M. White, K. Friehauf, D. Cramer, J. Constantine, Junjing Zhang, S. Schmidt, J. Long, Paul Mislan, J. Spencer, P. Meier, E. Davis
Plug-and-perforation (plug-and-perf) multistage hydraulic fracturing completions in unconventional reservoirs rely on complete hydraulic isolation from the previous stage to ensure effective treatment of the active stage. Failure to isolate stages can be a result of partially set plugs, plugs set in wellbore debris or deformed casing, unqualified pressure/temperature rating of plugs, and so on. This paper presents a case study with field examples in which unexpected casing erosion occurred at the setting depths of the dissolvable fracturing (frac) plugs during hydraulic fracturing and subsequently resulted in loss of interstage isolation. A 12-well, four-layer, cube pilot was designed with permanent fiber-optic cable to collect distributed acoustic sensing (DAS), distributed temperature sensing (DTS), and distributed strain sensing (DSS) data as well as downhole pressure gauges for development insight and future completion optimization. The cable was mapped, and oriented perforation techniques placed entry holes opposite the fiber along the wellbore, and no loss of communication was observed during perforating operations. However, fiber-optic signal was lost during hydraulic fracturing operations on one or more stages in all four instrumented horizontal wells. Real-time DAS/DTS analysis indicated the fiber breaks were consistently occurring below the lowermost perforation cluster in the stage, at or very near the frac plug setting depth. Step-down tests were also performed and showed significantly enlarged effective treating area. Based on this observation, post-frac downhole imaging tools were deployed to investigate potential casing and perforation erosion. Downhole imaging data clearly showed the casing was severely eroded at several locations. Additional interrogation of the damage with respect to plug design components indicated that damage always occurred near the plug sealing element. By integrating the analysis of DAS/DTS, step-down tests, and ultrasonic imaging, it was determined that the frac plug bypass was creating a loss of casing integrity at the plug set location. Casing integrity loss resulted in multiple fiber-optic cable breaks and lowered the ability to evenly distribute slurry into treatment clusters. Fiber-optic data analysis showed that 50% of the larger outer diameter (OD) dissolvable frac plugs had bypass compared to 100% bypass for the smaller OD high-expansion, dissolvable plugs. To establish key patterns and identify critical variables that influence stimulation effectiveness, it is important to obtain several different diagnostic data sets and perform an integrated evaluation using all available information. This study also reinforces the need for operators and manufacturers to work together to design and qualify frac plugs against realistic downhole conditions, particularly in areas with potential casing deformation issues. Industry innovation is required to enable fracturing operations to continue through deform
{"title":"One Stage Forward or Two Stages Back: What Are We Treating? Identification of Internal Casing Erosion during Hydraulic Fracturing—A Montney Case Study Using Ultrasonic and Fiber-Optic Diagnostics","authors":"M. White, K. Friehauf, D. Cramer, J. Constantine, Junjing Zhang, S. Schmidt, J. Long, Paul Mislan, J. Spencer, P. Meier, E. Davis","doi":"10.2118/201734-pa","DOIUrl":"https://doi.org/10.2118/201734-pa","url":null,"abstract":"\u0000 Plug-and-perforation (plug-and-perf) multistage hydraulic fracturing completions in unconventional reservoirs rely on complete hydraulic isolation from the previous stage to ensure effective treatment of the active stage. Failure to isolate stages can be a result of partially set plugs, plugs set in wellbore debris or deformed casing, unqualified pressure/temperature rating of plugs, and so on. This paper presents a case study with field examples in which unexpected casing erosion occurred at the setting depths of the dissolvable fracturing (frac) plugs during hydraulic fracturing and subsequently resulted in loss of interstage isolation.\u0000 A 12-well, four-layer, cube pilot was designed with permanent fiber-optic cable to collect distributed acoustic sensing (DAS), distributed temperature sensing (DTS), and distributed strain sensing (DSS) data as well as downhole pressure gauges for development insight and future completion optimization. The cable was mapped, and oriented perforation techniques placed entry holes opposite the fiber along the wellbore, and no loss of communication was observed during perforating operations. However, fiber-optic signal was lost during hydraulic fracturing operations on one or more stages in all four instrumented horizontal wells. Real-time DAS/DTS analysis indicated the fiber breaks were consistently occurring below the lowermost perforation cluster in the stage, at or very near the frac plug setting depth. Step-down tests were also performed and showed significantly enlarged effective treating area. Based on this observation, post-frac downhole imaging tools were deployed to investigate potential casing and perforation erosion.