Drilling motors are typically used in every well drilled globally with conventional steerable bottom-hole assemblies (BHA's) and powered rotary-steerable BHA's. Downhole drilling dysfunctions are common when mud motors are pushed to the limit for maximum drilling performance. High-frequency (1600Hz) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box and top sub of the motor to better understand drilling conditions in different shale plays throughout North America land. In the drilling industry, most downhole measurements for drilling dynamics utilize relatively low-frequency sensors (up to 100Hz). Typically, the measurements are burst and not continuous. These low-frequency burst acceleration devices cannot reliably measure high-frequency torsional oscillations (HFTO) which are known to be problematic while drilling in certain shale basins. Newly developed high-frequency (1600Hz) compact drilling dynamics sensors can now be embedded into the drill bit, mud motor bit box and top sub to record 3-axis accelerations continuously at high-speed sampling rates. The embedded sensors do not add any extra length to the steerable motor and therefore capture the true dynamic response of the system. Embedding the high-frequency sensors at both ends of the mud motor provides two unique data sets of dynamic measurements. With conventional steerable motors and motor-assist rotary-steerable systems (RSS), HFTO dominant frequencies between 100 and 400Hz were commonly observed. In some cases, HFTO dominant frequencies between 400-700Hz and their harmonics were captured, which have not previously been reported. In most cases, the HFTO amplitudes are between 20 and 200g peak (or 40 and 400g peak-to-peak). On some occasions, ±200g self-perpetuating HFTO were recorded in memory where its calculated angular acceleration is more than 25,000 rad/s2. The transitions between low-frequency stick-slip and HFTO were captured in high-speed recording. Negative string rotation speeds were commonly observed at the top sub of the motor while in rotary mode. It was noted that the bit would slow down to a stop but never turn backwards, resulting in the backward rotation of the motor top sub. During very high-amplitude multiple-axis shocks at the bit, it was discovered that there was a significant temperature rise due to loss of energy from bit dysfunction. The newly reported drilling dynamics phenomena, such as multiple dominant HFTO frequency shifts, micro-sticks and micro-slips, will be detailed in this paper. Monitoring and understanding high-frequency drilling dynamics dysfunctions allows us to make systematic changes to bit, BHA and drilling parameters to reduce dysfunction magnitude and improve overall drilling efficiency and minimize component wear.
{"title":"A Drill Bit and Drilling Motor with Embedded High-Frequency 1600Hz Drilling Dynamics Sensors Provide New Insights into Challenging Downhole Drilling Conditions","authors":"J. Sugiura, Steve Jones","doi":"10.2118/194138-MS","DOIUrl":"https://doi.org/10.2118/194138-MS","url":null,"abstract":"\u0000 Drilling motors are typically used in every well drilled globally with conventional steerable bottom-hole assemblies (BHA's) and powered rotary-steerable BHA's. Downhole drilling dysfunctions are common when mud motors are pushed to the limit for maximum drilling performance. High-frequency (1600Hz) continuous recording compact drilling dynamics sensors were embedded into the bit, bit box and top sub of the motor to better understand drilling conditions in different shale plays throughout North America land.\u0000 In the drilling industry, most downhole measurements for drilling dynamics utilize relatively low-frequency sensors (up to 100Hz). Typically, the measurements are burst and not continuous. These low-frequency burst acceleration devices cannot reliably measure high-frequency torsional oscillations (HFTO) which are known to be problematic while drilling in certain shale basins. Newly developed high-frequency (1600Hz) compact drilling dynamics sensors can now be embedded into the drill bit, mud motor bit box and top sub to record 3-axis accelerations continuously at high-speed sampling rates. The embedded sensors do not add any extra length to the steerable motor and therefore capture the true dynamic response of the system.\u0000 Embedding the high-frequency sensors at both ends of the mud motor provides two unique data sets of dynamic measurements. With conventional steerable motors and motor-assist rotary-steerable systems (RSS), HFTO dominant frequencies between 100 and 400Hz were commonly observed. In some cases, HFTO dominant frequencies between 400-700Hz and their harmonics were captured, which have not previously been reported. In most cases, the HFTO amplitudes are between 20 and 200g peak (or 40 and 400g peak-to-peak). On some occasions, ±200g self-perpetuating HFTO were recorded in memory where its calculated angular acceleration is more than 25,000 rad/s2.\u0000 The transitions between low-frequency stick-slip and HFTO were captured in high-speed recording. Negative string rotation speeds were commonly observed at the top sub of the motor while in rotary mode. It was noted that the bit would slow down to a stop but never turn backwards, resulting in the backward rotation of the motor top sub. During very high-amplitude multiple-axis shocks at the bit, it was discovered that there was a significant temperature rise due to loss of energy from bit dysfunction.\u0000 The newly reported drilling dynamics phenomena, such as multiple dominant HFTO frequency shifts, micro-sticks and micro-slips, will be detailed in this paper. Monitoring and understanding high-frequency drilling dynamics dysfunctions allows us to make systematic changes to bit, BHA and drilling parameters to reduce dysfunction magnitude and improve overall drilling efficiency and minimize component wear.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"78 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127497562","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}
