Extremely tortuous wells pose many wellbore quality repercussions and poorly affects several well drilling and production-based operations. To date, many indices have been developed for accurate tortuosity identification, but few have had the capability to efficiently mirror and quantify micro-tortuosity in real-time. This study applies a previously-proposed novel algorithm studied by some researchers to quantify well trajectory tortuosity using simple and readily available survey data. The process is followed and validated using twenty wells located in the Permian Basin. Python code was written to identify proper inflection points at the mid-point of the curve turns and using inclination and azimuth indices, a 3D overall TI index was generated for each well. The technique is inspired from the discipline of ophthalmology, specifically a method to determine tortuosity from retinal blood vessels. The approach successfully produced a tortuosity metric with three different risk categories characterizing three ranges of the index. The indices generated were matched against operator reports of drilling incidents and NPT. The methodology matched highly tortuous wells with greater downhole tool failures rates ranking it in the high-risk zone.
{"title":"Calculating a Tortuosity Index Metric Using Machine Learning Techniques","authors":"C. Noshi","doi":"10.2118/194076-MS","DOIUrl":"https://doi.org/10.2118/194076-MS","url":null,"abstract":"\u0000 Extremely tortuous wells pose many wellbore quality repercussions and poorly affects several well drilling and production-based operations. To date, many indices have been developed for accurate tortuosity identification, but few have had the capability to efficiently mirror and quantify micro-tortuosity in real-time. This study applies a previously-proposed novel algorithm studied by some researchers to quantify well trajectory tortuosity using simple and readily available survey data. The process is followed and validated using twenty wells located in the Permian Basin.\u0000 Python code was written to identify proper inflection points at the mid-point of the curve turns and using inclination and azimuth indices, a 3D overall TI index was generated for each well. The technique is inspired from the discipline of ophthalmology, specifically a method to determine tortuosity from retinal blood vessels.\u0000 The approach successfully produced a tortuosity metric with three different risk categories characterizing three ranges of the index. The indices generated were matched against operator reports of drilling incidents and NPT. The methodology matched highly tortuous wells with greater downhole tool failures rates ranking it in the high-risk zone.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129273705","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. Ciuperca, Davide Di Tommaso, M. Dawber, Jonathan Tidswell
A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool. An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall. Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements. The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination. It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job. The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.
{"title":"Determining Wellbore Stability Parameters Using a New LWD High Resolution Ultrasonic Imaging Tool","authors":"C. Ciuperca, Davide Di Tommaso, M. Dawber, Jonathan Tidswell","doi":"10.2118/194074-MS","DOIUrl":"https://doi.org/10.2118/194074-MS","url":null,"abstract":"\u0000 A new LWD ultrasonic imager for use in both water- and oil-based muds uses acoustic impedance contrast and ultrasonic amplitude measurements to obtain high-resolution structural, stratigraphic and borehole geometry information. Following extensive testing in the Middle East and the US, this paper presents results from the first European deployment of the new 4.75-in. high-resolution ultrasonic imaging tool.\u0000 An ultrasonic transducer, which operates at high frequency, scans the borehole at a high sampling rate to provide detailed measurements of amplitude and traveltime. A borehole caliper measurement is made, based on the time of arrival of the first reflection from the borehole wall. A second measurement detects formation features and tectonic stress indicators from the change in signal amplitude. The amplitude of the reflected wave is a function of the acoustic impedance of the medium. Resulting impedance maps have sufficient resolution to detect sinusoidal, non-sinusoidal and discontinuous features on the borehole wall.\u0000 Breakouts, drilling-induced fractures, and tensile zones were used for stress direction determination. Breakout identification was obtained both from amplitude images and oriented potato plot cross sections derived from traveltime measurements.\u0000 The orientation of natural fractures is parallel at the maximum stress direction, indicated by drilling-induced fractures and tensile zones. The World Stress Map confirms the maximum stress direction determination.