This study investigates the impact of induced low frequency axial excitations on drilling actions of Polycrystalline Diamond Compact (PDC) bits. Variations in drilling efficiency have been documented through a series of experiments at different intensities (frequency and amplitude) of axial excitations. Prior work has identified the challenges of bit wear due to high frequency oscillations and an experimental validation is conducted to incorporate vibration related force changes into mechanical specific energy (MSE) to allow for identification while drilling. Axial vibrations were induced using a controlled linear actuator at the cutter-rock interface, in low frequency regime (up to 5 Hz) using a rotary experimental setup, based on state-of-the-art modified lathe machine. Through imposition of bit kinematics of angular velocity and rate of penetration (ROP), a PDC cutter was used to drill several cores of donnybrook sandstone, at a constant angular velocity of 100 revolutions per minute (RPM). A piezoelectric triaxial sensor measured the cutting forces: normal (weight) and shear (torque) force, at the cutter-rock interface. The results quantify variation of drilling response under several combinations of frequency, amplitude and cutting speed. It was observed that forces required to penetrate through rock were reduced with minimum effect on degree of wear on the cutter, mainly due to lower intensity of induced oscillations. This shows that once periodic axial oscillations are imposed, a lesser amount of energy is required to achieve same rate of penetration (ROP), thereby indicating improvement in cutting efficiency of the drilling process. The results from this study also provides experimental evidence for the need to incorporate vibration induced force losses into the equation of drilling efficiency for correct estimations of rock strength downhole.

Maximizing drilling performance by pushing the limits of drilling tools is the key to reduce overall drilling cost. The interplay of complex parameters such as lithology, drilling parameters, drilling experience, downhole tool reliability, and the operational process help us to identify the limiting factors. Drilling dysfunction could deteriorate the reliability of downhole drilling tools including the overall drilling performance by causing damaged bits, failure of downhole electronic components, torsional fatigue of drillstring, over-torqued connections, etc. Precise modeling of dynamic responses of a bottomhole assembly in a given formation can help to identify operating limitations as well as post job analysis. The wellbore-drillstring interaction and well face-drill bit interaction are the sources of excitation of torsional oscillations. Stick-slip is one of the common and well-known torsional oscillation that usually occurs at low frequencies <1 Hz. High-frequency torsional oscillations (HFTO) are also recorded in the field by using high-bandwidth downhole vibration monitoring tools. HFTO occurs at much higher frequencies; >10Hz to 500 Hz. This paper summarizes the HFTO phenomenon that causes high tangential accelerations and torsional loads within the bottomhole assembly (BHA) during drilling in critical formations. HFTO modeling that is validated with high-speed measurements helps to identify tangential accelerations and torsional loads across the BHA components. This paper highlights the benefits of modeling the rotary steerable system (RSS) BHA for HFTO in order to identify the point in the BHA that is subjected to the highest tangential acceleration and torsional loads. Real time monitoring for drilling optimization of RSS BHA shows that the HFTO modeling and post-job data analysis of high-frequency data confirms the distribution of tangential acceleration and torsional loads along the BHA. The paper also highlights the accuracy of the HFTO modeling based on results of pre-job modeling and post-job high-speed data analysis from drilling runs. Based on the analysis and the study, recommendations for optimal BHA design and operational parameters are provided to yield maximum footage per run and improved BHA performance. High-frequency torsional oscillations in the BHA can be mitigated if adequate BHA design, drilling parameters, and procedures are implemented. The in-depth analysis of HFTO with accurate modeling and high-frequency measurements can be used to develop a knowledge base to further optimize the drilling process, reduce non-productive time, realize fewer trips for failures, extend the on-bottom drilling time, reduce maintenance costs, and increase the drilling efficiency and performance.

