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Rotary drilling uses two types of drill bits: roller-cone bits and fixed-cutter bits. Roller-cone bits are generally used to drill a wide variety of formations, from very soft to very hard. Milled-tooth (or steel-tooth) bits are typically used for drilling relatively soft formations. Tungsten carbide inserts bits (TCI or button bits) are used in a wider range of formations, including the hardest and most abrasive drilling applications (seeFigure 1.1). Fixed-cutter bits, including polycrystalline diamond compact (PDC), impregnated, and diamond bits, can drill an extensive array of formations at various depths. The following material outlines design considerations and general product characteristics for the two types.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Summary This paper focuses on the failure modes of polycrystalline-diamond-compact (PDc) cutters and discusses efforts to improve impact resistance, thermal stability, and hydraulic cooling. Composite-transition-layer technology has made possible a new generation of polycrystalline-diamond (PCD)-enhanced inserts that can be used in percussion and roller-cone applications. Introduction This paper deals with the application of PCD in drilling and gives a brief overview of the manufacturing process used in synthesizing PCD. Discussion focuses on the failure modes of PDC cutters, which include residual stress failure, mechanical fatigue failure, thermal-physical failure, and thermal-chemical failure. Efforts to improve the operating performance of PDC shear bits are evaluated, with specific attention given to improving PCD's thermal stability and to cooling PDC shear bits through better hydraulics. Curved PDC cutters offer potential benefits for drilling applications because they enhance cleaning, reduce cuttings buildup, and probably improve cooling. It is doubtful, however, that much can be done to improve the formations, such as granite or quartz. PDC cutters have limited impact resistance in hard formations and fail under repeated loadings. Also, hard, abrasive formations can generate too much friction at the cutter/rock interface for the convective cooling of drilling mud to keep operating temperatures within theoretical 730deg.C [1,346deg.f threshold. PCD more effectively fails rock through compressive impact loading rather than through shear. This paper discusses (from the perspective of a PCD manufacturer) the current state of high-pressure, high-temperature (HPHT) technology, failure mechanisms of PDC cutters, limitations that restrict the use of PCD in drilling, and recent developments in PCD technology. Overview For more than a decade, the oil industry has used synthetic diamond drill bits to increase drilling performance and to lower drilling costs. However, several problems that result from material properties, quality control, and limitations in drilling technology remain with PDC cutter bits. Problems with materials and bit design includespalling, delamination, and chipping of the diamond layer; bit balling in plastic formations; stud breakage in harder formations; excessive cutter wear in abrasive formations; inadequate hydraulics; and poor mechanical cleaning action. Quality control issues in manufacturing includeunsatisfactory bonding of PDC cutters to tungsten carbide (WC) stud; bonding of WC stud to bit; and positioning of PDC cutters on bit. PDC cutter bits also cause problems in drilling operations because theyare troublesome to operate-e.g., greater care is needed during drilling, rig crews need specialized instructions and training, and bits frequently need further refinement in design before they will perform in a given formation; are unable to drill medium and hard formations and are unknowingly used in unsuitable formations like pyrite or quartz; often deviate with high weight on bit (WOB); contain inadequate solids-separation equipment to keep up with high rates of penetration (ROP's); and need shock absorbers in formations that cause drillstring bounce.
- North America > United States (0.47)
- Europe > Norway > Norwegian Sea (0.34)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Mineral > Silicate > Tectosilicate > Quartz (0.45)
- North America > United States > West Virginia > Appalachian Basin (0.94)
- North America > United States > Virginia > Appalachian Basin (0.94)
- North America > United States > Tennessee > Appalachian Basin (0.94)
- (9 more...)
