Parameter Definition Using Vibration Prediction Software ...

Copyright 2012, Brazilian Petroleum, Gas and Biofuels Institute - IBP This Technical Paper was prepared for presentation at the Rio Oil & Gas Expo and Conference 2012, held between September, 17-20, 2012, in Rio de Janeiro. This Technical Paper was selected for presentation by the Technical Committee of the event according to the information contained in the final paper submitted by the author(s). The organizers are not supposed to translate or correct the submitted papers. The material as it is presented, does not necessarily represent Brazilian Petroleum, Gas and Biofuels Institute’s opinion, or that of its Members or Representatives. Authors consent to the publication of this Technical Paper in the Rio Oil & Gas Expo and Conference 2012 Proceedings.

______________________________ 1 Master in Petroleum Engineer - Western Hemisphere Training Instructor - National Oilwell Varco 2 Mechanical Engineer – Senior Software Project Leader – National Oilwell Varco 3 Mechanical Engineer – Optimization Leader – National Oilwell Varco 4 Master in Drilling Engineer – Drilling Solutions Engineer – National Oilwell Varco

5 Mechanical Engineer – Drilling Engineer Consulter – Petróleo Brasileiro S.A. 6 Petroleum Engineer – Drilling Engineer Consulter – Petróleo Brasileiro S.A. 7 Petroleum Engineer – Drilling Engineer – Petróleo Brasileiro S.A.

IBP1282_12 PARAMETER DEFINITION USING VIBRATION PREDICTION

SOFTWARE LEADS TO SIGNIFICANT DRILLING PERFORMANCE IMPROVEMENTS

Dalmo Amorim1, Chris Hanley2, Isaac Fonseca3, Juliana Santos4, Daltro J. Leite5, Augusto Borella6, Danilo Gozzi7

Abstract The understanding and mitigation of downhole vibration has been a heavily researched subject in the oil industry as it results in more expensive drilling operations, as vibrations significantly diminish the amount of effective drilling energy available to the bit and generate forces that can push the bit or the Bottom Hole Assembly (BHA) off its concentric axis of rotation, producing high magnitude impacts with the borehole wall. In order to drill ahead, a sufficient amount of energy must be supplied by the rig to overcome the resistance of the drilling system, including the reactive torque of the system, drag forces, fluid pressure losses and energy dissipated by downhole vibrations, then providing the bit with the energy required to fail the rock. If the drill string enters resonant modes of vibration, not only does it decreases the amount of available energy to drill, but increases the potential for catastrophic downhole equipment and drilling bit failures. In this sense, the mitigation of downhole vibrations will result in faster, smoother, and cheaper drilling operations. A software tool using Finite Element Analysis (FEA) has been developed to provide better understanding of downhole vibration phenomena in drilling environments. The software tool calculates the response of the drilling system at various input conditions, based on the design of the wellbore along with the geometry of the Bottom Hole Assembly (BHA) and the drill string. It identifies where undesired levels of resonant vibration will be driven by certain combinations of specific drilling parameters, and also which combinations of drilling parameters will result in lower levels of vibration, so the least shocks, the highest penetration rate and the lowest cost per foot can be achieved. With the growing performance of personal computers, complex software systems modeling the drilling vibrations using FEA has been accessible to a wider audience of field users, further complimenting with real time field monitoring. Vibration prediction diminishes the importance of trial-and-error procedures such as drill-off tests, which are valid only for short sections. It also solves an existing lapse in Mechanical Specific Energy (MSE) real-time drilling control programs applying the theory of Teale1, which states that a drilling system is perfectly efficient when it spends the exact energy to overcome the in situ rock strength. Using the proprietary software tool this paper will examine the resonant vibration modes that may be initiated while drilling with different BHA’s and drill string designs, showing that the combination of a proper BHA design along with the correct selection of input parameters results in an overall improvement to drilling efficiency. Also, being the BHA predictively analyzed, it will be reduced the potential for vibration or stress fatigue in the drill string components, leading to a safer operation. In the recent years there has been an increased focus on vibration detection, analysis, and mitigation techniques, where new technologies, like the Drilling Dynamics Data Recorders (DDDR), may provide the capability to capture high frequency dynamics data at multiple points along the drilling system. These tools allow the achievement of drilling performance improvements not possible before, opening a whole new array of opportunities for optimization and for verification of predictions calculated by the drill string dynamics modeling software tool. The results of this study will identify how the dynamics from the drilling

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system, interacting with formation, directly relate to inefficiencies and to the possible solutions to mitigate drilling vibrations in order to improve drilling performance. Software vibration prediction and downhole measurements can be used for non-drilling operations like drilling out casing or reaming, where extremely high vibration levels - devastating to the cutting structure of the bit before it has even touched bottom - have been measured by DDDR tools. A variety of case studies, incorporating the results of the software-based vibration analysis and measured downhole data, will demonstrate solid improvements in terms of time and cost savings, improved dull conditions and record setting in areas where the software was used for the first time.