In recent years, the phenomenon of drill string torsional oscillation at frequencies over 50 Hz has been well documented. This high frequency torsional oscillation (HFTO) creates cyclic fatigue loading on bits and drilling tools within the bottom hole assembly (BHA) and thus limits tool life and drilling performance. However, few models exist which can predict occurrence of HFTO and its severity. To our knowledge; none of these models consider the entire drilling system including the bit-rock interaction, downhole drive(s), BHA design, and surface drilling parameters, and hence there is a need to develop a system model for HFTO mitigation. A 3D transient drilling dynamics model has been extended to study the severity of HFTO and cyclical loading to drilling tools. The accuracy of the model was validated by theoretical calculation, and high frequency downhole data. An example analysis was conducted to evaluate drilling system design performance in terms of HFTO risks. Good correlation was found between the analysis and field data collected from the Permian Basin. Advanced models were developed for mud motors and rotary steerable system (RSS) tools. After conducting a full drilling simulation, the drilling system behavior under HFTO can be fully described. Cyclical torque loading of differing magnitudes and frequencies were observed for different BHA components depending on HFTO vibration mode, HFTO severity and BHA design. PDC cutters were subjected to different cyclical loading depending on bit design, formation and HFTO conditions. The mud motor power section was found to undergo high frequency cyclical loading which could accelerate its rubber degradation. Since the failure of PDC cutters and the degradation of mud motor power sections have a critical effect on drilling performance, the importance of mitigating HFTO cannot be underestimated. By evaluating the loading conditions, an optimized drilling system can be selected. Field data has proved the validity of this approach. The methodology presented in this paper offers a new way for the industry to systematically mitigate HFTO by considering the rock drilled, bit design, mud motor utilized, the mechanics of RSS and other tools in the BHA, as well as drilling parameters. The usage of this approach can reduce premature drilling component failure and improve drilling performance, especially in the high energy drilling applications found in North America Land and other areas.

The drilling process is impacted by vibrations through limited drilling efficiency and rate of penetration, reduced reliability and increased non-productive time. The understanding of the mechanisms and physics that lead to high levels of vibrations is extremely important to elaborate vibration mitigation strategies. A typical vibration excitation mechanism is forced response excitation, e.g., caused by the imbalance of the mud motor that can lead to lateral resonance with severe impact on tool life. Self-excitation is prominently caused by the bit-rock interaction and mainly excites torsional oscillations if PDC bits are used. Representations are stick/slip with low frequencies (<1 Hz) and high-frequency torsional oscillations (HFTO) with frequencies up to 500 Hz. The large frequency gap between stick/slip and HFTO allows for different effects and excessively increasing loads. The nature of this interaction is diverse and requires different strategies to reduce the loads associated to HFTO and stick/slip to a minimum. The interaction between stick/slip and HFTO is analyzed and appropriate drilling optimization strategies are proposed. Several scenarios are discussed by examination of high-frequency downhole data (1000 Hz) measured in different field applications and physical modeling. It is shown that averaged statistical data or diagnostic data that are typically available can lead to misinterpretation of the drilling conditions. The first scenario is pure HFTO. The second scenario is stick-slip with superimposed HFTO that can lead to an amplification (up to factor two) or reduction of HFTO loads compared to the first scenario. Influencing parameters are discussed that determine either an amplification or a reduction of the loads in the second scenario. The third scenario shows the interaction in the context of stability measures that are determined by the operational parameters. The increased rotary speed in the slip phase of stick/slip can lead to a stabilization of HFTO and actually decreasing amplitudes. The observations in the field are further validated using theoretical drilling scenarios. For each scenario different strategies are presented to reduce the field loads associated to HFTO and the compromise of the strategies to the drilling efficiency and rate of penetration is discussed. The nature of the interaction between stick/slip and HFTO is analyzed and unveiled. Clearly, the necessary depth of understanding can only be achieved by analysis of high-frequency downhole data. The physics-based interpretation of the problem allows the development of very specific drilling optimization strategies. Depending on the scenario a complete mitigation of HFTO or at least a significant reduction of loads can be achieved. Ultimately, the drilling process can be optimized leading to a reduced cost of the well delivery since HFTO can be a major cause for non-productive time if not handled properly.