\u0000 It was also possible to detect certain key-seat zones and investigate borehole conditions to prevent issues during the subsequent casing job.\u0000 The new LWD ultrasonic imaging technique represents an important alternative to density and water-based mud resistivity imaging, which has several limitations. Unlike the resistive imaging LWD tool that is very sensitive to standoff, the higher tolerance of the ultrasonic imaging tool enables the amplitude and traveltime ultrasonic images to contain fewer unwanted artifacts.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"51 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130209813","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Cutting forces at the bit or mass imbalances in downhole tools such as mud motors can cause severe vibrations in drillstrings and bottom-hole assemblies (BHA). Negative effects include reduced rate of penetration, low-quality measurements and downhole tool failures. A value that represents the real downhole vibration level is needed to perform a reasonable mitigation strategy. The most common values are statistical values derived from acceleration signals that are received from a sensor at a specific distance from the bit (DfB). The interpretation of an acceleration signal is limited if only one mode shape is dominantly excited. In this case, the measurement signal is very sensitive with respect to the DfB of the sensor placement. The derivation of a representative value for the severity of high-frequency torsional oscillation (HFTO) is shown that is independent of the sensor position. In the proposed approach, the dynamic torsional torque is used in addition to the tangential acceleration measurement. The frequency information of both measurement signals are determined and an analytical model is used to calculate the maximum value of vibration amplitudes that occurs along the BHA. The algorithm is implemented in the measurement-while drilling (MWD) tool for vibration and load measurements. The maximum load value in the BHA corresponding to HFTO can be sent to the surface in real time for interpretation by the driller. In a case study, different scenarios from the field are discussed. The maximum load values are compared to numerical simulations that show an excellent agreement. The maximum value calculated by the approach is factors higher than the values measured by the accelerometers. By using the algorithm-upgrade of the MWD tool, a representative measurement value for the severity of HFTO loads is derived. This is a clear advantage compared to tangential acceleration measurement only. The value enables the driller or an automated advisory system to initiate the optimal HFTO mitigation strategy that leads to reduced levels of vibration with the known benefits for the cost of a well.
{"title":"Real-Time System to Calculate the Maximum Load of High-Frequency Torsional Oscillations Independent of Sensor Positioning","authors":"H. Andreas, P. Eric, A. Pedro","doi":"10.2118/194071-MS","DOIUrl":"https://doi.org/10.2118/194071-MS","url":null,"abstract":"\u0000 Cutting forces at the bit or mass imbalances in downhole tools such as mud motors can cause severe vibrations in drillstrings and bottom-hole assemblies (BHA). Negative effects include reduced rate of penetration, low-quality measurements and downhole tool failures. A value that represents the real downhole vibration level is needed to perform a reasonable mitigation strategy. The most common values are statistical values derived from acceleration signals that are received from a sensor at a specific distance from the bit (DfB). The interpretation of an acceleration signal is limited if only one mode shape is dominantly excited. In this case, the measurement signal is very sensitive with respect to the DfB of the sensor placement.\u0000 The derivation of a representative value for the severity of high-frequency torsional oscillation (HFTO) is shown that is independent of the sensor position. In the proposed approach, the dynamic torsional torque is used in addition to the tangential acceleration measurement. The frequency information of both measurement signals are determined and an analytical model is used to calculate the maximum value of vibration amplitudes that occurs along the BHA. The algorithm is implemented in the measurement-while drilling (MWD) tool for vibration and load measurements. The maximum load value in the BHA corresponding to HFTO can be sent to the surface in real time for interpretation by the driller.\u0000 In a case study, different scenarios from the field are discussed. The maximum load values are compared to numerical simulations that show an excellent agreement. The maximum value calculated by the approach is factors higher than the values measured by the accelerometers.\u0000 By using the algorithm-upgrade of the MWD tool, a representative measurement value for the severity of HFTO loads is derived. This is a clear advantage compared to tangential acceleration measurement only. The value enables the driller or an automated advisory system to initiate the optimal HFTO mitigation strategy that leads to reduced levels of vibration with the known benefits for the cost of a well.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"24 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124956220","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. Dwars, Morten Lien, Søren Øydna, T. Baumgartner
