Harding field: a North Sea success story – part 3
W. McLellan
Part 3 – Use of drillstring vibration analysis systems proved helpful in lowering drilling costs. They enabled engineers to identify areas where steps could be taken to minimize destructive vibrations
One very important area that the BP Harding Team identified early on as being a sector where considerable costs could be saved was Drillstring Vibrational Dynamics Reduction. Downhole vibration can be extremely high in magnitude and can occur over very long periods of time. Destructive vibrations can have considerable costly effects on the drilling process and budget.
Reduced vibration often translates into reduced drilling costs through reduced drillstring failure, and reduced fishing and sidetrack risk (and therefore cost). Concurrently, there is an improved rate of penetration performance and greater bit/downhole tool longevity (which again means cost reduction).
To this end, BP Harding undertook to utilize a commercially available, downhole tool system, and a surface analysis system, to help identify and understand problematic areas. Team members wanted to iron out such problems, so that drillstring failure would be nullified (or at least minimized), and drilling performance would improve. Both, therefore, would improve drilling cost performance.
The advantages of drillstring vibrational dynamics reduction (particularly those vibrations relating to destructive frequencies) are fairly well known and documented in appropriate literature. This article shows how the Harding Team used the Lessons Learned/Drilling Management system to improve operations-from a drillstring vibration point-of-view – for successive wells. This enabled improvements to continually impact the drilling cost bottom line.
POTENTIAL BENEFITS OF SYSTEMS USAGE
The key benefit in using both downhole-based and surface-based tool systems to identify and minimize sources of vibration is to gain a reduction in drilling costs. This can be through a decrease in tripping due to BHA component/tubular/bit failures; a reduction of tripping caused by low bit life/poor bit performance; and a lowering of refurbishment costs of drillstring components. Due to the potential optimization of BHA/drillstring/drillbit design, both ROP and durability/longevity of system components is optimized.
Because all of these factors have a significant impact on drilling cost reduction, they are crucially important and should be studied in detail. For that reason, BP Harding undertook to ascertain, through study, just what was happening downhole so that the complete drilling system could (if necessary) be optimized on future wells.
OVERVIEW OF SYSTEMS
Downhole vibration can be detected on surface in real time, using System I with negative pulse MWD tools (FEWD). Looking at an overview of System 1, tri-axial, mutually orthogonal accelerometers are used to measure the X, Y & Z axes of accelerations that correspond, respectively, to lateral and radial, lateral and tangential, and axial vibration detection, Fig. 14. The Z plane accelerometer, measuring axial vibration, is thus able to detect the unwanted characteristics of bit bounce, for example.
The X & Y accelerometers are able to detect lateral vibration and shock, and torsional stick-slip vibrations. The accelerometers typically are rated for ca. 200 g-force, with a frequency response range of 100 to 2,000 Hz and a resolution of 0.2 g.
A downhole microprocessor and 512 KB of memory are utilized for the processing and storage of data. The data from all three accelerometers are recorded downhole, having been read by a surface computer at the end of the bit run.[1,2]
The system subsequently has been modified, so that vibration data over a pre-determined threshold is automatically transmitted to surface. The vibration data is transmitted in conjunction with other pertinent formation evaluation and directional drilling data.
Overview of System 2 (surface system). A second system also was utilized, specifically for monitoring torsional vibrations.[3] System 2 has proven to show good correlation in 12 1/4-in. hole.[4] The system is essentially a well site computer program, where data is monitored from drilling sensors. The data can be analyzed and then processed to provide a real-time display of the magnitude of torsional vibrations in the drillstring. The driller then can reduce or eliminate the problem by varying WOB or RPM, accordingly.
In BP Harding, this system was used principally in a manner similar to System 1; i.e., in recording mode, only, for post-well analysis purposes. However, a torsional vibration magnitude display was available for real-time monitoring.
TYPICAL RESULTS
From this program centered on reducing drillstring vibration, a number of results were obtained.[5] One typical example involves vibration, and its relationship with the formation drilled and bit whirl. System 1 indicated that there was minimal vibration until the top of the Grid Sandstone Member was reached at around 3,355 ft, MDBRT. As soon as the top of the sands was penetrated (as indicated by the Gamma Ray Trace), medium-to-high-severity lateral and axial vibrations were experienced, Fig. 15.
The vibration severity was higher in the sands than in the more shaley horizons. In this instance, vibration was lower when drilling in oriented mode as compared with drilling in rotary mode. Vibration also was sensitive to changes in WOB – increased vibration generally correlated with reduced ROP.
The assembly was slick, with a PDM incorporating an ABH (Adjustable Bent Housing) that was set at 1.5 [degrees]. It was intended that the six-bladed PDC would, hopefully, be able to drill the entire, 12 -in. hole section in one run, something that had not been achieved with the tungsten carbide insert rock bits used previously.