Cutting forces at the bit or mass imbalances in downhole tools such as mud motors can cause severe vibrations in drillstrings and bottom-hole assemblies (BHA). Negative effects include reduced rate of penetration, low-quality measurements and downhole tool failures. A value that represents the real downhole vibration level is needed to perform a reasonable mitigation strategy. The most common values are statistical values derived from acceleration signals that are received from a sensor at a specific distance from the bit (DfB). The interpretation of an acceleration signal is limited if only one mode shape is dominantly excited. In this case, the measurement signal is very sensitive with respect to the DfB of the sensor placement. The derivation of a representative value for the severity of high-frequency torsional oscillation (HFTO) is shown that is independent of the sensor position. In the proposed approach, the dynamic torsional torque is used in addition to the tangential acceleration measurement. The frequency information of both measurement signals are determined and an analytical model is used to calculate the maximum value of vibration amplitudes that occurs along the BHA. The algorithm is implemented in the measurement-while drilling (MWD) tool for vibration and load measurements. The maximum load value in the BHA corresponding to HFTO can be sent to the surface in real time for interpretation by the driller. In a case study, different scenarios from the field are discussed. The maximum load values are compared to numerical simulations that show an excellent agreement. The maximum value calculated by the approach is factors higher than the values measured by the accelerometers. By using the algorithm-upgrade of the MWD tool, a representative measurement value for the severity of HFTO loads is derived. This is a clear advantage compared to tangential acceleration measurement only. The value enables the driller or an automated advisory system to initiate the optimal HFTO mitigation strategy that leads to reduced levels of vibration with the known benefits for the cost of a well.

Extremely tortuous wells pose many wellbore quality repercussions and poorly affects several well drilling and production-based operations. To date, many indices have been developed for accurate tortuosity identification, but few have had the capability to efficiently mirror and quantify micro-tortuosity in real-time. This study applies a previously-proposed novel algorithm studied by some researchers to quantify well trajectory tortuosity using simple and readily available survey data. The process is followed and validated using twenty wells located in the Permian Basin. Python code was written to identify proper inflection points at the mid-point of the curve turns and using inclination and azimuth indices, a 3D overall TI index was generated for each well. The technique is inspired from the discipline of ophthalmology, specifically a method to determine tortuosity from retinal blood vessels. The approach successfully produced a tortuosity metric with three different risk categories characterizing three ranges of the index. The indices generated were matched against operator reports of drilling incidents and NPT. The methodology matched highly tortuous wells with greater downhole tool failures rates ranking it in the high-risk zone.

A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool. An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall. Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements. The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination. It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job. The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.

When drilling complex wells, such as those with long lateral sections, the friction forces become significantly high, which can impede advancement of the drill string and reduce drilling performance. In these situations, Axial Oscillation Tools (AOT) could be used to introduce an axial vibration to the drill string. By locally reducing the friction forces, better transmission of weight to the drill bit is possible and an increase in the rate of penetration occurs. However, to optimize the use of these tools, predictive modeling is necessary to assess their effect on drilling characteristics. A new modeling approach is proposed to accurately model the effect of the AOT on drilling operations without the need to carry out resource-intensive and time-consuming dynamic computations. To estimate the influence length ( i.e . the extent of the axial vibrations) and the maximum displacement at the AOT, a study was performed to determine the most important parameters. Based on this study and on the theory of wave propagation, new analytic expressions are proposed. Once the influence length and the maximum displacement are calculated, an effective friction coefficient is estimated as the mean value of the instantaneous friction coefficient and used in a stiff-string torque and drag model. The model was applied to a real case study, and an agreement between the modeling results and field measurements regarding the influence of the AOT was obtained. Moreover, the effect of the excitation force and rate of penetration on the drill string tension profile was investigated. This work should enable drilling engineers to better optimize the position of AOT along the drill string and to maximize its efficiency.