This work investigates the results of the first deployment in the industry of technology Z on an offshore drilling rig with a heavy top drive. The study uses a quantitative analysis of downhole data to confirm the benefits of Z. Z expands the stick-slip free operating envelope and does not require tuning. Following a dozen or so Z land rig deployments since 2015, the technology was added to a heavy offshore rig, a newbuilt, with modern hi-end variable frequency drives that enable near-zero control loop latencies. A study validates the effectiveness of the system with downhole rotary speed data. The Z system was used for multiple sections in the Barents Sea, where the overburden traditionally causes troublesome torsional vibrations. The users of the technology gave a positive feedback from their first experiences. This work aims to verify qualitative surface observations with a quantitative analysis of downhole data. Downhole sensors captured the dynamics of multiple locations in the drill string over the course of about 3 weeks. Stick-slip severity was quantified using downhole rotary speed data. Periods when Z was turned on were compared to periods when Z was turned off.
{"title":"Curing stick-slip: Eureka.","authors":"S. Dwars, Morten Lien, Søren Øydna, T. Baumgartner","doi":"10.2118/194108-MS","DOIUrl":"https://doi.org/10.2118/194108-MS","url":null,"abstract":"\u0000 This work investigates the results of the first deployment in the industry of technology Z on an offshore drilling rig with a heavy top drive. The study uses a quantitative analysis of downhole data to confirm the benefits of Z.\u0000 Z expands the stick-slip free operating envelope and does not require tuning. Following a dozen or so Z land rig deployments since 2015, the technology was added to a heavy offshore rig, a newbuilt, with modern hi-end variable frequency drives that enable near-zero control loop latencies. A study validates the effectiveness of the system with downhole rotary speed data.\u0000 The Z system was used for multiple sections in the Barents Sea, where the overburden traditionally causes troublesome torsional vibrations. The users of the technology gave a positive feedback from their first experiences. This work aims to verify qualitative surface observations with a quantitative analysis of downhole data. Downhole sensors captured the dynamics of multiple locations in the drill string over the course of about 3 weeks. Stick-slip severity was quantified using downhole rotary speed data. Periods when Z was turned on were compared to periods when Z was turned off.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"153 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127280193","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Arnø, Andreas Thuve, S. Knoop, S. Hovda, A. Pavlov, F. Florence
The Society of Petroleum Engineers (SPE) organizes the international student competition Drillbotics. The task is to develop a miniature robotic rig to drill, in a fully autonomous operation, a vertical hole in a 35 cm rock sample with unknown layers – as fast as possible, while maintaining rig integrity and borehole quality. This paper describes the key innovations of the 2nd generation NTNU robotic drilling rig, allowing it to take first place in the 2018 competition. The rig features a wide operational window for WOB and RPM, achieved by a custom-designed non-aggressive bit, improved BHA design, reinforced drill-string connections and improved rig framework. These improvements allow the rig to drill much faster at high WOB and RPM while avoiding drill-string twist-offs due to over-torqueing or fatigue caused by vibrations. An autonomous high-ROP mode was employed on the competition day. The best-fit PID controller tuning enables high performance drilling through both soft- and hard formations. Built-in logics automatically detect and handle over-torqueing and stuck pipe. A novel digitalization framework includes a fit-for-purpose data acquisition and visualization system, data-lake for unified data storage and an automatic well reporting functionality. The system logs all measurements, setpoints and calculations, including WOB, RPM, ROP, drill string torque, stand-pipe pressure, and downhole accelerations and angles (gyroscope). The NTNU drilling rig managed to drill through a 35 cm competition rock consisting of layers of varying hardness, including a hard tile inclined at 45 deg in 3 minutes and 15 seconds, thus proving its ability of efficient and safe autonomous drilling. The drilling time of the nearest competitor was 15 minutes.
