Roller Cone Bit Research Articles

Experimental results on the effect of Bit wear on torque response

Percussion bits, polycrystalline diamond compact (PDC) bits and roller cone bits are widely used in well drilling. The evaluation methods for downhole conditions, such as the wear condition of drill bits and the in situ rock strength, are important issues in improving the drilling efficiency and reducing the drilling cost. In this study, drilling tests were conducted in laboratory using the three types of drill bit and various types of rock. On the basis of the results, a close relation between the bit wear condition and bit torque was found for each bit.

Performance, simulation and field application modeling of rollercone bits

Abstract Drilling simulation technology has been used extensively to optimize drilling operations so as to minimize the associated costs and risks. Optimum bit types and designs with corresponding drilling parameters can be recommended utilizing a simulator with rate of penetration (ROP) models. There have been several attempts to develop ROP models that can deliver the most reliable outputs, required for the pre-planning and post analysis applications, using various sets of drilling parameters. However, due to the existing modeling complexities, these attempts have not been successful. In this study, a new ROP model is developed for the rollercone bits, which properly integrates the effect of main drilling parameters as well as cutting structure of the bit. The model is mathematically derived based on the mechanism of single cutter–rock interaction, and calibrated utilizing sets of full scale laboratory data. Also, the bit wear effect for simulating accurate rock strength and ROP values is included in the analysis using a previously published model. One of the most important features of the newly introduced ROP model is that it can be easily inverted to generate accurate rock strength values using offset and/or real-time field data. This unique characteristic of the ROP model makes it a valuable candidate for drilling simulation studies to optimize drilling operations in the most cost effective manner. The verification of the introduced ROP model is performed through series of simulation analysis and comparing the generated rock strength logs to the outputs of a commercially available drilling simulator. The comparison of the results obtained from the simulator and the ROP model as well as field data has been quite encouraging which signifies the application of the developed model in determining the best case scenario for planning and/or drilling of future wells with lowest possible expenditures.

Technology Update: Directional Hybrid Drill Bit Pushes Performance Standards

Technology Update It is inspiring to look back to 1909 when Howard Hughes Sr. and Walter Sharp introduced the roller-cone bit. The invention was the foundation for the discovery of vast amounts of oil in medium-and hard-rock formations, oil that many drillers suspected was there but was nearly impossible to reach with the bits of that day. The roller-cone bit changed the industry, but we may forget why its immediate predecessor, the fish-tail bit, was such a burden on drillers as they strived to probe deeper targets. Often 24 hours would not go by without a twist-off occurring, and rig hands were constantly changing bits and “fishing” parts out of the hole. For drilling anything other than loose formations near the surface, it had proved impractical. In a century’s time, the industry has made tremendous progress. But the limitations of physics continue to challenge the dynamic performance of the bit and bottomhole assembly (BHA) in the demanding downhole environments of today’s wells. Tools come equipped with features such as torque reducers, depth-of-cut controls, and more flexible assemblies, to mention a few. The inherent problem of controlling the reactive torque between the bit and formation, while achieving optimal performance to reduce the number of drilling days, has remained a challenge. The introduction of the hybrid drill bit in 2011, which combined roller cones and fixed cutters, was a catalyst to revisit these basic principles and better understand the benefits and efficacy of smooth drilling. The bit excelled in controlling torque fluctuations and exceeded the durability of fixed-cutter bits and the penetration rates of roller-cone bits. The hybrid bit soon became the standard bit for drilling in hard and interbedded formations, such as those in certain Oklahoma and Canadian plays, because it enabled drillers to reduce the number of curve runs needed. The use of the bit expanded globally, helping to improve drilling results in interbedded applications that historically have met with mixed success when medium-set roller cone or fixed-cutter bits have been used. As results continued to improve, interest in stretching the capability of the technology increased.