Because wells drilled by the oil and gas industry are becoming more complex, the drillstring is subjected to additional severe loading conditions, resulting in increased failure risk. It is universally known that fatigue is one of the primary causes of drillstring failure, accounting for more than 70% of the failures. Drillstring failure generally results in unexpected catastrophic twistoff of bottomhole assembly (BHA) components and costly fishing operations. For these reasons, it is important to develop a drillstring fatigue life prediction model. Fatigue is driven by cyclic stresses and accumulates over time. These cyclic stresses can occur in a wide range of conditions, such as rotating the drillstring through a high-dogleg severity well section, and severe bending due to whirling or buckling of the drillstring. The procedure relies on the powerful and accurate drilling dynamics computation engine, which is based on a 3D finite element model and which predicts transient dynamics response and stresses along the drillstring under drilling operations loading conditions. First, the section being drilled is subdivided into multiple small intervals. For each interval, simulation is used to predict the drillstring deformation and contact force. Stresses can then be evaluated for each component in the drillstring. Due to the cumulative nature of fatigue failure, it is necessary to track the cycle of alternative stresses of the drillstring while drilling an entire section. For stable rotary drilling, the number of stress cycles can be calculated from the number of rotation revolutions within the interval. In the real-time fatigue monitor application, the actual drillstring revolutions measured at the surface can be used directly as the stress cycle. When severe downhole vibration exists, the rain-flow counting method is used to count the stress cycles for the complex dynamics stress history. To consider mean stress effect, the Goodman law is used to compute the equivalent alternative stress. With the pre-collected fatigue S-N curves (stress level versus the cycle to failure) for different connection types and drilling tools, the fatigue life consumption in one interval is calculated. Finally, using Miner’s rule, the fatigue life results in all intervals are summed to obtain the cumulative fatigue damage to the drillstring. The fatigue model, which has been implemented as one of the key components in the drilling analysis workflow, provides engineers with the analysis capability to identify the potential factors influencing the integrity of BHA components. Two case studies validated the drillstring fatigue prediction model. This paper presents a practical and effective procedure for calculating drillstring and BHA component life due to fatigue accumulation. This modeling tool enables engineers to employ a systematic approach for quantifying the fatigue risk during the well planning and real-time execution phase.

Drillstring-borehole contact may result in backward whirl: a common and catastrophic phenomenon. To increase BHA (bottom hole assembly) reliability, reduce non-productive time (NPT), and ultimately improve service delivery, an in-house backward whirl testing rig is developed to investigate dynamic loads. Analytical and numerical models elucidate dynamic responses and are validated against backward whirl test results. A 6 ¾-in. BHA is tested in an 8.5 in. borehole using a continuous and discontinuous borehole profile. At a rotary speed of 60 rpm, and using a continuous borehole, lateral acceleration amplitudes range between 20 to 30 g with an RMS value of 3 gRMS. In comparison, a discontinuous profile results in acceleration amplitudes between 40 to 50 g with an RMS value of 7 gRMS. In regard to the discontinuous profile, the response spectrum shows a broader range of frequency content up to 200 Hz while distinct frequency peaks are evident in the spectrum when the continuous profile is used. Results indicate that backward whirl may occur from friction induced contact with different borehole profiles. Further, discontinuous profile yields drastically higher dynamic loads with a broader frequency spectrum than a continuous profile. Furthermore, validated models may serve as useful predictions for the backward whirl phenomenon and the system response. Backward whirl testing of full scale drilling tools with realistic, discontinuous borehole contact, supplemented with validated modeling, is a new approach to understand downhole dynamic events.

