R. Bulgachev, Michael Cromarty, Lee-Anne S. Milburn, K. Davies
bp’s (“the company’s”) wells organization manages its operational risks through what is known as the “three lines of defense” model. This is a three-tiered approach; the first line of defense is self-verification, which wells assets apply to prevent or mitigate operational risks. The second line of defense is conducted by the safety and operational risk function using deep technical expertise. The third line of defense is provided by group audit. In this paper, we discuss the wells self-verification program evolution from its first implementation and share case studies, results, impact, lessons learned, and further steps planned as part of the continuous improvement cycle.The company’s wells organization identified nine major accident risks that have the potential to result in significant health, safety, and environment (HSE) impacts. Examples include loss of well control (LoWC), offshore vessel collision, and dropped objects. The central risk team developed bowties for these risks, with prevention barriers on cause legs and mitigation barriers on consequence legs. Detailed risk bowties are fundamental to wells self-verification, adding technical depth to allow more focused verification to be performed when compared with the original bowties, because verification is now conducted using checklists targeting barriers at their component level, defined as critical tasks and equipment. Barriers are underpinned by barrier enablers (underlying supporting systems and processes) such as control of work, safe operating limits, inspection and maintenance, etc. Checklists are standardized and are available through a single, global digital application. This permits the verifiers, typically wellsite leaders, to conduct meaningful verification conversations, record the resulting actions, track them to closure within the application, and gain a better understanding of any cumulative impacts, ineffective barriers, and areas to focus on.Self-verification results are reviewed at rig, region, wells, and upstream levels. Rigs and regions analyze barrier effectiveness and gaps and implement corrective actions with contractors at the rig or region level. Global insights are collated monthly and presented centrally to wells leadership. Common themes and valuable learnings are then addressed at the functional level, shared across the organization, or escalated by the leadership.The self-verification program at the barrier component level proved to be an effective risk management tool for the company’s wells organization. It helps to continuously identify risks, address gaps, and learn from them. Recorded assessments not only provide the wells organization with barrier performance data but also highlight opportunities to improve. Leadership uses the results from barrier verification to gain a holistic view of how major accident risks are managed. Program evolution has also eliminated duplicate reviews, improved clarity of barrier components, and improved sustainability th
{"title":"Self-Verification Program in bp: Success Story of Major Accident Risk Management via Bowtie Barrier Model","authors":"R. Bulgachev, Michael Cromarty, Lee-Anne S. Milburn, K. Davies","doi":"10.2118/204132-PA","DOIUrl":"https://doi.org/10.2118/204132-PA","url":null,"abstract":"bp’s (“the company’s”) wells organization manages its operational risks through what is known as the “three lines of defense” model. This is a three-tiered approach; the first line of defense is self-verification, which wells assets apply to prevent or mitigate operational risks. The second line of defense is conducted by the safety and operational risk function using deep technical expertise. The third line of defense is provided by group audit. In this paper, we discuss the wells self-verification program evolution from its first implementation and share case studies, results, impact, lessons learned, and further steps planned as part of the continuous improvement cycle.The company’s wells organization identified nine major accident risks that have the potential to result in significant health, safety, and environment (HSE) impacts. Examples include loss of well control (LoWC), offshore vessel collision, and dropped objects. The central risk team developed bowties for these risks, with prevention barriers on cause legs and mitigation barriers on consequence legs. Detailed risk bowties are fundamental to wells self-verification, adding technical depth to allow more focused verification to be performed when compared with the original bowties, because verification is now conducted using checklists targeting barriers at their component level, defined as critical tasks and equipment. Barriers are underpinned by barrier enablers (underlying supporting systems and processes) such as control of work, safe operating limits, inspection and maintenance, etc. Checklists are standardized and are available through a single, global digital application. This permits the verifiers, typically wellsite leaders, to conduct meaningful verification conversations, record the resulting actions, track them to closure within the application, and gain a better understanding of any cumulative impacts, ineffective barriers, and areas to focus on.Self-verification results are reviewed at rig, region, wells, and upstream levels. Rigs and regions analyze barrier effectiveness and gaps and implement corrective actions with contractors at the rig or region level. Global insights are collated monthly and presented centrally to wells leadership. Common themes and valuable learnings are then addressed at the functional level, shared across the organization, or escalated by the leadership.The self-verification program at the barrier component level proved to be an effective risk management tool for the company’s wells organization. It helps to continuously identify risks, address gaps, and learn from them. Recorded assessments not only provide the wells organization with barrier performance data but also highlight opportunities to improve. Leadership uses the results from barrier verification to gain a holistic view of how major accident risks are managed. Program evolution has also eliminated duplicate reviews, improved clarity of barrier components, and improved sustainability th","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42153379","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The effect of axial flow of power-law drilling fluids on frictional pressure loss under turbulent conditions in eccentric annuli is investigated. A numerical model is developed to simulate the flow of Newtonian and power-law fluids for eccentric annular geometries. A turbulent eddy-viscosity model based on the mixing-length approach is proposed, where a damping constant as a function of flow parameters is presented to account for the near-wall effects. Numerical results including the velocity profile, eddy viscosity, and friction factors are compared with various sets of experimental data for Newtonian and power-law fluids in concentric and eccentric annular configurations with diameter ratios of 0.2 to 0.8. The simulation results are also compared with a numerical study and two approximate models in the literature. The results of extensive simulation scenarios are used to obtain a novel correlation for estimation of the frictional pressure loss in eccentric annuli under turbulent conditions. Two new correlations are also presented to estimate the maximum axial velocity in the wide and narrow sections of eccentric geometries.