\u0000 Downhole imaging data clearly showed the casing was severely eroded at several locations. Additional interrogation of the damage with respect to plug design components indicated that damage always occurred near the plug sealing element. By integrating the analysis of DAS/DTS, step-down tests, and ultrasonic imaging, it was determined that the frac plug bypass was creating a loss of casing integrity at the plug set location. Casing integrity loss resulted in multiple fiber-optic cable breaks and lowered the ability to evenly distribute slurry into treatment clusters. Fiber-optic data analysis showed that 50% of the larger outer diameter (OD) dissolvable frac plugs had bypass compared to 100% bypass for the smaller OD high-expansion, dissolvable plugs.\u0000 To establish key patterns and identify critical variables that influence stimulation effectiveness, it is important to obtain several different diagnostic data sets and perform an integrated evaluation using all available information. This study also reinforces the need for operators and manufacturers to work together to design and qualify frac plugs against realistic downhole conditions, particularly in areas with potential casing deformation issues. Industry innovation is required to enable fracturing operations to continue through deform","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"46543047","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}
Alternate or out-of-sequence fracturing (OOSF) has been field tested in western Siberia in 2014 and in western Canada in 2017, 2018, and 2019, with operational success and positive well-production performance. It is conducted by fracturing Stage 1 (at the toe) and then fracturing Stage 3 (toward the heel), followed by tripping back to place Stage 2 (center fracture) between Stages 1 and 3 (outside fractures). During placing the center fracture, OOSF can exploit the reduced stress anisotropy to effectively activate the planes of weakness (natural fractures, fissures, faults, and joints) to potentially create failure surfaces with different breakdown angles in virtually all directions. This can potentially lead to branch fractures that can connect the hydraulic fractures to stress-relief fractures that are created while placing the outside fractures, ultimately generating a complex fracture network and enhancing fracture connectivity. Despite prior works on fracture modeling (calibrated by field tests) and geomechanical modeling, a comparative analysis of wellbore-breakdown character and hydraulic-fracture orientation during OOSF is still lacking. Thus, in this study, the solutions to 3D Kirsch equations are provided for both low and high stress anisotropies to analyze the differences in breakdown gradient, failure angle, and fracture orientation under various geomechanical and treatment-design conditions. The consideration is given to an intact rock from an isotropic stress state to high-stress-anisotropy conditions. The results are analyzed in the context of the downhole-measured pressures and temperatures. The results indicate that the reduced stress anisotropy during OOSF leads to favorable treating conditions: With a net fracture-extension pressure greater than the reduced stress anisotropy, fracture complexity can be created by allowing the fracture to grow with different failure angles. Also, a well can be drilled and fractured at any inclination or azimuth with favorable breakdown gradients of 45 to 85% of the overburden gradient. The reduced stress anisotropy can also trigger some challenges. The near-well stress-concentration effects can become more pronounced, promoting longitudinal fracture creation. For treatments with tortuosity greater than the stress anisotropy, longitudinal fractures can be created instead of transverse fractures because the tortuosity is transmitted to the wellbore body and not into the fractures. In this case, to initiate transverse fractures, either the wellbore must intersect the pre-existing transverse notches or the near-well pore-fluid pressure must exceed the axial stress and rock strength (before the hoop stress reaches the tensile failure point). In addition, the fracture might lose directional control and follow any path of weakness. Hence, the rock-fabric effects become more dominant under a low-stress-anisotropy regime, which means that with no pre-existing transverse natural fractures or notches,
{"title":"Practical Considerations in Alternate Fracturing with Shift/Fracture/Close Operation: Learnings from Geomechanical Modeling and Downhole Diagnostics","authors":"Benyamin Yadali Jamaloei","doi":"10.2118/204211-PA","DOIUrl":"https://doi.org/10.2118/204211-PA","url":null,"abstract":"\u0000 Alternate or out-of-sequence fracturing (OOSF) has been field tested in western Siberia in 2014 and in western Canada in 2017, 2018, and 2019, with operational success and positive well-production performance. It is conducted by fracturing Stage 1 (at the toe) and then fracturing Stage 3 (toward the heel), followed by tripping back to place Stage 2 (center fracture) between Stages 1 and 3 (outside fractures). During placing the center fracture, OOSF can exploit the reduced stress anisotropy to effectively activate the planes of weakness (natural fractures, fissures, faults, and joints) to potentially create failure surfaces with different breakdown angles in virtually all directions. This can potentially lead to branch fractures that can connect the hydraulic fractures to stress-relief fractures that are created while placing the outside fractures, ultimately generating a complex fracture network and enhancing fracture connectivity.