Summary The penetration rate obtained with a roller cone bit is controlled by either the cuttings generation process or cuttings removal process. Most previously reported penetration rate models have not previously reported penetration rate models have not explicitly included the cuttings removal effects. This paper presents a penetration rate model that includes the effect of both the initial chip formation and cuttings removal processes. The model is an extension of a previously published model that neglected the effects of cuttings removal. The cuttings removal effects must be included in a valid penetration rate model because they can often penetration rate model because they can often the ROP to less than 20% of the expected ROP for perfect cleaning. perfect cleaning. The model is used to show that the reduction in penetration rate at high borehole pressure is the penetration rate at high borehole pressure is the result of both local cratering effects and global cleaning effects. Increased hydraulics will increase the penetration rate when it is limited by global cleaning effects. The penetration rate reduction due to local cratering effects is largely a function of mud properties and borehole pressure and is not helped much by increases in hydraulics. Introduction Although roller cone bits have been used for over 75 years, the complex mechanics and hydraulics involved with these bits has hindered the complete modeling of the drilling process. The combination of crushing and scraping of the teeth on a rolling cone makes it difficult to model the exact cratering process. The turbulent flow field of the mud under process. The turbulent flow field of the mud under the bit has not been completely modeled, so it is difficult to predict cuttings removal forces. The forces that hold cuttings to the formation can not be predicted very well because of the effects of mud properties on the equalization of the pressure properties on the equalization of the pressure around the chips. Consequently, most penetration rate models are based on empirical matching of experimental data. The complete drilling process is composed of a number of individual actions that must occur in order for the bit to penetrate. The complicated geometry of the bit makes measurement of the individual processes difficult, but test conditions can be designed to identify and model certain basic effects such as cuttings generation, cuttings removal, etc. By developing a model based on both theoretical concepts and experimental data taken under controlled conditions, the complex modeling problem can be reduced to a somewhat simpler one. problem can be reduced to a somewhat simpler one. After a basic model is developed, more complete conditions can be added to further define the model. If the physics of the process are handled property. the addition of the new conditions will not invalidate the previously determined model. The strategy described above was used to develop the model presented in this paper. The discussion of the model is intended mainly as a basis for presenting the effects of various parameters that control the rate of penetration (ROP). The model facilitates the comparison of the relative effects of changing various parameters that may be altered during drilling. It also aids in the evaluation of field bit performance to select conditions that may improve the ROP.
This paper presents the results or a study investigating PDC bit vibrations. The study shows that the most harmful vibrations can be attributed to a phenomena called "bit whirl". During whirl the instantaneous center of rotation moves around the face of the bit, and the bit backwards whirls around the hole. Cutters on a whirling bit can move sideways, backwards, and much faster than those on a true rotating bit. The impact loads associated with this motion cause PDC cutters to chip, which, in turn, causes accelerated wear. Lab and field results showing the detrimental effects of whirl on PDC bit penetration rate and life are included. LIMITS OF PDC BIT APPLICATION Since their introduction in the early 1970s, Polycrystalline Diamond Compact (PDC) bits have almost completely replaced tricone bits in relatively soft, and in nonabrasive formations. They have sometimes replaced tricone bits in harder or slower drilling intervals - if the section is uniform. It is fair to say, however, that drillers do not normally consider selecting a PDC bit when drilling in harder formations or even in soft formations with infrequent hard streaks. The problem with running PDC bits in hard formations is not the penetration rates. Adequate penetration rates are possible, at least for short periods of time. The problem is that the bit life is too short. Figure 1 shows that a sharp PDC bit can achieve penetration rates several times that of tricone bits in Carthage marble. Carthage marble has an unconfined compressive strength of approximately 16k psi and is stronger than rocks usually drilled with PDC bits. Yet, a new PDC bit will typically drill two to three times faster than the best tricone effort.
fax 01-972-952-9435. AbstractConoco has had a sustained, multi-rig, development program in the Lobo field of South Texas since the mid-1990's.