1. Fundamentals The natural frequency of a mechanical system is defined as the frequency at which it will oscillate in free vibration after an input is applied to the system with no additional driving motion forcing it. If we examine a simple mass, spring, damper system in translational motion with one degree-of-freedom; the undamped natural frequency of the system can be calculated using the following equation2:

M

kn

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n (rad/s) is the Undamped Natural Frequency

k (N/m or lbf/ft) is the System Stiffness

M (kg or lbm) is the System Mass

As there is always some level of damping in practical mechanical systems, the quantity above serves primarily as a theoretical value to describe the natural motion of the system with no damping. However, this value is related to the natural frequency of the system with damping and also to the input frequency at which the system would resonate in forced vibration. If we examine the same simple mass, spring, damper system in translational motion with one degree-of-freedom; the damped natural frequency of the system can be calculated using the following equation2:

21* nd

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d (rad/s) is the Damped Natural Frequency

n (rad/s) is the Undamped Natural Frequency

( ) is the Damping Ratio (defined below)

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c

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cc (N*s/m or lbf*s/ft) is the Critical Damping for the System (defined below)

Mkcc 2

where:

cc (N*s/m or lbf*s/ft) is the Critical Damping for the System

M (kg or lbm) is the System Mass

k (N/m or lbf/ft) is the System Stiffness

Forcing a system into motion with an input frequency close to or at a natural frequency of the system can result in large amplitude outputs that can escalate to destructive magnitudes when left unchecked. This phenomenon is known as


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resonance. The input frequency at which this large amplitude vibration occurs is referred to as the resonant frequency for the system2. Resonance in drilling applications has been previously documented and measured in varied global field cases3, 4.

For simple systems, such the single degree-of-freedom mass, spring, damper system described above; the natural frequency and harmonics can be calculated without too much difficulty using classical methods (assuming the mass, stiffness, and damping for the system can be accurately characterized). However, for mechanical systems with greater complexity, such as a drill string with multiple degrees-of-freedom and various interrelated subsystems, different techniques are required to calculate these frequencies.

Finite Element Analysis (FEA) is a technique that can be applied in cases where a solution is too complicated or inefficient to arrive at by using classical or experimental methods. The fundamental use of FEA is to provide a method to model a system in such a manner that a numerical solution can be found for a specific problem. Common types of problems that can be solved using FEA include: stress analysis, heat transfer, fluid mechanics, and dynamic system analysis5.

The Finite Element Method (FEM) more specifically breaks the modeled system into a finite number of smaller pieces referred to as elements. Each element in the modeled system carries with it specific aspects of the modeled system useful in the solution process (such as component geometries, material properties, boundary conditions, etc.) depending on the problem posed by the analyst. The elements in the model are then joined to one another by points at the element boundaries referred to as nodes. The FEM simultaneously interpolates quantities from node to node until a final solution is converged upon for the entire system to address the problem as modeled by the analyst5.

National Oilwell Varco has developed a custom software application to calculate the natural frequencies and harmonics of a drill string model in the axial, torsional, and lateral directions applying FEA calculation techniques to provide the solution. The software system uses proprietary finite element methods to model the dynamics of an entire BHA and drill string system from the bit to the surface. The software creates the finite element model of the drilling assembly considering the component geometries and mechanical properties of the drill string; the three-dimensional well path; the borehole geometry; along with the Weight-On-Bit (WOB) and mud weight ranges applied in the drilling sequence analyzed in the software.

Once the BHA and drill string system, borehole geometry, and well path have all been modeled in the software; the analysis routines are then run to characterize the dynamic behavior of the modeled system. In these calculation routines, the software identifies the operating RPM's at which the BHA and drill string system will resonate in the axial, lateral, and torsional directions at a variety of depths along the well path and with the different WOB and mud weight ranges specified by the user. The operating RPM's the program identifies in this process are stored as the critical speeds for the system over the depth range analyzed.

At the same time, the program identifies the harmonic response of the system at specific locations along the drill string model to user-defined excitations. These response analysis results can be used to quantify the effect that applying a drilling parameter set near one of the system critical speeds would have on user-specified downhole components in the modeled BHA and drill string system.

2. Background – Downhole Drilling Dynamics Recording Tools A compact DDDR tool was developed by NOV in the mid-2000’s with the primary intent of recording downhole vibration data for post-well analysis. The compact DDDR tool was designed based on a sensor set from larger collar-based drilling research tool that recorded a more extensive set of drilling mechanics and vibration data downhole6, 7.

The compact DDDR tool was developed to monitor high frequency downhole dynamics data as drilling vibration had become globally recognized as a substantial drilling dysfunction and source of inefficiency in the drilling process. The compact DDDR tool recorded three primary downhole vibration data types: maximum lateral shocks (in g), lateral vibration intensity (in g-RMS), and derived downhole rotational speed (in RPM). The lateral vibration intensity and maximum lateral shock measurements give an indication of the overall severity of lateral vibration during the recorded drilling interval. The derived downhole RPM delivered a measure of the torsional vibration severity downhole and also provided an indication of stick-slip events taking place downhole during the recorded drilling interval6, 7.

The relatively small size of the DDDR tool allowed for effective placement anywhere within the drilling assembly to monitor the dynamic behavior of the system (from inches above the bit to thousands of feet away from the bit in the drill pipe). The compact nature of the DDDR tool also allowed for multiple DDDR tool placements within the drilling assembly as the tools imposed only minor modifications to existing drilling assembly designs. The capability for multiple tool placements along the drill string opened the potential to analyze the drilling dynamics data distributed


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across significant distances of the drilling assembly and offered substantial insight into the dynamic situation associated with various drilling scenarios6, 7, 10, 11.