Dennis Ernens, Diana Westerwaal, Roel F. H. Roijmans, E. J. V. Riet, Stefan Daegling, A. Wheatley, E. A. Worthington, H. Kramer, W. M. Haaften, M. D. Rooij, H. R. Pasaribu
Thread compounds play an important role in the sealing ability of casing connections in the oil and gas industry. Next to their lubricating role during assembly, most of these thread compounds make use of nonbiodegradable or persistent particle additives to aid in the sealing ability. Soon, these additives need to be replaced by benign alternatives as agreed in the proceedings of the Oslo-Paris Commission. This is, however, a challenge in high temperature (>150°C) well environments. This paper presents an investigation of the high temperature failure mechanisms of thread compounds with the aim to develop biodegradable high temperature resistant thread compounds. To this end, the performance of commercially available, environmentally acceptable thread compounds was investigated with thermogravimetric analysis (TGA), differential scanning calorimetry (DSC), high temperature rheometry and high temperature pin-on-disc experiments. The compounds are assessed on their stability, consistency, lubricity, and the resulting wear at high temperature. The results indicated that, without exception the commercially available thread compounds investigated in this study fail by adhesive and/or abrasive wear at around 150 degrees Celsius because of thermally induced degradation. To remedy this and to validate the mechanisms, a prototype thread compound was developed which exhibits strong film forming. The conclusion is that a successful high temperature resistant environmentally acceptable thread compound can likely be developed. The key property of this thread compound should be the ability to form a tribofilm during make-up which protects the surface at a later stage when the lubricant has lost its consistency and the base oil is fully evaporated.
{"title":"Evaluation of the Elevated Temperature Performance and Degradation Mechanisms of Thread Compounds","authors":"Dennis Ernens, Diana Westerwaal, Roel F. H. Roijmans, E. J. V. Riet, Stefan Daegling, A. Wheatley, E. A. Worthington, H. Kramer, W. M. Haaften, M. D. Rooij, H. R. Pasaribu","doi":"10.2118/194113-MS","DOIUrl":"https://doi.org/10.2118/194113-MS","url":null,"abstract":"\u0000 Thread compounds play an important role in the sealing ability of casing connections in the oil and gas industry. Next to their lubricating role during assembly, most of these thread compounds make use of nonbiodegradable or persistent particle additives to aid in the sealing ability. Soon, these additives need to be replaced by benign alternatives as agreed in the proceedings of the Oslo-Paris Commission. This is, however, a challenge in high temperature (>150°C) well environments. This paper presents an investigation of the high temperature failure mechanisms of thread compounds with the aim to develop biodegradable high temperature resistant thread compounds. To this end, the performance of commercially available, environmentally acceptable thread compounds was investigated with thermogravimetric analysis (TGA), differential scanning calorimetry (DSC), high temperature rheometry and high temperature pin-on-disc experiments. The compounds are assessed on their stability, consistency, lubricity, and the resulting wear at high temperature. The results indicated that, without exception the commercially available thread compounds investigated in this study fail by adhesive and/or abrasive wear at around 150 degrees Celsius because of thermally induced degradation. To remedy this and to validate the mechanisms, a prototype thread compound was developed which exhibits strong film forming. The conclusion is that a successful high temperature resistant environmentally acceptable thread compound can likely be developed. The key property of this thread compound should be the ability to form a tribofilm during make-up which protects the surface at a later stage when the lubricant has lost its consistency and the base oil is fully evaporated.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130635945","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}
Austin M. Johnson, J. Nichols, K. Ameen, J. Fraczek
An active wellbore sealing system has undergone simulated drilling tests in a full-scale, purpose-built test rig facility. The active wellbore sealing system contains wellbore pressure during all drilling operations with an active, direct-hydraulic control system to actuate the dual non-rotating seal sleeve elements. The test rig facility enables simulated drilling testing including the use of drilling mud, simultaneous drillpipe stripping and rotation, production topside equipment, and application of wellbore pressure. The active wellbore sealing system test program operates the equipment under realistic field conditions and enables control parameter optimization. Test procedures have been developed based on historical well data with careful consideration given to the application of test results. Analysis of the test data is provided and discussed. This paper shares test results from the active wellbore sealing system test program. An overview of the system and test environment will be shared. Test procedures and technical considerations will be discussed. Data and analysis from the test program will be shared. The active wellbore sealing system offers distinct operational advantages over passive systems in deepwater. An active control system enables extended seal life and active seal integrity management. Rigorous simulated drilling tests provide a technical basis for comparison to real wells. Seal element condition monitoring allows the rig to replace the seal assembly only as required, saving rig time. The active wellbore sealing system is operated with the chamber pressure between the seal elements higher than the wellbore pressure, forming three mechanisms to ensure wellbore pressure is contained. Further, testing demonstrates that minimal human input is required to operate the system.