Simulation and experimental study of a new structural rubber seal for the roller-cone bit under high temperature

Seal element is an important component of roller-cone bit. In order to improve the sealing performance and service life of roller-cone bit under high temperature, a new seal structure with multi-segment arcs is designed and the structural parameters of this sealing ring are optimized by response surface method and finite element method. Firstly, the hydrogenated nitrile-butadiene rubber is used to improve the seal performance under high temperature, and the uniaxial, planar, and biaxial tensile experiments are carried out to study the constitutive model of this rubber. Then, a three-dimension transient thermo-mechanical coupling model is established. The comparison of sealing performance between the new structural seal and the traditional O-ring seal is implemented under high temperature through the proposed FEM and laboratory experiments. The results show that the new structural seal has lower contact pressure and Mises stress than the standard O-ring seal, and the service life of the former is almost twice of the later one. Additionally, a composite drill bit using the new structural seal is applied to a deep drilling. After servicing a certain time, it shows that the wearing capacity is very small. The results show that the new structure seal ring can adapt to high temperature environment and the optimization method is feasible.

Rotary-Steerable Tool Brings Cost-Effective Performance to High-Volume Drilling

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166717, ’Fully Mechanical 3D Rotary-Steerable Tool Brings RSS Performance to the High-Volume Drilling Market at a Fraction of the Cost of Conventional Rotary- Steerable Tools,’ by K. Hershberger and D. Herrington, NOV, prepared for the 2013 SPE/IADC Middle East Drilling Technology Conference and Exhibition, Dubai, 7-9 October. The paper has not been peer reviewed. A 100% fully mechanical rotary-steerable tool has been developed specifically for the high-volume drilling market, providing full 3D directional control while under full rotation of the drillstring from surface. This durable push-the-bit rotary-steerable system (RSS) has eliminated the costly and sensitive electronics common to most RSS tools and has eliminated a number of vibration-related failure modes, making it suited for applications where shock and vibration are prevalent and for high-temperature applications. Introduction With the introduction of the downhole drilling motor in the 1980s, horizontal drilling became much more feasible. Horizontal wells are now the most common well type drilled in the US. Successful horizontal wells rely on accurate placement of the wellbore inside the desired reservoir. To achieve this, a directional driller is provided with drilling targets on a well plan, which are typically selected on the basis of offset-well information, seismic data, and geological models. In an effort to optimize production while minimizing the number of rig moves and wells drilled, horizontal wells have stepped out farther and farther. As the horizontal displacement of a wellbore increases, torque and drag become major obstacles that must be overcome to enable efficient drilling. RSS tools provide a means to extend the wellbore beyond a steerable motor’s capabilities, but they come at a price that is often not economically feasible for the high-volume market. This forces operators to drill complex wells with either standard steerable motors or to pay for expensive RSS tools that challenge the economic viability of the well. Drilling With Motors. Drilling with steerable motors has been the backbone of directional drilling since the 1980s. However, steering the wellbore with a motor requires slide drilling, which slows down drilling, reduces hole cleaning, and potentially creates other problematic conditions. Rate of penetration (ROP) is reduced when sliding because of friction between the borehole wall and the bottomhole assembly (BHA) as well as hangup of drillstring components. Without drillstring rotation, the drilling mud is not agitated, allowing the cuttings to collect on the low side of the wellbore and potentially pack off the BHA. The steerable motor contains a bent-housing section. When sliding, the bent housing has to be maintained in the desired direction, or tool-face setting. This can become difficult because of the reactive torque produced by the motor itself when the bit is on bottom. The reactive torque turns the drillstring in a counterclockwise direction, working against the directional driller and making it difficult to maintain control. Reactive torque is a function of the formation being drilled, the bit type, and the motor output. It can be mitigated by use of lower-torque- rated motors, light-set polycrystalline- diamond-compact (PDC) bits, or roller-cone drill bits; however, all of these solutions result in lower ROPs. Although PDC-bit designs have advanced and many bits incorporate depth-of-cut-control technology to reduce reactive torque while sliding, the basic inefficiencies still remain. Rotating steerable motors also can result in inefficient drilling. When rotating a motor, there is no directional control, and the BHA will wander on the basis of formation push, formation dip, bit type, stabilizer placement, and drilling parameters, resulting in the wellbore deviating from the target line. Once the wellbore is off plan, a slide has to be performed to reorient the wellbore to the target. In addition, steerable motors can cause hole spiraling and an overgauge hole. This results from rotating a motor with a bend in it, and the larger the bend setting on the motor, the more eccentric the rotational pattern will be. This creates a spiraling hole gauge larger than the actual bit diameter, which can create poor-quality imaging logs because of the uneven wellbore walls.