Downhole tools in bottom-hole assemblies are subject to high dynamic loads during drilling operations. The negative impacts of these dynamic loads can be inefficient drilling with low rate of penetration (ROP), reduced downhole directional and formation measurement service quality, and downhole tool failures with associated non-productive time. The dynamic phenomena can be categorized by direction into axial, torsional and lateral vibrations, and by excitation mechanism into forced excitation, self-excitation, and parameter excitation. Forced vibrations are mainly caused by imbalances in the drilling system or by the working principles of downhole tools such as the mud motor. Self-excitation mechanisms are mostly driven by the interaction of the bit, reamer or drilling system with the formation, and can cause detrimental dynamic behavior such as torsional stick-slip, bit bounce, and backward whirl. These diverse vibration phenomena require tailored mitigation strategies. To a certain extent, these mitigation strategies are contradictory. Misinterpretation of downhole measurements can lead to even worse vibration levels with severe consequences for reliability, ROP, and measurement quality. As a consequence, downhole measurement devices should differentiate vibration phenomena. This distinct differentiation could then be used to choose appropriate mitigation strategies. This paper analyses and defines the requirements for dynamics measurement devices. The specification, number, and placement of sensors and their associated sampling rates are examined to distinguish vibration directions and phenomena. The usefulness of these requirements is demonstrated using examples of torsional stick-slip and high-frequency torsional oscillations, lateral vibrations, and backward whirl. The results of kinematic modeling are analyzed and compared to high-speed vibration data from field runs measured with the latest generation of vibration measurement tools. Possible misinterpretation of vibration conditions in the case of inappropriate measurements is shown. The results are discussed by comparing theoretical modeling with field data. The defined requirements and guidelines enable a flawless interpretation of downhole vibration measurements and unveil drilling optimization opportunities. Different vibration phenomena can be identified reliably and appropriate mitigation strategies applied in real time at the wellsite by the driller or automation systems. This finally reduces the vibration load on the drilling system, increasing its reliability and performance.

The transversal vibrations of the fastline have been studied. The fastline, which is the part of the drill line running between the drawworks drum and the fast sheave, is put into vibrations by spooling induced motion at the drum and by variations of the line tension. Both excitation mechanisms are described in some detail and the transversal line response is studied with and without fastline stabilizers applied to reduce the vibration amplitudes. Two type of models have been used in the study, a simplified linear model suitable for frequency analysis and another more advanced simulation model which can also handle non-linear stabilizer damping. Both models show that the vibration amplitude can be severe if the excitation is cyclic with a frequency component matching one of the natural resonance frequencies of the fastline. Both models also show that the effect of a stabilizer is highly dependent on its damping characteristics and on its vertical location. The study has resulted in the design of a new and patent applied type of stabilizer placed more close to the fast sheave than a conventional stabilizer commonly used today. One of its main advantages is that it provides equal damping to both transversal directions.

Severe vibrations in drilling systems are one of the main limiting factors for an efficient drilling operation. An adjustment of drilling parameters is necessary to avoid the negative impact of vibrations on reliability, measurement quality, and rate of penetration. The time to drill a well is therefore directly or indirectly affected if vibrations are not properly managed; measurements must be repeated, damaged tools can lead to additional tripping time, and rate of penetration is limited by reduced power that is delivered to the bit and restrictions of operational parameters. Complex well trajectories, a difficult drilling environment, and the extended-reach of wells are additional challenges for drilling operations. The use of a mud motor in the bottom-hole assembly (BHA) is one option to supply power directly to the bit. However, if the mud motor is not properly managed, its operation can lead to lateral vibrations. BHA design and optimization of operational parameters are options to mitigate lateral vibrations. A basic understanding of mud motor vibrations is necessary for this purpose. To characterize mud motor-induced vibrations, a statistical evaluation of averaged vibration measurement data from several runs is conducted. Distributions of the vibrational amplitudes are analyzed, in reference to different designs of the mud motor power section. Analysis continues by reviewing a large quantity of time-based acceleration data with a sampling frequency of 1000 Hz. Special downhole tests are conducted that cover the entire range of operational parameters of the mud motor. High-frequency vibration data with distributed sensors are collected for different motor types and stabilizer configurations. The outcome of the analysis is used to determine the ideal mud motor for a given application. Existing models for drillstring dynamics simulation are fine-tuned. Based on the models, sweet spots for operational parameters that avoid severe vibrations are derived and displayed in an innovative way. The extensive analysis of high-frequency vibration data enables a reliable determination of operational parameters for mud motor applications that correspond to low levels of lateral vibrations. The approach enables efficient drilling with a high rate of penetration and results in increased downhole tool reliability. This ultimately leads to an optimized service delivery for drilling operations.