{"title":"Simulated Drilling Testing of an Active Wellbore Sealing System on a Full-Scale Test Rig","authors":"Austin M. Johnson, J. Nichols, K. Ameen, J. Fraczek","doi":"10.2118/194079-MS","DOIUrl":"https://doi.org/10.2118/194079-MS","url":null,"abstract":"\u0000 \u0000 \u0000 An active wellbore sealing system has undergone simulated drilling tests in a full-scale, purpose-built test rig facility. The active wellbore sealing system contains wellbore pressure during all drilling operations with an active, direct-hydraulic control system to actuate the dual non-rotating seal sleeve elements. The test rig facility enables simulated drilling testing including the use of drilling mud, simultaneous drillpipe stripping and rotation, production topside equipment, and application of wellbore pressure.\u0000 The active wellbore sealing system test program operates the equipment under realistic field conditions and enables control parameter optimization. Test procedures have been developed based on historical well data with careful consideration given to the application of test results. Analysis of the test data is provided and discussed.\u0000 \u0000 \u0000 \u0000 This paper shares test results from the active wellbore sealing system test program. An overview of the system and test environment will be shared. Test procedures and technical considerations will be discussed. Data and analysis from the test program will be shared.\u0000 \u0000 \u0000 \u0000 The active wellbore sealing system offers distinct operational advantages over passive systems in deepwater. An active control system enables extended seal life and active seal integrity management. Rigorous simulated drilling tests provide a technical basis for comparison to real wells. Seal element condition monitoring allows the rig to replace the seal assembly only as required, saving rig time.\u0000 \u0000 \u0000 \u0000 The active wellbore sealing system is operated with the chamber pressure between the seal elements higher than the wellbore pressure, forming three mechanisms to ensure wellbore pressure is contained. Further, testing demonstrates that minimal human input is required to operate the system.\u0000","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"10 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":"125393047","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}
Stick-slip is still present in most of the wells drilled today, especially in unconventional wells. Friction is an inevitable and important force along the long lateral section, but it contributes to many types of dysfunctions that lead to drilling inefficiency. Stick-slip is caused mainly by rotational friction induced along the drillstring, from the drill bit cutting the rock formation to the bottom hole assembly and drill pipe that contact the well bore. In the past, much attention has been given the cutting action of polycrystalline diamond compact (PDC) bits to explain and mitigate stick-slip, without much emphasis on the frictional torque. However, it is important to understand that the torque generated on the remaining drillstring accounts for most of the total torque at surface. This paper presents a case study on an unconventional well where stick-slip modeling was used to explain and understand stick-slip vibrations with or without the presence of active control systems at surface. First, the stick-slip model, including a PDC bit law friction and accurate contact forces calculation along the drillstring and mud damping effect is fully described, with all necessary and field parameters needed. Then, it explains the process to reproduce and calibrate downhole and surface torque, using a sensitivity analysis showing the most important parameters that affect stick-slip results. The results reinforce the importance of drilling parameters, such as the weight on bit and associated torque on bit that define the bit aggressiveness and are key in controlling or mitigating stick-slip vibration. In addition, these results show the significance of string friction along the drill pipe. Next, the use of a downhole instrumented sub, along with wire drill pipe technology, enables a full comparison of the results of the model with downhole and surface data. Last, the affect of other parameters, such as friction coefficient and mud damping, are discussed. With a better understanding of the initiation and translation of stick-slip from the bit up the hole to surface provided by this case study, engineers can be better informed when making decisions on factors such as drill pipe size and type, bit aggressiveness, and parameter changes in wells with severe stick-slip in unconventional wells application.
