New sensor the key

July 1, 2006
A new downhole torsional vibration sensor built into a rotary steerable system provides a monitoring system for improving drilling efficiency and avoiding downhole failures related to torsional vibration.

Improving drilling efficiency and avoiding torsional vibration downhole failures

David C-K Chen, Blaine Comeaux, Graeme Gillespie, George Irvine, Boguslaw Wiecek - Halliburton Sperry Drilling Services

A new downhole torsional vibration sensor built into a rotary steerable system provides a monitoring system for improving drilling efficiency and avoiding downhole failures related to torsional vibration. The advantage of Halliburton’s new sensor is that it measures rotational changes at the bit, not 50-100 ft behind the bit as with conventional MWD/LWD sensors.

Since rotary steerable systems (RSS) routinely are used in the most expensive drilling operations, operators expect significant cost savings. However, because of the greater number of moving parts in rotary steerable systems, the level of reliability has been below that of measurement-while-drilling (MWD) and logging-while-drilling (LWD) systems, particularly when operating in high vibration environments. In some cases, the high cost of trips and tool repairs due to tool failures has compromised the economic benefit of RSS technology.

Torsional vibration

The industry has studied downhole vibrations, particularly torsional vibration (or stick-slip), extensively. The service industry’s downhole monitoring systems shed light on the dynamic drillstring motions with bit rotation speeds as high as 300%-400% more than surface RPM. However, a complete picture of the BHA (Bottom Hole Assembly) behavior would require downhole vibration sensors than can:

  • Detect and accurately measure the range of dynamic motion, including axial, lateral, and torsional vibration
  • Alert operators of dangerous vibration levels in real-time so changes can be made before severe damage occurs on the drillstring / bottom-hole assembly
  • Record higher density data for detailed post-run vibration analysis to pinpoint the modifications to the bit, or BHA can be made in the future
  • Monitor at different points in the drillstring

Operators avoid vibration sensors because of limited drilling budgets or reluctance to pay for additional services. This results in gaps in the data needed to investigate tool performance. In order for a service company (SC) to make fair performance comparisons to offset wells, good vibration data must be available.

The SC can measure the low-frequency torsional vibration, usually below 5 Hz (stick-slip), on the surface from the rotary torque oscillation. However, high-frequency torsional vibration (>50 Hz) will not transmit to the surface.

On the other hand, more use of extended gauge bits with their inherent bit stability and hole quality advantages has improved bit life and reduced bore friction, thus reducing the tendency of the BHA to induce stick-slip. While these are improvements, there are instances of stick-slip. The fact that rotary steerables are designed to allow 100% rotation of the drillstring means these systems have more exposure to torsional vibration. When an operator observes torsional vibration, a real-time downhole monitoring system becomes critical to minimize tool failures.

Torsional monitor

The SC has developed a new torsional efficiency monitor (TEM) that uses an rpm sensor embedded in the rotary steerable system as a direct indicator of bit rotational behavior. The sensor data is analyzed to monitor bit speed and to determine whether rotation is smooth or oscillating, and to what degree.

The torsional efficiency monitor measures rotational changes at the bit, not the usual 50-100 ft behind the bit as with conventional MWD/LWD sensors.
Click here to enlarge image

The SC learned a critical lesson in high levels of torsional vibration: system energy must be dissipated before picking the assembly off bottom. If the operator suddenly lifts the bit while chaotic motion continues, the energy stored in the drillstring releases dangerously high lateral shock levels and increases downhole failures. All personnel are advised to slow down or stop the rotary speed completely before picking up the string.

Operators recognize the benefit of this sensor is that it measures rotational changes at the bit rather than the usual 50-100 ft behind the bit as with most MWD/LWD sensors. In addition, it is at the same location regardless of BHA configuration for more consistent data measurement and less data ambiguity. The SC added more consistency to the measurement of the lower end of this particular rotary steerable BHA from well to well around the world for a given hole size. Thus, this monitor provides an objective evaluation of bit performance and the effectiveness of specific design changes.

Graph indicates the torsional vibration from the dominant spike seen in the Y-axis acceleration.
Click here to enlarge image

Operator’s use of this system in the field, particularly when pulsing real-time data, resulted in improvement in rotary steerable performance and reliability. The SC recognizes two main limitations of all downhole measurements: the bandwidth available to transmit downhole measurements to the surface; and, the detection of transmitted data at surface. Additionally, extremely high levels of vibration interrupt real-time data transmission. Under these conditions, the SC recommends a surface torsional vibration detection system to monitor stick-slip transmitted to the surface. However, high frequency torsional vibrations that do not reach the surface still may damage downhole tools.