The DDDR tools acquired high speed vibration data downhole (at 400 Hz). As the DDDR tool was a memory-mode recording tool, there were no data transmission restrictions limiting the density of the recorded data set. This allowed for the acquisition of high density dynamics data during the recorded drilling intervals, further enhancing the ability to characterize and analyze the downhole dynamic environment during the recorded drilling intervals. The DDDR tool has the memory capacity and rated battery life to record up to 200 hours of downhole data (including a continuous data set sampled at approximately 0.4 Hz, along with a distributed set of bursts at 400 Hz). Since the DDDR tools can literally be turned around in a number of minutes at the rig site, the memory capacity of the tools has rarely been a limiting factor for most standard drilling applications6, 7. A compact DDDR tool is shown below in Figure 1.

Figure 1 - A DDDR compact sensor

The DDDR tools provided significant insight into the downhole dynamic implications of the surface application of the selected drilling parameters during standard drilling practices. Since the DDDR tools were battery operated, the tools also recorded all activities associated with the process of drilling the interval including tripping in, drilling out, reaming, making connections, surveying, and tripping out along with the dynamics associated with standard drilling activities. The application of the compact DDDR’s distributed at multiple locations in the drilling system have been used in hundreds of drilling assemblies worldwide to better understand the downhole drilling dynamics associated with that drilling process and to optimize drilling operations8, 9, 10, 11. 3. BHA Design Various techniques exist in predicting the behavior of drilling assemblies when rotated at different speeds through different trajectories. Under the operational point of view, if the correct measures are achieved the bit will ideally rotate concentrically, with little or no variations in the angular speed, torque, or weight applied. Under this ideal situation the Mechanical Specific Energy (MSE) would be almost equivalent to the compressive strength of the rock. The efficiency of the operation would be close to 100%1 and the performance of the operation would be a direct function of the technology of the drilling bit and tools selected. Even though these methods help to reduce the chances of encountering damaging vibration events and improve overall performance, they do little to damp out vibrations when encountered. Without these techniques, the resources available at the rig site remain the traditional drill-off test and tentative parameter adjustments searching for immediate increments in the rate of penetration as drilling advances.

When hard formations are being drilled, the Coefficients of Restitution (COR) of these formations increase the importance of understanding the drilling dynamics and mitigating the destructive effect of the vibrations. Severe or catastrophic damage is commonly encountered in these situations due to shocks to the bit and in BHA components, associated with erratic and/or poor performance. High drilling costs are experienced and the learning curve12 can be almost endless. The most common practice in these situations is to replace the existing bits for more robust and higher IADC roller cone bits or by impregnated diamond bits run with turbine, leading to longer runs and less catastrophic damages, but very likely with even lower penetration rates achieved. Afterwards, these results are then taken as the local benchmarks with the assumption that a new optimum point has been reached.

Some of the objectives of the techniques described in this paper are to extend bit life and increase overall drilling performance by using parameters with the least loss of energy in vibrations, or to introduce rational changes to the BHA willing to generate the least harmonic modes of inefficiency. This would support an operator while designing a BHA, resulting in wider ranges of safe parameters. BHA modeling might include analyses of standard rotary, directional or rotary steerable assemblies, considering all types of drilling applications and trajectories applied.


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3.1. BHA Design using FEA Software Prediction: Lateral and Torsional Stabilization The first lesson learned by using the FEA analysis software is that each system is unique, i.e. the RPM selected after analyzing a combination of well trajectory, BHA design, and drilling parameters to meet a safe condition is not valid for other sceneries or trajectories4. It is understood, as a safe condition or safe window, this range of parameters is where the least amount of drilling energy is expended ineffectively to vibrations in the drill string. In this dynamic situation the bit will ideally be able to drill concentrically and with fewest variations in torque and weight. Under these conditions, the wellbore should be of better quality and the bit and BHA component life should be maximized.

Being so, the primary target for drilling dynamics optimization is finding these safe windows. As the well design is pre-determined and the applied WOB obeys to a range of values related to rock strength and bit technology, BHA design might be changed willing to produce larger windows of parameters.

The BHA optimization can be produced into different directions according to the vibration modes that the analyst is attempting to mitigate. Stabilization of the BHA modifies the harmonic frequencies in lateral vibrations and can make them disappear in the normal RPM ranges used on the rig, with little or no effect to the torsional or axial vibrations. The number of torsional and axial harmonic resonant modes will be affected by the rigidness of the drill string components and the well depth. As it will be demonstrated, the continuous addition of drill pipe significantly changes the flexibility of the entire system.

Three charts in Figure 2 represent the FEA Critical Speed Analysis of a BHA drilling from 1000 to 2400 meters of a vertical section, using 14 joints of 6.¾” x 2.13/16” Drill Collars (DC), 12 joints of 5.½” Heavy Weight Drill Pipe (HWDP) and 5” Drill Pipe (DP). The same BHA was used with different stabilizations: in the first one it simulated a packed BHA with three stabilizers positioned at 0 – 30 – 60 feet; in the second, a pendulum BHA with the stabilizer positioned at 60 feet and in the third a slick BHA. Red lines represent string RPM peaks where most energy will be dissipated with torsional vibrations or resonance, the blue lines represent axial vibrations, and yellow triangles the lateral vibration peaks. Being so, the safe windows are the intervals in-between these curves at a given depth, where – if a RPM value in this window is adopted – the best performance while drilling should be achieved and the least amount of energy should be dissipated to vibrations and impacts.

