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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractUltra-deepwater drilling activity is at an all time high. Recently, there were only two rigs rated to, and actually working in, water depths greater than 6,000 ft. Soon there will be over twenty. This increase will involve new deepwater operators and bring a large number of new people to deepwater. This paper presents some of the problems that have occurred in deepwater operations under the assumption that an understanding of what can go wrong is the best way to avoid problems. It will identify these problems and discuss the critical topics of rig positioning, environmental considerations, BOP control, riser management, well control, wellbore construction, production problems, and personnel training and safety.

A real-time, bi-directional, drill string telemetry network has been proven reliable over the course of seventeen field trial wells, including seven wells within the U.S. The network has demonstrated simultaneous upward and downward data rates of up to 57,000 bits per second, with reliability comparable to current mud pulse telemetry technology. The network utilizes unique inductive coupling coils and armored coaxial data cables embedded within premium double-shouldered drilling tubulars to provide high bandwidth telemetry without impacting drilling operations. U.S. field trials have included multiple vertical and directional gas wells drilled to depths exceeding 14,000 feet in the Arkoma region of southeastern Oklahoma. The drilling environment has involved extremely harsh vibrational conditions, including air hammer drilling and multiple jarring events. During these trials, a leading oilfield service company has deployed a number of different downhole measurement-while -drilling (MWD) tools interfaced directly to the drill string telemetry network. This interface allows real-time surface control and interrogation of the downhole tools and transmission of high-density, low-latency drilling dynamics, formation evaluation and directional MWD data at previously impossible speeds. In a recent well, the operator elected to eliminate their usual mud pulse transmission tool, utilizing the telemetry drill string network and compatible MWD tools as the primary downhole data source. This paper builds on prior publications and provides details of the latest field trials, including, for the first time, information on the development and performance of network enabled MWD tools. A summary of the mechanical and electrical design considerations associated with tool conversion is offered. Observations regarding mud-pulse and drill string telemetry performance, including operational differences, rig time impact, added value and deployment issues are provided. Finally, this paper provides details, and value propositions, of downhole measurement and drilling applications that are enabled by the availability of a reliable telemetry drill string network. Introduction Seven years of engineering and development, funded in part by the U.S. Department of Energy, has produced the IntelliServ® network, a high-speed, bi-directional drill string telemetry system.[1] This network makes it possible to obtain large volumes of data from downhole tools and other measurement nodes along the drill string instantaneously - greatly expanding the quantity and quality of information available in ‘real-time’. The system's bi-directional architecture allows high-speed transmission of downhole data to the surface and commands from the surface to downhole devices simultaneously. Through a physical and electrical interface to the telemetry drill string, existing MWD/LWD/RSS tools can be made fully compatible with the network, allowing high band-width communication between all connected tools and a surface acquisition/control system. Drill String Network Technology Overview The drill string telemetry network comprises conventional drilling tubulars modified to incorporate a high speed, low loss data cable running the length of each joint. The cable terminates at unique, inductive coils that are installed in the pin nose and corresponding box shoulder of every connection and transmit data across each tool joint interface. Second-generation, double-shoulder connection configurations provide an ideal location for coil placement, with each coil installed in a protective groove in the secondary torque shoulder. Figure 1 illustrates a coil installed in the pin end of a drill pipe joint.

Summary The application of whirl-reducing technology to core bits has provided significantly improved coring performance. Laboratory and field tests show that the elimination of bit whirl reduces core jamming problems and produces cores that are smoother, closer to gauge diameter, and less fractured than those drilled with standard polycrystalline-diamond-compact (PDC) core bits. Eliminating bit whirl also results in a more efficient cutting process, which can lead to improved rates of penetration. Utilizing the antiwhirl core-bit technology can improve the economics of conventional coring operations significantly and also can make wireline-retrievable coring with conventional rigs and drillstrings a practical alternative. Introduction The long-term economic success of a petroleum E&P company is highly dependent on its ability to produce the reserves in its current inventory effectively and to replenish and expand those reserves. In the U.S., the success ratio for finding oil and gas in new field wildcat wells has remained relatively constant for the past 4 decades, but both the size and total number of discoveries have continued a steep decline, as shown in Tables 1 and 2. This trend has had the effect of directing the exploration efforts of many companies toward more favorable international areas. Nevertheless, in 1989, 79% of the world's 763,000-plus producing oil wells (excluding the U.S.S.R. and eastern Europe) were still located in the U.S. This large inventory of wells provides an incentive to develop a better knowledge of the reservoir characteristics needed to produce these known reserves efficiently. The need to apply more effective exploration techniques and the need to exploit known reserves better can be affected by the availability of cost-effective coring technology. International exploration often involves drilling in locations where costs are very high, so the evaluation of a prospect hinges on the limited data obtained from a few exploratory wells. Coring the actual rock in these wells is often the best means of obtaining important geological and reservoir information about the field. Unfortunately, the high cost of coring associated with the use of specialized equipment, short runs because of jammed cores, increased rig time because of slower drilling, reduced bit life, and the additional trips required to retrieve the core is often prohibitive.

fax 01-972-952-9435. AbstractThis paper describes the successful introduction and application of a rotary steerable system for large hole sizes (17.5 and 18.25-inch.). The development of the large hole rotary steerable capability was seen to be mutually advantageous to both BP and Schlumberger. As such, this technology development was advanced as a collaborative effort.At the outset, the collaboration team identified the technology as being suitable for the intended application. Together, team members focused on the rapid development, construction, and field-testing of the rotary steerable system. Over a 9-month period, the system was designed, tested, and deployed by teams working concurrently in the UK and the USA. Prior experience gained with smaller hole sizes was used to design the system, including both the bit and the steering unit.The approach taken by BP asset teams in the Gulf of Mexico and Schlumberger contributed to accelerated initial field testing of the system in January 2002. Initial field trials proved successful. In its first application, the system was used to kick off from vertical, achieving a build rate of more than 3°/100 ft. Subsequently, the system has proven beneficial in other projects, and the value of the collaboration has been clearly demonstrated.