{"title":"Design and Implementation of a Miniature Autonomous Drilling Rig for Drillbotics 2018","authors":"M. Arnø, Andreas Thuve, S. Knoop, S. Hovda, A. Pavlov, F. Florence","doi":"10.2118/194226-MS","DOIUrl":"https://doi.org/10.2118/194226-MS","url":null,"abstract":"\u0000 The Society of Petroleum Engineers (SPE) organizes the international student competition Drillbotics. The task is to develop a miniature robotic rig to drill, in a fully autonomous operation, a vertical hole in a 35 cm rock sample with unknown layers – as fast as possible, while maintaining rig integrity and borehole quality. This paper describes the key innovations of the 2nd generation NTNU robotic drilling rig, allowing it to take first place in the 2018 competition.\u0000 The rig features a wide operational window for WOB and RPM, achieved by a custom-designed non-aggressive bit, improved BHA design, reinforced drill-string connections and improved rig framework. These improvements allow the rig to drill much faster at high WOB and RPM while avoiding drill-string twist-offs due to over-torqueing or fatigue caused by vibrations.\u0000 An autonomous high-ROP mode was employed on the competition day. The best-fit PID controller tuning enables high performance drilling through both soft- and hard formations. Built-in logics automatically detect and handle over-torqueing and stuck pipe.\u0000 A novel digitalization framework includes a fit-for-purpose data acquisition and visualization system, data-lake for unified data storage and an automatic well reporting functionality. The system logs all measurements, setpoints and calculations, including WOB, RPM, ROP, drill string torque, stand-pipe pressure, and downhole accelerations and angles (gyroscope).\u0000 The NTNU drilling rig managed to drill through a 35 cm competition rock consisting of layers of varying hardness, including a hard tile inclined at 45 deg in 3 minutes and 15 seconds, thus proving its ability of efficient and safe autonomous drilling. The drilling time of the nearest competitor was 15 minutes.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"33 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115962821","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The main objective of this study was to understand the impact high-resolution measurement-while-drilling (MWD) surveys have on casing standoff and mud removal simulations and its impact on final cement program design and risk analysis. High-resolution surveys use a combination of static and continuous MWD inclination data to characterize the well trajectory at 3-m (10-ft) intervals rather than the current industry practices at every stand; i.e., 30 m (100 ft). However, several case studies had demonstrated that surveying the well path at these intervals is often not sufficient to capture the true characterization of the well in question. This result, in some scenarios, leads to significant errors in the final reported dogleg severity (DLS) and tortuosity; therefore, resulting in optimistic well engineering simulations due the hidden additional tortuosity not applied in the models. Two North Sea wells were analyzed when using conventional trajectories defined at each drillstring stand as well as using high-resolution trajectories to evaluate the impact on casing centralization and mud removal simulations. The latest generation cementing software for placement simulation was used in this study. The simulation has the capabilities to deal with computing pipe standoff and angle direction in a 3D annulus, including gravitational forces for accurate mud displacement and removal. This study confirmed that high-resolution MWD survey data can provide additional precise input for casing standoff and mud removal simulation, resulting in a more realistic simulation result due to the appearance of microtortuosity and DLS. Simulation results using high-resolution directional survey data identified conditions where the original mud removal assessment using a standard survey was overestimated due to higher standoff. This result allows an appropriate level of risk assessment and cement job design optimization to improve both the casing standoff and mud removal, which will eventually impact the well integrity quality. This study proved that centralization and mud removal simulations can be, in some scenarios, optimistic if performed using standard trajectories. The results also proved that the risk assessments for the cement program designs will be evaluated differently because the enhanced simulations provide a more accurate result, which impacts the final centralization and mud removal to ensure effective zonal isolation.