SPE Members Abstract A study consisting of surface and downhole field experiments, theoretical analysis, and numerical modelling has shown that mass imbalance of drillstring components is a major source of downhole lateral vibrations. Factors which contribute to imbalance include bore misalignment, initial curvature, and gradual wear during service. The field experiments done on the surface were conducted to quantify drillstring component mass imbalance for modelling purposes. Tests have focussed on drill collars thus far. Lateral displacements of collars were measured while each was rotated in the derrick, and results were interpreted using simple models. All collars were unbalanced to some extent, A similar procedure can be used in the field to identify nearly balanced collars for use near the bit. Field experiments conducted downhole utilized a bull nose in place of a bit to evaluate drillstring vibrations without the bit as a source. A pendulum assembly with stabilizers 65 and 95 ft. from the bull nose was used. Simultaneous surface and downhole measurements of accelerations were made. Lateral shocks due to collar/wellbore collisions were measured at various locations in the drillstring at rotary speeds which caused the collars to whirl. Acceleration magnitudes were heavily influenced by local formation strength. Backward whirl of the drillstring was observed while rotating both on and off bottom. It was identified through downhole measurements, and was associated with sudden, dramatic increases in surface torque. Introduction Axial, torsional, and lateral vibrations of the drillstring can all be harmful to downhole equipment when they are severe, but lateral vibrations are most commonly associated with component failures. In particular, the transition from forward whirl of collars to backward whirl leads to strong lateral vibrations, which are often associated with violent shocks as collisions with the wellbore intensify. The combined effects can lead to drillstring fatigue failures (wash outs, twist-offs) and measurement while drilling (MWD) tool failures. The lateral vibrations of the portion of the bottom hole assembly (BHA) near the bit can also affect its performance, resulting in excessive bit wear and lower rates of penetration (ROP). Usually the source of the lateral vibrations has been assumed to be the bit. While it is true that the bit can generate substantial levels of vibration, the centrifugal forces which are generated when unbalanced drillstring components are rotated may be an even more important source. A rotating body is unbalanced when its center of gravity does not coincide with the axis of rotation. Figure 1 shows a cross section of an unbalanced shaft whose center of gravity is displaced from its geometric center by a distance . This distance is known as the eccentricity, and it causes a centrifugal force to act on the center of gravity when the shaft is rotated. The dynamic force (imbalance force) makes the shaft bow Out, as is also shown in the figure. The magnitude of the imbalance force (per unit length of the shaft) depends on its mass (m), its eccentricity (), and the rotary speed (); it is given by m 2. When the shaft is rotated at one of its natural frequencies of lateral vibration, the deflections due to mass imbalance can become very large. P. 171
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-pit 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. Introduction PDC bits have gained increasing favor because of advancements in the materials used in bit manufacturing and improvements in bit designs. These advancements have relaxed some of the requirements limiting PDC-bit use (e.g., use of oil muds to get good bit performance). In some areas, PDC bits are being used to drill more than 50% of the intermediate and production hole footage. The results of a laboratory study designed to evaluate various factors affecting bit performance are presented in this paper. The bits were chosen from several manufacturers on the basis of their present or prospective use in Louisiana gulf coast drilling. Because comparable bit designs can be obtained from more than one manufacturer, it is not intended to compare the performance of different manufacturers' bits, but rather to compare the general designs. The performance of a particular bit design may vary, depending on subtle design variations, manufacturing quality control, and cutter attachment procedures, but these differences may not be detected in the short-duration testing described here. Rarely is there a perfect bit design to drill a particular hole interval. Therefore, the bit selection for a specific application involves a compromise between positive and negative