Diamond Compact Bits Research Articles

ＰＤＣビットの性能に及ぼすレーキ角の影響

The effect of rake angles on the performance of polycrystalline diamond compact (PDC) bits was investigated by rock cutting tests, drilling tests and durability tests. Two types of PDC cutters, a conventional one and a new one, were used for these tests. The structure of the new PDC cutter, whose diamond layer is protected by a tungsten' carbide layer, is different from that of the conventional one. Rake angles of bits for the rock cutting tests were changed between negative 10 deg. and negative 40 deg. Core bits for the drilling and the durability tests had both backrake and siderake angles of negative 5 deg., 10 deg., 15 deg. and 20 deg. Marble, granite and two types of andesite were used for the tests. The results are summarized as follows:1. Horizontal and vertical forces were minimized at negative rake angle of 10 deg. independent of rock type.2. Core bits with negative 10 deg. and 15 deg. both backrake and siderake angles showed better performance concerning penetration rate and cutter strength.3. The new PDC core bit showed higher penetration rate and better cutter strength than the conventional PDC core bit. The new PDC cutter may be able to apply to drilling of hard formations.

Drag-bit performance modeling : SPE Drilling EngngV4, N2, June 1989, P119–127

Models for the forces required to remove a fixed volume of rock with a single cutter have been applied to different polycrystalline Diamond Compact (PDC) bit designs. The integration of the forces for each cutter over the bit face gives the torque and weight-on-bit (WOB) required for a particular rate-of-penetration (ROP). This paper presents the results of comparing such a model to laboratory drilling tests for four radically different bit designs in four different rocks. The geometry of each cutter on the bit was determined by detailed measurements of the bit with a 3-axis coordinate measuring machine. Drilling tests were conducted by ''reaming'' rock with an 8-1/2'' bit that had been previously drilled with a 6-1/4'' bit. Only the peripheral cutters engaged the rock during the reaming. Additional tests were conducted where the WOB and torque were recorded while drilling a pilot hole into the top of a flat rock and drilling through two different bed boundaries with constant ROP. The model predictions compared well to the measured data for both the reaming tests and the pilot hole tests.

BASS STRAIT DRILLING - PREPARING FOR THE NINETIES

Future development drilling in Bass Strait will be challenged by small field sizes, thin oil columns and increasing drilling difficulty due to greater hole angle and reach. New drilling technology successfully introduced in the recent Bream, Whiting, Perch and Dolphin developments including Steerable Drilling Systems (SDS), Polycrystalline Diamond Compact (PDC) bits and Logging While Drilling (LWD) tools, coupled with the successful use of jackup rigs for miniplatform development, has given Esso the tools and confidence to meet the development challenges of the 'nineties. Bass Strait's first horizontal well has been successfully drilled and completed with further wells planned in the current Bream development. There still remain some areas requiring improvements, including hole cleaning in high angle holes. Improvements in this and other areas will further improve drilling capability.Given the right incentives Bass Strait drilling technology is well positioned for the challenge of oil development in the 'nineties.