{"title":"An Accurate Model for Prediction of Turbulent Frictional Pressure Loss of Power-Law Fluids in Eccentric Geometries","authors":"V. Dokhani, Yu’e Ma, Zili Li, M. Yu","doi":"10.2118/205372-PA","DOIUrl":"https://doi.org/10.2118/205372-PA","url":null,"abstract":"\u0000 The effect of axial flow of power-law drilling fluids on frictional pressure loss under turbulent conditions in eccentric annuli is investigated. A numerical model is developed to simulate the flow of Newtonian and power-law fluids for eccentric annular geometries. A turbulent eddy-viscosity model based on the mixing-length approach is proposed, where a damping constant as a function of flow parameters is presented to account for the near-wall effects. Numerical results including the velocity profile, eddy viscosity, and friction factors are compared with various sets of experimental data for Newtonian and power-law fluids in concentric and eccentric annular configurations with diameter ratios of 0.2 to 0.8. The simulation results are also compared with a numerical study and two approximate models in the literature. The results of extensive simulation scenarios are used to obtain a novel correlation for estimation of the frictional pressure loss in eccentric annuli under turbulent conditions. Two new correlations are also presented to estimate the maximum axial velocity in the wide and narrow sections of eccentric geometries.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48351425","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Morteza Roostaei, M. Soroush, Farshad Mohammadtabar, M. Mohammadtabar, S. A. Hosseini, Mahdi Mahmoudi, M. Sadrzadeh, A. Ghalambor, Vahidoddin Fattahpour
The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased-hole gravel packing or frac packing as the preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion. In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail. A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control is deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage on pressure drop. The experiments consisted of a series of step-rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop and perforation parameters and determine the optimized design. The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completions. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy.
{"title":"Design for Reliability: Experimental and Numerical Simulation of Cased and Perforated Completions with Standalone Screen","authors":"Morteza Roostaei, M. Soroush, Farshad Mohammadtabar, M. Mohammadtabar, S. A. Hosseini, Mahdi Mahmoudi, M. Sadrzadeh, A. Ghalambor, Vahidoddin Fattahpour","doi":"10.2118/201315-PA","DOIUrl":"https://doi.org/10.2118/201315-PA","url":null,"abstract":"\u0000 The historical challenges and high failure rate of using standalone screen in cased and perforated wellbores pushed several operators to consider cased-hole gravel packing or frac packing as the preferred completion. Despite the reliability of these options, they are more expensive than a standalone screen completion.\u0000 In this paper, we employ a combined physical laboratory testing and computational fluid dynamics (CFD) for laboratory scale and field scale to assess the potential use of the standalone screen in completing the cased and perforated wells. The aim is to design a fit-to-purpose sand control method in cased and perforated wells and provide guidelines in perforation strategy and investigate screen and perforation characteristics. More specifically, the simultaneous effect of screen and perforation parameters, near wellbore conditions on pressure distribution and pressure drop are investigated in detail.\u0000 A common mistake in completion operation is to separately focus on the design of the screen based on the reservoir sand print and design of the perforation. If sand control is deemed to be required, the perforation strategy and design must go hand in hand with sand control design. Several experiments and simulation models were designed to better understand the effect of perforation density, the fill-up of the annular gap between the casing and screen, perforation collapse, and formation and perforation damage on pressure drop. The experiments consisted of a series of step-rate tests to investigate the role of fluid rate on pressure drop and sand production. There is a critical rate at which the sand filling up the annular gap will fluidize. Both test results and CFD simulation scenarios are comparatively capable to establish the relation between wellbore pressure drop and perforation parameters and determine the optimized design.\u0000 The results of this study highlight the workflow to optimize the standalone screen design for the application in cased and perforated completions. The proper design of standalone screen and perforation parameters allows maintaining cost-effective well productivity. Results of this work could be used for choosing the proper sand control and perforation strategy.