A dynamic stiff string torque and drag (T&D) model is presented that assumes steady state motion of the drillstring as its basis for calculations. Results are compared to previously published T&D models that are based on static equilibrium. The novelty of the new dynamic model is the ability to solve T&D operations of the entire drillstring from bit to top drive in reasonable time using standard engineering computers.The new approach is based on a 3D dynamic model of drillstring and BHA in an elastic borehole. It considers bending stiffness, torsional stiffness, contact forces, and friction with localization of contact points. A numerical method is described that has proven to have excellent convergence. Complete governing equations are provided and the method is described in detail to permit readers to replicate results.The dynamic model is compared to two static stiff string models. Comparisons are also provided for three conventional soft string models including the Lubinski-Paslay-Cernocky bending stress magnification factor. Three field case studies are presented for horizontal wells. One well is short radius with dogleg severity over 50 deg/100 ft and two wells are unconventional shale wells with doglegs up to 15 deg/100 ft. Predictions for surface torque and drag up and down for the new dynamic stiff string model are compared to the static stiff and soft string models. In many situations modeled the top-level results for surface torque and drag up/down are close enough for all six models to be within the uncertainty range associated with the commonly used, lumped-parameter friction factor. However, some major differences in hook load for sliding and slack off operations are observed, which are shown to be caused by differences in location and magnitude of contact force between the drillstring and wellbore. Further, significantly lower surface torque is predicted by the new dynamic stiff string compared to other models for one case history because of lower contact forces in the vertical section of the well. In fact, the key finding of this paper is that major differences are observed for contact forces for the new dynamic stiff string model compared to all five other models, including the two static stiff string models. These differences in contact forces are most significant when the drillstring has helically buckled or when doglegs in the wellbore are high. Contact forces have a large impact on local stress behavior, which is important for predictions of casing and drillpipe wear, drillstring fatigue, and failure points in the drillstring.Although several previous papers have published stiff string models there is no industry standard formulation. The main problem holding back the development of an industry standard stiff model is perhaps the complexity of the numerical algorithm and substantial running time. To address this problem, some previous stiff string models account for bending stiffness of the drillstring but not for radial clearance while others appear to model only portions of the drillstring ...

Summary A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time data analysis. It can be applied to all well types for any well operation, including drilling, casing running, completion activities, and re-entries. The method uses leading indicators of stuck pipe that were identified by use of historical data sets of 36 stuck-pipe incidents in the Eagle Ford, Utica, and Permian and in the Gulf of Mexico. Two case histories show the utility of the new method in shale and carbonate horizontal wells for both drilling and off-bottom operations. The new method combines two types of analysis: use of hydraulics and torque-and-drag (T&D) software to determine deviation of real-time data from the real-time model, and trend analysis (i.e., rate of change) of real-time data. Parameters used are pump pressure, flow rate, torque, rotary speed, hookload and drag, and weight on bit (WOB), along with static inputs such as bottomhole-assembly (BHA) and drillstring configuration and directional surveys. Additional parameters, such as downhole equivalent circulating density (ECD), are used when available and improve the results. But the method is designed to monitor all well types and provide a stuck-pipe-risk log even by use of only basic instrumentation. A novel algorithm predicts the probability of stuck pipe, which is presented in a real-time log. Results demonstrate that there is no single leading indicator in all stuck-pipe incidents. Our early-detection method, called the stuck-pipe-risk (SPR) log, relies on multiple indicators to strengthen the likelihood of detecting impending stuck pipe while avoiding false alerts. A key element to automating the process is the use of filtering for rig activity. The first indicator is deviation of actual data from model predictions. A second indicator is trend analysis (specifically, rate-of-change calculations), which provides valuable insight into rapidly deteriorating wellbore conditions when deviation from model predictions does not respond quickly enough over a short depth or time interval. Results are presented that show the SPR-detection method successfully detected impending stuck pipe on four historical shale wells an average 38 minutes before sticking and on one historical carbonate well more than 2 hours before the event. No false alerts were recorded in these wells. These results were viewed as meeting the initial goal of providing relevant alerts with sufficient time to prevent the pipe from becoming stuck.