{"title":"Using High-Resolution MWD Survey Data in Mud Removal Simulations for Effective Cementing Program Design","authors":"Leida C. Monterrosa, C. Tay, J. Salazar","doi":"10.2118/194101-MS","DOIUrl":"https://doi.org/10.2118/194101-MS","url":null,"abstract":"\u0000 The main objective of this study was to understand the impact high-resolution measurement-while-drilling (MWD) surveys have on casing standoff and mud removal simulations and its impact on final cement program design and risk analysis.\u0000 High-resolution surveys use a combination of static and continuous MWD inclination data to characterize the well trajectory at 3-m (10-ft) intervals rather than the current industry practices at every stand; i.e., 30 m (100 ft). However, several case studies had demonstrated that surveying the well path at these intervals is often not sufficient to capture the true characterization of the well in question. This result, in some scenarios, leads to significant errors in the final reported dogleg severity (DLS) and tortuosity; therefore, resulting in optimistic well engineering simulations due the hidden additional tortuosity not applied in the models.\u0000 Two North Sea wells were analyzed when using conventional trajectories defined at each drillstring stand as well as using high-resolution trajectories to evaluate the impact on casing centralization and mud removal simulations.\u0000 The latest generation cementing software for placement simulation was used in this study. The simulation has the capabilities to deal with computing pipe standoff and angle direction in a 3D annulus, including gravitational forces for accurate mud displacement and removal.\u0000 This study confirmed that high-resolution MWD survey data can provide additional precise input for casing standoff and mud removal simulation, resulting in a more realistic simulation result due to the appearance of microtortuosity and DLS. Simulation results using high-resolution directional survey data identified conditions where the original mud removal assessment using a standard survey was overestimated due to higher standoff. This result allows an appropriate level of risk assessment and cement job design optimization to improve both the casing standoff and mud removal, which will eventually impact the well integrity quality.\u0000 This study proved that centralization and mud removal simulations can be, in some scenarios, optimistic if performed using standard trajectories. The results also proved that the risk assessments for the cement program designs will be evaluated differently because the enhanced simulations provide a more accurate result, which impacts the final centralization and mud removal to ensure effective zonal isolation.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"111 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116810551","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The use of advanced solid-state gyroscopic sensors has now become both a viable and practical option for high accuracy wellbore placement, with the potential to out-perform traditional mechanical gyroscopic systems. This paper describes how the contributions of the new gyroscope technology are causing service providers to reconsider current survey practices, and to examine how the new gyroscopic survey tools can be best used for wellbore surveying and real-time wellbore placement. The simultaneous application of multiple survey tools, largely made possible as a result of the unique attributes of solid-state gyroscopic sensors (including small size and significant power reduction), has clear benefits in terms of enhanced well placement, reliability and the detection of gross errors in the survey process. Further benefits accrue through the combination of different, but complimentary survey methods. This paper focuses mainly on the benefits of combining gyroscopic and magnetic measurements to reduce or remove the known errors related to the Earth's magnetic field to which magnetic survey systems are susceptible; errors in total magnetic field, declination and dip angle. In this context, the use of statistical estimation techniques based on performance models of the survey systems used is described. For post-drilling surveys (using drop survey tools or wireline-conveyed tools for example), post-run analysis of the data using least-squares estimation techniques is appropriate. Alternative methods capable of achieving real-time data correction during drilling are also described and results are presented to demonstrate the potential for enhanced magnetic survey performance. The principles described may be used when running basic magnetic measurement while drilling (MWD) systems, and for systems that employ field correction methods, such as the various in-field referencing (IFR) techniques, that are frequently used. The proposed methodology is of particular benefit in the former case, allowing enhanced magnetic surveying to be achieved without the need for expensive and complex magnetic field correction procedures. The potential also exists either to identify or to correct possible errors in the IFR data when such methods are used. This information may be of great value for the safe drilling of additional wells in the same region.