Wear mechanisms of WC–Co drill bit inserts against alumina counterface under dry friction: Part 1 — WC–Co inserts with homogenous binder phase content

The tribological behavior of commercial roller cone bit inserts was studied by using a rotary tribometer and abrasive alumina counterfaces. Three cemented carbide WC–Co inserts were selected with different cobalt content and WC grain size distribution. During tests, a nominal load was set at 264N, the velocity at 0.5m⋅s−1 and the test time at 1h. The experimental measurements were performed using load, torque, displacement sensors, an acoustic emission sensor and four thermocouples. These measurements showed that the friction coefficient and the mean contact temperature decrease with the cemented carbide's cobalt content. The acoustic emission energy displayed a clear dependence with the mean WC grain size and the WC–Co fracture toughness. It was also found that the insert's wear is proportional to the load but not to the time (or distance). Eventually, a third body approach clearly showed that the inserts and the counterfaces contribute to form an interfacial abrasive paste. The stability, the composition and the cohesion of this paste govern the tribological behavior of the WC–Co/alumina contact.

An Innovative Approach for Pore Pressure Prediction and Drilling Optimization in an Abnormally Subpressured Basin

Summary Thus far, an indirect generalized method to predict pore pressure under subpressured conditions has not been reported in the literature. In this work, an innovative procedure is presented for estimation of pore pressure and optimization of wells drilled in the abnormally subpressured Deep Basin of the Western Canada Sedimentary Basin (WCSB). The procedure starts with detailed evaluation of five wells drilled in a township that covers the study area. Pore pressure was calculated from sonic logs and the modified D exponent by the use of Eaton's method (Eaton 1975), which proved to be the most effective approach for abnormally subpressured conditions over a variety of methods tested (Contreras et al. 2011). The optimization procedure was carried out by use of the apparent-rock-strength log (ARSL), which is an effective indicator of formation drillability and is very sensitive to the pore pressure. Next, optimization of individual sections in each well was carried out to determine the optimum types of bits and operational parameters for the lowest cost of drilling. An artificial-intelligence function was implemented to set up the optimum combination of parameters in such a way that the rate of penetration (ROP) (m/h) was increased after a number of simulation runs while controlling the bit wear. Special attention was focused on tight gas reservoirs for selection of the most suitable parameters that increase the quality of drill cuttings. It was concluded that the roller-cone bit IADC 547 (with at least 0.73 hp in the bit per square inch) provides the best-quality cuttings for the Nikanassin Group. This is of paramount importance for increasing accuracy in the quantitative determination of permeability and porosity from cuttings particularly in those tight gas reservoirs where the amount of cores is very limited. It is concluded that wells in the Deep Basin of the WCSB can be drilled efficiently with seven bit runs while maintaining the cuttings quality, bit-wear level, and well stability at a significantly high average ROP of 13 m/h. Another conclusion is that the normal trend methods from sonic logs are the most effective approach when dealing with an abnormally subpressured basin.

Experimental research on the surface strengthening technology of roller cone bit bearing based on the failure analysis

The roller cone bit is one of the most important rock breaking tools used in the oil–gas drilling industry. Its performance directly influences the drilling quality, efficiency and cost. As the world’s oil–gas resource exploration continuously developed, the drilling speed accelerated, accelerating the failure speed of the bearing. The roller cone bit’s service life was almost directly dependent on that of the bearing. In this paper, a bearing failure analysis, and an experimental research on the surface strengthening technology of the bearing with field applications etc. were carried out. The results showed that the bearing’s main failure modes included fracture, plastic deformation and wear. The main reasons were overload and uneven distribution of the load; elevated temperature due to friction caused property and structure change in material; wear increased the fit clearance between the bearing and the cone, increasing dynamic impact load etc. The bearing surface strengthening technology, employing plasma-arc surfacing DH-60 wear resistance alloy, could prolong the service life of the bearing. Experimental research and field tests showed that the wear and impact resistance of the enhanced bearing increased by 30% with an increased service life of 12% on average.

