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High-torque, low-speed drilling mud motors are typically used to drive rotary-steerable systems (RSS) to improve the rate of penetration (ROP) of the RSS bottomhole assemblies (BHA). Downhole drilling dysfunctions are common when powered RSS BHAs are pushed to the limit for maximum drilling performance. High-frequency (HF) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box of the RSS, slow-rotating housing (SRH) of the RSS, bit box of the mud motor, and top subassembly (sub) of the mud motor to better understand drilling conditions in different shale plays throughout North America. Embedded sensors placed on the outer diameter of the BHA vs. centerline-mounted sensors give a different measurement response and a different vision of the actual dynamics being experienced in the BHA.
The HF sensors were deployed in the in-house developed push-the-bit RSS and mud motors, allowing us to model the motor-assist RSS BHAs with analytical models and finite-element analysis models to predict the HF torsional oscillation (TO) and axial oscillation (AO) frequencies. The derivation of the high-frequency axial oscillation (HFAO) and TO analytical equations is detailed in the paper. In one of the example motor-assist RSS BHA analyses, the simulation results reveal that the fundamental high-frequency torsional oscillation (HFTO) frequency is 11.1 Hz whereas the fundamental HFAO frequency is 32.9 Hz, which is approximately three times higher than the fundamental-mode HFTO frequency. A good correlation was observed between the simulation result and the field data gathered from the HF accelerometer and gyro sensors embedded in the RSS and mud motors.
Two new types of HF axial drilling dynamics with a polycrystalline diamond compact (PDC) bit—(1) the third-order-mode HFAO and (2) the harmonics of the HFTO coupled to the longitudinal axis—were discovered and reported in detail. One example in this paper shows that the dominant HFTO frequency shifts occurred in the middle of drilling a stand with no connection involved and no surface parameter changes. The examination of the time-domain signal reveals that (1) the “baseline” HFTO-induced tangential accelerations are due to the mud motor output revolutions per minute (RPM) (2) the variation of the HFTO-induced peak tangential accelerations comes from the drillstring stick/slip, which is transmitted to the drill bit through the mud motor, and (3) the 76 and 114 Hz HFTO-induced accelerations are both approximately in a sinusoidal waveform, except in the 3-second transition period, where the mixture of both frequencies is observed. The 114 Hz-HFTO-induced tangential acceleration measured at the bit box is coupled with the 0.16 Hz drillstring stick/slip oscillation. The analytical equation is provided to describe the HFTO coupled with stick/slip as an analogy to communication theory. In addition, the extensive modeling and field measurement of the HFTO and HFAO lead to the mitigation measure of the harmful HF drilling dynamics in motor-assist RSS BHAs. The proposed HFTO mitigation mechanism is modeled, simulated, and demonstrated in the paper.
The latest-generation embedded HF drilling dynamics sensors are placed on the outside diameter of the BHA, as well as along the centerline of the BHA. The different responses of the sensors due to their placement are reported and analyzed. The quality of 1000 Hz continuous-sampled gyro data are discussed, comparing against low-frequency-sampled gyro data. Additionally, this paper shows the downhole HFTO-damping mechanism and lesser known drilling dynamics, such as HFAO with a PDC bit in detail.
CORRECTION NOTICE: This paper has been updated from its original version to correct the provenance statement.