{"title":"Combined Gyroscopic and Magnetic Surveys Provide Improved Magnetic Survey Data and Enhanced Survey Quality Control","authors":"J. Weston, Adrian G. Ledroz","doi":"10.2118/194130-MS","DOIUrl":"https://doi.org/10.2118/194130-MS","url":null,"abstract":"\u0000 The use of advanced solid-state gyroscopic sensors has now become both a viable and practical option for high accuracy wellbore placement, with the potential to out-perform traditional mechanical gyroscopic systems. This paper describes how the contributions of the new gyroscope technology are causing service providers to reconsider current survey practices, and to examine how the new gyroscopic survey tools can be best used for wellbore surveying and real-time wellbore placement.\u0000 The simultaneous application of multiple survey tools, largely made possible as a result of the unique attributes of solid-state gyroscopic sensors (including small size and significant power reduction), has clear benefits in terms of enhanced well placement, reliability and the detection of gross errors in the survey process. Further benefits accrue through the combination of different, but complimentary survey methods. This paper focuses mainly on the benefits of combining gyroscopic and magnetic measurements to reduce or remove the known errors related to the Earth's magnetic field to which magnetic survey systems are susceptible; errors in total magnetic field, declination and dip angle.\u0000 In this context, the use of statistical estimation techniques based on performance models of the survey systems used is described. For post-drilling surveys (using drop survey tools or wireline-conveyed tools for example), post-run analysis of the data using least-squares estimation techniques is appropriate. Alternative methods capable of achieving real-time data correction during drilling are also described and results are presented to demonstrate the potential for enhanced magnetic survey performance.\u0000 The principles described may be used when running basic magnetic measurement while drilling (MWD) systems, and for systems that employ field correction methods, such as the various in-field referencing (IFR) techniques, that are frequently used. The proposed methodology is of particular benefit in the former case, allowing enhanced magnetic surveying to be achieved without the need for expensive and complex magnetic field correction procedures. The potential also exists either to identify or to correct possible errors in the IFR data when such methods are used. This information may be of great value for the safe drilling of additional wells in the same region.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"74 3-4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114035530","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Z. Fang, Norshah Zamikhan, R. Tarang, Chee Khong On, Pieter Huver
Fracture gradient (FG) of wellbores is the function of not only stresses, formation pressure and rock mechanical properties but also well trajectories. An accurate FG prediction is critical for safe well drilling. However, the existing methods do not account for the trajectory effects. An integrated geomechanical approach has been developed to more accurately predict the FG of wellbores subject to various trajectories. The approach deploys the Kirsch equations and takes into account the effects of formation pressure variations on stresses. It further integrates the elaborated individual procedures for deriving the geomechanical input parameters from regional field data to form a FG model. After verifying the losses test and offset well drilling data with necessary modifications, the calibrated FG model is then able to more accurately predict the fracture initiation pressure (FIP) of wellbores to mitigate the drilling losses for not only vertical but also deviated wellbores by guiding the equivalent circulation density (ECD) management. The integrated geomechanical approach has been applied to the planning and drilling of more than 30 new wells at Brunei Shell Petroleum (BSP). It has significantly mitigated the drilling losses for the challenging wells of a field redevelopment project in which about 50 deviated wells were expecting narrow drilling windows due to penetrating heavily depleted reservoirs. In another drilling campaign, it saved the sidetrack of a lost hole section by revising the trajectory as instructed by the FIP predictions. The integrated geomechanical approach is an algorithm that can effectively mitigate drilling losses by accurately predicting the FG for any arbitrary wellbores.