Drilling Performance Is a Function of Power at the Bit and Drilling Efficiency

This article is a condensed version of paper IADC/SPE 151389, presented at the 2012 International Association of Drilling Contractors (IADC)/SPE Drilling Conference and Exhibition, held in San Diego, California, USA, 6-8 March 2012. Understanding of basic drilling mechanics has been greatly enhanced by the use of today’s sophisticated data acquisition systems for both surface and downhole drilling data. These systems have also helped in identifying major dysfunctions—particularly, harmful downhole vibrations. Various methods are used to optimize drilling practices, including monitoring efficiency indicators, such as mechanical specific energy (MSE), as well as preventing harmful vibrations by adjusting drilling parameters real time. However, focusing on the efficiency of components and the prevention of dysfunctions is only a partial solution. It is also necessary to focus on the magnitude of mechanical power delivered to the bit, as that defines the capacity of the system and directly affects efficiencies, operating practices, and performance. The paper shows how the power at the bit and drilling efficiency vary as a function of drillstring and bottomhole assembly (BHA) configuration, bit selection, and drilling parameter. Field examples illustrate the magnitude of parasitic losses caused by well geometry and the downhole environment. In many cases it is striking to learn how little power is left for the drill bit, which in the end dictates the potential rate of penetration (ROP) and thus the cost per foot and economics of the drilling process. Particular emphasis has been put on new and intuitive ways to visually display the power at the surface and downhole. These make it possible to quantify system limits and identify key dysfunctions in one simple graph that can be used in real time as well as in both pre- or post-well analysis. Better understanding of the entire drilling system and the functional relationship of its parts can be a strong driver for both short- and long-term improvements in system design, drilling practices, and bit selection, ultimately resulting in higher productivity and lower well construction cost. Introduction The oil and gas industry, unlike others, seldom focuses on power requirements for the rotating drilling system and their effect on performance and efficiency. This might be explained in part by the fact that for about 100 years roller cone bits have been the industry’s preferred drilling tool. Roller cone bits require relatively little torque due to their low aggressiveness, and, due to the limited load capacity of the bearings, they act as perfect torque limiters. The rotating power system therefore utilized only a small fraction of the total installed power of a rotary drill rig; lack of power was not considered a limiting factor.

Feasibility study on roller-cone bit wear detection from axial bit vibration

Previous studies reported that the peaks of a power spectrum for roller-cone bit axial vibration move to higher frequencies with the progression of bit-tooth wear. This result implies that monitoring and analyzing roller-cone bit vibration could be a new real-time detection method for downhole bit wear conditions.In this study, the dynamics of roller-cone bit axial vibration were modeled to quantitatively evaluate bit-tooth wear. The model includes the kinematics of roller-cone bit motion and a model for bit-tooth/rock interaction that considers the detailed geometry of a worn tooth. By sequentially solving the equation of motion with increments of cone rotation angles, the time history of axial bit vibration was simulated.The developed model was validated by comparing the power spectral densities for the simulated time histories of axial bit vibration with the experimental results of full-scale drilling tests. Detection of bit-tooth wear, bearing failure, and broken teeth was studied from a feasibility perspective.

An Analysis of Noise Characteristics of Drill Bits

There have been papers that analyze the relationship between bit design and a bit’s vibrational characteristics. These papers typically are based on the analysis of three-axis near-bit down-hole vibration sensors. In this paper, the authors take a simpler approach. Using a standard microphone literally pointed at the bit, they record the noise of the bit/rock interaction while drilling and analyze the resulting noise for these bit vibrational characteristics. The data were gathered at the Colorado School of Mines in Golden, CO. The noise of a PDC core, roller cone, and diamond core bits were recorded under various weight and rotary speeds using a microphone and a vertically mounted uniaxial geophone (used for confirming the data recorded on the microphones). Using a Fast Fourier Transform, the frequency spectra were extracted from the recorded data and analyzed. The data were normalized for rotational speed. The results of the frequency analysis of the roller cone, the PDC, and the natural diamond bits are presented in this paper. The major differences in the three bit frequency characteristics could be detected and furthermore, for drag bits, the frequency characteristics could be related to the bit’s design. The frequency spectra of the roller cone bit can best be described with a general high amplitude level that is relatively evenly distributed over the whole frequency spectrum. The drag bit data showed a strong relationship between the number and arrangement of cutting elements and frequency peaks on a plot of amplitude versus cycles per revolution. Frequency peaks were observed at multiples of the number of cutting elements. In general this relationship was strongly visible on the PDC bit data but not as strongly visible on the diamond bit data. The conclusion is that bit characteristics can be determined using only the noise of a bit. Potential applications of this research include detecting and diagnosing bit problems (e.g., broken teeth and bit balling) in real time using simple microphone based acoustic data.

