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Collaborating Authors
three-cone bit
Unlocking Two-Cone-Bit Potential: Technology, People, and Planning Make It Possible and the Lessons Learned
Centala, Prabhakaran K. (Smith International, Inc.) | Burley, Mark McCann (Smith Bits) | Burnett, Timm (Smith Bits) | Ford, Robert J. (Smith Tool) | Sinesi, John Patrick (Smith International, Inc.)
Abstract Many, perhaps most, who drill oil wells, know something about two-cone bits. These bits, for example, received the first cone bit patent nearly 100 years ago, yet, they have been popular in certain drilling environments within the last 20 years or less. Designers have always recognized great advantages in two-cone bits, but concerns with vibration, directional responsiveness, drilling straight holes, mechanical reliability, and hole cleaning lead to their displacement by three-cone bits. Unfortunately, two-cone bits have not, fully lived up to their potential. People have changed, and this has triggered changes in research philosophy. This together with technology advances in complex mathematical modeling, simulations and drilling processes has encouraged bit manufacturers to re-visit some older designs and learn to harness the potential inherent in those designs without their ill effects. This evolution has encouraged numerous step changes in drill bit technology. Could new people, new engineering and new manufacturing tools and tolerances, and a new sophistication at the rig finally unlock the potential of two-cone bits? To date, numerous runs with a modern two-cone bit design have taken place in Texas, Louisiana and internationally. Some of these runs are reported in this paper, detailing lessons learned and successes from the new two-cone bit that have been shared by the operators. Offset bits were one basis for performance evaluation and offset comparisons are also reported. In a direct offset well, a single modern two-cone bit drilled an interval, for which four offset bits were required (estimated savings: $342,000). Operator evaluations, performance outlines, information on reliability, bit vibration, directional responsiveness, deviation free performance, and hydraulic aspects of bottom hole cleaning, free of bit-balling, in several types of applications are included. The process and technology involved in designing the two-cone bits are identified in this paper. The lessons learned in planning between highly experienced drilling operators and bit company personnel toward overcoming paradigms and apprehensions in developing test plans for the improved technology are also discussed. Introduction Engineers pride themselves in being part of a forward looking profession and most probably feel they are leaders in the charge into the future. This paper is about a charge that involved a look into the rear view mirror as its starting point toward finding the future. Most who will read this paper are probably acquainted with two-cone drill bits. They were the first of the roller cone bits invented in the early 1900s. During that time, drilling methods were fairly simple and the two cone bits performed adequately. Since then many design derivatives of two cone bits have been produced, and for lack of other invention, vintage two-cone bits even grew in popularity until about 1980 because they had a number of favorable performance characteristics. Figure 1 shows a two-cone bit from this period. During the mid 1930s, a roller cone bit using three cones oriented 120 degrees apart was invented. Two-cone bits and three-cone bits subsequently co-existed for several decades. In both cases, there were numerous design derivatives and both types adequately served the needs of drillers of the time. As drilling became more complex, however, the invention of MWD and other down-hole tools clarified subtle performance differences between two and three-cone bits. Two-cone bits had better ROP performance and great reliability in drilling straight hole but at the price of axial and lateral vibration. After about 1970, drillers realized that two-cone bit vibration signatures were significantly larger than those for three-cone bits in similar applications. This vibration had the potential of significantly interfering with productivity and even damage to rig and equipment. Bit companies had, at the same time, invested resources to significantly improve three-cone, but not two-cone, bit performance. The focus of this investment together with the vibration issues slowed the use of two cone bits. Today two-cone bits are virtually extinct.