This paper describes an approach for identifying formations as annular isolation barriers. It also presents details of a novel analysis of cement evaluation and casing integrity data sets as an alternative to casing milling and secondary cementing use in plug and abandonment operations. Recent ultrasonic cement evaluation logs, performed as part of the integrity diagnostics required for plug and abandonment operations, showed an increase in casing ovality when logging through a specific halite formation in the southern North Sea. These findings were used to postulate that the formation was coupled mechanically to the casing and could be used as an abandonment barrier. The circumferential cement evaluation data helped to identify the azimuthal coverage of the formation, and subsequent pressure testing confirmed the integrity of the halite formation as an isolating medium. Multiple offset wells were also analyzed with a focus on identifying additional horizons exhibiting mobility that could be detected using casing logging tools. It became evident that this halite formation showed a consistent and clear correlation between casing ovality and circumferential coverage. Case studies are presented in which the halite formation was identified as an appropriate barrier, based on the combined interpretation of both cement evaluation and casing inspection data. This phenomenon typically occurred when the top of cement was below the halite interval; however, in some cases, the formation movement actually improved the cement bond quality across the zone. By cross-referencing the cement evaluation and casing inspection logging data sets, the mobility of the halite formation can be identified, and subsequent integrity testing confirms its isolating capabilities as an appropriate barrier for plug and abandonment operations. The use of geological formations with suitable mobility as an alternative to a standard milled casing window with a cement plug can reduce rig time and consequently reduce operational costs.

Drillstring vibration is a leading cause of downhole tool failure and premature wear of downhole equipment. The main challenges faced during drilling include performing rapid analyses to determine the root cause of the vibration, clear identification of the active mechanism, and implementation of the appropriate corrective action quickly enough to prevent failure. This paper describes a comprehensive methodology created to identify root causes, all vibration mechanisms, and methods to reduce or eliminate drillstring vibration on a range of different operations. A BHA and drillstring have six degrees of freedom and three dominant modes of vibration: axial, lateral, and torsional. This movement is used to describe the different vibration mechanisms, such as stick/slip, bit bounce, bit whirl, BHA whirl both forward and backward, torsional resonance, bit chatter, modal coupling, and lateral shocks. Data is collected from downhole and surface sensors, as well as cutting analyses that measure modes and magnitudes of vibration, tension, compression and bending within the (BHA), drilling parameters, fluid properties, and lithology and rock properties. The methodology uses some or all of these factors to identify the root cause and is enhanced by the ability to summarize the distribution of vibration levels across a run, histogram analysis, and the ability to filter across time or depth ranges and further filter based on rig-activity codes. There is a combination of factors that generate or influence drillstring vibration, including the energy inputs of weight on bit (WOB) and torque (TRQ), bit type, BHA design and stabilization, lithology type, geological structures, bit-lithology interaction, borehole size and BHA size, hole trajectory, backreaming or rotating off bottom, hole enlargement, the rig's electrical system, and on offshore floating vessels, rig heave. The methodology is able to identify and isolate which factors are the root cause of a specific mechanism by incorporating time-based analyses with depth-based logs and plotting a to-scale BHA to identify correlations of the bit position, stabilizer, and other BHA components to formation types and boundaries, hole-size changes, and casing positions. This enables a significantly faster data analysis and a more rapid assessment of the root cause of the vibration, thereby delivering specific benefits through identifying and then reducing or eliminating drillstring vibration on a range of different operations.