Mitigating Torsional Stick/Slip Vibrations in Oilwell Drilling Through PDC-Bit Design: Putting Theories to the Test

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 146561, ’Mitigation of Torsional Stick/Slip Vibrations in Oilwell Drilling Through PDC-Bit Design: Putting Theories to the Test,’ by Jayesh R. Jain, SPE, L.W. Ledgerwood III, SPE, Olivier J. Hoffmann, SPE, Thorsten Schwefe, SPE, and Danielle M. Fuselier, SPE, Baker Hughes, prepared for the 2011 SPE Annual Technical Conference and Exhibition, Denver, 30 October-2 November. The paper has not been peer reviewed. Stick/slip vibration of drillstrings is gaining renewed interest as operating parameters for polycrystalline-diamond-compact (PDC) bits move into the stick/slip regime of higher bit weight and lower rotary speed to enhance drilling performance. The main objective of this investigation was to determine the influence of bit design on stick/slip behavior of the drilling system. Pairs of PDC bits were designed and manufactured. Each pair had a bit with a standard design and one that embodied a stick/slip theory. Full-scale tests were performed under controlled conditions with a research drilling rig. Introduction Drilling vibrations can result in failure of bits and bottomhole-assembly (BHA) components. Axial and torsional vibrations are prominent with roller-cone bits. With PDC bits suffering catastrophic failure caused by backward whirl, the focus has been on lateral vibrations. Much attention has been given to combating backward whirl by use of antiwhirl bit designs. Meanwhile, cutter technology progressed dramatically with thermally stable PDC cutters that are more impact and abrasion resistant. Consequently, operating parameters for PDC bits have shifted to higher weight on bit (WOB) and lower rotary speed to enhance drilling performance. This parameter combination also avoids the low-WOB and high-rotary-speed regime (Fig. 1) in which backward whirl can destroy bits after drilling only a few feet. Unfortunately, higher WOB and lower rotary speed instigate torsional instability that matures into stick/slip vibrations. It has been shown in the field that for a surface rotary speed of 60 rev/min, the measured downhole rotary speed reached 400 rev/min during the slip phase. Lateral vibrations during the slip phase correlated well with observed damage. More-severe cases of measured stick/slip have been reported in the literature when the bit experienced reverse rotation at the end of the slip phase before coming to a standstill. A desirable solution for mitigating stick/slip is an inherently stable sys-tem that expands the stable-operating zone through improved bit and BHA/drillstring design to allow drilling at more-efficient operating parameters of high WOB and low rotary speed. The BHA design and the geometry (size and number) of drillpipe and drill collars can have a substantial effect on the stick/slip behavior of the system. Although larger drillpipe can mitigate stick/slip and enable more-efficient drilling, its availability and cost may limit its effectiveness as a solution. Prevailing industry perceptions were reviewed, and five leading theories regarding the root cause of stick/slip were identified.

Hybrid Bits Offer Distinct Advantages in Selected Roller-Cone and PDC-Bit Applications

Summary Early concepts of hybrid drill bits go back to the 1930s, but the development of a viable drilling tool has become feasible only with the recent advances in polycrystalline-diamond-compact (PDC) cutter technology. This paper describes a new generation of hybrid bits that is based on proven PDC-bit designs with rolling cutters on the periphery of the bit. Laboratory and field results will be presented that compare the performance of hybrid bits with that of conventional PDC and roller-cone bits. A hybrid bit can drill shale and other plastically behaving formations two to four times faster than a roller cone bit by being more aggressive and efficient. The penetration rate of a hybrid bit responds linearly to revolutions per minute (RPM) unlike that of roller-cone bits, which exhibit an exponential response with an exponent of less than unity. In other words, the hybrid bit will drill significantly faster than a comparable roller-cone bit in motor applications. Another benefit is the effect of the rolling cutters on the bit dynamics. Compared with conventional PDC bits, torsional oscillations are as much as 50% lower, and stick/slip is reduced at low RPM and whirl at high RPM. This gives the hybrid bit a wider operating window and greatly improves toolface control in directional drilling. The hybrid drill bit is a highly application-specific drill bit aimed at (1) traditional roller-cone applications that are rate-of-penetration (ROP) limited, (2) large-diameter PDC-bit and roller-cone-bit applications that are torque or weight-on-bit (WOB) limited, (3) highly interbedded formations where high torque fluctuations can cause premature failures and limit the mean operating torque, and (4) motor and/or directional applications where a higher ROP and better build rates and toolface control are desired.