Maalouf, Janine (Schlumberger) | Benny, Praveen Joseph (Schlumberger) | Cantarelli, Elena (Schlumberger) | Al-Hassani, Sultan Dahi (ADNOC Offshore) | Altameemi, Ibrahim Mohamed (ADNOC Offshore) | Ahmed, Shafiq Naseem (ADNOC Offshore) | Khan, Owais Ameer (ADNOC Offshore) | Al Hammadi, Mariam Khaleel (ADNOC Offshore) | Zakaria, Hasan Mohammed (ADNOC Offshore) | Aboujmeih, Hassan Fathi (ADNOC Offshore)
Ultrahigh-resolution electrical images (UHRIs) acquired with logging while drilling (LWD) tools have brought to light different side effects of using drilling tools such as rotary steerable systems (RSSs) and bits when drilling a horizontal borehole. This paper will go through the extensive analysis and simulations that followed, gathering data from almost thirty wells, to try and understand the root causes behind these side effects, along with the actions put in place to mitigate it. UHRIs were used while drilling a 6-in horizontal hole to achieve a 100% net-to-gross and perform advanced formation evaluation to optimize well production. Surprisingly, these images revealed more details: wellbore threading–a type of spiral–inside the formation. To understand the cause behind such marks, RSS and bit data was gathered from around thirty wells, compared, and analyzed. Simulations were run over months, considering rock types, drilling parameters, and bottom hole assembly (BHA) design to reproduce the issue and propose the best solution to prevent these events from reoccurring. After the data compilation, a trend emerged. Wellbore threading was observed in soft, high-porosity reservoir formations. It also appeared in tandem with controlled rate of penetration (ROP), low weight on bit (WOB), and a low steering ratio. At this point, advanced analysis and simulations were needed to determine the root cause of this phenomenon. A Finite Element Analysis (FEA) based 4D modeling software showed that the bit gauge pad length, combined with the RSS pad force, contributed to this threading. A pad pressure force higher than 7,000 N in conjunction with a short-gauge bit increased the likelihood of having this borehole deformation. Simulations comparing different size tapered and nominal bit gauge pad lengths were run to determine the effect on the borehole and on the steerability. Bit design is directly linked to the wellbore threading effect. It is more pronounced when associated with a powerful rotary steerable system and in a soft formation environment. However, altering a specific bit design can have a direct and undesirable effect on the steerability of the BHA. UHRI revealed details of borehole deformation that new drilling technologies are causing. It enabled an in-depth analysis of the different causes behind it, revealing ad-hoc solutions.
Horizontal wells are being drilled in more challenging environments such as through thin formation layers, unpredictable geology, and unknown fluid movement. Detailed evaluation has a direct impact on the completion approach. But we also need to drill faster and more efficiently. The wellbore threading caused formation damage that masked information needed for formation evaluation. In a novel application of UHRI data, simulations gave birth to information which has been lacking and incentivized the development of new, formation-friendly technology.
Stefánsson, Ari (HS Orka) | Duerholt, Ralf (Baker Hughes, a GE company) | Schroder, Jon (Baker Hughes, a GE company) | Macpherson, John (Baker Hughes, a GE company) | Hohl, Carsten (Baker Hughes, a GE company) | Kruspe, Thomas (Baker Hughes, a GE company) | Eriksen, Tor-Jan (Baker Hughes, a GE company)
The typical rating for downhole measurement-while-drilling equipment for oil and gas drilling is between 150°C and 175°C. There are currently few available drilling systems rated for operation at temperatures above 200°C. This paper describes the development, testing and field deployment of a drilling system comprised of drill bits, positive displacement motors and drilling fluids capable of drilling at operating temperatures up to 300°C. It also describes the development and testing of a 300°C capable measurement-while-drilling platform.
The development of 300°C technologies for geothermal drilling also extends tool capabilities, longevity and reliability at lower oilfield temperatures. New technologies developed in this project include 300°C drill bits, metal-to-metal motors, and drilling fluid, and an advanced hybrid electronics and downhole cooling system for a measurement-while-drilling platform. The overall approach was to remove elastomers from the drilling system and to provide a robust "drilling-ready" downhole cooling system for electronics. The project included laboratory testing, field testing and full field deployment of the drilling system. The US Department of Energy Geothermal Technologies Office partially funded the project.