{"title":"Mitigating and Understanding Stick-Slip in Unconventional Wells","authors":"N. Dao, S. Menand, M. Isbell","doi":"10.2118/194117-MS","DOIUrl":"https://doi.org/10.2118/194117-MS","url":null,"abstract":"\u0000 Stick-slip is still present in most of the wells drilled today, especially in unconventional wells. Friction is an inevitable and important force along the long lateral section, but it contributes to many types of dysfunctions that lead to drilling inefficiency. Stick-slip is caused mainly by rotational friction induced along the drillstring, from the drill bit cutting the rock formation to the bottom hole assembly and drill pipe that contact the well bore. In the past, much attention has been given the cutting action of polycrystalline diamond compact (PDC) bits to explain and mitigate stick-slip, without much emphasis on the frictional torque. However, it is important to understand that the torque generated on the remaining drillstring accounts for most of the total torque at surface.\u0000 This paper presents a case study on an unconventional well where stick-slip modeling was used to explain and understand stick-slip vibrations with or without the presence of active control systems at surface. First, the stick-slip model, including a PDC bit law friction and accurate contact forces calculation along the drillstring and mud damping effect is fully described, with all necessary and field parameters needed. Then, it explains the process to reproduce and calibrate downhole and surface torque, using a sensitivity analysis showing the most important parameters that affect stick-slip results. The results reinforce the importance of drilling parameters, such as the weight on bit and associated torque on bit that define the bit aggressiveness and are key in controlling or mitigating stick-slip vibration. In addition, these results show the significance of string friction along the drill pipe. Next, the use of a downhole instrumented sub, along with wire drill pipe technology, enables a full comparison of the results of the model with downhole and surface data. Last, the affect of other parameters, such as friction coefficient and mud damping, are discussed.\u0000 With a better understanding of the initiation and translation of stick-slip from the bit up the hole to surface provided by this case study, engineers can be better informed when making decisions on factors such as drill pipe size and type, bit aggressiveness, and parameter changes in wells with severe stick-slip in unconventional wells application.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"136 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":"115183572","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}
A. Knudsen, Y. Couturier, Jesse Alan Hardt, Magne Boganes, B. Dow, Kim Eivind Nord-Varhaug
This case history paper describes the well integrity challenges Spirit Energy was faced with for executing the drilling operations on the Scarecrow wildcat well in the Barents Sea. The expected reservoir depth on Scarecrow was the shallowest reservoir ever drilled in the Barents Sea being only 188 m below mudline with a water depth of 454 m MSL. Several mitigating actions were implemented to improve robustness of the well integrity such as: The focus in this paper is to describe the qualification of a new automated pressure control method (Autochoke system) used on the Scarecrow wildcat well in the Barents Sea for circulating out an influx. Simulations and return of experience indicated that manual conventional well control practices would not provide sufficient pressure control precision to maintain bottomhole pressure within the +/- 4 bar (58 psi) operational window required to circulate out an influx. A new automated pressure control method based on a commercial managed pressure drilling (MPD) control system was developed, tested, and DNV approved to achieve the required pressure control precision for both single- and multi-phase scenarios, and permit safe operations. A pressure control method was developed to automate control of well control chokes to maintain a constant standpipe pressure, as required during circulating using Driller's Method. The methodology used is comparable to commercial MPD pressure control systems, in which pressure transducer (PT) measurements are input to a control loop which actuates chokes to attain the pressure demand while minimizing overshoot. Unlike a typical MPD installation, in which PTs are typically located upstream of a choke manifold, this installation utilized PTs installed on the rig standpipe, with chokes installed in the well control manifold. The choke control system was improved to automatically compute and account for pressure wave propagation lag due to the distance between the chokes and the control PTs. The system was tested at a test rig in Norway that permitted the injection of air into the standpipe to simulate a gas kick. In multiple test cases, various quantities of air were injected into the standpipe, circulated into the annulus, and finally circulated out of the wellbore with automated chokes operating to maintain a constant standpipe pressure as the air was circulated out of the wellbore and through the chokes. Testing was repeated with varying quantities of injected air and varying standpipe pressure setpoints to validate the process across a range of operating conditions. The control system demonstrated standpipe pressure control precision of +/- 1 bar (14.5 psi) during all test phases, achieving the required precision. Testing under additional operating conditions was conducted to approximate a real-world well control scenario, in which constant casing pressure is maintained while ramping the pumps, and constant standpipe pressure is maintained while circulating