Summary. 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. Introduction The introduction of PDC cutters in 1973 facilitated the development of the first drill bit that used synthetic diamonds as cutting elements. The development process has progressed so that today a large amount of footage is drilled with PDC bits. Through this process, several design features that affect bit performance have become clear. Specifically, the effects of bit body material, cutter placement and density, bit profile, back rake, side rake, and hydraulic horsepower on application and performance have been delineated. The industry has seen the introduction of fine steel-body, then tungsten-carbide-matrix-body drill bits. Cutter placement and density were initially determined by way of an equal-volume-percutter calculation. The state-of-the-art PDC drill bits feature com-puterized cutter placement and density based on an equal work rate per cutter. Also incorporated is a torque-balancing function and a vector resolution that considers back rake, side rake, and bit profile. Hydraulic layouts are now optimized with the aid of a flow-visualition chamber. Extensive field testing, in conjunction with engineering design evaluation, has defined the current application zones and limits of PDC bits. The availability of new cutter shapes and sizes, as well as improved thermal stability and mechanical toughness of the PDC cutter, will enable further evolution of PDC bit designs. Currently, large-diameter PDC cutters providing increased exposure and shaped cutters featuring a higher point loading per cutter are some of the technological advancements being tested. This influx of improved superhard materials, coupled with hydraulically and mechanically more efficient bit designs, will expand the PDC application zone of the future. Initial Designs Initial PDC bits differed quite drastically from the present catalog models of manufacturers. Ear]Y Prototypes used concepts very similar to those of natural diamond bits (Fig. 1). The profiles used were basically the same as those of conventional natural diamond bits, simply replacing the natural diamonds with the PDC cutting element. Various flow arrangements were investigated, including the conventional crowsfoot, waterways, and fixed nozzles. Additionally, there were changes in the PDC cutting element. Initial cutters were 0.323 in. [8.2 mm] in diameter vs. the standard 0. 524-in. [ 13.3-mm] diameter cutter, which is most commonly used today. Early PDC cutters were available in both a 180 and a 360 deg. [3.14- and 6.28-rad) blank affixed to a stud. Early bits used steel, carbide, and hardfaced steel studs, and combinations of both the 180 and 360deg. [3.14- and 6.28-rad] blank. Field Application An early field test of a petroleum drill bit that used PDC cutters took place in Nov. 1973 in Colorado. From these tests, numerous inherent design weaknesses were apparent. The problems are thoroughly documented by Walker et al. Basically, the problems were that the small-diameter (0.323-in. [8.2-mm) blanks did not provide sufficient area to allow a competent braze to the stud. Furthermore, the small blank did not provide sufficient exposure necessary for high rates of penetration (ROP's). Problems were also encountered with impact breakage of the studs, cutter loss caused by braze failures, and poor hydraulic configuration to provide adequate cleaning. Improved Designs After discouraging early field results, bit designers realized that to make use of this new cutting element, the trend of g would have to deviate completely from conventional natural-diamond-bit designs. The contrast between the grinding and plowing cutting mechanism of a natural diamond and the shearing action of rock by PDC cutters necessitated that a workable bit have a radically different design for efficient drilling. This realization led to the first PDC bit style, which resembles what is commonly found today in manufacturer catalogs (Fig. 2). This bit features a bladed-type ar-rangement, tungsten-carbide-matrix body, waterways, and several nozzles (actual number depending on the particular design). Performance was marginal but encouraging, with the typical problems being plugged nozzles and cutter loss. In 1978, the PDC cutter became available with an additional piece of tungsten carbide attached. This provided a larger area to braze to the bit body, and thereby a stronger bond (Fig. 3). Field testing proceeded, and the cutter-loss problem was not completely solved until a new brazing process was developed in 1979. The success of field tests during this time was sporadic, because the Teaming curve of application and operating parameters of these bits was in the very early stages. However, some runs showed sensational performance and savings. By this time, operators and manufacturers had begun to realize, the potential of PDC bits, and development work received new attention in the following time period. Advancement in design, operating parameters, and formation application proceeded at a rapid pace. Note that the bulk of the early bits mentioned here are the tungsten-carbide-matrix body bits with brazed cutters. Stud cutter used in steel-body bits, however, were also being investigated in parallel. By now the basics of PDC bit designs were apparent, and what remained was the determination of the specifics and the effects on bit performance. Design Features Affecting Bit Performance Bit-Body Material. Currently, the two aforementioned materials, tungsten-carbide matrix and steel, are being used in PDC drill bit (Figs. 4 and 5). No conclusions are drawn as to which design is more efficient, but some characteristics of each have become apparent. Steel-body bits use a stud cutter (Fig. 6) that is interference-fitted into a receptacle on the bit body. JPT P. 327^
- North America > United States > Alaska (0.28)
- North America > United States > Colorado (0.24)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.49)
- Geology > Mineral (0.47)