- North America > United States > Texas (0.49)
- North America > United States > Louisiana (0.35)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Summary The Japanese government-funded geothermal exploration Well WD-1A reached 3729 m at total depth, where the bottomhole static temperature is more than 500ยฐC. A trajectory correction run was carried out with a positive displacement motor and measurement while drilling tool where the formation temperature is greater than 350ยฐC. The combination of large surface mud containers and sufficient mud cooling equipment were used to cool return mud from the well. A top drive system was used to cool the bottomhole assembly while running each drillpipe stand in the hole. A borehole dynamic temperature experiment and drill bit tests were carried out in this well. Introduction The New Energy & Industrial Technology Development Organization (NEDO) exploration Well WD-1A was drilled to delineate deep-seated geothermal resources in the Kakkonda geothermal area, located approximately 500 km north of Tokyo (Fig. 1). The well was planned to be drilled to a 4000 m depth using rotary methods. Eleven trajectory correction runs were needed to penetrate to the assigned target area. The well reached 3729 m at total depth (TD) in July 1995, but did not encounter steam production zones. The formation temperature, measured by thermal indication materials, was about 500ยฐC at 159 hours recovery time after pumping ceased. At 2600 m depth, where the formation temperature is greater than 350ยฐC, the last trajectory correction run was carried out successfully with a positive displacement motor (PDM) and a measurement while drilling (MWD) tool. A mud cooling system was used to cool returned mud. A top drive system (TDS) was used to cool the bottomhole assembly (BHA) while running each stand of drillpipe into the hole for this operation. At 2650 m depth, a 2 1/2-day borehole dynamic temperature experiment was conducted. This verified the borehole temperature data, both with and without pumping mud, and the cooling effect by continuous pumping with the TDS while running the BHA. The O-ring seal and diaphragm conditions of three-cone bits were inspected after use. From this study, it was verified that a few bit seals had survived even where the formation temperature is over 400ยฐC. Geology and Formation Temperatures The Kakkonda Geothermal Field is one of the highest temperature geothermal areas in the world. More than 70 geothermal wells, ranging in depth from 1000 to 3000 m, have been drilled. Geothermal generation has been conducted in this area since 1978. The overlaying tertiary formation, which has a thickness of about 2200 to 2500 m, consists mainly of dacitic pyroclastic rocks, tuffaceous sandstone, and black shale. The pretertiary formation is highly metamorphosed and is a few hundred meters thick, as confirmed by drilling. The neo-granitic pluton is thought to be one of the heat-source rocks in this area that has intruded into tertiary and pretertiary formations (Fig. 1). Most of the rocks are very abrasive. Also, the geological structure is characterized as a fold structure. Therefore, bit walk is often encountered and well trajectory control is very difficult in this area. In general, formation temperatures in this area reach 200ยฐC at a few hundred meter depths, 300ยฐC at 1500 m depths, and over 350ยฐC at around 2000 m depths. Purpose for Drilling WD-1 Well The purpose of this project is to delineate deep-seated geothermal resources by drilling a 4000 m well. It includes a comprehensive supporting research. Several research studies have been involved in this project. As for drilling technologies, an evaluation of existing drilling technologies at the high-temperature downhole condition has been planned. This plan includes a PDM, MWD, drill bits, a drill mud cooling system, and multiple-stage cementing tools. Also, mud coolers and a TDS, which enables continuous pumping of mud and cooling of the BHA while running drillpipe stands in the hole, were planned for evaluation. In addition, casing corrosion tests included in production tests at 3000 and 4000 m and casing damage evaluations are planned. Drilling History WD-1 was planned with a target depth of 4000 m in the neo-granite where formation temperature was expected to be 400ยฐC. The drilling strategy was devised to drill with five holes of different diameter to safely reach the planned depth. Many lost circulation zones were expected in the shallower depths where previously drilled shallow wells are producing geothermal fluids at depths ranging from 1000 to 1500 m. A 3000 m class rig was employed from spud-in until the setting and cementing of the 13 3/8-in. casing (Fig. 2). All drilling operations were suspended for six months, until the next fiscal year. The rig was then changed to a 5000 m class rig and operations began again in January 1995. The expected productive reservoir was not encountered at about 3000 m, therefore, the well was deepened to 3729 m 6 July 1995 with 8 1/2-in. bits. At 2860 m depth, the well entered the quaternary granite formation, and a 900 m section of the same rock was drilled. Below 3451 m, the drilling mud in the hole deteriorated because of a temperature increase while round trips to change bits were made. CO2 gas was ejected when the bottom part of the mud was returned to the surface. Lime was added to the drilling mud to control the CO2 gas. After a new bit was run to 3642 m and mud was circulated at that depth, high H2S gas-content mud returned to the surface. The H2S gas was thought to be derived from the formation and continuously flowing into the well, even if at a very low rate. A very thin mud system (mud density was less than 1.1 g/cm) had been used for drilling to prevent mud gelation. It was necessary to raise mud density to control the H2S gas ejection, but the borehole temperature was thought to be too high to continue drilling with higher density mud. The drilling operation terminated at 3729 m because of safety concerns. A closed injection system, which was able to dump H2S gas content fluids into an injection well without venting H2S gas to the atmosphere, was installed to accomplish borehole surveys. Temperature surveys and many wireline logs were performed by various methods. Also, chemistry samples were taken from the TD by the reverse circulation method. The well was plugged again in August 1995 at 2400 m. This was done in preparation for a planned sidetracking operation and re-drill toward a steam production zone at 3000 m depth, to start in October 1996.
