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Summary This paper identifies wellbore-stability concerns caused by transient swab/surge pressures during deepwater-drilling tripping and reaming operations. Wellbore-stability analysis that couples transient swab/surge wellbore-pressure oscillations and in-situ-stress field oscillations in the near-wellbore (NWB) zone in deepwater drilling is presented. A transient swab/surge model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, and the flow between wellbore and formation. Real-time pressure oscillations during tripping/reaming are obtained. On the basis of geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with swab/surge pressure, pore pressure, and original formation-stress status to perform wellbore-stability analysis. By applying the breakout failure and wellbore-fracture failure in the analysis, a work flow is proposed to obtain the safe-operating window for tripping and reaming processes. On the basis of this study, it is determined that the safe drilling-operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the frictional pressure loss during the normal-circulation process. With the effect of swab/surge pressure, the safe-operating window can become narrower than expected. The induced pore pressure decreases monotonically as the radial distance increases, and it is limited only to the NWB region and dissipates within one to two hole diameters away from the wellbore. This study provides insight into the integration of wellbore-stability analysis and transient swab/surge-pressure analysis, which is discussed rarely in the literature. It indicates that tripping-induced transient-stress and pore-pressure changes can place important impacts on the effective-stress clouds for the NWB region, which affect the wellbore-stability status significantly.

Fluid displacement due to pipe movement in and out of the wellbore generates surge/swab pressure. Surge/swab pressure could result in formation fracturing, lost circulation, kicks, and even blowouts. Transient surge pressure depends on tripping velocity, mud viscosity, fluid compressibility, wellbore expansion, and elasticity of the drillpipe. Considering wellbore stability, sudden pressurization of the wellbore causes rapid change in stress distribution in the zone near the wellbore that may result in wellbore instability. This makes it necessary to have an estimation of transient surge pressure and stresses for safe and effective tripping operations. In this work, for the first time, stress distribution and the stability around the wellbore are being investigated when transient surge pressure is generated in the wellbore. Firstly, a transient surge pressure model is developed to calculate the pressure along the wellbore during the tripping-in operation. The model is based on transient wave propagation due to fluid compressibility and wellbore expansion. Then, the following steps are taken to obtain stresses around the wellbore: 1- Stress distribution around directional wellbore is calculated based on poroelasticity concept. 2- Induced pressure and stresses due to constant borehole pressure change are calculated. 3- The model is modified to include the effect of time dependency of surge pressure using Duhamel's theorem (superposition principle). 4- Induced stresses are calculated and added to existing stresses around the wellbore using the superposition principle. The model is implemented for tripping into a directional wellbore with trapezoidal and parabolic velocity profiles. The induced pressure, radial and hoop stresses versus radius are calculated at different times. Results indicate that these induced effects almost vanish at a distance of about five times the wellbore radius. Induced pressure increases with time until it reaches its maximum which is the maximum of surge pressure and then dissipates with time. Its peak propagates into the formation and dissipates with time. Induced radial stress shows similar trend as induced pressure. However, its peak is always at the wellbore wall. Induced hoop stress is tensile with a maximum value of about 35% of induced radial stress before it decays and dissipates in both cases of tripping velocities. Total radial stress peaks about 30% for the case of trapezoidal velocity and 35% for the case of parabolic velocity compared to base value. However, same comparison for total tangential stress shows a reduction of 7% decrease for the case of trapezoidal velocity and 11% for the case of parabolic velocity which is due to the induced tensile stress. Comparing results for both velocity profiles show no difference in the trend of induced pressure and stresses. However, the magnitude of induced pressure and stresses depends on surge pressure which is different in case of trapezoidal and parabolic velocity profiles. A failure criterion can be applied to analyze the stability of the wellbore. It is noted that surge pressure changes as a function of time and dynamic rock strength must be taken into account in wellbore strength management. The developed model presents an effective tool for wellbore stability analysis in tripping operations. The tool can be applied for optimization of tripping operations in vertical and directional wellbores.

This paper identifies wellbore stability concerns caused by transient surge and swab pressures during deepwater drilling tripping and reaming operations. Wellbore stability analysis is presented that couples transient surge and swab wellbore pressure oscillations and in-situ stress field oscillations in the near wellbore (NWB) zone in deepwater drilling. Deepwater drilling is usually subjected to narrow drilling windows and significant wellbore pressure oscillations during tripping/reaming because of well depth. However, integration of transient surge and swab pressure analysis, and its effects on in-situ stress analysis around the wellbore, is rarely industry studied. A transient surge and swab model is developed by considering drillstring components, wellbore structure, formation elasticity, pipe elasticity, fluid compressibility, fluid rheology, etc. Real-time pressure oscillations during tripping/reaming are obtained. Based on geomechanical principles, in-situ stress around the wellbore is calculated by coupling transient wellbore pressure with surge and swab pressure, pore pressure, and original formation stress status to perform wellbore stability analysis. By applying the breakout failure and wellbore fracture failure in the analysis, a workflow is proposed to obtain the safe operating window for tripping and reaming processes. Based on this study, it is determined that the safe drilling operation window for wellbore stability consists of more than just fluid density. The oscillation magnitude of transient wellbore pressure can be larger than the friction pressure loss during normal circulation process. With the effect of surge and swab pressure, the safe operating window can become narrower than expected. Although it is stable and not a concern during a normal penetration process, the wellbore stability can become problematic. By using the methodology described, unnecessary breakouts and borehole failures during tripping and reaming can be avoided. This work can also be used in the next generation of drilling automation. This study provides insight into the integration of wellbore stability analysis and transient surge and swab pressure analysis, which is rarely discussed in the literature. It indicates that, when surge and swab pressure analysis is not carefully performed, the actual safe operating window can become narrower than originally predicted.