Summary A dynamic stiff-string torque-and-drag (T&D) model is presented that assumes steady-state motion of the drillstring as its basis for calculations. Results are compared with previously published T&D models that are based on static equilibrium. The novelty of the new dynamic model is the ability to solve T&D operations of the entire drillstring from bit to topdrive in reasonable time by use of standard engineering computers. The new approach is modeled after a 3D dynamic model of drillstring and bottomhole assembly in an elastic borehole. It considers bending stiffness, torsional stiffness, contact forces, and friction with localization of contact points. A numerical method is described that has proved to have excellent convergence. Complete governing equations are provided, and the method is described in detail to permit readers to replicate results. The dynamic model is compared with two static stiff-string models. Comparisons are also provided for three conventional soft-string models, including the Lubinski-Paslay-Cernocky bending-stress-magnification factor. Four field case studies are presented for horizontal wells. One well is short radius with dogleg severity greater than 50°/100 ft, and three wells are unconventional shale wells with doglegs up to 15°/100 ft. Predictions for surface T&D up/down for the new dynamic stiff-string model are compared with the static stiff- and soft-string models. In many situations modeled, the top-level results for surface T&D up/down are close enough for all six models to be within the uncertainty range associated with the commonly used, lumped-parameter friction factor. However, some major differences in hookload for sliding and slackoff operations are observed, which are shown to be caused by differences in location and magnitude of contact force between the drillstring and wellbore. Further, significantly lower surface torque is predicted by the new dynamic stiff-string model compared with other models for one case history because of lower contact forces in the vertical section of the well. In fact, the key finding of this paper is that major differences are observed for contact forces for the new dynamic stiff-string model compared with all five other models, including the two static stiff-string models. These differences in contact forces are most significant when the drillstring has helically buckled or when doglegs in the wellbore are high. Contact forces have a large impact on local stress behavior, which is important for predictions of casing and drillpipe wear, drillstring fatigue, and failure points in the drillstring. Although several previous papers have published stiff-string models, there is no industry-standard formulation. The main problem holding back the development of an industry-standard stiff-string model is perhaps the complexity of the numerical algorithm and substantial running time. To address this problem, some previous stiff-string models account for bending stiffness of the drillstring but not for radial clearance, whereas others appear to model only portions of the drillstring as stiff. The new stiff-string model accounts for bending stiffness and radial clearance for the entire drillstring while still giving reasonable computational times. For stiff-string models, the advantage of the use of a dynamic approach to solve the steady-state position of the drillstring is mainly related to superior convergence of the numerical algorithm compared with static stiff-string models because the calculation of contact points is faster.

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A real-time method is presented to predict impending stuck pipe with sufficient warning to prevent it. The new method uses automated analysis of real-time modeling coupled with real-time data analysis. It can be applied to all well types for any well operation including drilling, casing running, completion activities, and re-entries. The method uses leading indicators of stuck pipe that were identified using historical data sets of 36 stuck pipe incidents in the Eagle Ford, Utica, Permian, and Gulf of Mexico. Four case histories show the utility of the new method in four shale horizontal wells for both drilling and off-bottom operations. The new method combines two types of analysis: (1) deviation of real-time data from real-time model predictions using hydraulics and torque and drag (T&D) software, and (2) trend analysis (i.e., rate of change) of real-time data. Parameters used are pump pressure, flow rate, torque, rotary speed, hookload and drag, and weight on bit along with static inputs such as BHA and drillstring configuration and directional surveys. Additional parameters such as downhole ECD are used when available and improve the results. But the method is designed to monitor all well types and provide a stuck-pipe-risk log even using only basic instrumentation. A novel algorithm predicts the probability of stuck pipe which is presented in a real-time log. Results demonstrate there is no single leading indicator present in all stuck pipe incidents. Consequently, relying on a single specific pattern (such as increasing pump pressure at constant flow rate) leads to inability to predict stuck pipe in some cases. Our early detection method relies on multiple indicators to strengthen the likelihood of detecting an increase in stuck pipe while avoiding false alerts. Deviations of parameters from model predictions have been used with success in the past by experts but the new method provides contextual awareness and provides thresholds that automate the process. A key element is the use of filtering for rig activity. Rate of change calculations provide valuable insight into rapidly deteriorating wellbore conditions when deviation from model predictions does not respond quickly enough over a short depth or time interval. The detection method was tested on four historical wells in which four stuck pipe and two near-miss events occurred. Testing showed that an alert was generated, on average, 38 minutes before the event. There were no false alerts recorded in these wells.