attributes of the available designs. Considerations must be made for variations in lithology, as well as for operational limitations of other drilling-system components that affect bit performance. This paper is intended to help quantify the effect of various design features, formation types, bit wear, and fluid types on the overall PDC-bit performance. It is recognized that to do this properly, much more information is needed than can be presented in a single paper. Even so, the material presented here is useful in improving bit selections. The results documented here were obtained from a laboratory PDC-bit testing program over a 2-year period. These tests were conducted in different sets designed to investigatethe effect of bit dullness on ROP,performance differences in water- and oil-based muds,the effect of number of cutters on the bit performance, andthe performance of current bit designs. The purpose of the testing was to understand better the strengths and weaknesses of the different bit designs, thereby improving the bit-selection process and helping to define operating guidelines. Bit Designs Four basic bit styles, shown in Figs. 1 and 2, were used in the test program. All the bits were 8 1/2-in. [21.6-cm] diameter. The two bits in Fig. 1, designated as Bits A and B, are similar designs built with 1/2-in. [1.27-cm] -diameter cutters. Bit A is a matrix-body bit with 32 cutters and four jets on the bit face. Bit B, designed with a slightly more rounded face, is a steel-body bit with 39 cutters and five jets. Two bladed bits with tapered or parabolic profiles were also tested. The major design difference in these bits is the number and size of the cutters. These bits are shown as Bits C and D in Fig. 2 and are referred to as the large-cutter bladed bit and small-cutter bladed bit, respectively. The cutting structure of the large-cutter bladed bit is made up of seven 1 1/2-in.. [3.8-cm] -diameter PDC cutters arranged on three blades with six 1/2-in. [1.27-cm] -diameter cutters for gauge protection. The small-cutter bladed bit has 41 conventional 1/2-in. [1.27-cm] -diameter round cutters set in six radial blades. In addition to these bits, three bits similar to Bit B were also tested. Two of these bits were field-worn and had significant wear flats on the cutters. The third bit was new and had chisel-shaped cutters. Testing Procedures Bit-performance tests were conducted by drilling 14-in. [36-cm] -diameter cores that were about 3 ft [0.9 m] long. The cores were held in a pressure vessel with a constant borehole pressure of 1,250 psi [8.6 MPa]. Data for each bit were collected by varying the weight on bit (WOB) during drilling at a fixed rotary speed and flow rate. The WOB was computer-controlled and incremented according to a preprogrammed schedule. Time averages of 21 performance variables, including ROP and torque, were recorded at each level of WOB. Tests were conducted at flow rates, varying from 250 to 460 gal/min [0.9 to 1.7 m3/min] to determine the effect of hydraulics. Rotary speeds of 60 to 175 rev/min were tested. In addition to the bit-performance tests, ROP and torque data were collected at normal and reduced hydraulic levels while the tendency of a bit to ball was studied under stabilized operating conditions. The tests were conducted by drilling all but the top 6 to 10 in. [15 to 25 cm] of the core under constant operating conditions. The first few inches of the core was drilled to establish a bottomhole pattern and to build the WOB to the desired level. The bits were examined visually and photographed at the completion of each test to understand the balling mechanism better. Unless otherwise indicated, the tests were run with an unweighted bentonite/water mud. Typical properties for this mud were as follows: mud-weight, 9.2 lbm/gal [1102 kg/m3]; plastic viscosity, 10 cp [10 mPa·s]; yield point, 12 lbf/100 ft2 [5.7 Pa]; and solids content, 4%. The actual properties for any particular test may have been somewhat different. Bit Performance Bit performance is strongly influenced by rock properties (see descriptions of the test rocks in the Appendix). Figs. 3 and 4 show the performance of each bit in the Berea sandstone. No appreciable difference is seen in either the ROP or the bit torque in this rock. There is a more pronounced difference in the performance of the bits in the Carthage limestone (see Fig. 5). Three of the bits performed similarly with only a minor difference between the two flat-faced bits. Bit D drilled much faster than the other bits for the same operating conditions. Its performance was confirmed by three separate tests that proved it did drill faster than the other bits.
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