The use of a sub-optimal drilling system due to the limited availability of very high temperature technology can result in unnecessarily high overall wellbore construction costs. It can lead to short runs, downhole tool failures and poor drilling rates. The paper presents results from the testing and deployment of the 300°C drilling system. It describes successful laboratory testing of individual bottom-hole-assembly components, and full-scale integration tests on an in-house research rig. The paper also describes the successful deployment of the 300°C drilling system in the exploratory geothermal well IDDP-2 as part of the Iceland Deep Drilling Project. The well reached a measured depth of 4659m, by far the deepest in Iceland. The paper includes drilling performance data and the results of post-run analysis of bits and motors used in this well, which confirm the encouraging results obtained during laboratory tests. The paper also discusses testing and performance of the 300°C rated measurement-while-drilling components – hybrid electronics, power and telemetry - and the performance of the drilling tolerant cooling system.
This is the industry's first 300°C capable drilling system, comprising metal-to-metal motors, drill bits, drilling fluid and accompanying measurement-while-drilling system. These new technologies provide opportunities for drilling oil and gas wells in previously undrillable ultra-high temperature environments.
With the deepening of exploration and development of onshore and offshore oilfields, cluster wells and infill wells are more and more popular. It will greatly increase the possibility of well collision during the drilling and would have great harm to drilling and the production of oilfield. The normal detecting technique of anti-collision is based on the measured well trajectory data and the judgment on the abnormality during drilling. The error of measured data and the uncertainty of downhole situation will result a high risk of collision. Based on detecting the drill bit vibration, a new anti-collision technology is proposed. Firstly, the acceleration sensors are installed on the casing head of risky well to collect the drill bit vibration signal transmitted by the formation and casing. Secondly, the signals are feature extraction by the calculation analysis software based on the time domain analysis and frequency domain analysis to recognize the approach motive of the drilling bit to the risky well. Thirdly, the characteristic signals are shown in real time. When the characteristic value is greater than the threshold value, an alarm will be given for the directional drilling engineer to do the anti-collision scanning in time and decide whether or not to change the well trajectory. This technology was applied in an offshore block in Bohai Oilfield and some fields in South China Sea. The results showed that the risk casing head vibration signal induced by drill bit vibration had a characteristic frequency range and the vibration signal characteristics were related with the distance between drill bit and the risk casing definitely. The vibration signals at the drilling casing head were very strong when cement plug was drilled, which could be used to judge whether bit was close to the cement sheath and casing of risky wells. The signal amplitude acquired at the casing head of risky well declined with the increase of distance between the drilling well and risky well. It can be used to judge the risk of wellbore collision. The results of field tests showed that new technology could monitor the well anti-collision and alert. It can improve the cluster and infill drilling effectively.
This is a new anti-collision technology based on detecting the drill bit vibration signal collected by the acceleration sensors installed on the casing head of drilling and risky wells.
Copyright 2012, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Saudi Arabia Section Technical Symposium and Exhibition held in Al-Khobar, Saudi Arabia, 8-11 April 2012. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Papers presented at the SPE meetings are subject to publication review by Editorial Committee of Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied.
Abtahi, A. (Memorial University of Newfoundland) | Butt, S. (Memorial University of Newfoundland) | Molgaard, J. (Memorial University of Newfoundland) | Arvani, F. (Memorial University of Newfoundland)
X-ray computed tomography (CT scanning) was used to determine the vesicular porosity, average vesicle size, and average vesicle perimeter of fourteen specimens taken from five boulders. Band Pass Filtering was determined to be the best image processing technique to determine vesicular porosity. Porosity values determined using density values were 1.2 to 2.0 times greater than those determined using CT scanning. Porosity values and average vesicle size were very consistent between boulders but vesicle perimeter varied between specimens from the same boulder. The difference is attributed to the shape of the vesicles. Unconfined compressive strength of the specimens was also determined and plotted as a function of porosity as determined using Band Pass Filtering. One anomalous result was attributed to a difference in vesicle shape. CT scanning is an appropriate technique for measuring porosity and vesicle characteristics in a repeatable, non-destructive fashion. Additional work is being conducted for determining vesicle shape parameters to further develop a predicative relationship between strength and porosity.