{"title":"An Integrated Geomechanical Approach to Accurately Predicting the Fracture Gradient for Mitigating Drilling Losses of Challenging Wellbores","authors":"Z. Fang, Norshah Zamikhan, R. Tarang, Chee Khong On, Pieter Huver","doi":"10.2118/194139-MS","DOIUrl":"https://doi.org/10.2118/194139-MS","url":null,"abstract":"\u0000 Fracture gradient (FG) of wellbores is the function of not only stresses, formation pressure and rock mechanical properties but also well trajectories. An accurate FG prediction is critical for safe well drilling. However, the existing methods do not account for the trajectory effects. An integrated geomechanical approach has been developed to more accurately predict the FG of wellbores subject to various trajectories. The approach deploys the Kirsch equations and takes into account the effects of formation pressure variations on stresses. It further integrates the elaborated individual procedures for deriving the geomechanical input parameters from regional field data to form a FG model. After verifying the losses test and offset well drilling data with necessary modifications, the calibrated FG model is then able to more accurately predict the fracture initiation pressure (FIP) of wellbores to mitigate the drilling losses for not only vertical but also deviated wellbores by guiding the equivalent circulation density (ECD) management.\u0000 The integrated geomechanical approach has been applied to the planning and drilling of more than 30 new wells at Brunei Shell Petroleum (BSP). It has significantly mitigated the drilling losses for the challenging wells of a field redevelopment project in which about 50 deviated wells were expecting narrow drilling windows due to penetrating heavily depleted reservoirs. In another drilling campaign, it saved the sidetrack of a lost hole section by revising the trajectory as instructed by the FIP predictions. The integrated geomechanical approach is an algorithm that can effectively mitigate drilling losses by accurately predicting the FG for any arbitrary wellbores.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"94 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128317642","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Alexander M. Mitkus, S. Maus, Marc E. Willerth, Andrew Reetz, R. Oskarsen, Morten H. Emilsen, Amir Gergerechi
As development of the Barents Sea continues with new plays such as the Castberg, accurate specification of the local magnetic field is important to reliably infer the orientation of the bottomhole assembly (BHA) in horizontal drilling. Since magnetic fields at high latitudes vary spatially and temporally, one requires both spatial models and a way to capture temporal changes. Large temporal changes in the magnetic field can severly distort measured azimuths and therefore must be corrected for. This study, based on a report written for Petroleumstilsynet (Maus et al., 2017), shows that in regions of the Barents Sea within 50 km of a magnetic observatory, either the nearest observatory, interpolated infield referencing (IIFR), or the disturbance function (DF) method may be used for corrections in wellbore surveying to meet accuracy requirements. IIFR and DF will give better error reduction but are slightly more complicated to implement. At distances between 50 km and 250 km, the disturbance field (DF) method best meets accuracy requirements. In remote regions beyond 250 km, a local observatory must be deployed to meet the highest accuracy specifications, but the DF will still far outperform the other interpolated methods at such large distances from an existing observatory. Despite having focused on the Barents Sea region, this comparison of the accuracy of different spatial and temporal magnetic field mitigation methods for wellbore surveying is applicable to high latitude northern and southern regions across the globe.