这篇案例历史论文描述了Spirit Energy在巴伦支海的稻草人野猫井钻井作业中所面临的井完整性挑战。稻草人的预期储层深度是巴伦支海有史以来钻探的最浅的储层，仅在泥线以下188米，水深为454米。本文重点介绍了一种新的自动化压力控制方法(Autochoke系统)的性能，该方法应用于巴伦支海的稻草人野猫井，用于循环出注入物。模拟和经验反馈表明，手动常规井控方法无法提供足够的压力控制精度，无法将井底压力保持在+/- 4 bar (58 psi)的作业窗口内，以循环出流入物。一种基于商业控压钻井(MPD)控制系统的新型自动化压力控制方法得到了开发、测试和DNV的认可，该方法可以在单相和多相工况下实现所需的压力控制精度，并保证安全作业。开发了一种压力控制方法，可以自动控制井控扼流圈，以保持固定的立管压力，这是使用司钻法循环时所需要的。所使用的方法与商业MPD压力控制系统相当，在MPD压力控制系统中，压力传感器(PT)的测量值被输入到控制回路，该控制回路驱动扼流圈，以达到压力需求，同时最大限度地减少超调。与典型的MPD安装不同的是，pt通常位于节流管汇的上游，该装置将pt安装在钻机立管上，而节流管汇则安装在井控管汇上。节流器控制系统得到了改进，可以自动计算和计算由于节流器与控制点之间距离造成的压力波传播滞后。该系统在挪威的一个测试平台上进行了测试，允许向立管注入空气来模拟气涌。在多个测试案例中，将不同数量的空气注入立管，循环进入环空，最后通过自动节流器循环出井筒，以保持空气从井筒中循环出并通过节流器时立管压力恒定。在不同的注入空气量和不同的立管压力设定值下重复测试，以验证该过程在一系列操作条件下的有效性。在所有测试阶段，控制系统的立管压力控制精度为+/- 1 bar (14.5 psi)，达到了所需的精度。在额外的操作条件下进行了测试，以近似于真实的井控场景，在此场景中，在泵泵的同时保持恒定的套管压力，在井涌循环时保持恒定的立管压力(即司钻的井控方法的第一次循环)。观察到的与控制值的最大偏差为2 bar (29 psi)，再次满足所需的控制精度。这些试验由DNV观察、验证和批准。该技术于2018年7月引入该油田。
{"title":"Demonstration of Automated Pressure Control System for Assisted Well Control Offshore Norway","authors":"A. Knudsen, Y. Couturier, Jesse Alan Hardt, Magne Boganes, B. Dow, Kim Eivind Nord-Varhaug","doi":"10.2118/194089-MS","DOIUrl":"https://doi.org/10.2118/194089-MS","url":null,"abstract":"\u0000 \u0000 \u0000 This case history paper describes the well integrity challenges Spirit Energy was faced with for executing the drilling operations on the Scarecrow wildcat well in the Barents Sea. The expected reservoir depth on Scarecrow was the shallowest reservoir ever drilled in the Barents Sea being only 188 m below mudline with a water depth of 454 m MSL.\u0000 Several mitigating actions were implemented to improve robustness of the well integrity such as:\u0000 The focus in this paper is to describe the qualification of a new automated pressure control method (Autochoke system) used on the Scarecrow wildcat well in the Barents Sea for circulating out an influx. Simulations and return of experience indicated that manual conventional well control practices would not provide sufficient pressure control precision to maintain bottomhole pressure within the +/- 4 bar (58 psi) operational window required to circulate out an influx. A new automated pressure control method based on a commercial managed pressure drilling (MPD) control system was developed, tested, and DNV approved to achieve the required pressure control precision for both single- and multi-phase scenarios, and permit safe operations.\u0000 \u0000 \u0000 \u0000 A pressure control method was developed to automate control of well control chokes to maintain a constant standpipe pressure, as required during circulating using Driller's Method. The methodology used is comparable to commercial MPD pressure control systems, in which pressure transducer (PT) measurements are input to a control loop which actuates chokes to attain the pressure demand while minimizing overshoot. Unlike a typical MPD installation, in which PTs are typically located upstream of a choke manifold, this installation utilized PTs installed on the rig standpipe, with chokes installed in the well control manifold. The choke control system was improved to automatically compute and account for pressure wave propagation lag due to the distance between the chokes and the control PTs.\u0000 \u0000 \u0000 \u0000 The system was tested at a test rig in Norway that permitted the injection of air into the standpipe to simulate a gas kick. In multiple test cases, various quantities of air were injected into the standpipe, circulated into the annulus, and finally circulated out of the wellbore with automated chokes operating to maintain a constant standpipe pressure as the air was circulated out of the wellbore and through the chokes. Testing was repeated with varying quantities of injected air and varying standpipe pressure setpoints to validate the process across a range of operating conditions. The control system demonstrated standpipe pressure control precision of +/- 1 bar (14.5 psi) during all test phases, achieving the required precision. Testing under additional operating conditions was conducted to approximate a real-world well control scenario, in which constant casing pressure is maintained while ramping the pumps, and constant standpipe pressure is maintained while circulating","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"7 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":"133964689","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}
Umut Zalluhoglu, Nazlı Demirer, J. Marck, Hossam Gharib, Robert Darbe
The challenging offshore and shale production environments have increased the need for cost-effective, standardized drilling operations while providing accurate well placement and high borehole quality. Automation of directional drilling processes bears the promise of delivering these consistent and reliable performances while maximizing production potential. This paper introduces a steering advisory system for rotary steerable systems (RSS), which provides steering decisions automatically given the BHA configuration, bit selection, well plan and/or target(s), and real-time sensory information received from the RSS. These decisions can be either displayed to directional drillers or down-linked directly to the tool for autonomous directional drilling. The system has proven itself on multiple commercial jobs across North America with a new generation RSS. By exactly following the advisory system-generated steering decisions, multiple curve sections were smoothly drilled and accurately landed within tight tolerances.