It is well established that porosity, both microporosity and macroporosity, has a detrimental effect on the strength and stiffness of rock. In order to investigate the effects of porosity on strength and stiffness it is imperative to have accurate measures of total porosity. Other porosity parameters such as pore size, pore shape, and relative location of pores within a specimen would also be valuable parameters. Vesicular basalt specimens obtained from surface boulders from southern Nevada were used in this study. In terms of mechanical strength, basalt is one of the most competent of all rocks. Formed by extrusive volcanic action, it commonly has a micro-fine texture and consists of micro-crystals of augite and plagioclase held together by strong mechanical bonding . A characteristic of basalt that reduces its intact strength and stiffness is the presence of voids (vesicles) formed by trapped gases unable to escape during its rapid cooling process. Vesicular porosity within basalt is typically comprised of isolated pores that may or may not have coalesced with other pores to form larger pores . This paper presents the results of an investigation of the vesicular porosity of fourteen vesicular basalt specimens cored from boulders from southern Nevada. The vesicular porosity was determined using x-ray computed tomography (CT) images from the Montana State University CT scanner. The CT images were analyzed using three different image processing techniques. Vesicular porosity was also determined using specific gravity values of basalt. The porosity values from the four techniques are compared and relationships between vesicular porosity and unconfined compressive strength are presented.
2. PORES AND POROSITY
Pores are open spaces between mineral grains. All pores, regardless of size, shape, location, etc., influence macroscopic physical and engineering properties. There are a number of methods of classifying pores but perhaps the most convenient is accessibility to external fluids. Figure 1 is an exaggerated core slice showing different types of pores. The heavy black line represents the hypothetical edge of the core. The actual edge of the core is gray.
Borehole quality of point-the-bit rotary steerable systems (RSS) has been well documented in the industry. This type of system, using an extended passive-gauge polycrystalline diamond compact (PDC) bit and/or a full-gauge near-bit stabilizer to tilt the bit, is known to produce high-quality borehole due to the extra lateral stability added to the lower part of the bottom-hole assembly (BHA), below the RSS deflection unit. Yet, extended-gauge PDC bits and full-gauge stabilizers are not suitable for every drilling environment, and a push-the-bit system may be more applicable in certain formations.
On the other hand, borehole quality of push-the-bit RSS has not been extensively discussed in the past, partly because the PDC bit gauge length and profile are directly related to the directional response of the tool, and different gauge lengths may be used based on the application. This type of system may lack lateral stabilization between the bit face and steering unit, depending on the type of bits used and the steering mechanism. To increase the lateral stability and borehole quality of the system, in-depth analysis of PDC bit (gauge type and length) and BHA design is required.
This paper describes the results of extensive downhole drilling tests conducted on a push-the-bit RSS. The controlled tests were conducted using various PDC bits drilling through different formations. Improvements in stability and borehole quality have been examined using vibration data and a unique near-bit 2-D/3-D caliper image. Visualization of the borehole, using 3-D caliper images and their spectrum analysis, reveals that borehole quality is highly dependant on the BHA components below the RSS steering unit.
The test results show that progressive testing with innovative imaging techniques can systematically improve the performance of push-the-bit RSS and produce a better understanding of the interaction among the bit, formation, and RSS steering unit. Proper use of these techniques helps during the development of a field where troublesome formations are encountered and poor borehole quality leads to high torque and drag which limits the drilling performance.
This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 112650, "Drilling- Vibrations Modeling and Field Validation," by J.R. Bailey, SPE, E.A.O. Biediger, SPE, V. Gupta, SPE, D. Ertas, SPE, W.C. Elks, SPE, and F.E. Dupriest, SPE, ExxonMobil, originally prepared for the 2008 IADC/SPE Drilling Conference, Orlando, Florida, 4-6 March. The paper has not been peer reviewed.
A modeling tool has been developed that enables drilling engineers to design vibration-resistant bottomhole assemblies (BHAs), given tool-placement constraints and desired directional objectives. This model can be applied to configurations with the majority of common drilling components. Modeling results have been validated in large, intermediate, and small hole sizes. Redesign has resulted in improved drilling results, including increased on-bottom drilling time, longer tool life, higher rate of penetration (ROP), reduced nonproductive time associated with tripping, and better hole quality.