Status of Polycrystalline-Diamond-Compact Bits: Part 2-Applications

Distinguished Author Series articles are general, descriptiverepresentations that summarize the state of the art in an area of technology bydescribing recent developments for readers who are not specialists in thetopics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and presentspecific details only to illustrate the technology. Purpose: to informthe general readership of recent advances in various areas of petroleumengineering. Summary. Part 1 (June JPT, Pages 675–84) discussed the characteristics, development, and outlook for polycrystalline diamond compact (PDC) bits. Thissecond part treats applications of PDC bits, including suitable locations, types of hole, and uses. Introduction This paper is intended as a quick reference for operational staff who may beconsidering the application of PDC bits. Unfortunately, these bits cannot yetcope with all formations. Consequently, bit selection is of paramountimportance to avoid misruns, as will be indicated. Suitable Formations PDC bits usually can be used with success only in soft, soft to PDC bitsusually can be used with success only in soft, soft to medium-hard, andmedium-hard, non-abrasive formations. Success, however, is fully dependent on agood match between the bit, the formation to be drilled, and the operatingconditions. (See PDC-Bit Development in Part 1, where performance of thecorrect PDC bits with both oil- and performance of the correct PDC bits withboth oil- and water-based muds is explained.) Experience has shown that, forPDC bits, the type of mud, the bit hydraulics, and bit design PDC bits, thetype of mud, the bit hydraulics, and bit design affect bit performance muchmore than variations in mud properties. Over and over again, it has been foundthat it properties. Over and over again, it has been found that it pays todevelop the best bit design for a particular field rather pays to develop thebest bit design for a particular field rather than to select one from a range.PDC bits can be tailored to the job to provide surprisingly goodperformance. Hard and/or abrasive formations are taboo for PDC bits in that they causeexcessive wear. Streaks of limited extent, lenses, or thin sections of suchrocks within thick sections of a suitable formation can be drilled. It isimperative to consult wireline logs, mud logs, and bit records of neighboringwells. With local expertise at hand, available from bit suppliers and withinthe oil company, it is then decided where to spot the bits, if at all. Refs. 1through 3 and 5 through 15 provide detailed examples of recent case histories. Mudstone and siltstone have been drilled well; sandstones, particularly ifcoarse-grained and cemented, are virtually impossible to drill economically andare highly destructive to the bit. Hard limestone, dolomite, etc., can be cutwith great difficulty. Consult PDC Cutters in Part 1 for an understanding, Sections on TSP Diamond Bits and Hybrid Bits, also in Part 1, provideassistance in seeking alternative bits. Applications PDC bits may play a significant role in a number of drilling PDC bits mayplay a significant role in a number of drilling related applications ashighlighted here. A wealth of referenced literature is available to elaborateon the various aspects. Depleted Reservoirs. Because such reservoirs usually cannot be drilled at areasonable overbalance, the drilling may become extremely slow and costly. Inthe case of roller-cone bits, the common excessive overbalance causes them tocrush the rock to a very thick, dense layer that is hardly removed at all. Diamond bits can often do better because of their plowing action. PDC bitsshave the rock and expose the permeable rock to mud filtration, which can bepromoted by hydraulics to lessen the effective overbalance. Koskie and Appenreport a side benefit of "fishtail" PDC bits in Colombia: their ability todrill depleted sands rapidly at an overbalance of as much as 10 Ibm/gal [1198kg/m3]! Apparently, the sand was not really abrasive and the bit and the mudwere well selected. Others report economically successful runs of TSP diamondbits in depleted sands in south Louisiana. The TSP diamond bit is of limitedversatility; if much shale is encountered, the bit may slow down too much. Deviation Control. PDC bits require only light weight on bit (WOB) to drillrapidly. Because of this feature, the bits have become popular where deviationcontrol is needed, particularly for use in a crooked-hole area. If theformations are suitable for PDC bits, impressive savings can be achieved inthis application. Even less suitable formations, causing accelerated bit wear, can be tolerated to benefit from the PDC bit's favorable characteristic, if thealternative bits performed very poorly. The bit's profile can affect thebuilding or drop of poorly. The bit's profile can affect the building or dropof bottomhole assemblies (BHA, s). Refs. 5 and 17 report local experience. Directional Control. The directional characteristics of PDC bits differpronouncedly, but not unfavorably, from those of roller cone bits. PDC bits, particularly matrix-body bits, have been used to arrest the right-walktendencies experienced with roller-cone bits. JPT P. 817

PDC Applications in the Gulf of Mexico With Water-Based Drilling Fluids

Summary This paper presents the results of a recent study conducted to determine application and operating requirements for polycrystalline diamond compact (PDC) bits in the Gulf of Mexico. This study evaluated PDC-bit usage in Miocene sections of the Gulf of Mexico and has resulted in a saving of more than $1.4 million based on 22 bit runs. As a result of this study, operational guidelines for PDC bits were established and drilling costs per foot were significantly reduced. In addition, a relationship was found between shale reactivity, strength, and density. This proved to be an effective aid in bit selection and determination of hydraulic requirements and verified the results of the study.