- Geology > Rock Type > Igneous Rock > Granite (0.74)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.74)
- Energy > Renewable > Geothermal > Geothermal Energy Engineering > Geothermal Drilling (0.41)
Abstract The Japanese government funded geothermal exploration well WD-1A reached 3,729 m at TD, where the BHST is more than 500 C. A trajectory correction run was carried out with a PDM and MWD tool where the formation temperature is greater than 350 C. A TDS was used to cool the BHA while running each drill pipe stand in the hole. A borehole dynamic temperature experiment and drill bit tests were carried out in this well. Introduction The NEDO exploration well WD-1A was drilled to delineate deep-seated geothermal resources in the Kakkonda geothermal area, located approximately 500 km north of Tokyo (Fig. 1, Kato et al., 1994). The well was planned to be drilled to a 4,000 m depth using rotary methods. Eleven trajectory correction runs were needed to penetrate to the assigned target area. The well reached 3,729 m at total depth (TD) in July, 1995, but did not encounter steam production zones. But the formation temperature, measured by thermal indication materials, was about 500 C at 159 hours recovery time after pumping ceased. At 2,600 m depth, where the formation temperature is greater than 350 C, the last trajectory correction run was successfully carried out with a positive displacement motor (PDM) and a measurement while drilling (MWD) tool. A mud cooling system was used to cool returned mud. And a top drive system (TDS) was used to cool the bottom hole assembly (BHA) while running each stand of drill pipe into the hole for this operation. At 2,650 m depth, a two-and-one-half day borehole dynamic temperature experiment was conducted. This verified the borehole temperature data, both with and without pumping mud, and the cooling effect by continuous pumping with TDS while running the BHA. The O-ring seal and diaphragm conditions of three-cone bits were inspected after use. From this study, it was verified that a few bit seals had survived even where the formation temperature is over 400 C. Geology and Formation Temperatures The Kakkonda Geothermal Field is one of the highest temperature geothermal areas in the world. More than 70 geothermal wells, ranging in depth from 1,000 to 3,000 m, have been drilled and geothermal generation has been conducted since 1978 in this area. The over-laying tertiary formation, which has a thickness of about 2,200 to 2,500 m, consists mainly of dacitic pyroclastic rocks, tuffaceous sandstone and black shale. The pre-tertiary formation is highly metamorphosed and is of a few hundred meters thickness, confirmed thus far by drilling. The neogranitic pluton is thought to be one of the heat-source rocks in this area, that has intruded into tertiary and pre-tertiary formations (Fig. 1). Most of the rocks are very abrasive. Also the geological structure is characterized as a fold structure. Therefore, bit walk is often encountered and well trajectory control is very difficult in this area (Saito, 1993a). In general, formation temperatures in this area reach 200 C at a few hundred meter depths, 300 C at 1,500 m depths and over 350 C at around 2,000 m depths. Purpose for Drilling WD-1 Well The purpose of this project is to delineate deep-seated geothermal resources by drilling a 4,000 m well and includes a comprehensive supporting research program (Sasada et al., 1993, Muraoka et, al., 1995, Yasukawa et al., 1995, Sawaki et al., 1995, Uchida et al., 1996). Several research studies have been involved in this project. P. 445^
- Europe > Norway > Norwegian Sea (0.24)
- Asia > Japan > Kantล > Tokyo Metropolis Prefecture > Tokyo (0.24)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource (0.75)
- Energy > Renewable > Geothermal > Geothermal Energy Engineering > Geothermal Drilling (0.41)
SPE Members Abstract This paper presents field data that indicates the gauge on Polycrystalline Diamond Compact (PDC) bits may act as a near bit Polycrystalline Diamond Compact (PDC) bits may act as a near bit stabilizer. When used with a pendulum bottomhole assembly (BHA) having stabilizers placed at 60 and 90 feet above the bit, the BHA can have the tendencies of a building assembly. Field observations were verified by computer simulation using a two-dimensional static BHA model providing a predictive method for BHA analysis when using PDC bits. The results of a sensitivity analysis using the computer model are presented and will provide guidelines for stabilizer placement when using PDC bits in straight hole drilling applications. Included in the analysis will be the effects of PDC bit gauge