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. Polycrystalline-diamond-compact (PDC)bits have become anestablished new generation of oilfield bits particularly for drillingsoft-to-medium-hard, nonabrasive formations. The development of these bits isstill at an exciting stage. The state of the art in PDC cutters and bits isdiscussed and illustrated by a rich source of fairly recent literature. A lookinto the future is attempted in light of the bits'potential. Introduction In the past, roller-cone bits dominated rotary drilling and diamond bitscoring and turbodrilling. The manufacturers of bits made either roller bits ordiamond bits. During the 1980's, this picture changed markedly because of thesuccess of the PDC bit and more recently the collapse of oil prices. PDC bitshave taken an important share of the drilling. coring and motor-andturbodrilling, market, and are now produced by both diamond-bit androller-cone-bit manufacturers as a new generation of bits. The trend among themanufacturers is clearly toward fewer, more integrated companies that sell allthree types of bits in addition to other tools for downhole use. This paper focuses on PDC bit development through the 1980's and highlightsthe state of the art in the PDC cutters and bits. PDC Cutters Most characteristics of the PDC bit stem from those of the PDC cutter, whichhas been in use in the oil field for roughly 10 years. The development of PDCcutters lies mainly in the hands of cutter manufacturers. The originator ofthese cutters has maintained a leading, role but competing companies haveplayed a stimulating role in bringing, about a steady improvement in thequality and variety of the cutters. Cutters and bits currently are manufacturedby separate companies but a trend is apparent that bit manufacturers areexploring the idea of integration. The strength of the bit manufacturers isthat they can get firsthand, rapid feedback on cutter performance in the field, whereas cutter manufacturers must rely on their clients' responses-i.e., thebit manufacturers. In addition. for cutter manufacturers the oilfield is onlyone of many application of diamond technology, albeit an interesting one. This section provides some understanding, of the status of today's cutter, as developed for oilfield use. Nomenclature. A selective number of terms are used to identify PDC bits."PDC" refers to the cutter (Fig. 1a) that is mounted in PDC bits and isdiscussed here. Such generic terms as "shear bits" and "polycrystallinediamond" (PCD) are not limited to the specific diamond compact with atungsten-carbide substrate identified in Fig. 1a. The term "Stratapax bit"isdying out; it referred to the trade name used by the originator of the diamondcompact. A new product, the thermally stable polycrystalline (TSP) diamond, is asynthetic diamond, not a diamond compact, and therefore more related to diamondbits than to PDC bits. A TSP diamond (Fig. 2) is used to replace crystallinenatural diamonds in diamond bits, TSP diamonds will be discussed briefly forthe sake of completeness. Characteristics. A characteristic of the PDC cutter is the thin(=0.5-mm[=-0.02-in.]) PCD layer on top of a thicker (=-3-mm [-=0.12-in.])tungsten-carbide substrate (see Fig. 1a). This characteristic is of paramountimportance in the PDC bit: the cutter is self-sharpening because the tungstencarbide wears at least an order of magnitude faster than diamond and hence theweight on bit (WOB) is carried by the diamond layers. This explains why PDCbits can drill so rapidly at light bit loads, a feature exploited by many ofthe applications to be highlighted in "Status ofPolycrystalline-Diamond-Compact Bits: Part 2-Application" (scheduled for theJuly 1988 Journal of Petroleum Technology). The cutter-set at a negative rake of 0.26 rad [15 degrees] (Figs. 1b and1d)-acts initially as an extremely sharp cutter. The cutter wears with time anda thin flat develops on the diamond, which is why the bit load needs to begradually increased to maintain penetration. This is sometimes overlooked whenPDC bits are being tested in the laboratory: test results for a brand-new bitmay not be representative of an average bit run under conditions prevailingdownhole. The advent of the PDC cutter has in fact given rise to what is probably thefirst self-sharpening drag bit. Such a bit suffers from less chip holddown thandoes a roller-cone bit and much less than a diamond bit. This feature isanother reason for its rapid drilling characteristic downhole in the absence ofballing phenomena.
- Europe (1.00)
- North America > United States > Texas (0.93)
- Geology > Mineral > Native Element Mineral > Diamond (0.49)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- South America > Colombia > Santander Department > Middle Magdalena Basin > Provincia Field (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- (26 more...)
Abstract One of the main challenges drilling within the Troll field, offshore Norway is maintaining a high Rate of Penetration (ROP) while drilling through hard calcite cemented stringers (Jones et al. 2008a; Gunderson et al. 2008). The calcite distribution in this field is complex and can be difficult to predict, while it is easy to maintain a high ROP when drilling the sand sections between the stringers. Early wear or damage to the cutting structure limits the bit's ability to apply sufficient point loading to efficiently cut through the calcite and remaining lithologies, so the key aspects in solving this challenge is to retain the sharpness of the Polycrystalline Diamond Compact (PDC) cutters and minimize the risk of impact damage when hitting these thin inter-bedded stringers at high penetration rates. Following an in-depth study of the application, the drill bit design evolved following several iterations that included computational fluid dynamics to optimize fluid impingement angles and reduce fluid induced shear stress on both the bit body and cutter substrates. Torque control components were introduced to improve the design's response to weight-on-bit, minimize stick-slip and improve directional response. Detailed laboratory tests were conducted to investigate a new edge preparation applied to a new thermally stable PDC cutter, and the cutter-rock interaction was modeled to investigate complex wear, involving impact, abrasion and thermal mechanisms, while drilling these highly inter-bedded formations. The results of this research led to new cutter and bit technologies which have proven that the combination of improved thermal resistance and more efficient cutter geometry enables the cutters to stay sharp while drilling through the hardest stringers and maintain greater durability to complete the section. The improved designs have now drilled further and faster than any previous attempts, resulting in significant cost savings for the operator.
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Limestone Field > Wabamun Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Sognefjord Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 054 > Block 31/6 > Troll Field > Heather Formation (0.99)
- (35 more...)