Resolving Torsional Vibration in Limestone Reservoirs Reduces Equipment Damage
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Torsional vibration (also known as stick/slip) is a major contributor to equipment failure and severe damage when drilling the 6.125-in. lateral limestone Shuaiba reservoir section. This paper examines multiple factors that can affect the severity of stick/slip and measures their actual effect. These factors include bit and bottomhole assembly (BHA) design and formation and mud properties. The authors examined the effect of using a software plugin to an automated drilling system to mitigate stick/slip when drilling the 6.125-in. lateral section.
Before the deployment of rotary steerable systems (RSS) in the Shuaiba reservoir section, all directional sections (12.25-, 8.5-, and 6.125-in.) had been drilled with positive displacement motors (PDMs), but with the implementation of RSS, the operator achieved dramatically reduced well-delivery time. In the 12.25- and 8.5-in. sections, the shale and shallow limestone formations did not introduce any negative effect on drilling mechanics along with the change in the directional drive. In the lateral reservoir section (6.125 in.), stick/slip became more severe and resulted in higher costs. It was vital to identify the root cause of, and to implement preventative measures for, the damage.
Controllable factors related to stick/slip in the bit/BHA design include type of drillpipe, the directional drive used, and stabilization. Fig. 1 shows a significant change in stick/slip behavior between two different bit designs in simulations.
Type of Drillpipe Used in Horizontal Drilling. In long lateral sections, drillpipes of 3.5 or 4 in. occupy most of the drillstring below the 7-in. liner hanger. Generally, the larger the size of the drillpipe, the higher the makeup torque limit. In terms of shocks and vibration, the purpose of having a larger drillpipe size is to stiffen the BHA and reduce the overall vibration of the drillstring. Upgrading to larger drillpipe size offers further improvement from a hydraulics perspective. The standpipe pressure drops because of the increase in the tubular inside diameter; furthermore, hole cleaning improves with larger pipe size.
Directional Drive (Motor or RSS). The two available directional-drive options in this application are PDM and RSS. The RSS is preferable for the long lateral section in this case. The RSS creates a borehole with a higher integrity because it does not create microdogleg severity. However, a PDM system is more reliable in delivering directional requirements quantitatively. The motor can generate a higher rate of penetration (ROP) than RSS tools, with a lower rate of surface rev/min.
Stabilization. Stabilizers have a size clearance of 0.125 to 0.25 in. compared with the size of the borehole. As the drillstring rotates, the stabilizers act as centralizers that are in contact with the sides of the borehole most of the time. The friction can introduce severe stick/slip from the stabilizers’ contact. Introducing a stabilization point can, on the other hand, restrict the lateral movement of the string at that point.
Mud and Formation Properties. Mud and formation properties are factors that cannot be controlled or are difficult to control. Formation properties such as density and interbedding can contribute to stick/slip. Mud properties can also be factors in stick/slip, but, for various reasons, are difficult to change.
Finite-Element Analysis (FEA) of Proposed Solutions
The modeling software used to simulate the changes in BHA, and the corresponding drilling mechanics, is based on FEA. This allows time-based simulations of the complex drilling process that include 4D (3D+time) modeling of the entire drillstring; bit/rock interaction; vibrations, stresses, and forces with six degrees of freedom; and predictions of bit performance.
To gauge the effect of bit features on stick/slip, two major aspects of the bit design were examined. The commonly used polycrystalline diamond (PDC) bit design in the field has five blades and 16-mm cutters (referred to as 516). FEA simulations were run to compare and contrast the dynamic drilling characteristics of the PDC bits examined, which were the first bit (516)—the main bit used in the field—and the proposed bit, which had six blades and 13-mm cutters (referred to as 613).
Simulation Result. FEA results showed that the 613 bit has less rev/min fluctuation compared with the 516 bit in the same environment. With 80 rev/min for the 613 compared with 120 rev/min for the 516 bit, the result promises roughly 33% less stick/slip.