length, wellbore inclination, drill collar stiffness, and hole diameter on the build and drop tendencies of pendulum BHA's when used with PDC bits as a function of weight on bit (WOB). Introduction When planning wells deeper than 10,000 feet in California's Southern San Joaquin Valley (Figure 1), it is necessary to take into account the natural drift tendencies of the wellbore caused by local geology. Bottomhole targets are specified as a result of reservoir and legal restrictions. These targets range from 50 foot radius circles to 300 foot by 600 foot rectangles. Since the magnitude of wellbore drift can be as much as 800 feet in horizontal displacement (Figure 2), proper selection of the surface location is critical if expensive directional corrections and cost overruns are to be avoided. After the bottomhole target has been specified, surface locations of new wells are picked based on offset well data. Most wells are drilled with pendulum BHA's having two full gauge stabilizer, the spacing of the stabilizers being a function of the hole size (Figure 3). Typically three-cone bits are used to drill most of the well, however PDC bits have been effectively used in this area to reduce well costs by an average of $40.60 per foot through the interval drilled with the PDC bit (Reference 1). A 14,300 foot well recently drilled in one of ARCO's Southern San Joaquin Valley fields, was planned with the surface location being 750 feet from the bottomhole target. Stuck pipe in the intermediate hole section resulted in a sidetrack of the original wellbore (Figure 4). PDC bits were used in both the original and sidetrack holes but at different depth intervals. In the intervals drilled with PDC bits, three-cone bits were used to drill the same interval adjacent to the PDC bit run in either the original or side-track hole. However, different wellbore inclination changes were observed with both of the PDC bits building angle and the three cone bits dropping angle even though the pendulum BHA's were the same in all bit runs. In one PDC bit run, the wellbore inclination increased to the point that expensive directional corrections had to be made in an effort to hit the bottomhole target. This paper wig present the results of a study performed to determine the cause of the different build and drop tendencies observed when using PDC and three-cone bits with the same BHA while drilling straight holes (i.e., wellbore inclination less than 6 degrees) in the same geological setting. Using a static, two-dimensional BHA computer model that predicted field data with good accuracy, a sensitivity analysis was performed. The results are presented to provide guidelines for stabilizer performed. The results are presented to provide guidelines for stabilizer placement when using PDC bits in straight hole g applications. Included in placement when using PDC bits in straight hole g applications. Included in the analysis are the effects of PDC bit gauge length, wellbore inclination, drill collar stiffness, and hole diameter on the build and drop tendencies of several pendulum BHA's as a function of WOB. Literature Review The differences in directional tendencies between PDC and three cone bits have been widely discussed. Balkenbush and Onisko (Reference 2) reported using PDC bits in the Kuparuk River field of Alaska solely for the purpose of arresting right-hand walk tendencies that were experienced with three-cone bits. P. 67
- North America > United States > California (0.75)
- North America > United States > Alaska > North Slope Borough (0.54)
- Europe > United Kingdom > Irish Sea > East Irish Sea > Liverpool Bay (0.24)
- Well Drilling > Drilling Operations (1.00)
- Well Drilling > Drill Bits > Bit design (1.00)
Summary In this paper, empirical formulations have been developed to calculate, from full-scale experimental results, the hydraulic horsepower and impact force at the rock surface. Two new hydraulic programs were established to optimize bit hydraulics on the rock surface of the hole bottom. The new theory and methods, when tested in oilfield drilling practice, have increased rate of penetration (ROP) and reduced drilling cost. Introduction This paper deals with our experiments on the measurement of the hydraulic energy imposed on the rock surface of the hole bottom (RSHB). (RSHB is defined as the instantaneous rock surface ofthe hole bottom drilled by the rock bit during penetration.) We have established two new theories about the hydraulic programs in design. These theories concern the maximum hydraulic horsepower and impact force on the RSHB. The "black box" theory, which can be used effectively to solve modern engineering problems, has now