It is well accepted that torque and drag calculations are essential for well construction applications. To the authors' knowledge, the calculations are performed based on the concepts of the soft string model. This approach enables the wellbore designer to determine torque and other forces in the drillstring. While several modifications of the soft string model have been proposed and implemented in commercial software, the model mainly used in the oil and gas drilling industry is the static soft string model. As such, not only the string bending stiffness is neglected, but also it is assumed that the string is motionless and the direction of motion changes by merely changing the sign of friction coefficient. Clearly, there is a strong need for including acceleration effects in the soft string model to permit analysis of tripping operations and more accurate evaluation of the drillstring loading and consequently, the rig equipment (hoisting system, etc.).In this paper, an improved dynamic soft string model is proposed that accounts for drillstring motion in 2D and 3D wellbores. This mathematical model explains how to compute forces along a moving drillstring or casing. The aims of this model are: 1) to analyze dynamic drillstring behavior, 2) to estimate local contact forces, and 3) to predict the effect of different tripping velocity profiles on axial and lateral contact forces. A system of equations for drillstring translational motion is solved using numerical methods. A computer code has been developed for practical design calculations.The improved dynamic soft string model can be used to determine surface load and contact force as functions of time and measured depth. This model is also applied to predict surface load and contact forces in tripping operations. In particular, the model is implemented for drillpipe in two different 2D wellbores: horizontal and S-shaped, and a 3D wellbore while tripping in and out of the hole. As expected, the surface load vs. time plot shows a similar trend of tripping accelerations. Depending on the well path shape, drillstring properties, tripping acceleration, and velocity profile, the maximum dynamic loads can be in the range of 4-40% higher compared to the conventional soft string model. In addition, results for two different tripping velocity profiles (trapezoidal and parabolic) are compared. The maximum surface load is up to 4% higher with trapezoidal velocity profile which is not significant, because both velocity profiles provide 90 ft displacement. It is noted that the governing parameter for the maximum load needed is the maximum tripping acceleration, not the maximum velocity.Improved dynamic soft string model will have significant impact on well path shape, drillstring design, drillpipe failure analysis, tripping operations optimization, and automatic control of the drawworks.

The soft string model has been widely used for torque and drag calculations. Although several modifications have been developed, the standard model in the oil and gas industry is the static soft string model, in which the string is assumed to be motionless and its stiffness is neglected. In order to estimate more realistic and accurate calculation of drillstring loading, not only the acceleration, but also axial stiffness of the string must be considered in force calculations. In this paper, a dynamic, axially-stiff string model is presented for force calculations of drillstring in tripping operations. The mathematical model is developed to include axial stiffness of the drillstring and acceleration into the soft string model by coupling mass-spring system with the soft string model. Moreover, static friction and drilling fluid drag are taken into account. The drillstring is considered to be a system of coupled oscillators subject to external forces. Then, the motion of the individual oscillator is governed by external forces and the forces applied by its two neighboring elements. In this model, the static friction effect is included as a constraint for initiation of motion. The drillstring configuration is considered to be drillpipe, drillcollar, and directional assembly. The developed model ("new model") is implemented for tripping-out one stand in two ideal directional wellbores plus one field case wellbore trajectory. Axial force behavior shows a trend of acceleration that is similar to that observed with the previous dynamic soft string model ("previous model": SPE-173084-MS), and the first peak contains the effect of static friction. Displacement at the end of the string shows that the whole drillstring is in motion after few seconds. The axial force using the new model is compared to that (axial force) calculated using the previous model for two different cases. In the acceleration part of the motion, the new model shows a peak about 12% higher than the maximum load in the previous model which is due to the static friction force. In the constant velocity part of the motion, depending on the amount of damping, the new model can show a result similar to that of the previous model. The new dynamic axially-stiff string model provides a more realistic prediction of hookload, and consequently more realistic loading of the hoisting equipment and fatigue life of the drillstring. Other applications of this model are for wellbore planning, drillstring design, optimization and automation of tripping operations.