Vibration of drillstrings and BHAs has contributed to operational problems since rotary drilling was first invented. Failure of drillstring components, such as rotary-steerable (RS) BHAs or logging-while-drilling (LWD) tools, may result in nonproductive time while tripping to replace the failed equipment. Downhole components may eventually part so that fishing or sidetracking operations are required. In some situations, equipment failure also can result in well abandonment. In addition to these unplanned events, whirl or lateral vibration causes the cutting action of the bit to be inefficient, and ROP may decline significantly. The operator drills approximately four million ft of hole each year, and mechanical-specific-energy (MSE) analysis suggests that the performance in more than 40% of this footage is affected adversely by whirl.
At various times in the past, investigators have focused on certain elements of the drillstring-dynamics problem and have made some progress, to be succeeded by new theories using generally more-complicated models. The current activity is marked by an emphasis on digital-data collection using both surface and downhole instruments, and the use of time-domain modeling to take advantage of increasing computing power. The full-length paper represents an attempt by the operator to strike a forward path by maximizing the benefits of both worlds: using digital systems to take measurements only recently made possible and developing and using sophisticated frequency-domain dynamic-modeling tools to characterize the dynamic performance of BHAs.
There have been significant attempts to optimize the various bottom-hole assemblies (BHAs) used in rotary steerable (RS) applications because the optimal RS assembly can provide operators with significant cost savings by providing less vibration, high BHA stability, high-quality borehole, and thus predictable steerability.
This paper presents the development of BHA analysis models using simplified mathematical equations. RS BHA optimization process is demonstrated through the extensive field test program. The predictions of BHA response and directional drilling performance of the RSS have been examined with the numerous field test data taken in a controlled and non-commercial environment, allowing single step changes in both the drill bit features and RS configurations.
The testing is unique since the specific rotary-steerable system (RSS) works in field-configurable point-the-bit and push-the-bit modes. Between two distinct RSS operation modes, consistency in stiffness, weight, force applying capability, and control system lead to a direct comparison of different BHA models. Confidential test sites were selected for evaluating different RS BHA configurations in both push-the-bit and point-the-bit modes. The systematic BHA testing was conducted in two different test facilities in North America.
A unique sensor system, integrated into the specific RSS, provided real-time measurement of near-bit borehole caliper and near-bit stick-slip and vibration 1,2. This feature allowed real-time evaluation of bit and BHA stability and borehole quality while the maximum build-up test was performed. After each test run, memory data was retrieved and used for more detailed assessment of bit and BHA performance.
BHA configuration tests were systematically conducted in a controlled environment so that the relationship between BHA analysis models and actual BHA behaviors could be identified. As a result, the systematic testing and verification lead to the optimal RS BHA design in both push-the-bit and point-the-bit configurations for stability, steerability and borehole quality.
Copyright 2008, IADC/SPE Drilling Conference This paper was prepared for presentation at the 2008 IADC/SPE Drilling Conference held in Orlando, Florida, U.S.A., 4-6 March 2008. This paper was selected for presentation by an IADC/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the International Association of Drilling Contractors or the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the International Association of Drilling Contractors or the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the International Association of Drilling Contractors or the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of IADC/SPE copyright. Abstract There is significant discussion concerning what type of Rotary Steerable System (RSS) provides the best-quality hole, and which key characteristics of the drill bit, along with a particular RSS, will produce the optimal balance between stability and steerability in directional wells. Although some evidence can be drawn from field performance with various tools and customized drill bits, these results can often be inconclusive due to the large variance in factors involved with commercial drilling. This paper describes an extensive series of test wells drilled in a controlled and noncommercial environment, allowing single step changes in both the drill bit features and Rotary Steerable (RS) configurations. The testing is unique in that the specific RSS works in shop-configurable point-the-bit and push-the-bit modes.