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41907089","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Variable ram blowout prevention (VRBOP) valves are elastomeric material-based flow control devices used in offshore oil drilling applications as the primary safety mechanism to respond to high wellbore pressure emergency situations. During their operation, the elastomer deforms and distorts extensively to form a tight seal around the drillpipe. Because of the large deformation and distortion of the elastomer, developing a Lagrangian-based finite element analysis model to simulate the operation of a VRBOP valve is quite challenging. The finite elements of the Lagrangian finite element mesh degrade in quality because they deform with the material when the deformation becomes excessive. This leads to poor convergence of the numerical solution. In this study, we first demonstrate that the numerical convergence issues can be resolved by using a suite of modeling techniques: explicit integration scheme, Ogden second-order hyperelastic constitutive model for the elastomer, and the selection of appropriate values for element sizes and other modeling parameters. After resolving the convergence issues, we used the model to study the sealing efficiency and material failure of a VRBOP valve for two different operating temperatures and drillpipe diameters. The sealing efficiency is studied using two performance criteria: the uniformity of the sealing pressure around the drillpipe and the magnitude of the overall deformation of the elastomer. For the material failure analysis of the elastomer, we used multiple failure criteria. The results of this study provide many new insights that have the potential to improve VRBOP valve design. For instance, results show that elevated temperature improves the sealing efficiency of a VRBOP valve because of the higher flexibility of the elastomer at elevated temperatures. Likewise, the wellbore pressure also improves the sealing efficiency. However, all these improvements in sealing pressure come with the risk of a higher probability of material failure.
{"title":"Stress Analysis of Variable Ram Blowout Prevention Valves","authors":"A. Achuthan, Shiyan Jayanath","doi":"10.2118/205348-PA","DOIUrl":"https://doi.org/10.2118/205348-PA","url":null,"abstract":"\u0000 Variable ram blowout prevention (VRBOP) valves are elastomeric material-based flow control devices used in offshore oil drilling applications as the primary safety mechanism to respond to high wellbore pressure emergency situations. During their operation, the elastomer deforms and distorts extensively to form a tight seal around the drillpipe. Because of the large deformation and distortion of the elastomer, developing a Lagrangian-based finite element analysis model to simulate the operation of a VRBOP valve is quite challenging. The finite elements of the Lagrangian finite element mesh degrade in quality because they deform with the material when the deformation becomes excessive. This leads to poor convergence of the numerical solution. In this study, we first demonstrate that the numerical convergence issues can be resolved by using a suite of modeling techniques: explicit integration scheme, Ogden second-order hyperelastic constitutive model for the elastomer, and the selection of appropriate values for element sizes and other modeling parameters. After resolving the convergence issues, we used the model to study the sealing efficiency and material failure of a VRBOP valve for two different operating temperatures and drillpipe diameters. The sealing efficiency is studied using two performance criteria: the uniformity of the sealing pressure around the drillpipe and the magnitude of the overall deformation of the elastomer. For the material failure analysis of the elastomer, we used multiple failure criteria. The results of this study provide many new insights that have the potential to improve VRBOP valve design. For instance, results show that elevated temperature improves the sealing efficiency of a VRBOP valve because of the higher flexibility of the elastomer at elevated temperatures. Likewise, the wellbore pressure also improves the sealing efficiency. However, all these improvements in sealing pressure come with the risk of a higher probability of material failure.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-03-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49158063","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wells are sometimes deformed due to geomechanical shear slip, which occurs on a localized slip surface, such as a bedding plane, fault, or natural fracture. This can occur in the overburden above a conventional reservoir (during production) or within an unconventional reservoir (during completion operations). Shear slip will usually deform the casing into a recognizable shape, with lateral offset and two opposite-trending bends, and ovalized cross sections. Multifinger casing caliper tools have a recognizable response to this shape and are especially useful for diagnosing well shear. Certain other tools can also provide evidence for shear deformation. Shear deformations above a depleting, compacting reservoir are usually due to slip on bedding planes. They usually occur at multiple depths and are driven by overburden bending in response to reservoir differential compaction. Shear deformations in unconventional reservoirs, for the examples studied, have been found to be caused by slip on bedding planes and natural fractures. In both cases, models, field data, and physical reasoning suggest that slip occurs primarily due to fluid pressurization of the interface. In the case of bedding plane slip, fracturing pressure greater than the vertical stress (in regions where the vertical stress is the intermediate stress) could lead to propagation of a horizontal fracture, which then slips in shear.