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Figure 2 - FEA software prediction for a packed, a pendulum and a slick BHA with 6.¾” DC’s


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For the drill string and vertical trajectory described, a safe window of about 40 RPM can be detected at 1000 meters of depth, ranging from 40 to 85 RPM, and a second safe window from 140 to 165 RPM. One can notice that as more drill pipe is added to the string the safe windows narrow down; at the end of the run not only the first window narrowed down to 25 RPM and the second window to 60 to 80 RPM, but even more harmonic modes were introduced. Also, the charts show that in vertical drilling the pendulum BHA’s present more lateral vibration than in the packed or the slick BHA designs. The torsional and axial vibrations in all cases demonstrate fairly similar behaviors due to the very similar mass, material, and stiffness in the three BHA designs.

So, the second lesson learned is that deeper sections are more difficult to be drilled, not only due to an increase in rock strength, but also as fewer safe windows of operating parameters exist and the safe parameter windows are quite smaller.

3.2. BHA Design Using FEA Software Prediction: Stiffer BHA’s In an 8.½” hole section, different than in 12.¼” and larger borehole diameter sections where 9.½” Outer Diameter (OD) or larger drill collars might be used, there are limited geometric opportunities to make the drill string more resistant to torsional and/or axial vibrations, which would usually be achieved by selecting stiffer drill string components. Most drill collars in this borehole diameter range from 6” to 6.¾” OD, while the typical drill pipe OD is 4.½”, 5” or 5.½”, in different steel grades and thread types.

The FEA Critical Speed Analysis charts above described the packed and pendulum BHA design shown in the charts below; now using 7” OD DC, 5.½” HWDP and 5.½” DP. The curves indicate that no substantial changes in the torsional or axial harmonics were met by making BHA designs more rigid within the available geometric constraints though the resonant speeds had changed.

Packed BHA - 3 STB'sCritical Speed Analysis - 8.1/2” section

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Figure 3 - FEA software prediction for a packed BHA’s with 6.¾” DC’s versus 7” DC’s

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Figure 4 - FEA software prediction for slick BHA’s with 6.¾” DC’s versus 7” DC’s


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The third lesson learned is that the FEA pre-analysis of the BHA is of increasing importance in the optimization of deeper hole sections and is essential for the overall performance of the drilling system to work in the safe windows of operational parameters.

4. Case Studies – Mexico Offshore The Cantarell field in the Southern Gulf of Mexico was discovered approximately 50 years ago, which presumably would leave little or no space for performance improvements, as statistically almost all techniques and technologies have logically been tried there with the long history of the drilling operation. An optimization process would require careful monitoring of any gains of performance, so the valid practices could be monitored and repeated in subsequent operations. DDDR tools were used to measure drilling vibrations with the intent of validating the surface actions initiated to improve penetration rates and reduce shocks in the drill string.

In two subsequent wells in Cantarell field, two identical 14.½” 6-bladed, 16 mm cutter PDC bits were programmed to be used. The BHA designs included a rotary steerable system with a positive displacement drilling motor. The drilling motor was run with the intent of delivering higher total RPM to the bit with the side effect of reducing the RPM of the drill string. This way the total amount of energy available in the system would be reduced, and the potential shock levels would also be reduced in the BHA and at the drill bit, presumably bringing ROP and bit life improvements. In the second well an Asymmetric Vibration Damping Tool (AVDT) 13 would be added to the drill string design, with the intent of further mitigating downhole vibrations and improving drilling performance from the first run.

The DDDR tools were used to provide downhole measurements during both operations, to better understand the complex nature of the interactions between the drill string and wellbore; and between the drill string geometry, hole trajectory, and drive type. In each BHA two DDDR tools were applied, with one sensor at the bit and a second sensor at the upper part of the BHA. Each DDDR tool monitored vibration levels, shocks, downhole RPM, and temperature. The use of the DDDR tools proved to be extremely important as the tools validated the FEA Critical Speed Analysis predictions based on the actual measurements, giving confidence in the conclusions established from the runs.

In both 14.½” sections, the FEA Critical Speed Analysis predictions were plotted in a depth based chart. These charts showed the safe windows and assisted in orienting the surface parameters at the rig site to points where the overall MSE would be minimized. There was a surface rotary speed range of 50 to 100 RPM imposed during the runs due to the limits of the downhole motor used.

4.1. Performance in Well 1

In the first well the selected bit drilled the entire section, building from 0° to 44° and completing 1822 meters in 27.45 hours. A FEA pre-run analysis of the dynamics of the run, shown at the left side of figure 3, was conducted to recommend a series of parameters shown in the shaded safe windows and recommended by the arrows. The highest string speed recommended was 100 RPM and the lowest 50 RPM, both selected within the limits established by the motor operators attempting to produce the longest tool life possible.

The post-run analysis is shown in the right side of the same figure, with actual parameters charted in black. The post-run analysis demonstrated that during the run the recommended parameters were followed, nonetheless, some types of vibrations were encountered. It is not uncommon in the field that, despite recommendations given based on vibration predictions, some recommended parameters are not used in practice either because the subject is unknown by the field operations team or there is enough confidence in past experience to ignore the new methodology.