Drilling Action of Roller-Cone Bits: Modeling and Experimental Validation

This paper presents a new model of the drilling response of roller-cone bits. First, a set of relations between the weight-on-bit W, the torque-on-bit T, the rate of penetration V, and the angular velocity Ω is established in the spirit of the model developed for polycrystalline diamond compact (PDC) bits. In contrast to models that depend on a precise description of the bit, the drilling response is investigated by lumping the effect of the bit geometry into a few parameters and on averaging the drilling quantities (W,T,V,Ω) over at least one revolution of the bit. Within the framework of the model, quantitative information from drilling data related to rock properties, bit conditions, and drilling efficiency can be extracted. Finally, a series of laboratory tests at atmospheric pressure conducted with an in-house designed drilling rig, together with published experimental data, is used to evaluate the proposed model. The good match between the experimental results and the theoretical predictions are promising in regard to the potential use of this model to investigate the drilling response of roller-cone bits.

Roller cone bit bearing elastomeric seal

Roller cone bit bearing elastomeric seal

Advances in SAGD Drilling in Western Canada Using Innovative Bit Technology

Abstract Western Canada's massive oil sands are being exploited at deeper levels by steam-assisted gravity drainage (SAGD). Carefully geosteered parallel pairs of large diameter horizontal wellbores are drilled for concurrent steam injection into the upper well and oil production from the lower. The bitumen cemented sands of the McMurray Formation have challenged both operational and engineering personnel responsible for drilling these difficult wells. Bits of all designs have required custom features to combat the highly abrasive sands with sloughing and hole cleaning problems, while delivering an optimally steered well path through tight reservoir tolerances. A cross-functional team of operator engineers and drilling personnel, together with field engineers, bit designers and office personnel from the bit manufacturer, joined together to analyze the challenges and fast track fit-for-purpose solutions for all SAGD projects in Alberta. Steel tooth roller cone bits require extensive extra thick layers of hard facing to resist tooth wear. Sand washing through the cones causes high levels of erosion which is hindered by extensive hard facing. The gauge areas of the bits are rotated and/or slid through a cuttings bed of coarse abrasive sand particles, resulting in rounded gauge (RG) and shirttail damage (SD), which again require tungsten carbide and hard facing wear pads and shirttail protection. Elastomer or metal-faced seals have been enhanced to prevent sand encroachment on the bearings during motor drilling. Polycrystalline Diamond Compact (PDC) bits were also faced with significant erosional problems drilling horizontally, which have required special wear pads and updrill features to ensure hole gauge, steer ability and the ability to back ream through the cuttings bed. Depth-of-cut (DOC) features for build rates of 9 degrees per 30 m, ensure steer ability when linked to wear-resistant cutters, especially when placed on the gauge. Spiral gauge features work like an auger to clean sand away from the bit, while customized gauge lengths ensure a match between bit and motor for optimized steerability. Collectively, these PDC and steel tooth bits have become the enabling technology for drilling and completing SAGD wells, especially now that bits can be re-run on future wells, further reducing cost per metre. Introduction Steam-assisted gravity drainage (SAGD) is the most popular enhanced oil recovery technology being adopted by Canadian heavy oil producers. It is very effective in mobilizing bitumen and achieving high recovery from thick, high permeability reservoirs (low gravity <10 °API). An estimated 174 billion barrels of oil in the Athabasca, Cold Lake and Peace River deposits are potentially recoverable with the present technology(1–3). However, with technological improvements, Canada oil sands reserves could be close to 315 billion barrels. The biggest deposit is the Athabasca, which is thicker and shallower; the Cold Lake deposit is thinner and deeper. Surface mining is only feasible for recovering 10% of the oil sands deposits between 70 and 75 m of surface. SAGD is the current method of choice to access resources too deep to mine and will recover the potential 90% of the remaining oil sands deposits with cyclic steam stimulation (CSS).