{"title":"Well Shear Associated with Conventional and Unconventional Operations: Diagnosis and Mechanisms","authors":"R. Ewy","doi":"10.2118/205007-PA","DOIUrl":"https://doi.org/10.2118/205007-PA","url":null,"abstract":"\u0000 Wells are sometimes deformed due to geomechanical shear slip, which occurs on a localized slip surface, such as a bedding plane, fault, or natural fracture. This can occur in the overburden above a conventional reservoir (during production) or within an unconventional reservoir (during completion operations). Shear slip will usually deform the casing into a recognizable shape, with lateral offset and two opposite-trending bends, and ovalized cross sections. Multifinger casing caliper tools have a recognizable response to this shape and are especially useful for diagnosing well shear. Certain other tools can also provide evidence for shear deformation. Shear deformations above a depleting, compacting reservoir are usually due to slip on bedding planes. They usually occur at multiple depths and are driven by overburden bending in response to reservoir differential compaction. Shear deformations in unconventional reservoirs, for the examples studied, have been found to be caused by slip on bedding planes and natural fractures. In both cases, models, field data, and physical reasoning suggest that slip occurs primarily due to fluid pressurization of the interface. In the case of bedding plane slip, fracturing pressure greater than the vertical stress (in regions where the vertical stress is the intermediate stress) could lead to propagation of a horizontal fracture, which then slips in shear.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48952425","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
North American shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for the maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past. High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud motor bit box, and motor top subassembly (top-sub) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. Three-axis shock, gyro, and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, weight on bit, and drillpipe size. The torsional energy stored and released in the drillstring can be high because of the interaction between surface rotation speed/torque output and mud motor downhole rotation speed/torque. Torsional drillstring energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration, rapid fatigue on downhole equipment, and motor or drillstring backoffs and twistoffs. A new mechanism of motor back-drive dynamics caused by the use of an MWD pulser above a steerable motor has been discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one-third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a polycrystalline diamond compact (PDC) drill bit during severe stick-slip and back-drive events (−50 rev/min above the motor), confirming that the bit rotated backward for 9 milliseconds (ms) every 133.3 ms (at 7.5 Hz), using a 1,000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It was discovered that the back-drive dynamics are worse at the drillstring, approximately 1,110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring backoffs and twistoffs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool signif
{"title":"Measurement of Mud Motor Back-Drive Dynamics, Associated Risks, and Benefits of Real-Time Detection and Mitigation Measures","authors":"J. Sugiura, Steve Jones","doi":"10.2118/204032-PA","DOIUrl":"https://doi.org/10.2118/204032-PA","url":null,"abstract":"\u0000 North American shale drilling is a fast-paced environment where downhole drilling equipment is pushed to the limits for the maximum rate of penetration (ROP). Downhole mud motor power sections have rapidly advanced to deliver more horsepower and torque, resulting in different downhole dynamics that have not been identified in the past.\u0000 High-frequency (HF) compact drilling dynamics recorders embedded in the drill bit, mud motor bit box, and motor top subassembly (top-sub) provide unique measurements to fully understand the reaction of the steerable-motor power section under load relative to the type of rock being drilled. Three-axis shock, gyro, and temperature sensors placed above and below the power section measure the dynamic response of power transfer to the bit and associated losses caused by back-drive dynamics. Detection of back-drive from surface measurements is not possible, and many measurement-while-drilling (MWD) systems do not have the measurement capability to identify the problem. Motor back-drive dynamics severity is dependent on many factors, including formation type, bit type, power section, weight on bit, and drillpipe size. The torsional energy stored and released in the drillstring can be high because of the interaction between surface rotation speed/torque output and mud motor downhole rotation speed/torque. Torsional drillstring energy wind-up and release results in variable power output at the bit, inconsistent rate of penetration, rapid fatigue on downhole equipment, and motor or drillstring backoffs and twistoffs.