performance increased, inconsistencies in bit performance held back the use of PDC bits on turbodrills.

Since late 1992, PDC bits with the trackset cutting configuration have been used on several turbodrill runs in the Gulf of Mexico. Eleven trackset PDC bits (International Association of Drilling Contractors bit code M434) have been used on turbodrills, drilling an average of 2,088 ft each. After being pulled, more than half of the bits were graded re-runnable. Bit durability, increased because of the stabilizing effect of this cutting structure.

BIT DEVELOPMENT

In general, PDC bits have had inconsistent performance since their inception. For nearly 2 decades, these inconsistencies have been frequently blamed on factors other than the bit, such as misapplication of the bit or the use of improper drilling parameters. In many cases, the cutter loss and seemingly self destructing cutting structures resulted from the PDC bit's instability.

Common damage from bit instability includes chipped and spalled cutters, broken cutters, and catastrophic failure (Fig. 1). The destructive forces caused by instability and the resultant breakdown of the cutters drastically can reduce bit life and efficiency.

In 1989, Brett, et al., described the phenomenon of PDC bit whirl and how destructive forces were generated by dynamic instability. The low friction gauge pad was one of the first PDC bit designs to combat dynamic instability successfully.2 This method uses an unbalanced cutting structure to produce an imbalance force with a relatively constant magnitude focused on the low friction gauge pad (Fig. 2). This pad remains in constant contact with the borehole wall, thereby reducing bit whirl.

Prior to the identification of bit whirl, self stabilizing cutting structures were used for stability. Impregnated diamond bits designed with cutting structures that form concentric ribs of formation during drilling can provide a measure of lateral stability.3 The bit tends to hold center and operate more smoothly than conventional designs.3

The PDC cutter arrangement produces a bottom hole pattern consisting of a series of sharp kerfs, aiding lateral stability (Fig. 3).4 Laboratory tests confirmed field reports that PDC bits with this kerfing design run smoother than conventional PDC bits.

Conventional PDC bits traditionally have cutters arranged in a partially overlapping pattern that ensures complete coverage of the bottom hole (Fig. 4). In this configuration, cutter density increases across the profile from the bit center to gauge.

This design has cutter density distributed according to expected work loads and protects against premature failures (ring outs). The smooth, defined cutting profile created by this method of cutter placement offers virtually no resistance to lateral instability. The result is gauge pad stabilization only, which may enhance the bit's tendency to whirl.

TRACKSET STRUCTURE

Eliminating cutter overlap allows deep kerfs to be cut into the formation, improving lateral stability (Fig. 5).5 Sets of cutters are located across the bit face in a series of concentric rings. This arrangement allows undrilled formation to fit between the rings, creating a highly defined series of alternating troughs and ridges.

The resulting full cutter engagement greatly increases axial contact with the formation. The tendency for cutters to bite laterally is reduced, and the bit is constantly re centered. The trackset cutting structure resists the start of backwards whirl.

The centering effect created between the trackset cutting structure and the formation stabilizes the bit. The bit runs more smoothly, which significantly reduces the damage that is typical of standard PDC bits. In turn, this stability increases the durability of the trackset bit, allowing longer runs.

In several field tests, the trackset bits have drilled entire sections which had previously been uneconomical to drill or which damaged standard PDC bits. The trackset bits have been used successfully with rotary drilling and with downhole motors.

The trackset bits can drill long sections of hard rock generally drilled by Type 5 and 6 insert bits. The bits have run less erratically than standard design PDC bits. The bits have long fixes because they wear from abrasion and not from chipping.

FIELD TESTS

The trackset PDC bits have been field tested in several formations along the Texas and Louisiana Gulf Coasts. The following case studies compare the turbodrill/trackset bit combination with standard design PDC bits and rolling cone bits used with positive displacement motors and rotary drilling.

Fig. 6 shows the type of trackset PDC bit (IADC M434) used in the following applications.

WEST DELTA

The stratigraphic section of interest consists of late Miocene to early Pliocene sandstone and shale sequences. The sands range from fine to very fine grain with varying amounts of silt and shale.

The first offset well studied was drilled with positive displacement motors and roller cone bits. The well was drilled with six rock-tooth bits, one insert bit, and one PDC bit to 14,217 ft total depth. The interval from 9,648 ft to 14,217 ft was drilled with two rock tooth bits and one PDC bit at a cost of $75.39/ft.

A second offset well was drilled with nine rock tooth bits and two standard PDC bits to 13,786 ft. The same interval of interest was drilled with an estimated cost of $90.51/ft.

The well in which the turbodrill/trackset bit combination was used required four rock tooth bits and one trackset PDC bit to reach 13,618 ft total depth. The interval of interest (9,616-13,618 ft) was turbodrilled with one trackset bit. The turbodrill and trackset bit drilled the 4,002 ft interval at a cost of $67.92/ft. During 40% of the drilling, the bottom hole assembly was steered without difficulty to maintain a 470 hole angle and make necessary azimuth changes.