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Figure 5 - Pre-run analysis with recommended RPM in green (left), post-run analysis with actual RPM in black (right).

The cost per meter and MSE were monitored while drilling to detect any decrease in drilling performance or changes in tendency. Both metrics provided net positive indications during the run that good performance overall was being achieved. The charted metrics for the run are shown below in Figure 6.

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The bit was pulled at total depth exhibiting an IADC dull grade of 1-3-CT-N-X-I-BT-TD. Photos of the dull bit are shown below in Figure 7.

Figure 7 - Pictures of the steel bit after the run, showing little wear at the cutting structure.


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This run established a new World Record for ROP for 14.½” PDC bits at 66.3 m/h, validated by Hart’s E&P. Furthermore, another record was set on this run for the longest interval drilled in 24 rotating hours in offshore basins in Mexico, by drilling 1630 meters in 24 hours. Lastly, the total interval drilled set an international record for the directional drilling company for the longest run with the combination of the rotary steerable system with a positive displacement motor. Field comparison charts of drilling performance in terms of ROP and equivalent extension are shown below in Figure 8.

Figure 8 - Best ROP’s achieved and the longest equivalent extension drilled in Cantarell field per bit run.

4.2. Performance in Well 2

In the following well an identical 6-bladed, 16 mm cutter PDC bit was used, and once more succeeded in drilling the entire section. Identical procedures were adopted on the second well regarding the mitigation of vibrations by FEA pre-run analysis of the drill string dynamics. For well 2, an additional tool was added to the BHA. The new tool applied in the drilling system was a novel AVDT designed to damp drilling vibrations. The addition of the AVDT to the drilling assembly was expected to change the dynamics of the upper BHA and to reduce the intensity of shocks reaching the bit. It was also anticipated that a reduction in shock and vibration intensity would be confirmed by the two DDDR tools placed at the drill string, in a similar configuration to the DDDR tools applied in well 1.

Due to a significant increase in drilling performance, the optimized parameters were abandoned after less than 100 meters had been drilled. The enormous amount of cuttings surpassed the cleaning capacity of the cuttings removal system at the rig site. At this time, the average ROP had surpassed 107 m/h and a set of more moderate surface drilling parameters were adopted by the rig to limit the penetration rate.

The bit built from 0° to 25°, drilling 740 meters in 14.78 hours, with an average ROP of 50.1 m/h. A trip was made after the build section to add a LWD tool to the BHA and to remove the AVDT from the drilling system to establish a direct comparison of drilling dynamics from well 1 to well 2. There were no signs of wear on the cutting structure of the bit detected during the trip. The applied drilling parameters followed the conventional recommendations used in the field for the drilling process from this point onwards. The bit drilled an additional 300 meters in 21.97 hours and reached final well depth at an average ROP of 13.7 m/h, coming out of the hole in excellent condition. The IADC dull grade was 0-1-WT-S-X-I-CT-TD: however, sudden changes in the both the Cost per Meter and the MSE curves could be noticed right after the trip to change the BHA. The Cost per Meter and MSE charts for these runs are shown below in Figure 9.


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Figure 9 - Cost per Meter and MSE charts show a distinct increase in both curves after the AVDT is removed

The average MSE levels, where the surface drilling parameter optimization was conducted, are a good indication of the success of the methods adopted by the rig. In well 1, the overall average MSE was 4.2 Kpsi. In the first section of well 2, with the AVDT and optimized parameters, the average MSE had lowered to 2.3 Kpsi. In the second section of well 2, with AVDT but without optimized parameters, the average MSE increased slightly to 4.4 Kpsi. In the final section of well 2, now without the AVDT and using a more conventional parameter set, the average MSE increased more significantly to 33.0 Kpsi.

Similar tendencies are seen when comparing the measured vibration levels measured by the DDDR tools for both runs. This information is shown below in Figure 10.

Figure 10 - Max and RMS Lateral Accelerations measured by the DDDR tools in first and second wells

In the charts, BB1 denotes the measurements from the DDDR sensor directly above the bit and BB2 from the upper part of the BHA. The run in first well without the AVDT in the BHA is marked with the -VS, while +VS indicates the run in the second well with the AVDT applied in the BHA.

The average lateral vibrations for both runs measured by the DDDR tools were under 1 g RMS, which is a low vibration level, denoting the success of the optimization methodology applied on both runs and leading to the unprecedented penetration rates achieved. Also, both DDDR sensor locations in the BHA showed decreases in the peak values after the AVDT was added to the system, indicating improvements to drilling dynamics environment when an AVDT is used in the BHA.


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5. Case Studies – Brazil Offshore Deep water offshore wells in Santos Basin in Brazil have the 8.½” vertical section drilled through pre-salt carbonate layers. This section poses several technical challenges, especially in the Cretaceous carbonate formation, which is very hard, abrasive and has a high COR. In this section, severe torsional vibrations and shocks are also a common occurrence that results in a harmful drilling environment for drill bits and downhole tools. To investigate this phenomena, it was used a database of 49 bits run deeper than 4000 meters of depth, all manufactured with the best existing technology. The overall average performances were 178 m / 87.0 h equating to an average ROP of 2.0 m/h.