Laboratory Drilling Performance of PDC Bits

Summary A laboratory study of polycrystalline diamond compact (PDC) bit designs has generated data that give an insight into PDC-bit performance in the field. The tests reviewed in this paper include those for rate of penetration (ROP), torque response, hydraulic energy sensitivity, balling tendency, dull-bit performance, and bit performance after the removal of selected cutters. A total of four bit designs was tested. The designs included flat-faced profiles and parabolic profiles.

PDC Drill Bit Design and Field Application Evolution

This paper traces the development of polycrystalline diamond compact (PDC) bits from their introduction in 1973. Such design features as body materials, crown profiles, cutter density, and cutter exposure and their effect on bit performance are discussed. In addition, the paper reviews various aspects of bit applications engineering, including bit hydraulics, drilling fluids, directional behavior, and formation types.

Water-Sensitive Shales of Gulf of Mexico: Correlation with CEC Values for PDC Bit Applications: ABSTRACT

The use of the Formation Methylene Blue Test (FMBT), an indicator of shale reactivity, has proven to be a quick and easy qualitative method of defining application windows for polycrystalline diamond compact (PDC) bits used to drill Gulf of Mexico clay shales using water-based drilling fluid. This paper presents the results of a laboratory test program wherein a correlation was established between FMBT corrected for pH effects and quantitative Cation Exchange Capacity (CEC) values on selected samples of various shales. Relationships were determined for drill cuttings and sidewall core samples from the Gulf of Mexico. Mineralogical identification of selected shale samples and Gulf of Mexico well samples was performed using x-ray diffraction techniques. CEC was done by wet-chemistry using both barium and ammonium acetate methods. Other factors influencing shale reactivity in the field data are local temperature and pressure gradients as related to growth faults or other geologic processes. A relationship was noted between FMBT and gamma-ray log response. The program responsible for this work has saved significant dollars in drilling costs since its inception. Other developments have been innovative improvements through use of latest technology in bit hydraulics, design, and materials.

Life Models for Small-Diameter Polycrystalline Diamond Compact Bits in Hard Abrasive Media

Mathematical models for bit life of polycrystalline diamond compact (PDC) drill bits were developed for drilling small holes in hard abrasive media. Based on the wear-out criterion of an average 0.060 in. (1.5 mm) flank wear land, bit life equations were formulated in three forms: bit life versus rotary speed and feed rate, bit life versus rotary speed and penetration rate, and wear rate versus cutting speed and cutter engagement area. The traditional linear-logarithmic model proved inadequate to describe bit life, whereas the quadratic-logarithmic model provided the best bit life prediction equation. Consequently, it would be possible to predict the optimum economical drilling conditions more accurately by employing a quadratic-logarithmic based bit life equation. The equation demonstrated the ability to predict the bit life precisely under different modes of wear.

Wear Characteristics of Polycrystalline Diamond Compact Drill Bits in Small Diameter Rock Drilling

The wear characteristics of polycrystalline diamond compact (PDC) drill bits were investigated in the context of drilling small holes in a hard abrasive medium. An efficient method for measuring wear of the PDC drill bits was developed. The wear test results were grouped or categorized in terms of rotary speed, feed and wear or failure characteristics. Contrary to the three classical wear phases (break-in, uniform wear and rapid breakdown) of the single material cutters, four distinctive wear phases were formed for the PDC cutters: I–break-in, II–diamond wear, III–carbide wear, and IV–rapid breakdown. The characteristics of the wear phases were identified and some suggestions were made to alleviate the wear problem.

Application of Polycrystalline Diamond Compact Bits in the Kuparuk River Field, Alaska

Application of Polycrystalline Diamond Compact Bits in the Kuparuk River Field, Alaska

Evolution of Polycrystalline Diamond Compact Bit Designs for Rocky Mountain Drilling

The Rocky Mountain region of the U.S. has proved to be a good area for polycrystalline diamond compact (PDC) bits in selected formations. Lower costs per foot as a result of higher penetration rates and longer bit lives have been realized in many applications. PDC bits are used routinely in Wyoming in the Green River and Powder River basins. Simply using a PDC bit in these areas does not necessarily ensure an economical run. Care must be taken in choosing the correct bit design for each application to obtain the lowest cost per foot. Since the first PDC bit run, there has been an evolution of designs to enhance penetration rates, and thus to lower drilling cost per foot. This evolution has included changes in bit profile, cutter density, cutter exposure, cutter side rake, and cutter shape. When optimally combined, these features have increased penetration rates by well over 100% in many formations.