been introduced in the research of the flow field of the jet bit above the hole bottom. A unique full-scale experiment (i.e., the experiment measuring the. hydraulic energy on the RSHB) has been done to measure directly the hydraulic horsepower and the impact force of the jets beneath a three-cone bit striking on the RSHB. Empirical formulas have been developed for calculating the hydraulic horsepower and the impact force on the RSHB. Two new hydraulic programs have been provided that consider the maximum hydraulic horsepower and impact force on the RSHB as the design criteria for the optimized hydraulic programs. Under the experimental conditions in this paper, critical values have been obtained, such as the ratio of the horsepower distribution, RN, for the maximum hydraulic energy on the RSHB and the range of the hydraulic energy decline factor at the full standoff distance (135 mm [5.3 in.] from the nozzle exit to the RSHB). Under the same condition, the optimum flow rate for the maximum hydraulic energy on the RSHB is about 7.5% more than that for the maximum hydraulic energy on the bit nozzle. Theory and drilling practice have proved that a proper increase in the flow rate and pump horsepower is necessary. Since Kendall and Goins developed the jet-bit programs for maximum hydraulic horsepower, impact force, or jet velocity in 1960, experimental studies of the fluid flow in the bottomhole flow field (BHFF), the characteristics of the symmetric BHFF, and the effective cuttings removal have been investigated by several research departments and specialists. Until now, however, no one has directly measured the hydraulic energy (hydraulic horsepower and impact force) of a three-cone jet bit while the jets strike on the RSHB. Consequently, a lot of analysis and calculation of bit hydraulics have to be considered only on the exit of bit nozzles. The function of the jet striking on the formation, however, should be reflected by the hydraulic energy imposed on the RSHB. Generally, the standoff distance (from the nozzle exit to the RSHB) for the present three-cone bit is longer than 100 mm [3.9 in.]. This jet distance is long enough to affect the hydraulic parameters on the RSHB greatly. Therefore, we must consider the following questions.How much of the hydraulic energy of the jet will be lost from the nozzle exit of the three-cone bit to the RSHB? Will the designed optimized hydraulic parameters (e.g., qopt and deqopt) based on the hydraulic programs for the maximum hydraulic horsepower on the bit nozzle be the true optimized values? If the hydraulic parameters can be optimized on the basis of maximum hydraulic horsepower on the RSHB, what are the optimized hydraulic parameters and what are the differences between these two sets of parameters? To answer these questions, we have done the following research.Under the guidance of the black box theory, a full-scale experiment has been carried out under the conditions of the actual bottomhole jet flow field made from a 21.6-cm [8 1/2-in.] three-cone bit and a simulated borehole. By using a special measuring unit, we have obtained directly data on the hydraulic. horsepower and the impact force of the jet imposed on the RSHB. On the basis of experimental data, mathematical models (or empirical formulas) of the hydraulic horsepower and the impact force on the RSHB have been developed by means of the theory of system identification. From these empirical formulas, the nonlinear programming mathematical models of the maximum hydraulic horsepower, Nrsmax, and the maximum impact force on the RSHB, Frsmax, have been developed and solved. Thus, two unique optimized hydraulic programs for the maximum Nrs and maximum Frs have been developed. Experimental Determination of the Hydraulic Energy on the RSHB The bottomhole jet flow field beneath a rotating three-cone bit is a very complex, adhesive-submerged, none free multijet flow (as shown in Fig. 1). Because of its complexity, the flow field cannot be solved with the theories of fluid mechanics and turbulent jet flow. It can be studied only if it is considered as a "fuzzy system." The RSHB is not only the working surface of the bit, but also the acting surface of the jet. Only the hydraulic energy imposed on the RSHB can overcome the "hold-down effect," remove cuttings, and break rock hydraulically. Therefore, rather than focusing on the intermediate process of jet flow, our attention will be on the hydraulic horsepower of the jet striking on the RSHB, as well as the transmission and decline of the hydraulic energy between the bit nozzle and the RSHB.
- Research Report > New Finding (0.34)
- Research Report > Experimental Study (0.34)