{"title":"Steering Advisory System for Rotary Steerable Systems","authors":"Umut Zalluhoglu, Nazlı Demirer, J. Marck, Hossam Gharib, Robert Darbe","doi":"10.2118/194090-MS","DOIUrl":"https://doi.org/10.2118/194090-MS","url":null,"abstract":"\u0000 The challenging offshore and shale production environments have increased the need for cost-effective, standardized drilling operations while providing accurate well placement and high borehole quality. Automation of directional drilling processes bears the promise of delivering these consistent and reliable performances while maximizing production potential. This paper introduces a steering advisory system for rotary steerable systems (RSS), which provides steering decisions automatically given the BHA configuration, bit selection, well plan and/or target(s), and real-time sensory information received from the RSS. These decisions can be either displayed to directional drillers or down-linked directly to the tool for autonomous directional drilling. The system has proven itself on multiple commercial jobs across North America with a new generation RSS. By exactly following the advisory system-generated steering decisions, multiple curve sections were smoothly drilled and accurately landed within tight tolerances.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"25 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":"127078917","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}
R. Lowdon, Michael Breen, Michael Mouyiasis, Michael Edmunds, Konstantin Bulychenkov, K. Brovko
Directional surveys are taken while drilling a well to enable well placement and to avoid hitting other wells. This requirement is becoming increasingly important as reservoirs become more complex to reach and fields become ever more crowded. Taking directional surveys either before, during or post connection takes time, waiting for surveys to be pumped up takes longer and may need to be repeated if a critical survey cannot be taken first time which is a particular problem in shallow hole offshore operations. This paper outlines an industry first technology that will effectively eliminate surveying time, a definitive continuous survey will be available to the directional driller at all times, eliminating the need to take and wait for a survey before making the next directional drilling decision. Continuous 6 axis surveys are cutting edge replacement for the static six axis Measurement While Drilling (MWD) surveys which have been used as the primary surveying tool worldwide for decades. The three magnetometers and Inclinometers provide an accurate inclination and azimuth when the drillstring is stationary. Continuous six axis MWD surveying could be described as a static survey captured continuously while drilling a stand allowing for accurate inclination and azimuth at all times. The directional driller will know where they are definitively at all time, eliminating the requirement for surveying time, enabling efficient decision making while eliminating the need for additional pump cycles, their associated wash outs and the directional difficulties that stem from that. Field test examples of this continuous 6 axis MWD surveying will be shown with comparisons between other MWD systems these will be analyzed to establish consistency and accuracy. An error model for the continuous six axis survey will be discussed in some detail, as it is inherently different to a normal static MWD survey and comparison will be made to other error models. The time savings involved with continuous six axis surveys will also be shown, with a discussion on the associated benefits to the directional driller from reduced pump cycles. Directional surveying is generally seen as a must have on a rig, however the associated rig time is considerable. This unique and world first method will discuss how continuous six axis survey are made, the accuracy modelled and so how the industry can eliminate rig time associated with MWD surveying.
{"title":"Eliminating Rig Time from MWD Surveying","authors":"R. Lowdon, Michael Breen, Michael Mouyiasis, Michael Edmunds, Konstantin Bulychenkov, K. Brovko","doi":"10.2118/194057-MS","DOIUrl":"https://doi.org/10.2118/194057-MS","url":null,"abstract":"\u0000 Directional surveys are taken while drilling a well to enable well placement and to avoid hitting other wells. This requirement is becoming increasingly important as reservoirs become more complex to reach and fields become ever more crowded. Taking directional surveys either before, during or post connection takes time, waiting for surveys to be pumped up takes longer and may need to be repeated if a critical survey cannot be taken first time which is a particular problem in shallow hole offshore operations. This paper outlines an industry first technology that will effectively eliminate surveying time, a definitive continuous survey will be available to the directional driller at all times, eliminating the need to take and wait for a survey before making the next directional drilling decision.\u0000 Continuous 6 axis surveys are cutting edge replacement for the static six axis Measurement While Drilling (MWD) surveys which have been used as the primary surveying tool worldwide for decades. The three magnetometers and Inclinometers provide an accurate inclination and azimuth when the drillstring is stationary. Continuous six axis MWD surveying could be described as a static survey captured continuously while drilling a stand allowing for accurate inclination and azimuth at all times. The directional driller will know where they are definitively at all time, eliminating the requirement for surveying time, enabling efficient decision making while eliminating the need for additional pump cycles, their associated wash outs and the directional difficulties that stem from that.\u0000 Field test examples of this continuous 6 axis MWD surveying will be shown with comparisons between other MWD systems these will be analyzed to establish consistency and accuracy. An error model for the continuous six axis survey will be discussed in some detail, as it is inherently different to a normal static MWD survey and comparison will be made to other error models. The time savings involved with continuous six axis surveys will also be shown, with a discussion on the associated benefits to the directional driller from reduced pump cycles.\u0000 Directional surveying is generally seen as a must have on a rig, however the associated rig time is considerable. This unique and world first method will discuss how continuous six axis survey are made, the accuracy modelled and so how the industry can eliminate rig time associated with MWD surveying.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"14 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":"125293149","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}
Positional uncertainty is a critical component of managing collision risk while drilling. Ensuring that survey data meet the requirements of their uncertainty models has historically required complicated analysis. Most consumers of survey data are not experts and knowing when escalation is required in a high-risk situation can be unclear. This problem will increase as more data is evaluated by automated decision-making systems. Two novel methods are proposed to analyze sets of survey data against uncertainty models with the intent to answer the questions: "Is it safe to continue drilling" and "Does this wellbore need to be resurveyed?". The proposed methods evaluate a survey set using the error sources, error magnitudes, and error propagations contained in positional uncertainty models. A quality control error covariance matrix is constructed, and the set is evaluated against it. Two statistical outputs are generated: a statistical distance that explains how well an additional survey fits with the existing survey data, and an overall survey assessment that describes the likelihood of an error-model compliant system producing the observed dataset. The methods are used to evaluate downhole magnetic survey data that was flagged after evaluation by subject matter experts, but traditional quality control measures had failed to identify as problematic. Errors that do not fit the expectations of the error model are flagged in a way that is apparent to a non-expert user and can be integrated into an automated alert system. How to include these procedures in drilling workflows is discussed, including when escalation to a subject matter expert is required. A system is proposed where, with minor modification to existing error models, this analysis can be automated for wellbore surveys of all kinds. Additional discussion is included on how these methods will fit into the upcoming API recommended practice on wellbore surveying.