Polycrystalline Diamond Compact Bit Proves Effective at South Graham Deese Sand Unit

Summary In the past 2 years, polycrystalline diamond compact (PDC) bits have gained acceptance in the U.S. with many spot applications in soft to medium-hard formations. PDC bits were chosen by Tenneco's Mid-Continent Div. Drilling Dept. to be used at its South Graham Deese Sand Unit (SGDSU) in southern Oklahoma. Drilling in the field is complicated by a plunging anticline that has caused deviations of more than 20 degrees. Previous wells were drilled in 24 days, excluding completion time, using conventional rotary bits and applying light bit weight to control deviation. By using a PDC bit, similar wells can be drilled in as little as 10 days. Introduction The oil industry is going through some very unstable times compared to just 2 years ago. Inflation in the 1981 and 1982 boom years, along with declining oil prices, have caused companies now, more than ever, to reduce their overall cost per foot (CPF) when exploring for hydrocarbons. One method Tenneco has found effective is the use of PDC bits to improve rate of penetration (ROP). Since the development of the Stratapax drill blanks by General Electric Corp. in the early 1970's. PDC bits have made steady advances in the drilling industry. The performance of PDC bits are well documented in the North Sea, Arabian Gulf, and many other areas where rig cost can still be as high as $60,000/D. This paper presents specific applications of PDC bits in Tenneco Oil's SGDSU. The first step in determining if PDC bits could be used was to study logs and offset bit records over the interval to be drilled. The Graham Deese field has 16 productive sands connected by long homogeneous shale sections that seemed ideal for PDC use. The first runs of PDC bits in the field proved that placement of the bit in formations that were either too hard or abrasive proved detrimental to the bit's life. Subsequent runs were more economical because bits were properly placed in the right intervals. Also, PDC use is favored because the smaller rigs used in southern Oklahoma do not have the pump pressure requirements to run downhole motors, which have been used to solve some of the slow ROP's caused by low bit weights with conventional roller cone bits. By using light bit weights with high rpm's, the PDC bit performed better than any previous drilling procedure used at SGDSU, resulting in time and money saved. Field History The South Graham Deese field is located in Carter county, approximately 100 mi [161 km] south of Oklahoma City. The field is situated from Sec. 31-T2S-R2W to Sec. 22-T3S-R2W in the Fox-Graham-Wheeler trend, which is part of the Ardmore basin (Fig. 1). It is one of a series of Pennsylvanian anticlines that are productive in this area. The discovery well for the South Graham field was drilled in 1917 near an oil seep at the surface. By 1967, the field comprised 416 total wells-381 producers and 35 dry holes. In Feb. 1969, APCO Oil Co. unitized the area shown in Fig. 1 and began secondary recovery by a line drive water injection flood pattern on 10-acre [40 468-m ] tracts. Before unitization, the area had produced 18.9 million bbl [3x10 M ] oil with minimal water production. As of late 1982, 20 new infill wells have been drilled to recover oil beneath subsurface locations that had been bypassed because of severe deviation problems. The initial potential from these 20 wells totaled 1,750 B/D [278 m /d] oil and 2,454 B/D [390 M /d] water. It is estimated that 9 million bbl [1.4 × 10 M ] oil in place are still recoverable. Geology The Graham anticline along the SGDSU is a northwest-southeast-trending, thrusted, asymmetrical anticlinal fold with steep dip on both flanks (Fig. 2). The Deese group is composed of interbedded, fine-grained sands and soft to medium-hard. gray, fissile shales, which were deposited in a shallow marine environment. Deposition and structural growth were contemporaneous; therefore, the formations are thinner over the crest of the structure and thicker on the flanks. The productive zones in the unit area have been divided into 16 separate Deese sands ranging in depth from 1,850 to 7.600 ft [564.9 to 2316.5 m]. They are Lower Fusulinid (1 through 6), Upper Tussy (1 through 4), Lower Tussy (1 and 2), Upper and Lower Carpenter. Morris, and Dornick Hill. These sands are shown on the composite type log of the field (Fig. 3). Deviation begins drastically from 1.000 to 1,200 ft [3 .8 to 365.8 m] deep. This interval is where an angular unconformity between Permian Age rocks and older Pennsylvanian rocks occurs. JPT P. 2103^