Case history

An operator drilled wells on three projects (A, B, and C) in the central North Sea. The SC’s rotary steerable tool drilled the 121⁄4-in and 81⁄2-in hole sections. The wells had vertical and deviated intervals, and a relatively shallow chalk section with varying rock strength throughout the interval. The operator recognized that this sequence generated harsh drilling conditions, specifically high levels of both lateral shocks and stick-slip. Prior to introduction of the rotary steerable system, the SC matched drilling systems consisting of an extended gauge bit and a modified positive displacement motor that reduced lateral shocks.

Project A

In the initial project with the rotary steerable system, the operator ran a standard MWD vibration sensor with 3-axis accelerometers to monitor downhole vibration. The SC observed some lateral vibration indicated in the real-time lateral accelerations but at relatively low levels. Also observed were multiple symptoms of torsional vibration such as cyclical fluctuations of the surface torque, surface rotary speed, and downhole differential pressure as measured by the PWD (pressure-while-drilling) sensor. However, SC observed similar symptoms on other projects with no significant increase in downhole tool failure rate. The project experienced multiple failures of a specific component in the RSS, leading to a number of premature trips and significant non-productive time and repair cost. Of 16 runs with the rotary steerable, there were eight failures that required trips. In all cases, the post-run failure analysis revealed consistent downhole torsional vibration wear patterns on the tool.

SC’s post-well analysis of the recorded, higher density vibration data uncovered a high amplitude spike at 195 Hz on the Y-axis, which is most sensitive to high-frequency torsional vibration. This 195 Hz high torsional frequency is far above the usual 0-5 Hz frequency from stick-slip. The high-frequency torsional vibration most likely was generated by interaction between the cutters on the bit and the formation. In addition, the frequency is far higher than the natural frequencies of the BHA components, indicating that BHA resonance was not a source of excitation. SC concluded that the torsional vibrations at this high frequency tend to be absorbed by the drillstring, and not transmitted to the surface.

SC attempted to reduce the vibration level by selecting a different bit design for the later runs. The initial runs used a 7-bladed bit with 16 mm (3/4-in) PDC cutters. Operator’s subsequent runs using a less aggressive 8-bladed bit with 13 mm (1/2-in.) cutters with an improved extended-gauge area reduced vibration levels without reducing rate of penetration.

Project B

Following project A, the SC redesigned the area affected in the rotary steerable system and made it more rugged. At the same time, the SC introduced a torsional efficiency monitor for field testing. In project B, the rotary steerable system survived an extremely long run through the chalk sequence, doubling the endurance of the tool. During the first two runs, the operator’s drilling team monitored the new information from the torsional efficiency monitor to establish optimal drilling parameters. Overall project performance was improved by 34% compared to the first project, and no further failures occurred for the remainder of the well.

Project C

In Project C, the SC’s combination of ruggedized tool and real-time alarms from the new torsional efficiency monitoring system resulted in rotary steerable success and no lost time. Neither of these improvements completely prevents stick-slip. However, having a real-time alarm indicating that torsional vibrations are present, including both stick-slip and higher frequency torsional vibration, improved the operator’s and SC’s ability to manage this issue and reduce risk of damage.

These cases show that the monitor in a rotary steerable system improves performance and lowers drilling cost. The operator can see the effect of bit designs more accurately measured, which should accelerate the learning curve in each new drilling area.

The operator developed best practices and optimized drilling parameters to mitigate torsional vibrations in areas with known stick-slip. Other areas have confirmed the drilling problem and quantified its size to at least operate at the lowest end of the spectrum.

Because the sensor is fixed in the bottom-hole assembly and the rotary steerable configuration is consistent throughout the world, the new sensor should serve as an excellent controlled data acquisition system to compare drilling performance.

Acknowledgements

The authors wish to thank the management of Halliburton Co. for permission to publish this paper. We would also like to thank Jeremy Greenwood for his significant contribution to the development of this new sensor.

Editors Note: This is a summary of IADC/SPE 99193 paper presented at the drilling conference in Miami, Florida on Feb. 21-23, 2006.