{"title":"Challenges and Solutions for Accurate Wellbore Placement in the Barents Sea","authors":"Alexander M. Mitkus, S. Maus, Marc E. Willerth, Andrew Reetz, R. Oskarsen, Morten H. Emilsen, Amir Gergerechi","doi":"10.2118/194067-MS","DOIUrl":"https://doi.org/10.2118/194067-MS","url":null,"abstract":"\u0000 As development of the Barents Sea continues with new plays such as the Castberg, accurate specification of the local magnetic field is important to reliably infer the orientation of the bottomhole assembly (BHA) in horizontal drilling. Since magnetic fields at high latitudes vary spatially and temporally, one requires both spatial models and a way to capture temporal changes. Large temporal changes in the magnetic field can severly distort measured azimuths and therefore must be corrected for.\u0000 This study, based on a report written for Petroleumstilsynet (Maus et al., 2017), shows that in regions of the Barents Sea within 50 km of a magnetic observatory, either the nearest observatory, interpolated infield referencing (IIFR), or the disturbance function (DF) method may be used for corrections in wellbore surveying to meet accuracy requirements. IIFR and DF will give better error reduction but are slightly more complicated to implement. At distances between 50 km and 250 km, the disturbance field (DF) method best meets accuracy requirements. In remote regions beyond 250 km, a local observatory must be deployed to meet the highest accuracy specifications, but the DF will still far outperform the other interpolated methods at such large distances from an existing observatory.\u0000 Despite having focused on the Barents Sea region, this comparison of the accuracy of different spatial and temporal magnetic field mitigation methods for wellbore surveying is applicable to high latitude northern and southern regions across the globe.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128407441","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Managed Pressure Drilling is a new technology that has recently emerged in the industry. It has special well control capabilities supported by the rotating control device to simultaneously provide the required pressure control on a certain volume gas influx and maintain the pipe rotation for drilling or any other operation. This paper examines the effect of pipe rotation on casing pressure profiles while circulating out the kick using MPD equipment. The PERTT lab personnel conducted experiments during the 80s in a real scale well under controlled environment that mimicked downhole conditions with a gas influx entering the wellbore. The data experimental analysis was coupled with the effect of pipe rotation through the application of correlations. The correlations from literature show a change in the expected frictional pressure loss when comparing the rotating case to the non-rotating case. This change is then applied on the geometric configuration of the well to find the changein the surface casing pressure caused by rotation.This paper covers the developed dispersed bubble model in WBM. This model includes the effect of the bubble dispersing into smaller bubble size on surface casing pressure. The validity of the single bubble model was examined inthis paper. The results showed that the changes in surface pressure are considerable when the gas bubble is able to break down with a decrease of up to 30 %. These changes are only applicable to cases with similar mud properties and well design of the experiments. The practical outcome is to further the understanding of a gas bubble behavior in a wellbore experiencing an influx. Since new technologies allow for the rotation of the pipe during the kick circulation process, this paper helps in answering the question of whether or not the pipe rotation aids in overall expected surface pressure. Furthering the window of applicability of the MPD can possibly touch into its unexploited potential.
{"title":"The Effect of Pipe Rotation on Dynamic Well Control Casing Pressure Using the Dispersed Bubble Model","authors":"Z. Marhoon, Hussain Al Ramis","doi":"10.2118/194187-MS","DOIUrl":"https://doi.org/10.2118/194187-MS","url":null,"abstract":"\u0000 Managed Pressure Drilling is a new technology that has recently emerged in the industry. It has special well control capabilities supported by the rotating control device to simultaneously provide the required pressure control on a certain volume gas influx and maintain the pipe rotation for drilling or any other operation. This paper examines the effect of pipe rotation on casing pressure profiles while circulating out the kick using MPD equipment.\u0000 The PERTT lab personnel conducted experiments during the 80s in a real scale well under controlled environment that mimicked downhole conditions with a gas influx entering the wellbore. The data experimental analysis was coupled with the effect of pipe rotation through the application of correlations. The correlations from literature show a change in the expected frictional pressure loss when comparing the rotating case to the non-rotating case. This change is then applied on the geometric configuration of the well to find the changein the surface casing pressure caused by rotation.This paper covers the developed dispersed bubble model in WBM. This model includes the effect of the bubble dispersing into smaller bubble size on surface casing pressure. The validity of the single bubble model was examined inthis paper. The results showed that the changes in surface pressure are considerable when the gas bubble is able to break down with a decrease of up to 30 %. These changes are only applicable to cases with similar mud properties and well design of the experiments. The practical outcome is to further the understanding of a gas bubble behavior in a wellbore experiencing an influx. Since new technologies allow for the rotation of the pipe during the kick circulation process, this paper helps in answering the question of whether or not the pipe rotation aids in overall expected surface pressure. Furthering the window of applicability of the MPD can possibly touch into its unexploited potential.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"62 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122990549","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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