Stick-slip is still present in most of the wells drilled today, especially in unconventional wells. Friction is an inevitable and important force along the long lateral section, but it contributes to many types of dysfunctions that lead to drilling inefficiency. Stick-slip is caused mainly by rotational friction induced along the drillstring, from the drill bit cutting the rock formation to the bottom hole assembly and drill pipe that contact the well bore. In the past, much attention has been given the cutting action of polycrystalline diamond compact (PDC) bits to explain and mitigate stick-slip, without much emphasis on the frictional torque. However, it is important to understand that the torque generated on the remaining drillstring accounts for most of the total torque at surface. This paper presents a case study on an unconventional well where stick-slip modeling was used to explain and understand stick-slip vibrations with or without the presence of active control systems at surface. First, the stick-slip model, including a PDC bit law friction and accurate contact forces calculation along the drillstring and mud damping effect is fully described, with all necessary and field parameters needed. Then, it explains the process to reproduce and calibrate downhole and surface torque, using a sensitivity analysis showing the most important parameters that affect stick-slip results. The results reinforce the importance of drilling parameters, such as the weight on bit and associated torque on bit that define the bit aggressiveness and are key in controlling or mitigating stick-slip vibration. In addition, these results show the significance of string friction along the drill pipe. Next, the use of a downhole instrumented sub, along with wire drill pipe technology, enables a full comparison of the results of the model with downhole and surface data. Last, the affect of other parameters, such as friction coefficient and mud damping, are discussed. With a better understanding of the initiation and translation of stick-slip from the bit up the hole to surface provided by this case study, engineers can be better informed when making decisions on factors such as drill pipe size and type, bit aggressiveness, and parameter changes in wells with severe stick-slip in unconventional wells application.
Casing wear due to pipe body and tool-joint of Range 2 and Range 3 DP is compared using a stiff-string torque & drag & buckling model coupled to a 3D meshed casing wear calculation. Results are compared for multiple well profiles, either smooth or tortuous, in addition to differing pipe-body and tool-joint wear factors.
Drilling operations can induce several external excitations to the drillstring and bottom-hole assembly (BHA) due, namely, to the drillstring-wellbore contacts, bit-rock interactions, fluid flow, and mass imbalances. On the one hand, such undesirable excitations may lead to excessive vibrations and damage to the drill bit, BHA, or drill-pipes. On the other hand, some vibration tools are used to intentionally introduce a source of lateral vibrations in the drillstring to reduce the friction effects and enhance the rate of penetration. Whether these vibrations are undesirable or intentional, efficient models are necessary to predict them accurately to help optimize the drilling parameters and vibration tools placement in the drillstring. The time-domain analysis can give a detailed portrayal of drillstring vibrations, but usually requires a lengthy computational time, especially for the simulation of long structures. This paper focuses on an alternative analysis using a forced vibration model based on a linearized frequency analysis. It consists of studying the magnitude of the displacement, velocity, acceleration, and internal efforts, when the drillstring is subject to an external harmonic excitation at a given frequency. This numerical model is based on the beam finite element method, where the wellbore-drillstring contact effects are considered using a Jacobian matrix approach. The forced vibration model is applied to study the lateral vibrations produced either by mud motors or lateral vibration tools. The comparison between the results of frequency and time-domain analyses shows that the forced vibration model can describe the global behavior of drillstring vibrations with a fast computation. When varying the excitation frequency, critical values giving large vibrations could be identified and avoided by the driller thanks to a heat map representation of the vibration magnitude as a function of the position and excitation frequency. The novelty of this work is in showing the capacities and limitations of the forced vibration analysis compared to time-domain analysis. The fast computation of the frequency analysis can provide efficient and accurate predictions and, therefore, could be employed to optimize the BHA design and drilling parameters, and therefore reduce the harmful vibrations and improve the performance of any drilling systems equipped with downhole excitation tools.
Various stabilizer types are used in the industry, such as bladed stabilizers with straight or spiral blades, roller-reamers, and other emergent forms. Their designs are proved, via many in-field measurements, to have a significant impact on vibration levels. Although experimental data is extremely valuable to rank the available design options, testing the different stabilizers can be costly and sometimes risky. In addition, in-field conditions can be difficult to control making the comparisons between stabilizers even more complicated. Assessing the design impact using numerical simulations represents an interesting alternative to provide objective comparisons based on tests in a controlled environment. When a stabilizer is rotating, the contact forces between its different blades and the wellbore are transient. A static approach like torque and drag or directional models is then insufficient to properly investigate the stabilizer's design characteristics. Therefore, a time-domain dynamics approach is adopted in this work. A detailed modeling of bladed stabilizers including the blade geometry (number of blades, spirality, and blade width) and friction characteristics are introduced in an existing time-domain model. These characteristics are used to compute the contact forces between the wellbore and each individual blade. This numerical model is applied to quantify the effect of stabilizer design in terms of vibration, from straight blades to highly spiraled blades. First, a parametric study of blade design and wellbore inclination effects on stabilizer vibrations is presented by considering different stabilizers in straight well conditions. Simulations of an actual drill string configuration in an unconventional well is discussed. For vertical, curved, and horizontal sections, the acceleration levels, contact forces, and rotation speeds are investigated. These analyses can constitute guidelines about stabilizer design to minimize vibrations. The novelty of this work is to introduce the geometry details of the stabilizers in the time-domain dynamics to differentiate designs in terms of likelihood to trigger vibrations.
Overcoming friction in sliding mode represents a challenging task when drilling an unconventional well with a long lateral section. Among the possible ways to reduce these frictional forces is to use a surface oscillation tool (SOT). By alternating the rotation at surface between the forward and reverse directions, a part of the friction forces is transferred from the axial to tangential direction. Hence, a better transmission of the weight to the drill bit and increased rate of penetration can be achieved. To take full advantage of this tool, an accurate and fast modeling of the influence of its oscillation characteristics is necessary. The SOT is operated at surface by changing its rotation speed and number of wraps in forward and reverse directions. If these characteristics are underestimated, the torsional oscillationsare quickly stopped by the friction moments, and the rate of penetration is not increased enough. However, if they are over estimated, the torsional oscillations can reach the bent motor, and destabilize the tool face orientation (TFO). In this paper, a full time-domain dynamics model and a simplified model coupled with a stiff-string torque and drag model are used to identity the influence length of the SOT, and hence provide an opportunity to optimize its operating parameters. Full and simplified models are compared to each other to ensure their validity. Namely, the effect of the drillstring-wellbore contact distribution is showed to have a substantial impact on the SOT performance. Consequently, it was proved that optimal SOT characteristics Off-Bottom are generally not enough to overcome the friction when drilling. In addition, the torque and drag model is applied to a real case study of an unconventional well with surface and downhole data. It helps provide the driller with a guideline of recommendations on the SOT parameters. These results open some very interesting perspectives in terms of TFO accuracy and slide optimization. The use of modelling in the calibration of the SOT characteristics and the development of the simplified model are both novelties introduced here. This work should lead to significant improvement to extend the length of laterals with steerable mud motor with minimum tortuosity.
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