Tortuosity is an important metric in evaluating wellbore quality. A tortuous well path can lead to such well problems as stuck pipe, poor cementation, and early production equipment failure. The industry currently lacks a readily usable real-time tortuosity (density) index to enable the driller to make corrections during the drilling process. This paper presents a new algorithm to calculate the tortuosity index and validates the index using field data. Until the last decade, average and maximum dogleg severity were the main indicators of wellbore tortuosity and quality. Recently, approaches which measure/model indirect quantities such as wellbore friction, bending moment, elastic energy etc. and then translate these to a measure of tortuosity, have gained popularity. However, such an indirect process introduces errors when the model used is not accurate. Another approach produces high precision 3D wellbore profiles to assist in ascertaining the tortuosity of the well. This method, however, requires additional downhole sensors at additional cost and a need for additional data-communicating and processing. To overcome these shortcomings, this paper proposes a methodology that is leveraging techniques used in medical field, more specifically in ophthalmology, to determine the tortuosity of the narrow veins in human eyes. The methodology described in this paper produces a tortuosity "density" that has the ability to capture tortuosity at different length scales (from 1 foot to 10,000 feet). It works with conventional directional survey data and/or high-resolution survey as input and calculates a normalized number, the tortuosity (density) index , in real-time. The methodology was applied on the horizontal sections of 18 wells drilled in 2013 and 2014, and the tortuosity indices derived for these wells were compared against reports of drilling dysfunction and non-productive time. The tortuosity index correctly identified problematic wells that had multiple downhole equipment failures during drilling, and showed a strong correlation with other drilling dysfunctions. The new real-time index provides a holistic view of wellbore tortuosity and may help to mitigate and correct problems before they occur. No new sensors or special practices are needed for the adoption of the method. This index is also robust to changes in survey distance, and provides an indication of micro-tortuosity when continuous/high-frequency gyro data is available.

Cement is a critical component in an oil well because it provides sealing and zonal isolation within the well. To help ensure proper performance of a cementing operation, various evaluation techniques/tools have been developed and used over the years, including some based on ultrasonic pulse echo technology. Ultrasonic pulse echo evaluation tools can play a key role in determining in-situ cement performance and if any remedial cementing is required. As the oil and gas industry continues to migrate toward more challenging reservoirs with increasingly harsh conditions, and coupled with more stringent regulatory requirements, significant technology improvements are helping ensure well integrity and safety. For example, ultrasonic tools are being reengineered for the capability to penetrate thick-walled casings (>0.75 in.) commonly used in complex situations, such as deepwater and high-pressure/high-temperature (HP/HT) wells. Meanwhile, there is also great demand for better optimized validation techniques to confirm the operational performance of these new evaluation tools. This paper focuses on investigating the use of oilwell cements as validation media of current and advanced ultrasonic tools designed for cement and casing evaluations. The evaluation system developed in this study consists of a combination of various validation media with a wide range of acoustic impedances (1.5 to 8.5 MRayl) and a multicasing fixture with casing wall thicknesses ranging from 0.4 to 1.4 in. This system could be used for the evaluation of tool performance in the presence of various muds and across a range of temperature and pressure conditions. Performance effectiveness was evaluated by measuring the acoustic impedance of the different media bonded to a multithickness casing and comparing the results to those acquired by direct acoustic measurement performed on the same media. The evolution of acoustic properties over time, directly related to cement hydration, was also monitored. An advanced pulse echo technology tool was used to perform preliminary validation using the newly developed evaluation system. This resulted in a clear trend of impedance evolution that correlates well with the direct impedance measurement of cement media.

