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Recent advances in downhole measurements allow to accurately measure drilling forces at the drill bit, and estimate the evolution of the rock strength along the well profile. This paper presents an experimental methodology that allows to measure drilling forces, at the cutter scale, with a sensor embedded behind a polycrystalline diamond compact (PDC) cutter, and to infer the 3D spatial distribution of the rock strength. Two experimental campaigns have been performed on a laboratory-scaled drilling rig and complemented with standard mechanical tests to validate rock strength estimations. In the first campaign, homogeneous synthetic rock samples have been prepared. The average rock strength of each sample derived from cutter force measurements and a cutter–rock interaction model, compares well with the one derived from mechanical tests. In the second campaign, heterogeneous synthetic rock samples have been prepared. They are made of two layers of gypsum mixtures of different strengths, separated by a slanted bedding plane. Based on the instrumented cutter measurements, the 3D spatial distribution of the rock strength has been reconstructed along its path. Rock strength estimations are consistent with results obtained from mechanical tests, and the reconstructed geometry of the bedding plane matches well its actual geometry. The experimental methodology and technology presented in this paper lay the foundations for estimating rock properties in 3D, at the drilling stage. It has the potential to provide geoscientists information about complex lithological structures at an early stage, reducing the need for expensive and time-consuming coring and logging operations.
Recent advances in downhole measurements allow to accurately measure drilling forces at the drill bit, and estimate the evolution of the rock strength along the well profile. This paper presents an experimental methodology that allows to measure drilling forces, at the cutter scale, with a sensor embedded behind a polycrystalline diamond compact (PDC) cutter, and to infer the 3D spatial distribution of the rock strength. Two experimental campaigns have been performed on a laboratory-scaled drilling rig and complemented with standard mechanical tests to validate rock strength estimations. In the first campaign, homogeneous synthetic rock samples have been prepared. The average rock strength of each sample derived from cutter force measurements and a cutter–rock interaction model, compares well with the one derived from mechanical tests. In the second campaign, heterogeneous synthetic rock samples have been prepared. They are made of two layers of gypsum mixtures of different strengths, separated by a slanted bedding plane. Based on the instrumented cutter measurements, the 3D spatial distribution of the rock strength has been reconstructed along its path. Rock strength estimations are consistent with results obtained from mechanical tests, and the reconstructed geometry of the bedding plane matches well its actual geometry. The experimental methodology and technology presented in this paper lay the foundations for estimating rock properties in 3D, at the drilling stage. It has the potential to provide geoscientists information about complex lithological structures at an early stage, reducing the need for expensive and time-consuming coring and logging operations.
Drill bits are iteratively developed for specific applications to meet performance objectives such as aggressiveness, durability, stability, steerability, etc. The transition from one iteration to the next occurs when dull bits are examined, run data is analyzed and the inferences are implemented as revisions to the bit design and/or the operating parameters. Experience has shown that the efficiency of the process depends strongly upon the appropriateness and significance of the data collected. If, for example, a dominant cutter failure mechanism is incorrectly characterized as abrasive wear and is, in fact, impact wear, then the proposed solution and the development time will both be significantly affected. One method for improving the significance of the data collected is to implement a special-purpose data-acquisition system within the bit. Such a device has at least three significant advantages over available sub-based data acquisition systems:its bit-based sensors will more accurately detect bit-based events,it can be economically deployed over many bits andit is relatively transparent to the user. The paper describes an effort to develop, validate, and utilize a bit-based module designed to monitor accelerometer and magnetometer sensors and to record selected data. The authors also describe the effort to infer dynamic dysfunction(s) from the data in the fast-growing hard rock PDC bit application and to mitigate them via modifications to drilling parameters and bit designs. Background Rotary rock bits are developed iteratively. Typically, the process begins when a performance deficiency is observed in the field. During an investigation phase, dull bits and associated run data are examined under the performance objective. Performance objectives are usually tailored for particular applications and stated in terms such as aggressiveness, durability, stability, steerability, etc. During a proposal phase, a hypothesis is formed in an attempt to explain the deficiency in terms of bit design and / or operating parameters and a solution is proposed. During the test phase, the proposed solution is incorporated into either test bits or into operating practices and then evaluated. If the proposed solution is justified, the process ends and insight is gained; otherwise and more commonly, the next iteration is started. Experience has shown that the efficiency of the development process is strongly dependent on the appropriateness and significance of the data collected during the investigation phase. If, for example, a dominant cutter failure mechanism is incorrectly characterized as abrasive wear and is, in fact, impact wear, then the proposed solution and the development time will both be significantly affected. Representative nearbit dynamic data are needed to directly support drill bit and drilling parameter development programs. Indirectly, the data are also needed to validate laboratory simulation tests and software. There is a long history of researchers trying to understand down-hole dynamic dysfunctions. In the 1960s, Esso Research reported accelerations measured down-hole. Since then, the development of data-acquisition tools and interpretation techniques has continued unabated1–19. Now, dynamic dysfunction data is collected down-hole using measurement-while drilling (MWD) systems and transmitted to the rig floor in near real time2–6. In fact, recently, some of the tools have become available as stand-alone subs to address those applications in which a complete MWD system could not be justified7–9. Even so, the tools have at least three limitations when characterizing bit behavior is the objective:the cost can be prohibitive which can preclude the use of a tool even when dynamic dysfunction is suspected,the data-acquisition tool may be removed from the bit by as much as 10 - 100 feet and therefore, the data collected may not necessarily represent the conditions at the bit andthe subbased tools alter the bottom-hole assembly.
The response of the drilling system to axial and torsional vibration inputs has a significant impact on drilling performance. Usually the goal is to minimize dynamic response to limit the effects of potentially damaging phenomena in the low frequency range (e.g. bit bounce and torsional stick-slip) and high frequency range (e.g. axial chatter and torsional resonance). However, in some cases the goal is to maximize dynamic response, for example when introducing oscillation tools to overcome wellbore friction while directional drilling or to free stuck pipe. Whether the intention is to maximize or minimize, a suitable mathematical model is required. The model presented in this study uses the transfer matrix approach to predict how a harmonic vibration input propagates through the remainder of the drillstring. Novel features of the model include the ability to place the excitation source anywhere in the drillstring and to estimate damping effects due to Coulomb friction in directional wells.Model inputs include drillstring and bottom hole assembly composition, well survey data, surface equipment and drilling parameters. Drillstring components are modeled as spring or beam elements and the surface equipment is modeled as a mass-spring system. Bit-formation interaction is modeled as a spring, the stiffness of which can be adjusted to provide a boundary condition ranging from fixed to free. Damping due to material hysteresis and interaction with the drilling fluid is modeled using a velocitydependent term. Coulomb friction is modeled as an equivalent viscous damping coefficient. A harmonic excitation is specified at a given location in the drillstring and the responses at other locations in the system are computed via transfer matrices. This approach allows rapid characterization of the axial and torsional response of the drillstring in the frequency domain and may be applied to analyses of induced oscillation, such as from axial oscillation tools (AOTs), or unintended vibration, such as bit bounce.Case studies show that predicted frequency responses in the axial and torsional domain compare favorably with high sampling rate downhole and surface measurements, respectively. Additional case studies demonstrate how the model has been successfully applied to diagnose and resolve severe axial vibrations while drilling with roller cone bits. Finally, model predictions are compared with downhole acceleration measurements to evaluate effectiveness of axial oscillation tools while drilling with steerable motor systems. Recommended practices for device placement and drillstring configuration are provided based on the findings from these studies.
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