\u0000 A new mechanism of motor back-drive dynamics caused by the use of an MWD pulser above a steerable motor has been discovered. HF continuous gyro sensors and pressure sensors were deployed to capture the mechanism in which a positive mud pulser reduces as much as one-third of the mud flow in the motor and bit rotation speed, creating a propensity for a bit to come to a complete stop in certain conditions and for the motor to rotate the drillstring backward. We have observed the backward rotation of a polycrystalline diamond compact (PDC) drill bit during severe stick-slip and back-drive events (−50 rev/min above the motor), confirming that the bit rotated backward for 9 milliseconds (ms) every 133.3 ms (at 7.5 Hz), using a 1,000-Hz continuous sampling/recording in-bit gyro. In one field test, multiple drillstring dynamics recorders were used to measure the motor back-drive severity along the drillstring. It was discovered that the back-drive dynamics are worse at the drillstring, approximately 1,110 ft behind the bit, than these measured at the motor top-sub position. These dynamics caused drillstring backoffs and twistoffs in a particular field. A motor back-drive mitigation tool was used in the field to compare the runs with and without the mitigation tool while keeping the surface drilling parameters nearly the same. The downhole drilling dynamics sensors were used to confirm that the mitigation tool signif","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49647397","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Total field strength, declination, and dip angle of the Earth's magnetic field, in conjunction with gravity, are used by magnetic-survey tools to determine a wellbore's location. Magnetic field values may be obtained from global models that, depending on the model, have a wide range of spatial resolution at the Earth's surface from large scale (3000 km) to small scale (28 km). The magnetic field varies continuously in both time and space, so no model can fully capture the complexity of all sources; hence, there are uncertainties associated with the values provided. The SPE Wellbore Positioning Technical Section/Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA) published their original measurement-while-drilling (MWD) error model in 2000. Such models and uncertainties define positional error ellipsoids along the wellbore, which assist the driller in achieving their geological target, in addition to aiding collision avoidance. With the recent update to Revision 5 of the ISCWSA error model, we have reassessed the uncertainties associated with our latest high-resolution global magnetic field model. We describe the derivation of location-specific global and random uncertainties for use with predicted geomagnetic values from high-resolution models within magnetic MWD survey-tool-error models. We propose a sophisticated approach to provide realistic values at different locations around the globe; for example, we determine separate errors for regions where the models have high spatial resolution from aeromagnetic data compared to regions where only satellite data are available. The combined uncertainties are freely available via a web service with which the user can also see how they vary with time. The use of the revised uncertainty values in the MWD-error model, in most cases, reduces the positional error ellipsoids and allows better use of the increased accuracy from recent improvements in geomagnetic modeling. This is demonstrated using the new uncertainty values in the MWD-error model for three standard ISCWSA well profiles. A fourth theoretical well offshore Brazil where the vertical magnetic field is weak shows that with drillstring interference correction relying on the more uncertain magnetic dip, the positional error ellipsoids can increase. This is clearly of concern for attaining geological targets and collision avoidance.