The objective of primary cementing is to protect the casing and to ensure zonal isolation. It can be difficult to obtain a good cement job along the full length of a well, and casing centralization is one of the main factors that influence this. Even if the dependence of cement placement on casing centralization is well-known, little information is available on how the degree of casing centralization affects the well during its production phase. Well temperatures cycle up and down as a part of normal production operations – and well barrier materials, in particular steel, cement and rock, will consequently repeatedly expand and contract their volumes. Over time, this is likely to induce debonding and radial cracking of the cement sheath which threatens well integrity. This paper reports the results of an experimental study mapping how, where and when the annular cement loses its sealing ability upon temperature variations, and how this is dependent on casing centralization. The studied samples consisted of rock, cement and casing, and the temperature was cycled in a controlled and programmable manner. In-situ monitoring by Acoustic Emission (AE) sensors detected the development of cracking and debonding in the samples during thermal cycling. Initial and post-experiment computed tomography (CT) scans provided complementary three-dimensional (3D) information on the geometry and location of the induced cracks and debonding. Our study compared the thermal cycling resistance of two samples, one with centralized casing and one with a 50% casing stand-off. The AE monitoring results indicated that most of the cracking/debonding occurred during the actual heating and cooling, and not in between cycles when the temperature was held constant. The CT analyses showed that the thermal cycling caused considerable enlargement of cracks and voids initially present in the cement sheath, and this enlargement was significantly more severe when the casing was not centralized. The paper presents, for the first time, a 3D visualization of cracks and debonded volumes in the cement sheath, and it underlines the importance of obtaining a good initial cement job. Also, it is shown that it is important to obtain a good casing centralization during well construction – not only for optimal cement placement, but also for maintaining well integrity during production.

With the ongoing changes affecting the global drilling industry, well integrity has become an area of great engineering focus and development. Cement bond analysis is of key interest as the consequences of failed, or partially complete, cementing operations can, at best, be a costly delay in drilling operations and, at worst, an extremely hazardous safety issue. Traditionally, wireline acoustic tools have been used to analyze the quality of the cement bond between the casing and the formation. Wireline tools have been developed over many years to produce high-quality assessments of cement bond, which can then be confidently used to confirm well integrity. However, the conveyance method requires that the analysis be performed on the critical path and also that additional methods be used in high-angle wells. Logging-while-drilling (LWD) technology offers a potential alternative without these issues, provided the current limitations of the technology are understood and its applicability properly assessed as a fit-for-purpose solution. As a minimum, the LWD logging technique can provide a trigger as to whether more advanced logging techniques must be deployed or can be avoided. This paper explores the applicability of LWD sonic tools to the analysis of cement behind casing. It considers both the currently accepted deliverable of top of cement (TOC) analysis, along with examples of more advanced processing techniques and their comparison to wireline cement evaluation, providing case study examples in each case. The benefits and limitations of these methods will be discussed, along with operational considerations to aid in successful logging, including the use of repeat logging passes to indicate changes in cement quality with time. The use of LWD sonic tools to identify casing collar connections on driller's depth, enabling the safe positioning of cased-hole whipstocks, is also covered, demonstrating a novel and little-used application of LWD technology.

Perforating wells calls for careful planning to maximize well productivity over the life of the well, and to prevent time and money losses due to unexpected side effects. A large class of wells and in particular high-pressure wells are susceptible to gunshock damage when they are perforated with inappropriate gun systems. This paper presents applications of a simulation methodology to predict gunshock loads for tubing-conveyed and wireline-conveyed perforating jobs. With this simulation methodology we can evaluate the sensitivity of gunshock loads to changes in gun type, charge type, shot density, cable size, tubing size and length, number of shock absorbers, rathole length, placement and setting of packers, and early reservoir response, among many others. When planning perforating jobs, engineers strive to minimize the risk of equipment damage due to gunshock loads. With the simulation software presented in this paper, engineers can identify perforating jobs with significant risk of gunshock related damage, such as unintentional pull-offs, bent tubing and unset packers. When predicted gunshock loads are large, changes to the perforating equipment or job execution parameters are made to reduce gunshock loads to an acceptable level. Fast gauge pressure data from perforating jobs shows that wellbore pressure transients can be accurately predicted. For well prepared simulation models, typical peak sustained pressure amplitudes at the gauges are on average within 10% of simulated values. In jobs where shock absorbers were used, residual deformations of crushable elements correlate well with predicted peak axial loads; which confirms that gunshock loads on the equipment are well predicted. With the simulation methodology described in this paper engineers can evaluate perforating job designs in a short time, and they can optimize perforating jobs by reducing gunshock loads and equipment costs. The ability to predict and mitigate gunshock damage in perforating operations is very important because of the high cost of typical high-pressure wells.