Development of a Downhole Separator and Intensifier for Coiled Tubing Jetting

Abstract Wells often build scale deposits on the inside of their tubulars that can impede production or interfere with a workover operation. When this scale buildup is over long intervals, coiled tubing (CT) is often the conveyance system used to deliver acid, drilling or jetting technologies to remove the scale. Acidizing through coil can be effective only if the scale is acid soluble and it can be expensive. Drilling with motors can be very effective, but motors are susceptible to performance issues, especially if high nitrogen ratios are required. Jetting the scale is possible, but this technology also faces challenges. Delivering sufficient downhole hydraulic pressure to overcome the scale's threshold pressure is very difficult due to the limited pressure capacity of CT and frictional pressure losses in long CT strings. Further, if nitrogen is required to ensure returns, the gas phase quickly disperses the fluid jet as it exits the jetting tool, and very little power is delivered to the scale face. Recent technical advances in CT jetting technology include a rotary separator to separate the nitrogen from the fluid and a downhole pressure intensifier to take the separated water and increase the hydraulic pressure delivered to the jetting tool. The paper first discusses measurements of the threshold pressure required for removal of oilfield scales. The development of a gas separator and downhole intensifier are discussed next, followed by the results of testing these tools. Introduction Mineral scale deposits inside of production tubing can reduce production or interfere with workover operations. Coiled tubing is used to remove this scale using motors or jetting tools. Jet milling of scale is an attractive option because fluid jets will not damage tubulars or other downhole equipment. Jet milling capabilities are limited by the threshold pressure required to initiate milling and by fluid jet dissipation. The jet pressure delivered to the scale surface determines the ability of the jet to cut a given scale. The jet power then determines the rate at which the scale can be removed. The pressure that can be delivered to a jetting tool through CT is limited by fatigue limits of the coil and the pressure capabilities of available pumps. The jet power, which determines milling rates, is further limited by friction pressure loss in the CT. These losses become more significant in deep wells. One approach to cutting scale at the pressure available using coil is to add abrasives(1), however, this approach adds cost and complexity to the operation. Another approach is to boost the pressure of the jets with a downhole intensifier. In the 1990s, the FlowDril Corporation manufactured a large-scale downhole intensifier pump to drill 77/8 in to 83/4 in holes with jet assisted roller cone bits(2). The unit was designed to work with a conventional rotary drill string and run on drilling mud. The intensifier ratio was 14:1, delivering 84 l/min at 200 MPa from mud supplied at 1,260 l/min and 23 MPa. A similar approach would allow CT pressure to be boosted to a level capable of milling hard scale. The effectiveness of fluid jetting tools is further limited by dissipation of the jet in the high pressure well environment. Submerged, non-cavitating fluid jets are subject to rapid dissipation due to turbulent mixing of the fluid. The maximum length of the high pressure jet core produced by an ideal jet under these conditions is under seven nozzle diameters(3). Intense turbulence persists to a range of around 20 nozzle diameters. By contrast, water jets in air can be effective at ranges of over 1,000 nozzle diameters. Jet dissipation effects

Optimization of Deep-Drilling Performance (November 2008)

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112731, "Optimization of Deep-Drilling Performance With Im provements in Drill-Bit and Drilling-Fluid De sign," by Alan D. Black, SPE, TerraTek; Ronald G. Bland, SPE, Baker Hughes; David A. Curry, SPE, and L.W. Ledgerwood III, SPE, Hughes Christensen; Homer A. Robertson, SPE, and Arnis Judzis, SPE, TerraTek; Umesh Prasad, SPE, Hughes Christensen; and Timothy Grant, US Department of Energy, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed. Full-scale laboratory testing was conducted under a joint-industry and US Department of Energy program. Seven bits and 12 drilling fluids were tested in three different rocks at a variety of drilling conditions. Phase-1 results were reported in a previous paper. The goal of Phase-2 testing was to evaluate bit features and mud additives that might enhance rate of penetration (ROP) under high-pressure conditions. The test protocols developed in Phase 1 to simulate Arbuckle-play and Tuscaloosa-trend drilling at pressures greater than 10,000 psi were used to evaluate these features. Introduction An important factor in future gas-reserves recovery is the cost to drill a well. This cost is dominated by the ROP, which becomes increasingly important with increasing depth. The object of this study was to improve the economics of deep exploration and development. In September 2002, the US Department of Energy's National Energy Technology Laboratory awarded funding to the Deep Trek program to develop technologies that make it feasible economically to produce deep oil and gas reserves and increase the ROPs in deep drilling. The researcher's proposal was to test drill bits and advanced fluids under high-pressure conditions. Phase 1 of the proposal was to establish a baseline of performance and provide data upon which to make design improvements. Phase 2 was to establish improvements in design. Phase-2 tests were an extension of Phase 1 and attempted to improve significantly the ROP and mechanical specific energy with modified drill bits and enhanced drilling fluids. There were 21 tests run during Phase 2. For consistency, the type of rock used in Phase 2 was the same as in Phase 1. The drill bits selected for Phase-2 testing included a roller-cone bit to re-establish a baseline, three polycrystalline-diamond-compact (PDC) bits, and a diamond-impregnated bit. One of the PDC bits, a seven-blade bit, was identical to the one used in Phase 1; all others were modified. The drilling fluids used in Phase 2 included an 11-lbm/gal water-based mud for four tests, a 16-lbm/gal cesium formate brine for five tests, and 16-lbm/gal oil-based fluids for the others. Methods and Materials Test Facilities. All drilling experiments were performed at a drilling-and-completions laboratory under simulated down-hole conditions in a wellbore simulator that applied overburden and confining stresses to the rock. The drillstring loading and rotation were provided by the full-scale laboratory drill rig. The drilling and rock-loading parameters used during Phase-2 testing are provided in Table 1 in the full-length paper.