{"title":"Validation of Directional Survey Data Against Positional Uncertainty Models","authors":"Marc E. Willerth, S. Maus","doi":"10.2118/194179-MS","DOIUrl":"https://doi.org/10.2118/194179-MS","url":null,"abstract":"\u0000 Positional uncertainty is a critical component of managing collision risk while drilling. Ensuring that survey data meet the requirements of their uncertainty models has historically required complicated analysis. Most consumers of survey data are not experts and knowing when escalation is required in a high-risk situation can be unclear. This problem will increase as more data is evaluated by automated decision-making systems. Two novel methods are proposed to analyze sets of survey data against uncertainty models with the intent to answer the questions: \"Is it safe to continue drilling\" and \"Does this wellbore need to be resurveyed?\".\u0000 The proposed methods evaluate a survey set using the error sources, error magnitudes, and error propagations contained in positional uncertainty models. A quality control error covariance matrix is constructed, and the set is evaluated against it. Two statistical outputs are generated: a statistical distance that explains how well an additional survey fits with the existing survey data, and an overall survey assessment that describes the likelihood of an error-model compliant system producing the observed dataset.\u0000 The methods are used to evaluate downhole magnetic survey data that was flagged after evaluation by subject matter experts, but traditional quality control measures had failed to identify as problematic. Errors that do not fit the expectations of the error model are flagged in a way that is apparent to a non-expert user and can be integrated into an automated alert system. How to include these procedures in drilling workflows is discussed, including when escalation to a subject matter expert is required.\u0000 A system is proposed where, with minor modification to existing error models, this analysis can be automated for wellbore surveys of all kinds. Additional discussion is included on how these methods will fit into the upcoming API recommended practice on wellbore surveying.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"4 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":"121770937","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}
A drill string in a wellbore always contacts a casing. However, in a curved section of casing the contact force between the drill string and the casing can be significant. Friction between the casing and a rotating drill string tool joint in contact with the casing generates a heat source at the interface between the two objects. The generated heat energy is a function of rotational speed of the drill string, side force and friction coefficient between the hard-banding layer covering the tool joint and the casing. Heat partition between hard banding layer and casing depends on the thermal properties of both. When there is no mud circulation, e.g. due to a pack-off in the annulus or lost circulation, and the contact region stays in the same section, the resulting temperature increase can lead to degradation of the mechanical strength of both the drill string tool joint and the casing. In addition, the casing strength reduction can facilitate casing wear, which may lead to leak and tool joint heating can lead to heat checking cracks or mechanical strength weakening which may result in a parted drill string due to brittle or ductile fracture. When there is no mud circulation, rotation of the drill string leads to mud angular rotation inside and outside the drill string. Convection heat transfer occurs due to mud rotation and convection heat transfer coefficient depends on mud flow regime. CFD simulations were performed to compute the convection heat transfer coefficient. Two and three-dimensional steady state and transient finite element simulations were performed to compute the temperature distribution in the casing and the drill string tool joint when there is no mud circulation. Results show that, when there is no mud circulation, conduction through the drill string and casing has the highest impact on the maximum temperature generated due to frictional heating. Two graphs are plotted, one shows the steady state temperature versus side load at different rotational speeds while the other shows casing yield and ultimate stresses degradation versus increase in temperature. Both graphs can be used by drilling engineers at the well design phase to select the appropriate rotational speed of drill string to avoid failure when there is no mud circulation. Novelty of this paper is in thermal analysis of a tool joint hard banding layer rubbing against casing. In the analysis the convection heat transfer through mud rotation is involved.