{"title":"Quantifying Global and Random Uncertainties in High Resolution Global Geomagnetic Field Models Used for Directional Drilling","authors":"C. Beggan, S. Macmillan, W. Brown, S. Grindrod","doi":"10.2118/204038-PA","DOIUrl":"https://doi.org/10.2118/204038-PA","url":null,"abstract":"\u0000 Total field strength, declination, and dip angle of the Earth's magnetic field, in conjunction with gravity, are used by magnetic-survey tools to determine a wellbore's location. Magnetic field values may be obtained from global models that, depending on the model, have a wide range of spatial resolution at the Earth's surface from large scale (3000 km) to small scale (28 km). The magnetic field varies continuously in both time and space, so no model can fully capture the complexity of all sources; hence, there are uncertainties associated with the values provided. The SPE Wellbore Positioning Technical Section/Industry Steering Committee on Wellbore Surveying Accuracy (ISCWSA) published their original measurement-while-drilling (MWD) error model in 2000. Such models and uncertainties define positional error ellipsoids along the wellbore, which assist the driller in achieving their geological target, in addition to aiding collision avoidance. With the recent update to Revision 5 of the ISCWSA error model, we have reassessed the uncertainties associated with our latest high-resolution global magnetic field model.\u0000 We describe the derivation of location-specific global and random uncertainties for use with predicted geomagnetic values from high-resolution models within magnetic MWD survey-tool-error models. We propose a sophisticated approach to provide realistic values at different locations around the globe; for example, we determine separate errors for regions where the models have high spatial resolution from aeromagnetic data compared to regions where only satellite data are available.\u0000 The combined uncertainties are freely available via a web service with which the user can also see how they vary with time. The use of the revised uncertainty values in the MWD-error model, in most cases, reduces the positional error ellipsoids and allows better use of the increased accuracy from recent improvements in geomagnetic modeling. This is demonstrated using the new uncertainty values in the MWD-error model for three standard ISCWSA well profiles. A fourth theoretical well offshore Brazil where the vertical magnetic field is weak shows that with drillstring interference correction relying on the more uncertain magnetic dip, the positional error ellipsoids can increase. This is clearly of concern for attaining geological targets and collision avoidance.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"67779940","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Khatere Sokhanvarian, C. Stanciu, Jorge Fernandez, A. Ibrahim, H. Kumar, H. Nasr-El-Din
Matrix acidizing improves productivity in oil and gas wells. Hydrochloric acid (HCl), because of its many advantages such as its effectiveness, availability, and low cost, has been a typical first-choice fluid for acidizing operations. However, HCl in high-pressure/high-temperature (HP/HT) wells can be problematic because of its high reactivity, resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. Several alternatives to HCl have been tested; among them, emulsified acid is a favorable choice because of its inherent low corrosion rate, deeper penetration into the reservoir, fewer asphaltene/sludge problems, and better acid distribution due to its higher viscosity. The success of the new system is dependent upon the stability of the emulsion, especially at high temperatures. The emulsified acid must be stable until it is properly placed, and it must also be compatible with other additives in an acidizing package. This study develops a stable, emulsified acid system at 300°F using aliphatic nonionic surfactants. This paper introduces a new nonaromatic, nonionic surfactant to form an emulsified acid for HP/HT wells. The type and quality of the emulsified acid were assessed through conductivity measurements and drop tests. The thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. A LUMisizer® (LUM GmbH, Berlin, Germany) and Turbiscan® (Formulaction, S. A., L’Union, France) were used to determine the stability and the average droplet size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 300°F as a function of shear rate (1 to 1,000 s−1). The microscopy study was used to examine the shape and the distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes in carbonate rocks. Inductively coupled plasma and computed tomography (CT) scans were used to determine the dissolved cations and wormhole propagation, respectively. Superior stimulation results with a low pore volume of acid to breakthrough (PVBT) were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branched wormholes resulting from conventional emulsified acid systems. Results indicate that a nonionic surfactant with optimal chemistry, such as a suitable hydrophobe chain length and structure, can form a stable emulsified acid. In this study we introduce a new and effective aliphatic nonionic surfactant to create a stable emulsified acid system for matrix acidizing at HP/HT conditions, leading to a deeper penetration of acid with low pore volume to breakthrough. The successful core flood studies in the laboratory using carbonate cores suggest that the new emulsified acid system may efficiently stimula