Depending on the technology of the bit and the drive system applied in each case, the average ROP’s ranged from 1.6 to 2.9 m/h on a per run basis, while the drilling intervals ranged from 80 to 280 meters per run. Fixed cutter (FC) bits run with a top drive did not drill as much formation as the FC bits run with Vertical Rotary Steerable Systems (VRSS) or with turbines. The FC bits run with a top drive do present the best ROP and deliver the lowest cost per meter, as seen below in Figure 11. The practical limitation for the FC bits is that 32% of the runs end due to a Ring Out in the cutting structure (IADC dull characteristic RO). In this sense, the path to further cost reductions drilling this section is the mitigation of the hazardous drilling vibrations and the reduction of shocks that results in this dull condition. Correctly identifying the environment and understanding the dynamic phenomena of these runs will lead to the improvement of the drilling conditions and the extension of the bit life.

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Figure 11 – Average performances of deep 8.½” high tech bits run in Santos Basin

Investigations using the DDDR tools were conducted in this area. The measurements demonstrated that shock levels of higher than 50 g’s existed while drilling this section. The DDDR tools also confirmed that stick-slip and severe harmonic vibrations existed in this application and could be properly identified by way of the downhole measurements. It was noticed that during the slip phase of stick-slip recorded, the torsional vibrations were coupled with lateral vibrations. It was also observed that when the drill bit eccentrically tags the bottom, this action would instigate lateral vibrations that would then further progress to bit and/or BHA whirl. A common troubleshooting method in this scenario on the rig, in an effort to mitigate the stick-slip occurrences, would be to reduce WOB and increase RPM. However, it was found that this change to the surface parameters would actually temporarily lead to the damaging motion of backwards whirl with the stick-slip14. This coupling is extremely detrimental to BHA components, particularly the drill


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bit, leading to fast PDC cutter wear and eventually ring outs as seen in the investigation of the field data. In these occasions, high MSE values are expected as the drill bit is not efficiently drilling ahead. Also, in this section, there was the presence of silicate interlayers in the formation, which contributed to making the scenario worse. High reactive torque, severe well tortuosity, and excessive drag are expected under these conditions; consequently, buckling and erratic torque issues should not be discarded.

With the purpose of fully understanding how the drill string interacts with the formation and reacts to the surface drilling parameters applied, and in pursuit of a complete and reliable dynamic study of the BHA behavior to identify the main vibration source, two DDDR sensors were applied as a part of the BHA design in a specific well. The beginning of the section of this well was drilled using a steerable motor BHA and a rotary BHA for comparison. Two high technology FC bits were expected to be able to complete the entire section.

The first bit was run at 4778 meters MD using a steerable motor BHA. This bit drilled 97 meters in 74 h, equating to an ROP of 1.3 m/h. A FC bit with 8 blades, 13 mm cutters was used for this run. One DDDR was placed directly above the drill bit and a second one higher in the drill string so the dynamics at the drill bit and further up the drill string could be studied separately, this DDDR tool placement also provided the ability to investigate how the bit and the drill string affect each other to better understand the overall system dynamics. After the run, the bit exhibited severe mechanical damages and a ring out of nose, being graded as 8-6-RO-A-X-2-LC-HP as shown below in Figure 12. The potential causes for such mechanical damages to the cutting structure might be associated with bottom hole pattern break-in, drilling parameter selection, junk damage, low hydraulics, or severe drilling vibration.

Figure 12 – Dull condition of first bit of the section, run in pre-salt carbonates, showing ring out and damaged cutters

The drilling vibration signatures provided by the DDDR tools were deeply analyzed to assist in the identification of the possible root problems, which limited the drilling performance in the run. Analyses of the continuous data from vibration sensors revealed that the drill bit experienced high levels of torsional vibrations (including stick-slip) followed by severe lateral vibrations during the slip phase of the stick-slip vibrations. The lateral vibrations in this phase of the stick-slip motion included backwards bit whirl. During the most severe instances of this backwards whirl motion, peaks of over 10 g RMS and shocks exceeding 50 g (instantaneous) could be observed. The stick-slip also resulted in erratic torque, and several events caused the mud motor to stall. The chart below in Figure 13 shows some events in a time-based log of the run.


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Figure 13 – Stick-slip associated with lateral vibrations, while bit and string torsional vibrations are moderate

At the depth of 4803 meters in Figure 13, the orange arrows on the log point to instances where the downhole RPM recorded by the DDDR tools went to zero. These points matched very low lateral vibration readings from the DDDR tools at the same point, representing the stick phase of stick-slip. The green arrows point to the slip phase of stick-slip, high lateral vibration and correspondingly high MSE values are demonstrated on the log during this phase of the stick-slip motion. The vibration intensity, including shocks above 50 g, would have severely damaged the PDC cutters in the slip phase, which would then not be able to deliver reasonable ROP even with further reduced vibration levels. Increased WOB, shown as a green log in the left most channels on the chart, was applied in an attempt to improve the ROP. However, this likely contributed to further PDC cutter damage, resulting in decreased drilling efficiency and higher MSE values.

The information above was substantiated by the FEA post-run analysis shown below in Figure 14. In this chart, the drill string was rotating at close to 30 RPM at 4801 meters, this input parameter overlaps with one of the torsional resonance harmonics of the system. At this same point in the well, the DDDR tools register stick-slip and the associated lateral vibrations as seen in Figure 14. This is later aggravated at 4819 meters when 45 RPM is applied at surface, which matches the next torsional resonance harmonics, and at this time more energy can be expended as the string was rotated twice faster.