Effect of Bit Hydraulic Horsepower on the Drilling Rate of a Polycrystalline Diamond Compact Bit

Summary A laboratory drilling program was conducted to measure the effect of bit hydraulic horsepower on the drilling rate obtained with a polycrystalline diamond compact (PDC) bit. Drilling tests were conducted under simulated downhole conditions with an 8 1/2-in. [21.59-cm] diameter PDC bit fitted with four sets of five equal-sized nozzles. PDC bit fitted with four sets of five equal-sized nozzles. Mancos shale, Pierre shale, and Berea sandstone were drilled with both water- and oil-based drilling fluids to determine the interactions among bit hydraulics, rock characteristics, and the drilling fluid. For the range of drilling conditions and rocks examined, the results indicated that bit hydraulic horsepower had a significant influence on the drilling rate. The degree to which drilling rate was affected by bit hydraulic horsepower was dependent on the rock/drilling-fluid combination. Introduction Proper hydraulic design for effective cleaning and Proper hydraulic design for effective cleaning and cooling of PDC bits has been recognized as a major factor in their successful application since these bits were introduced. Historically, there have been two approaches to the hydraulic design of PDC bits:natural diamond-bit flow-distribution systems (water courses with large total flow areas) andhigh-velocity jet nozzles. Both types have been used with varying degrees of success but often for unrecognized reasons. The water-course-type hydraulic designs were characteristic of most early matrix-bodied PDC bits. Nozzled bits evolved from the steel-bodied bits with stud-mounted cutters, although matrix-bodied bits are now available with jet nozzles. An increasing number of commercial PDC bits are becoming available with interchangeable nozzles, providing the flexibility of rig-site hydraulics optimization, providing the flexibility of rig-site hydraulics optimization, With these interchangeable nozzles, the hydraulic energy (or power) of the drilling fluid that is dissipated across the bit face can be adjusted to match that portion of the rig's hydraulic power that is available for the bit after other system losses have been considered. Unfortunately, the benefit in increased drilling rate that can be expected by an optimization of bit hydraulic horsepower has yet to be adequately defined quantitatively for PDC bits. The objective of our work was to determine experimentally the effect of bit hydraulic horsepower on the drilling rate achieved with a jet-nozzled PDC bit while three rock types were drilled with both oil- and water-based drilling fluids. PDC Bit Hydraulics-Background PDC Bit Hydraulics- JPT p. 2110

Applications for polycrystalline diamond compact bits from analysis of carbide insert and steel tooth bit performance : Madigan, J A; Caldwell, R H J Pet Technol, V33, N7, July 1981, P1171–1179

Applications for polycrystalline diamond compact bits from analysis of carbide insert and steel tooth bit performance : Madigan, J A; Caldwell, R H J Pet Technol, V33, N7, July 1981, P1171–1179

Norwegian Oil Policy and Economic Outlook: A Study of a Country in Energy Surplus