{"title":"Experimental Evaluation of a New Nonaromatic Nonionic Surfactant for Deep Carbonate Stimulation","authors":"Khatere Sokhanvarian, C. Stanciu, Jorge Fernandez, A. Ibrahim, H. Kumar, H. Nasr-El-Din","doi":"10.2118/193596-PA","DOIUrl":"https://doi.org/10.2118/193596-PA","url":null,"abstract":"\u0000 Matrix acidizing improves productivity in oil and gas wells. Hydrochloric acid (HCl), because of its many advantages such as its effectiveness, availability, and low cost, has been a typical first-choice fluid for acidizing operations. However, HCl in high-pressure/high-temperature (HP/HT) wells can be problematic because of its high reactivity, resulting in face dissolution, high corrosion rates, and high corrosion inhibition costs. Several alternatives to HCl have been tested; among them, emulsified acid is a favorable choice because of its inherent low corrosion rate, deeper penetration into the reservoir, fewer asphaltene/sludge problems, and better acid distribution due to its higher viscosity. The success of the new system is dependent upon the stability of the emulsion, especially at high temperatures. The emulsified acid must be stable until it is properly placed, and it must also be compatible with other additives in an acidizing package. This study develops a stable, emulsified acid system at 300°F using aliphatic nonionic surfactants.\u0000 This paper introduces a new nonaromatic, nonionic surfactant to form an emulsified acid for HP/HT wells. The type and quality of the emulsified acid were assessed through conductivity measurements and drop tests. The thermal stability of the system was monitored as a function of time through the use of pressure tubes and a preheated oil bath at 300°F. A LUMisizer® (LUM GmbH, Berlin, Germany) and Turbiscan® (Formulaction, S. A., L’Union, France) were used to determine the stability and the average droplet size of the emulsion, respectively. The viscosity of the emulsified acid was measured at different temperatures up to 300°F as a function of shear rate (1 to 1,000 s−1). The microscopy study was used to examine the shape and the distribution of acid droplets in diesel. Coreflood studies at low and high flow rates were conducted to determine the performance of the newly developed stable emulsified acid in creating wormholes in carbonate rocks. Inductively coupled plasma and computed tomography (CT) scans were used to determine the dissolved cations and wormhole propagation, respectively.\u0000 Superior stimulation results with a low pore volume of acid to breakthrough (PVBT) were achieved at 300°F with the newly developed emulsified acid system. The wormhole propagation was narrow and dominant compared to branched wormholes resulting from conventional emulsified acid systems. Results indicate that a nonionic surfactant with optimal chemistry, such as a suitable hydrophobe chain length and structure, can form a stable emulsified acid.\u0000 In this study we introduce a new and effective aliphatic nonionic surfactant to create a stable emulsified acid system for matrix acidizing at HP/HT conditions, leading to a deeper penetration of acid with low pore volume to breakthrough. The successful core flood studies in the laboratory using carbonate cores suggest that the new emulsified acid system may efficiently stimula","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43174754","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wei Chen, Yuelin Shen, Rongbing Chen, Zhengxin Zhang, S. Rawlins
As drilling sections become deeper and longer, transferring more weight downhole to improve rate of penetration is the primary concern for the operator. Drillstring dynamics and buckling are some primary limiters for drilling efficiency. Aggressive drilling parameters may lead to severe downhole dynamics, which leads to cutter breakage and tool damage. When axial compression exceeds a certain threshold, the drillstring buckles sinusoidally inside the wellbore first, followed by helical buckling. Buckling leads to accelerated joint wear, tool fatigue failures, and lower drilling efficiency. To better manage drillstring dynamics and buckling, we propose a method of simulating drillstring dynamics motion and postbuckling state using an advanced transient dynamics model. An analysis methodology was developed on the basis of the finite element transient dynamics model. The model captures the enriched physics of drillstring dynamics and loading: the large deformation of buckled drillstring, the strong nonlinearity of contact and friction forces, and the dynamically triggered instability caused by drilling rotation. Transient dynamics simulations are conducted for drillstring with the actual well trajectory and rotation speed. The weight on bit (WOB) is ramped up gradually, and the drillstring deformation is monitored to detect the onset of buckling or dynamics instability. To conduct the model validation, the buckling inception loads predicted by the model are compared against the analytical equation of critical buckling loads. A field extended reach drilling (ERD) job was simulated by the model. The downhole weight and torque data from the measurement-while-drilling (MWD) tool was used to validate the weight transfer prediction by the model. Most existing buckling theories use the analytical equations of critical buckling load, which were normally derived on the basis of the idealized assumptions, such as perfect wellbore shape and uniform tubular geometry. The proposed method simulates the drillstring behaviors in the field drilling conditions and aims to capture effects of wellbore friction and string rotation. The transient dynamics model is capable of simulating drillstring dynamics movement (whirling and snaking) and weight lockup under severe helical buckling. An automatic method is proposed to interpret the drillstring behaviors from the simulation results. Using the transient dynamics model, the procedure presented in this article can simulate the dynamics and buckling behaviors of drillstring and help mitigate associated risks in well-planning and execution phases.