{"title":"Frictional Heating of Casing Due to Drill String Rotation – Finite Element and CFD Simulations","authors":"W. Assaad, B. Tarr, K. C. See","doi":"10.2118/194155-MS","DOIUrl":"https://doi.org/10.2118/194155-MS","url":null,"abstract":"\u0000 A drill string in a wellbore always contacts a casing. However, in a curved section of casing the contact force between the drill string and the casing can be significant. Friction between the casing and a rotating drill string tool joint in contact with the casing generates a heat source at the interface between the two objects. The generated heat energy is a function of rotational speed of the drill string, side force and friction coefficient between the hard-banding layer covering the tool joint and the casing. Heat partition between hard banding layer and casing depends on the thermal properties of both. When there is no mud circulation, e.g. due to a pack-off in the annulus or lost circulation, and the contact region stays in the same section, the resulting temperature increase can lead to degradation of the mechanical strength of both the drill string tool joint and the casing. In addition, the casing strength reduction can facilitate casing wear, which may lead to leak and tool joint heating can lead to heat checking cracks or mechanical strength weakening which may result in a parted drill string due to brittle or ductile fracture.\u0000 When there is no mud circulation, rotation of the drill string leads to mud angular rotation inside and outside the drill string. Convection heat transfer occurs due to mud rotation and convection heat transfer coefficient depends on mud flow regime. CFD simulations were performed to compute the convection heat transfer coefficient. Two and three-dimensional steady state and transient finite element simulations were performed to compute the temperature distribution in the casing and the drill string tool joint when there is no mud circulation.\u0000 Results show that, when there is no mud circulation, conduction through the drill string and casing has the highest impact on the maximum temperature generated due to frictional heating. Two graphs are plotted, one shows the steady state temperature versus side load at different rotational speeds while the other shows casing yield and ultimate stresses degradation versus increase in temperature. Both graphs can be used by drilling engineers at the well design phase to select the appropriate rotational speed of drill string to avoid failure when there is no mud circulation.\u0000 Novelty of this paper is in thermal analysis of a tool joint hard banding layer rubbing against casing. In the analysis the convection heat transfer through mud rotation is involved.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"11 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":"127643080","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}
R. Mitchell, N. Zwarich, H. Hunt, A. McSpadden, R. Trevisan, M. Goodman
Recent development of a new dynamic model for tubular stress analysis is now extended to the design challenges and failure modes characteristic of long production casing strings in extended horizontal shale wells. In particular, the issue of cyclic loading due to repeated sequences of multi-stage fracturing has not been addressed until now. The new model provides the ideal means of analysis of cyclic thermal loads as well as critical impact of compression due to initial running friction. The new dynamic model of tubular stress solves the one-dimensional momentum equation over a time step sequence initiated from the original running of the string into the wellbore. Friction is modeled in a fully history dependent manner, with damping provided naturally by the wellbore fluid viscosity. Local pipe velocity as well as magnitude and orientation of sliding friction is solved at each node with friction aggregated at the connection upset and joint mid-point. Unconventional shale wells pose critical design challenges especially in regard to the long production casing strings run in extended horizontal or lateral sections. Compressive frictional loads accumulated during running are trapped in the string by cement, packers and the wellhead. Thus the initial load state must fully account for the initial frictional state in order to be realistic and conservative. Hydraulic fracturing at high flow rates and significant pump pressures, including the possibility of screen-out, represents a critical design load on the casing which can also significantly alter the orientation and magnitude of tubular/wellbore frictional contact. The particular phenomenon of repeated fracturing treatements in a multi-stage stimulation compounds the design challenge. Cycles of cold stimulation followed by renewed hot production can lead to unexpected migration of axial loads and localization of critical stresses. The cyclic nature of loading due to repeated sequences of multi-stage re-fractures and renewed production has not received industry attention due to the unavailability of appropriate models. Lack of adequate models has perhaps resulted in the problem being overlooked. A dynamic model is ideally suited to the analysis of cyclic loads because of its inherent ability to account for a full history of friction loads. The dynamics of loading and unloading are also critical to this new ability to address the design problem. Previous static-based stress models have been unable to provide a comprehensive basis of design.
{"title":"Dynamic Stress Analysis of Critical and Cyclic Loads for Production Casing in Horizontal Shale Wells","authors":"R. Mitchell, N. Zwarich, H. Hunt, A. McSpadden, R. Trevisan, M. Goodman","doi":"10.2118/194062-MS","DOIUrl":"https://doi.org/10.2118/194062-MS","url":null,"abstract":"\u0000 Recent development of a new dynamic model for tubular stress analysis is now extended to the design challenges and failure modes characteristic of long production casing strings in extended horizontal shale wells. In particular, the issue of cyclic loading due to repeated sequences of multi-stage fracturing has not been addressed until now. The new model provides the ideal means of analysis of cyclic thermal loads as well as critical impact of compression due to initial running friction.\u0000 The new dynamic model of tubular stress solves the one-dimensional momentum equation over a time step sequence initiated from the original running of the string into the wellbore. Friction is modeled in a fully history dependent manner, with damping provided naturally by the wellbore fluid viscosity. Local pipe velocity as well as magnitude and orientation of sliding friction is solved at each node with friction aggregated at the connection upset and joint mid-point.\u0000 Unconventional shale wells pose critical design challenges especially in regard to the long production casing strings run in extended horizontal or lateral sections. Compressive frictional loads accumulated during running are trapped in the string by cement, packers and the wellhead. Thus the initial load state must fully account for the initial frictional state in order to be realistic and conservative. Hydraulic fracturing at high flow rates and significant pump pressures, including the possibility of screen-out, represents a critical design load on the casing which can also significantly alter the orientation and magnitude of tubular/wellbore frictional contact. The particular phenomenon of repeated fracturing treatements in a multi-stage stimulation compounds the design challenge. Cycles of cold stimulation followed by renewed hot production can lead to unexpected migration of axial loads and localization of critical stresses.\u0000 The cyclic nature of loading due to repeated sequences of multi-stage re-fractures and renewed production has not received industry attention due to the unavailability of appropriate models. Lack of adequate models has perhaps resulted in the problem being overlooked. A dynamic model is ideally suited to the analysis of cyclic loads because of its inherent ability to account for a full history of friction loads. The dynamics of loading and unloading are also critical to this new ability to address the design problem. Previous static-based stress models have been unable to provide a comprehensive basis of design.","PeriodicalId":441797,"journal":{"name":"Day 2 Wed, March 06, 2019","volume":"459 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-03-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114015718","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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