Abstract From the first field tests in The Netherlands in late 1975, a new family of high-performance synthetic polycrystalline diamond compact bits has been developed. Following a progression of major efforts to develop a commercially proven product, the breakthrough was achieved in early 1978 in The Netherlands. Additional successes in the Northern North Sea led to rapidly increased applications with turbine drilling. Because of the sharp cutting edges of the synthetic diamond cutters, high penetration rates could be obtained with relatively light drilling weight, requiring fewer drill collars. The maximum rate of penetration (ROP) with these bits was achieved in oil-base mud running with turbines. Field tests confirmed laboratory tests showing that as future turbine speeds are increased, the operator will achieve even greater cost reduction. Recent field tests also indicate a significant economic potential for rotary drilling applications in certain formations. Further development work is required to improve the performance in sticky shales drilled with water-base mud. Additional improvements on the synthetic diamond cutters are needed for broader applications in medium hard and abrasive formations. Introduction The first downhole testing outside the U.S. with a new generation of stud-type synthetic diamond cutter-bits was done in the North Sea in Sept. 1975. The first test bit drilled with a remarkably high ROP, 62 ft/hr for 3.0 hours. The second test bit drilled 124 m in 11.25 hours, resulting in an ROP of 36 ft/hr in anhydrite and salt formations. These initial tests indicated high potential for good rates with light bit weight. Drilling speeds were three to four times higher and required only 30% of the weight on bit (WOB) needed with rock bits. The main problem that these first diamond compact bits encountered was loss of cutters resulting from inadequate bonding techniques. Starting in 1975, an intensive development effort was undertaken jointly by a major European oil company and Christensen Inc., to develop a commercially suitable product. With the success of this program in 1977 and 1978, improved diamond compact bits were used for rotary applications on a larger scale in The Netherlands, to drill anhydrite and salt formations. Also during this period, tests with downhole turbines gave encouraging results drilling Cretaceous and Jurassic formations. In the North Sea (where performance, although acceptable, did not yield the lowest cost per foot) a technical breakthrough was achieved in the first quarter of 1979, when drilling with synthetic polycrystalline diamond compact bits on turbines in oil-base mud became successful. Since that date, the use of diamond compact bits has been expanding rapidly, especially when turbine drilling with oil-base mud in the northern North Sea. Furthermore, excellent results have been obtained with diamond compact bits (both rotary and turbine) with water-base mud on- and offshore Netherlands. The results achieved in the Middle East during 1980 showed outstanding savings when using diamond compact bits for drilling formations such as limestone, chalk, marl, dolomite, and certain shales. During the last quarter of 1980, more than 20% of the total footage of 8 1/2- and 12 1/4-in. hole in The Netherlands was drilled with diamond compact bits using turbine or rotary drilling techniques. A recent record run (where a diamond compact Type 4W bit drilled the complete 12 1/4-in. section from 8,297 to 15,099 ft in 486.5 hours) resulted in savings of $195,370. JPT P. 1938^

Laboratory Evaluation of PDC Drill Bits Under High-Speed and High-Wear Conditions