{"title":"Simulating Drillstring Dynamics Motion and Post-Buckling State with Advanced Transient Dynamics Model","authors":"Wei Chen, Yuelin Shen, Rongbing Chen, Zhengxin Zhang, S. Rawlins","doi":"10.2118/199557-PA","DOIUrl":"https://doi.org/10.2118/199557-PA","url":null,"abstract":"\u0000 As drilling sections become deeper and longer, transferring more weight downhole to improve rate of penetration is the primary concern for the operator. Drillstring dynamics and buckling are some primary limiters for drilling efficiency. Aggressive drilling parameters may lead to severe downhole dynamics, which leads to cutter breakage and tool damage. When axial compression exceeds a certain threshold, the drillstring buckles sinusoidally inside the wellbore first, followed by helical buckling. Buckling leads to accelerated joint wear, tool fatigue failures, and lower drilling efficiency. To better manage drillstring dynamics and buckling, we propose a method of simulating drillstring dynamics motion and postbuckling state using an advanced transient dynamics model.\u0000 An analysis methodology was developed on the basis of the finite element transient dynamics model. The model captures the enriched physics of drillstring dynamics and loading: the large deformation of buckled drillstring, the strong nonlinearity of contact and friction forces, and the dynamically triggered instability caused by drilling rotation. Transient dynamics simulations are conducted for drillstring with the actual well trajectory and rotation speed. The weight on bit (WOB) is ramped up gradually, and the drillstring deformation is monitored to detect the onset of buckling or dynamics instability.\u0000 To conduct the model validation, the buckling inception loads predicted by the model are compared against the analytical equation of critical buckling loads. A field extended reach drilling (ERD) job was simulated by the model. The downhole weight and torque data from the measurement-while-drilling (MWD) tool was used to validate the weight transfer prediction by the model. Most existing buckling theories use the analytical equations of critical buckling load, which were normally derived on the basis of the idealized assumptions, such as perfect wellbore shape and uniform tubular geometry. The proposed method simulates the drillstring behaviors in the field drilling conditions and aims to capture effects of wellbore friction and string rotation. The transient dynamics model is capable of simulating drillstring dynamics movement (whirling and snaking) and weight lockup under severe helical buckling. An automatic method is proposed to interpret the drillstring behaviors from the simulation results. Using the transient dynamics model, the procedure presented in this article can simulate the dynamics and buckling behaviors of drillstring and help mitigate associated risks in well-planning and execution phases.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"47663895","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Habib, S. Imtiaz, F. Khan, Salim Ahmed, J. Baker
The sudden influx of reservoir fluids (i.e., reservoir kick) into the drilling annulus is one of the common abnormal events encountered in drilling operations. A kick can lead to a blowout, causing loss of lives, assets, and damage to the environment. This study presents a framework for real-time kick monitoring and management in managed-pressure-drilling (MPD) operation. The proposed framework consists of three distinct steps: the unscented Kalman filter (UKF) is used to detect and estimate the kick's severity; the estimated kick size and optimal control theory are used to calculate the time to mitigate the kick in the best-case scenario; and on the basis of the total predicted influx and pressure rise, the monitoring system generates a warning and activates the mitigation strategy. Thus, the proposed method can estimate, monitor, and manage kick in real time, enhancing the safety and efficiency of the MPD operation. The developed method was validated and demonstrated using a simulated MPD system, a pilot-scale experimental setup, and field data collected from an MPD operation in western Canada.
{"title":"Prediction of Reservoir-Kick Effect and Its Management in the Managed-Pressure-Drilling Operation","authors":"M. Habib, S. Imtiaz, F. Khan, Salim Ahmed, J. Baker","doi":"10.2118/205020-PA","DOIUrl":"https://doi.org/10.2118/205020-PA","url":null,"abstract":"\u0000 The sudden influx of reservoir fluids (i.e., reservoir kick) into the drilling annulus is one of the common abnormal events encountered in drilling operations. A kick can lead to a blowout, causing loss of lives, assets, and damage to the environment. This study presents a framework for real-time kick monitoring and management in managed-pressure-drilling (MPD) operation. The proposed framework consists of three distinct steps: the unscented Kalman filter (UKF) is used to detect and estimate the kick's severity; the estimated kick size and optimal control theory are used to calculate the time to mitigate the kick in the best-case scenario; and on the basis of the total predicted influx and pressure rise, the monitoring system generates a warning and activates the mitigation strategy. Thus, the proposed method can estimate, monitor, and manage kick in real time, enhancing the safety and efficiency of the MPD operation. The developed method was validated and demonstrated using a simulated MPD system, a pilot-scale experimental setup, and field data collected from an MPD operation in western Canada.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2021-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46710179","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":4,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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