Actual Results. The two types of bits were compared by analyzing eight wells, four of which were drilled with the 516 PDC bit and four with the proposed 613 bit. The results did not agree with the simulations because it appears that, in this formation, stick/slip levels varied from 100 to approximately 250% in both bit types. The new bit also surprisingly induced more lateral shocks in measurement-while-drilling and logging-while-drilling tools, which increased the risk of equipment failure and fatigue. ROP, on the other hand, had a steep drop with the 613 bit. Although the drop was logically expected, there was no tangible improvement in the levels of torsional vibration. These results indicated that the bit was not the main contributor to the stick/slip environment.
The 6.125-in. horizontal hole section in the Shuaiba reservoir generally is drilled with an RSS and a PDC bit. The dominant tubulars are slim drillpipes that generally lie on the lower side of the lateral section. All of the wells had been drilled before the study using 3.5-in. drillpipes below the 7-in. liner shoe. Theoretically, 4-in. drillpipes are much stiffer and have greater buckling margins compared with those of 3½-in. drillpipes. Simulation results have shown that using 4-in. drillpipes will reduce the overall fluctuation in rev/min, which directly reduces the level of stick/slip.
Drilling Results. After drilling multiple wells with 3.5-in. drillpipes, a drilling campaign was performed with 4-in. drillpipes. The use of these drillpipes decreased the standpipe pressure by approximately 30% at the same flow rate, given that the drillstring consists primarily of the smaller drillpipes. Although these larger drillpipes provided multiple advantages, the upgrade did not solve the stick/slip by the amount expected from the FEA.
Motorized RSS. Because bit interaction with the formation made the greatest contribution to stick/slip generation, introduction of a downhole drive system was proposed. This system would provide the power and rev/min to overcome the torsional vibration from the bit. This would also reduce the load on the rest of the BHA equipment by running the equipment at lower rotational speeds and minimizing the exposed fatigue cycles. After examining the effect of adding a downhole motor to the BHA and confirming the benefit through simulations, the proposed BHA was implemented in three fields in the 6.125-in. hole section as a trial to reduce stick/slip while drilling. PDC bits with five blades and 16-mm cutters were used in these trials. Motorized RSS trials showed a significant reduction in stick/slip levels. The results reflected the anticipated behavior of the BHA that was suggested by the FEA. Furthermore, ROP of the wells drilled with motorized RSS BHA was approximately 40% higher than that of the wells drilled with the nonmotorized RSS BHA.
Software Plugin for Mitigating Torque. Apart from BHA design and improvement in the drillstring, one of the globally known approaches to eliminate downhole stick/slip damage is the use of software designed to mitigate torque. The concept behind the software plugin is to help stop the flow of torsional energy up and down the drillstring. The software controls the rotary table motion; thus, vibrations in the drillstring are dampened instead of reflected. The software reduces the likelihood of an unnecessary trip because of a worn-out bit, tool failure, or drillstring damage. Software systems have historically worked well in reducing torque in deep vertical gas wells.
On the basis of experience from deep vertical wells in the 8.375-in. section, the next step was to test the software plugin on the 6.125-in. horizontal section of the Shuaiba limestone reservoir. Unlike the experience in the deep vertical wells, the stick/slip levels remained high and no improvement was achieved. Wells drilled without the software plugin showed a variation of approximately 90 rev/min between stick/slip measurements. However, wells drilled with the software plugin had a higher variation of nearly 130 rev/min.
From these trials, it is fair to conclude that, although it is highly efficient in deep vertical bigger boreholes, the software plugin system did not provide a tangible improvement in the lateral limestone Shuaiba reservoir.
The purpose of the trial analysis was to identify the root cause of torsional vibration (stick/slip) in the lateral section of a limestone reservoir of Shuaiba and to determine the best measures to drastically reduce, if not eliminate, such vibration.
The introduction of a motorized RSS had a significant effect; stick/slip levels were reduced to nearly half the nominal values seen in a conventional RSS BHA. The motorized RSS solution offered a significant reduction in the level of equipment damage. When trying to duplicate the experience of the software plugin from deep vertical 8.375-in. borehole to the 6.125-in. lateral limestone borehole, however, the results were not promising. The stick/slip levels remained high in general, with wider rev/min fluctuations.
Resolving Torsional Vibration in Limestone Reservoirs Reduces Equipment Damage
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