DESIGN AND TRIAL OF INTELLIGENT SLIDING BEARING SYSTEM

A patented intelligent sliding bearing system of roller cone bit is invented to monitor radial wear and to stop the running of bearing automatically when the wear reaches the predetermined limit so as to prevent the wear-induced cone loss by early warning. In this paper, the basic operating mechanism of new bearing is stated and discussed. A series of tests are conducted to investigate the mechanical features and the reliability of the new bearing system. The performance of the system is proven to be adequate by the test results.

Technology Update: Aggressive Drilling Parameters, PDC-Bit Innovations Cut Run Times in Abrasive Oklahoma Granite Wash

Technology Update A combination of new drill-bit technology and new operational practices has enabled operator Marathon Oil to use polycrystalline-diamond-compact (PDC) drill bits, and reduce drilling time by 24%, on wells in a part of the Anadarko basin where abrasive conditions at shallow depths previously have required the use of roller-cone bits. Much of the Anadarko basin is dominated by PDC-bit drilling. However, in the southwest Canute area of Washita County, Oklahoma, the highly abrasive Granite Wash formation is encountered at depths of 5,000−6,000 ft, compared with its more typical 11,000-ft point of emergence in most of the Anadarko basin. In the deep Anadarko, of which the southwest Canute area is a part, exploratory wells are drilled either to approximately 13,500 ft to produce the Atoka Wash and Red Fork sands or to approximately 17,500 ft to pro-duce the Morrow sands. The surface string in either type of well is set in or below the Brown dolomite formation (≈3,500−4,500 ft). The lithology below the surface casing consists of a long sequence of sand/shale with interbedded granite wash. This gives way to more-consolidated sand intervals and granite-wash formations, a transition often marked by the showing of the Tonkawa and Prue sands at approximately 9,000 and 11,000 ft, respectively. In drilling Atoka Wash/Red Fork wells in the southwest Canute area, the operator set a goal of reaching the Prue sands by use of two PDC bits, eliminating the use of three to eight roller-cone bits that previously would have been required. Aggressive drilling parameters typically reserved for roller-cone bits, employing high weight on bit (WOB) and low revolutions per minute (rev/min), were combined with innovative PDC-bit frames, designed to increase the load/cutter ratio, and with new cutter technology to enable the operator to achieve the goal. A depth of 10,700 ft was reached with two PDC bits, and cost savings of approximately USD 200,000 were realized. Well Plan For the operator, a typical Atoka Wash/Red Fork well involves a 12.25-in. section drilled into the Brown dolomite and a 7.875-in. section then drilled to total depth (TD). For the 12.25-in. section, casing points differ according to TD. Typically, 9.625-in. casing is set at ≈3,500 ft. The 12.25-in. interval is easily drilled with a single PDC bit. A 7.875-in. hole is drilled below the 9.625-in. casing and extends to TD. Historically, this interval has been drilled with multiple IADC 5–2–7 or 5–3–7 roller-cone bits. More recently, the use of PDC bits at drillout has become common. However, the ability to make the interval to the Prue sands has proved very elusive.