Summary Recently, five experimental polycrystalline diamond compact (PDC) bit designs were tested in the laboratory, at 100 and 500 rpm in three different types of rock: Nugget sandstone. Crab Orchard sandstone, and Sierra White granite. This paper describes the testing procedures, summarizes bit performance and wear procedures, summarizes bit performance and wear characteristics, and correlates these experimental results with specific design options such as rake angle, bit profile, and material selection. profile, and material selection. Introduction The significant improvements in turbodrill technology over the past few years have generated a great deal of interest in the development of drill bits capable of operating at the high speeds typically associated with these downhole motors. Because of severe wear of moving parts such as bearings and seals, tricone rock bits generally have performed poorly on high-speed turbines. PDC drag bits, on the other hand, have no moving parts and have been used successfully on turbines in the North Sea and elsewhere overseas. In 1979, Sandia Natl. Laboratories initiated a program to investigate the limitations of PDC drill bits as applied to high-speed, high-temperature geothermal drilling.Recently, five different experimental PDC bit designs were tested in the laboratory under atmospheric conditions at both 100 and 500 rpm. Four of the designs were developed by commercial bit manufacturers, while the fifth was developed at Sandia. In general, the designs were very diverse and used different bit profiles, cutter rake angles, cutter positioning strategies, material selection rationales, etc. This diversity allowed the comparison of different design concepts. General Description Two 6.75-in.-diameter PDC drill bits were procured from each of the following commercial bit manufacturers: American Coldset Corp., NL Hycalog, Smith Intl. Inc., and Dresser Industries Inc./Security Div. In a parallel effort, two 6.5-in.-diameter PDC bits were parallel effort, two 6.5-in.-diameter PDC bits were designed and built at Sandia. All of these experimental drill bits were developed specifically for high-speed operation (greater than 300 rpm). The five different designs are pictured in Figs. 1 and 2.A typical PDC cutter assembly (Fig. 3) consists of a PDC drill blank bonded to a support post or stud using PDC drill blank bonded to a support post or stud using either General Electric Co.'s high-temperature LS-brazing process or a diffusion-bonding technique developed at Sandia. For purposes of comparison, the 10 drill bits fabricated for this experiment used both bonding techniques. In addition, both steel and tungsten carbide support posts or studs were used. Six of the bits had all LS-brazed carbide cutters (a PDC drill blank attached to a tungsten carbide stud using GE's LS-brazing process), one had all diffusion-bonded steel cutters, and the process), one had all diffusion-bonded steel cutters, and the other three bits had some combination of LS-brazed carbide cutters, diffusion-bonded steel cutters, and diffusion-bonded carbide cutters. All 10 bits are described in detail in Table 1. The full-scale drilling tests were conducted at the Drilling Research Laboratory in Salt Lake City under atmospheric conditions and using water as the drilling fluid. The flow rate was held constant at 200 gal/min for all tests. For these PDC bits, the hydraulic pumpoff effect was found to be insignificant with respect to the bit weights used. The hits were tested in Nugget sandstone, Crab Orchard sandstone, and Sierra White granite at two different rotary speeds: 100 and 500 rpm. The unconfined compressive strength of these three types of rock was found to be 18,000, 20,800, and 24,000 psi, respectively. Depending on the type of rock, rotary speed, and bit design used, the weight or vertical force on each cutter varied from 30 to 1,500 lbf. JPT P. 2316

Applications for Polycrystalline Diamond Compact Bits From Analysis of Carbide Insert and Steel Tooth Bit Performance

Summary A thousand field runs of typical roller cone and diamond drill bits were studied to form a comparative basis for assessing the impact of the polycrystalline diamond compact bit. Statistical analysis of mud log data was conducted on a formation-by-formation basis involving 2,581 data intervals. Baseline performance in general drilling was established, and key drilling situations for improved performance with the new bits were determined. Introduction During 1979, a study was conducted to document performance of specific commercially available drill bits in more than 1,000 actual field runs to form a comparative basis for assessing the impact of a new innovation - the polycrystalline diamond compact bit. Three basins were studied - the Williston and Permian basins in the U.S. and the North Sea basin. Sedimentary environments ranged from easily drilled, soft sediments to dense, extremely hard and abrasive rock, with an associated range of drilling practices and problems. Statistical analysis of data derived from mud logs was conducted on a formation-by-formation basis, involving 2,581 data intervals. The resulting information is a computerized bit performance data base detailing rate of penetration, footage, rotary hours, and key drilling parameters including mud properties, weight on bit, rotary speed, and rock type. In addition to forming a baseline to evaluate performance of new bit designs, the study highlights key problem drilling situations where polycrystalline diamond compact bits can provide improved performance - e.g., overbalanced drilling, deviation control, high-rpm drilling, slim-hole drilling, and other applications. Actual testing of polycrystalline diamond compact bits in these applications has been in progress both in the U.S. and Europe, with favorable results to the baseline data. The paper outlines the study and offset comparisons of polycrystalline diamond compact bits with conventional bits in slim-hole drilling, oil-base fluids, pressure coring, and offshore drilling. Early Development Efforts on Polycrystalline Diamond Compact Drag Bits The U.S., consuming some 40% of the free world's oil production while producing only 19%, is faced with the challenge of rapidly boosting production to avoid increasing dependence on expensive foreign oil and the resulting consequences to the economy. This must result in more drilling. Drilling costs have increased at almost exponential rates, and the industry continually is looking to new technology to halt this trend. This new technology includes advances in drill bit design directed toward improving both overall performance and performance of specific designs in particular problem drilling situations.