4750

4770

4790

4810

4830

4850

4870

4890

0 10 20 30 40 50 60String RPM

MD

[m

eter

s]

Dalmo Amorim

Figure 14 – Resonance harmonics met at 4801 and 4819 m, lead to the stick-slip registered by DDDR’s

-o- String RPM -o Inst. ROP


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The Power Spectral Density (PSD) plots for burst data from the DDDR tools, for both bit and BHA, indicated that drill bit experienced lateral vibration at a frequency of approximately 30 Hz. Backwards bit whirl is developed when the instantaneous center of drill bit rotation travels around the borehole in an opposite direction to the driving rotation. This motion then results in the formation of a lobed bottom hole pattern with N+1 lobes, where N is the bit blade count. The dynamic motion of the bit during backwards bit whirl results in repetitive lateral bit vibration at a frequency given by:

Whirl frequency = (bit RPM/60) × (N+1)

Being that the motor plus string RPM is approximately 200 RPM, the expected backward bit whirl frequency was 30 Hz, matching the frequency identified in the PSD plot from the DDDR burst at this location in the well. The large lateral vibration amplitude during this period was the direct result of the bit undergoing backwards whirl.

In Figure 15 below, several sudden increases in surface pressure followed by zero downhole RPM and high lateral vibrations recorded by the DDDR tools indicate that mud motor had stalled.

Figure 15 – the motor stalls due to torsional and lateral vibrations associated

Other occurrences of backward bits whirl could be identified by means of this same technique. Severe lateral vibrations experienced during these events led to damaged PDC cutters and the eventual ring out of the bit. Calculated MSE presented high values, proving that the bit was drilling inefficiently and that large amounts of energy were expended to the environment through vibration, rather than destroying rock formation. Based on the findings, the drilling performance was limited by lateral instabilities, which intrinsically were correlated to torsional instabilities of the system. The conclusion is that the matching of the downhole motor and drill bit characteristics needed to be improved considering the drilling system, formation, and borehole size, in order to obtain an improved drilling environment.

The following 8.½” bit was an 8-bladed bit with 13 mm PDC cutters, boasting innovative design features to improve lateral stability. A conventional packed rotary BHA was used for this run to drill from 4875 meters to 4940 meters, which resulted in better lateral stabilization at the bit and in the BHA. Drilling dynamic measurements were taken again by DDDR tools at two discrete points in the BHA, similar to the previous run. The final ROP was improved more than 100% to 3.0 m/h, an indication that substantial positive changes occurred in drilling dynamics, which validate the statistics shown in Figure 11. The bit also exhibited very few mechanical damages, IADC dull graded as 1-2-WT-A-X-1-BT-PR. Bit dull is shown below in Figure 16.


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Figure 16 – better drilling dynamics and Torque Control Components result in higher ROP, less mechanical damages

The major dull characteristics seen on this bit were the worn teeth, though some chipped and broken cutters could still be seen. These types of mechanical damages are usually driven by excessive RPM, which accelerates the standard cutter wear mechanism due to significant increases in the relative surface velocities, inducing thermal cycles that lead to heating checking and localized impact loading, among others. Initial field evaluation of the drill bit indicated that the mechanical damage was also possibly associated to torsional vibration.

Closer examination of the complex downhole dynamics of the continuous data diagnosed severe torsional vibrations and instances of stick-slip, occurring at both the drill bit and the BHA. Figure 17 below depicts that during the slip phase of the stick-slip, the drill bit experienced moderated lateral vibration. While downhole measures indicated that bit and BHA experienced rotational speeds in excess of 200 RPM at several instances, showing how detrimental the torsional vibration and stick-slip was to the rotary BHA design. In addition, the stick-slip experienced at the BHA and the drill bit resulted in an erratic torque response.

Figure 17 – Log shows BHA and bit affected by stick-slip, followed by moderate lateral vibration

The PSD plots of some burst data in this section of well also revealed backwards bit whirl occurring at approximately 20 Hz. The PSD plot from this section of the well is shown below in Figure 18. At around 4928 meters MD, the drill bit was rotating at approximately 125 RPM; given this, the computed backwards bit whirl frequency by means of the bit whirl frequency equation above was 19 Hz. This calculated 19 Hz bit whirl frequency value matched directly with the


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actual frequency recorded by the DDDR tools. Other backwards bit whirl occurrences were also identified for this run using this technique.

10 20 30 40 50 60 70 80 90 1000

0.5

1

1.5

2

2.5x 10

6

X: 18.65Y: 1.65e+006

Frequency (Hz)

Pow

er S

pect

rum

(g2 /H

z)

Power Spectrum: BBP510

BBS

290

NB

burst

148.r5kb

Figure 18 – Power Spectrum of the drilling operation at 4930 meters MD

6. Conclusion Drilling deep, hard formations with rotary BHA’s has so far demonstrated to be the path to the lowest operational costs. Cost reductions might be further achieved by the proper control of the drill string dynamics and by identification of root causes of issues like Ring Out, responsible for most drill bit failures of fixed cutter bits. The FEA software for vibration harmonics prediction has shown to be the most efficient way to predict and avoid undesired levels of vibrations, achieved by using drilling parameter combinations specified by the program, and by producing improvements on BHA design after its behavior is pre-simulated. The validation of the process using high frequency DDDR sensors, to produce better quality of data on downhole dynamics in multiple places of BHA, allow to understand and identify the main root causes of problems of this costly activity. These actions will generate a more stable environment and lead to lower overall costs for the driller.

