Real-Time Advisory System Mitigates Drilling Vibrations in a Lateral Section
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A real-time drilling-data analysis and recommendation system that leverages surface drilling data was deployed in a lateral section of a well from an artificial island in Abu Dhabi. A key objective of this technology was to provide the driller with an easy-to-use display of a novel drilling-performance map. This paper presents data from the demonstration run, illustrates the features of this technology, and provides general observations on optimization of drilling parameters in this hole section.
A research prototype drilling advisory system (DAS) was set up on an island rig with a wellsite information transfer specification (WITS) data feed from the mudlogger cabin over a fiber-to-serial cable to the computer in the driller’s cabin.
The DAS helps the driller make decisions for managing controllable drilling parameters to enable a high rate of penetration (ROP) and low vibrations. The system uses surface data only (i.e., data obtained from sensors instrumented on surface equipment) from the mud logger. The platform then analyzes the data and displays basic surveillance information, including heat maps that vary with the controllable drilling parameters. On the basis of this data and processing algorithms, the system makes recommendations for the controllable parameter values.
Data from three intervals were analyzed, and two of the three saw contrasting trends of stick/slip [torsional severity estimate (TSE)] and mechanical specific energy (MSE) with increasing rotary speed, whereas one interval did not see such a trade-off. The complex interplay between these dysfunctions requires an application-specific real-time advisory system to provide optimal drilling performance.
The control variables for this drilling application were ROP and rotary speed.
Intervals for Data Analysis
The 8½-in. drilling interval started from the 9⅝-in. casing shoe at 13,916 ft, and section total depth was called at 23,974 ft. Drilling data from this interval was subdivided into seven intervals corresponding to drilling tests, with parameter recommendations from the DAS analysis.
Examples of Drilling-Parameter Optimization
To initiate the DAS, the driller conducts a drilling test by starting the calibration mode on the advisory system to reset the system memory. Parameter set-point values then must be maintained relatively constant for a time sufficient to determine good average values for the drilling response. The advisory system requires a statistically significant sampling of data at stationary parameter values. When several such calibration points have been recorded, the system then provides automated analysis of the drilling test for the span of operating parameters. If the formation changes over this interval substantially, the calibration process should be repeated.
Drilling Test in Interval 1. A drilling test conducted in Interval 1 showed a significant decrease in stick/slip vibration for a small increase in rotary speed.
It should be noted that (1) stick/slip could be mitigated in this interval by increasing rotary speed and (2) better results were obtained at higher ROP.
Drilling Test in Interval 3. Another drilling test was conducted in Interval 3. Both the MSE and the composite objective-function trend better for lower rotary speeds and higher ROP values. In this interval, the objective function was dominated by MSE because that had the greatest variation in this parameter range.
Drilling Test in Interval 5. A subsequent drilling test in Interval 5 reiterated this conclusion, wherein the summary objective function responds to the parameter that has the most dysfunction improvement. Looking separately at the TSE and MSE components reveals that MSE has more response parameter variation than TSE within this drilling test. In this example, the parameters at the optimal objective function operating point reflect MSE more than TSE.
Drilling Test in Interval 6. In Interval 6, severe drilling dysfunctions were indicated by downhole shock and vibration measurements at approximately 18,800 ft and the service provider required parameter changes. A drilling test was conducted that held high ROP but primarily varied the rotary speed. As seen in prior drilling tests beyond 17,000 ft, little change was seen in stick/slip vibrations as rotary speed changed; however, the downhole tools recorded a significant reduction in lateral shocks at lower rotary speeds.
With diminished lateral vibrations, the amplitude of any coupled vibration modes that convolved stick/slip and whirl also were mitigated. The result was surprising to the drilling crew, and, although the greatest vibration mitigation was achieved at 100 rev/min, this was not a comfortable operating parameter value. Concern soon arose regarding the possible side effects of low rotary speed on hole cleaning, and the rotary speed was increased to 110 rev/min.
With no discernible increase in equivalent circulating density (ECD), the rotary speed was later increased to 130 rev/min and held for approximately 2,000 ft. This is a rare example where the limiter to vibration mitigation was essentially a perception that hole cleaning might be compromised at lower rotary speeds, without data showing that a hole-cleaning problem was developing.
Drilling-Vibration Limiting Conditions
Typically, a tradeoff in drilling performance between lateral and stick/slip vibrations may be expected. Lateral vibrations are often represented by MSE and downhole vibration measurements. Stick/slip can be determined from surface torque data and downhole drilling tools. In most sections, the following are observed:
- Increasing rotary speed tends to reduce stick/slip, and increasing weight on bit (WOB)/ROP while decreasing rotary speed increases stick/slip.
- Increasing WOB/ROP at a lower rotary speed tends to reduce lateral vibrations and whirl, whereas reducing WOB or ROP and increasing rotary speed generally increases lateral vibrations.
- The overall balance between these factors often, but not always, creates a stable zone at intermediate rotary-speed and WOB/ROP values.
In this section, it was not possible to mitigate stick/slip after approximately 7,000 ft measured depth, which is a phenomenon that may occur in some laterals but may not be the general case.
- Only a slight reduction in stick/slip was seen at higher rotary speeds. In fact, stick/slip was seen off bottom, with zero WOB.
- Increasing WOB/ROP at a lower rotary speed reduced lateral vibrations and whirl, and reducing WOB/ROP and increasing rotary speed increased lateral vibrations.
- The balance between these factors led to a preferred operating zone at lower rotary speed and higher WOB/ROP values, which is not stable in the classic sense. It is better than the alternative, but stick/slip persists.
The balance between these factors of stick/slip and lateral vibrations is typically different for different hole sections, and a data-driven system can help identify the best parameters within the constraints of the specific operating conditions. The transition point in this well was approximately 17,000 ft but could be significantly different, or even nonexistent, in other wells. Furthermore, the critical rotary speed associated with the lateral vibration transition can vary, even as the stick/slip tradeoff also may change in different wells. The advisory system identified and documented this change in operating zones, leading to guidelines for consideration in the forward drilling program.
A project to design a driller-friendly user interface and implement enhanced usability features recently concluded. A view of the application and identification of the interface elements is provided in Fig. 1.
With positive field results in this and other field applications, the technology is now being deployed more broadly. The system can be used on any rig through the WITS data feed, just as it was used in the prototype deployment. When used with the vendor’s electronic data recorder, it is available as an integrated application. In standalone deployments, a bidirectional communication link provides data to the system and returns data from the advisory system to the surface data logger. This output comprises the recommended control variables (e.g., WOB, rotary speed, ROP) as well as the stick/slip index, MSE, and depth-of-cut values.
This field application of a prototype DAS yielded surprising results. Although the operator considered that the tool might not have a role in a lateral application in which the formation is relatively constant, distinct vibrational regimes were identified. Unknown was the fact that stick/slip vibrations would be sensitive to rotary speed initially and that stick/slip would become significantly less sensitive to rotary speed further out in the lateral.
This fact enabled optimization in the deeper section that was not previously under consideration by the operator or service provider. Rotary speed was reduced to mitigate lateral vibrations (and increase WOB) and a high ROP was maintained. The relatively low values of rotary speed gave rise to hole-cleaning concerns that were not substantiated by data because no evidence was seen of an abnormal increase in ECD in the recorded data. Rarely does hole cleaning limit vibration mitigation by setting an effective lower bound on rotary speed.
The DAS embodies a portion of the technology of the operator’s ROP-management process that has proved to be of significant commercial value.
Real-Time Advisory System Mitigates Drilling Vibrations in a Lateral Section
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