Periodic medium-to-high-severity vibration continued for the remainder of the run. It was particularly high between 3,555 ft and 3,610 ft, MDBRT. Bit whirl was detected at around 3,410 ft, MDBRT. The frequency of whirl in the X & Y axes was close to six times the RPM. This indicates six impacts per revolution, which is consistent with whirl being generated by the six-bladed PDC bit used.
After withstanding about three hours of severe vibration, the PDM backed off at the ABH (point of maximum impact loading). Retrospective analysis shows the failure coincided with drilling hard stringers via an aggressive PDC bit. The initial solution in this instance was to apply thread-locking compound to the ABH and use insert rock bits with a PDM, rather than use aggressive-type PDC bits.
System 2 also was run. It indicated an alarm immediately prior to the failure, and one of System 1’s bursts of whirl virtually coincided with the failure. The main cause of the vibration appears to have been bit/formation interaction with the PDC bit’s design, making the bit/system inherently unstable and susceptible to whirl.
The aggressive cutter arrangement most likely would cause it to “dig in” to the formation, with the ensuing reactive torque prompting the motor body to try to turn against itself as the bit held the stator firm. Meanwhile, the torque applied at surface would try to turn the system in the opposite direction, causing severe cyclical loading downhole and excessive stress on the BHA components, resulting in failure.
The use of a less aggressive PDC bit (with anti-whirl features), combined with a higher-torque/higher-speed motor, has subsequently proven to be a solution for the drilling of the 12 1/4-in. hole section. This particular failure resulted in an expensive sidetrack, because it was considered too difficult to fish the parted motor. The well was plugged back to the 13 3/8-in. shoe.
Confirmation. The above was confirmed by the next BHA run, which utilized the same aggressive PDC bit, slick BHA and PDM (although the ABH was reduced from 1.5 [degrees] to 1.375 [degrees] to make the build tendency less aggressive). One should realize, of course, that the vibrational post-analysis work had not yet been carried out-data was still being acquired.
Again, drilling was largely uneventful until the Grid Sandstone Member was penetrated. There, a virtually identical pattern of vibration was noted – it again varied with changes in WOB, Fig. 16. Note how much vibration increases when the bit tags bottom, suggesting harsh interaction with the PDC cutters and the formation, Fig. 17.
Background vibration is higher when drilling in oriented mode, as compared with rotating off bottom, Fig. 18. This suggests that the bulk of the downhole vibration is the result of bit-to-formation interaction due to the bit’s aggressiveness. The area of bit aggressiveness and bit design will be covered later in Part 5 of this article series, where it will be seen that ideally designed bits can improve, rather than binder, performance. Nevertheless, it can be concluded that aggressive, symmetrically-bladed PDC bits encourage whirl and, in turn, destructive vibration, particularly in hard formations. Thus, bit selection is crucially important.
BHA Stabilization. This factor is particularly important when drilling the 8 1/2-in. horizontal sections, especially for directional control reasons. However, its importance in the 12 1/4-in. section also cannot be understated.
Regarding the 8 1/2-in. hole section, there was a period of excessive vibration when the third full-gauge stabilizer was the only stabilizer adjacent to a hard, calcite cemented zone, Fig. 19. This correlation was noted over a number of intervals. When this occurred, vibrations were lateral and axial, and the variance in torque indicated a torsional element, also. High lateral movement adjacent to any stabilizer (especially the near-bit) will induce vibration.
Where hard, calcite cemented zones have been spaced particularly close together, it is not always possible to separate out individual impacts. In such situations, multiple simultaneous impacts cause periods of complex, high severity vibration.
Interestingly, there also were occasional periods of low vibration which were not related to drilling parameter changes, Fig. 20. In the chart, it appears that spacing between the hard, calcite cemented stringers was such that there was a stabilizing effect on the BHA. The torque was highly variable over the first part of the interval of low vibration.
WOB, RPM and BHA. There also were examples, where changes in drilling parameters (WOB, RPM and BHA selection) induced changes in vibration severity. In one particular instance, the effect of reducing RPM and increasing WOB actually resulted in reduced levels of vibration.
Other areas. There are, of course, many other areas that have been studied. Regretfully, there is not sufficient space in an article of this nature to cover everything. Suffice to say, that as more and more areas are studied, and more and more tentative conclusions are proven, more preventative actions can be taken with resulting cost reductions in the drilling process.
LITERATURE CITED
1 “Development and field testing of a new downhole MWD drillstring dynamics sensor,” SPE paper 26341.
2 DDS hardware description, Sperry-Sun Drilling Services, May 14, 1996.
3 Halliburton DrilSaver Torsional Vibration Control Information Bulletin H00140, Halliburton Energy Services, Inc., January 1997.
4 Smith, Mark, and Irvine, George, “BP Harding Drilling Optimization Drillstring Dynamics Sensor Vibration Report,” Sperry-Sun Drilling Services for Halliburton Energy Services/BP, February 1997.
5 Ibid.
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