In the decision-making process, predicting and promptly mitigating the detrimental drilling problems are the next technological step in the Oil & Gas industry, a procedure to produce a similar effect as the introduction of the PDC bits in the 80’s.

7. Nomenclature AVDT = Asymmetric Vibration Damping Tool BHA = Bottom Hole Assembly COR = Coefficient of Restitution DC = Drill Collar DDDR = Drilling Dynamics Data Recorder DLS = Dogleg Severity (in degrees per 100 feet) DP = Drill Pipe FEA = Finite Element Analysis FEM = Finite Element Method GPM = Gallons Per Minute HWDP = Heavy Weight Drill Pipe LWD = Logging While Drilling MD = Measured Depth MWD = Measurement While Drilling NB = Near Bit OD = Outside Diameter PDC = Polycrystalline Diamond Compact PSD = Power Spectral Density


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ROP = Drilling Rate Of Penetration RPM = Revolutions Per Minute RS = Rotary Steerable RSS = Rotary Steerable System SS% = Stick-Slip Severity (in Percentage) TD = Target Depth TVD = True Vertical Depth VS = Vertical Section WOB = Weight On Bit 8. References

1. Teale, R.: “The Concept of Specific Energy in Rock Drilling,” Intl. J. Rock Mech. Mining Sci., 1965 2. Beachley, N.H., Harrison, H.L., Fronczak, F.J.: “Introduction to Dynamic System Analysis”, University of

Wisconsin-Madison (Mechanical Engineering Department), 1998 3. Craig, A.D., Hanley, C.M., McFarland, B., Shearer, D., King, P.: “A Proven Approach to Mitigating Drilling

Vibration Problems in offshore Western Australia” paper IPTC 13399 presented at the 2009 International Petroleum Technology Conference, Doha, Qatar, 7-9 December 2009

4. Amorim Jr, D.S.; Hanley, C.M.; Leite, D.J.: “BHA Selection and Parameter Definition Using Vibration Prediction Software Leads to Significant Drilling Performance Improvements” paper SPE 152231, presented at SPE LACPEC - Latin American and Caribbean Petroleum Engineering Conference, Mexico City, Mexico, 16-18 April 2012

5. Cook, R.D.: “Finite Element Modeling for Stress Analysis”, John Wiley and Sons, New York, 1995 6. Schen, A.E., Snell, A.D., Stanes, B.H..: “Optimization of Bit Drilling Performance Using a New Small

Vibration Logging Tool” paper SPE 92336 presented at the 2005 SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 23-25 February 2005

7. Perez, D., Lockley, R., Clarke, A.J., Hanley, C.M.: “Application of Small Vibration Logging Tool Yields Improved Dynamic Drilling Performance” paper SPE/IADC 105898 presented at the 2007 SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 20-22 February 2007

8. Barton, S. Clarke, A.J., Garcia, A., Perez, D., Mora, G., Carrion, C.: “Improved drilling performance: downhole dynamic logging tools break paradigm in Ecuador” paper SPE 122208 presented at the 2009 SPE Latin American and Caribbean Petroleum Engineering Conference, Cartagena, Colombia, 31 May-3 June 2009

9. Pink, T., Harrell, L., Perez, D., Carrico, J., Mackinnon, P.: “Integrated drilling optimization and down hole drilling dynamics enables PDC bits to drill in the Colorado region of the San Juan unconventional gas basin” paper SPE/IADC 139848 presented at the 2011 SPE/IADC Drilling Conference, Amsterdam, The Netherlands, 1-3 March 2011

10. Raap, C., Craig, A.D., Perez, D.: “Understanding and Eliminating Drill String Twist-Offs by the Collection of High Frequency Dynamics Data” paper SPE/IADC 148445 presented at the 2012 SPE/IADC Middle East Drilling Technology Conference, Muscat, Oman, 24-26 October 2011

11. D'Ambrosio, P., Bouska, R., Clarke, A.J., Laird, J., McKay, J., Edwards, S.: “Distributed Dynamics Feasibility Study” paper IADC/SPE 151477 presented at the IADC/SPE Drilling Conference, San Diego, CA, USA, 6-8 March 2012

12. Amorim Jr, Dalmo S.: “Methodology for the Reduction of Oil and Gas Drilling Costs”, Mastership Thesis, University of São Paulo, October 2008

13. Forster, I., Macfarlane, A., Dinnie, R.: “Asymmetric Vibration Damping Tool - Small Scale Rig Testing and Full Scale Field Testing” paper IADC/SPE 128458 presented at the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, Louisiana, USA, 2-4 February 2010

14. Lesso, B.; Ignova, M.; Zeineddine, F.; Burks, J., Welch, B.: “Testing the Combination of High Frequency Surface and Downhole Drilling Mechanics and Dynamics Data under a Variety of Drilling Conditions” paper SPE 140347, presented at the 2011 IADC/SPE Drilling Conference and Exhibition, Amsterdam, The Netherlands, 1-3 March 2011

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