The use of the turbodrill and trackset bit in the bottom hole assembly saved $29,900 compared to the first offset well (drilled with rock-tooth bits and a positive displacement motor) and $90,400 compared to the second offset well (drilled using the rotary table).

The trackset PDC bit had more than 8.7 million revolutions (1,000 rpm bit rotational speed), about nine times more than those for the PDC bit (IADC M321) used on the first offset well, yet both bits had similar amounts of wear. The trackset bit's dull condition was 1 1 WT A X I NO TD, and the standard PDC bit's was 1 1 WT A X I NO LC.

SHIP SHOAL

The Ship Shoal field studied consists of Miocene and Pliocene shale and sand sequences. Minor shale beds separate the Miocene Pliocene sandstones, the shale beds thicken in the Pliocene formation. The section through the Pliocene is normally pressured, and the Miocene section has abnormal pressures.

On an offset well in Ship Shoal Block 38, three roller cone rock bits and two conventional PDC bits were run with positive displacement motors in an interval from 10,000 to 13,114 ft. (An IADC 437 bit drilled 575 ft, an M223 bit drilled 749 ft, a 517 bit drilled 806 ft, a 126 bit drilled 537 ft, and an M321 bit drilled 447 ft.) In this section of the well, the total bit cost was $45,900. The average cost to total depth was $132.36/ft.

A similar section in Well No. 13 on Ship Shoal Block 30 was turbodrilled with one PDC bit (IADC M434). This bit, with tracking cutting structures and a ballistic profile, was an intermediate step between a standard PDC and a trackset PDC. The section from 9,100 to 12,867 ft was turbodrilled at an average cost of $58.25/ft, saving $279,200 on the well.

Based on the dull bit (IADC dull code 2 8 1 in. UG) condition and the extent of wear on the outer diameter, the bit design was modified to a full trackset cutting structure.

On Ship Shoal Block 27, a second well was drilled with a turbodrill and trackset bit (IADC M434). The new bit design showed a marked improvement in the dull condition (IADC dull code 3 5 1/8 in. UG). The section from 8,533 ft to total depth at 13,037 ft was turbodrilled at an average cost of $59.10/ft.

OUISKI BAYOU

In the Ouiski Bayou field in east central Terrebonne Parish, La., the targeted stratigraphy was a 1,500 ft section of Miocene, medium hard shale just above the Hollywood sands.

The offset bit records indicated the shale would require rock tooth bits in the top of the section and insert bits in the lower section. The first offset well used five rock tooth bits. The top of the Hollywood sands were reached at a cost of $147.75/ft.

The second offset well studied was drilled in 1992 and required three rock-tooth bits and one insert bit to reach the Hollywood sands. The four bits cumulated 197 drilling hr, and the dull bit grades were identical to the that on the first offset well: T4 34 WT. The estimated cost to drill to the Hollywood sands was $146.82/ft. The application for the turbodrill and the trackset bit was in the same section, township, and range as the two offset wells. In all three wells, the mud was water based, and mud weights ranged between 15 and 16 ppg.

The turbodrill and trackset bit were run in the hole just below the casing shoe and pulled out at the first Hollywood marker. The well was drilled with 10,000 14,000 lb weight on bit, 50 rpm at the rotary and 750 rpm at the bit on turbodrill, 422 gpm flow rate, and 3,500 psi pumping pressure. The targeted shale section was drilled at a cost of $120.33/ft, saving an estimated $37,600.

The pulled bit had an IADC dull grade of 3 3 WT-A I ER TD after a total of 4.8 million revolutions. The trackset bit withstood the high rotational speed of the turbodrill while drilling the medium hard lower Miocene formations.

REFERENCES

Brett, J.F., Warren, T.M., and Behr, S.M., "Bit Whirl A New Theory of PDC Bit Failure," SPE paper 19571, presented at the Society of Petroleum Engineers Annual Conference and Exhibition, San Antonio, Oct. 8 11, 1989.
Warren, T.M., Brett, J.F., and Sinor, L.A., "Development of a Whirl Resistant Bit," SPE paper 19572, presented at the SPE Annual Conference and Exhibition, San Antonio, Oct. 8 11, 1989.
Christensen, F.L., "Rotary Drill Bits," U.S. patent 3,106,973, Oct. 15, 1963.
Weaver, G.E., and Bunch, W., "Application of Thermally Stable Polycrystalline Bits/Downhole Motors in West Texas," SPE/IADC paper 16116, presented at the Society of Petroleum Engineers/International Association of Drilling Contractors Annual Drilling Conference, New Orleans, Mar. 15 18, 1987.
Weaver, G.E., and Clayton, R.I., "A New PDC Cutting Structure Improves Bit Stabilization and Extends Application Into Harder Rock Types," SPE/IADC paper 25734, presented at the SPE/IADC Annual Drilling Conference, Amsterdam, Feb. 23 25, 1993.