\u0000 Despite prior works on fracture modeling (calibrated by field tests) and geomechanical modeling, a comparative analysis of wellbore-breakdown character and hydraulic-fracture orientation during OOSF is still lacking. Thus, in this study, the solutions to 3D Kirsch equations are provided for both low and high stress anisotropies to analyze the differences in breakdown gradient, failure angle, and fracture orientation under various geomechanical and treatment-design conditions. The consideration is given to an intact rock from an isotropic stress state to high-stress-anisotropy conditions. The results are analyzed in the context of the downhole-measured pressures and temperatures.\u0000 The results indicate that the reduced stress anisotropy during OOSF leads to favorable treating conditions: With a net fracture-extension pressure greater than the reduced stress anisotropy, fracture complexity can be created by allowing the fracture to grow with different failure angles. Also, a well can be drilled and fractured at any inclination or azimuth with favorable breakdown gradients of 45 to 85% of the overburden gradient. The reduced stress anisotropy can also trigger some challenges. The near-well stress-concentration effects can become more pronounced, promoting longitudinal fracture creation. For treatments with tortuosity greater than the stress anisotropy, longitudinal fractures can be created instead of transverse fractures because the tortuosity is transmitted to the wellbore body and not into the fractures. In this case, to initiate transverse fractures, either the wellbore must intersect the pre-existing transverse notches or the near-well pore-fluid pressure must exceed the axial stress and rock strength (before the hoop stress reaches the tensile failure point). In addition, the fracture might lose directional control and follow any path of weakness. Hence, the rock-fabric effects become more dominant under a low-stress-anisotropy regime, which means that with no pre-existing transverse natural fractures or notches, ","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41440912","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}
Abhishek Govindu, R. Ahmed, Subhash N. Shah, M. Amani
To minimize fluid loss and the associated formation damage, foam is a preferred fluid to perform cleanout operations and reestablish communication with an open completion interval. Because of their high viscosity and structure, foams are suitable cleanout fluids when underbalanced well-cleanout operations are applied. Although several studies have been conducted to better understand foam-flow behavior and hydraulics, investigations performed on foam stability are very limited. Specifically, very little is known regarding the impact of wellbore inclination on the stability of foams. Unstable foams do not possess high viscosity, and as a result, they are not effective in cleanout operations, especially in inclined wellbores. Predicting the downhole instability of foam could reduce the number of drilling problems associated with excessive liquid drainage, such as temporary overbalance, formation damage, and wellbore instability. The objectives of this study are to investigate the effects of wellbore inclination on the stability of various types of foams and develop a method to account for the effect of inclination on foam stability in inclined wells. In this study, foam-drainage experiments were performed using a flow loop that consists of a foam-drainage-measurement section and pipe viscometers. To verify proper foam generation, foam viscosity was measured using pipe viscometers and compared with previous measurements. Drainage experiments were performed with aqueous, polymer-based, and oil-based foams in concentric annulus and pipe under pressurized conditions. Tests were also conducted in vertical and inclined orientations to examine the effect of wellbore inclination on the stability of foams. The foam-bubble structure was examined and monitored in real time using a microscopic camera to study bubble coarsening. The foam quality (i.e., gas volume fraction) was varied from 40 to 80%. Results show that the drainage rates in the pipe and annular section were approximately the same, indicating a minor effect of column geometry. More importantly, the drainage rate of foam in an inclined configuration was significantly higher than that observed in a vertical orientation. The inclination exacerbated foam drainage and instability substantially. The mechanisms of foam drainage are different in an inclined configuration. In inclined wellbores, drainage occurs not only axially but also laterally. As a result, the drained liquid quickly reaches a wellbore wall before reaching the bottom of foam column. Then, a layer of liquid forms on the low side of the wellbore. The liquid layer flows downward because of gravity and reaches the bottom of the test section without facing the major hydraulic resistance of the foam network. This phenomenon aggravates the drainage process considerably. Although foam-drainage experiments have been reported in the literature, there exists only limited information on the effects of geometry and inclination on foam drainage a
{"title":"The Effect of Inclination on the Stability of Foam Systems in Drilling and Well Operations","authors":"Abhishek Govindu, R. Ahmed, Subhash N. Shah, M. Amani","doi":"10.2118/199821-pa","DOIUrl":"https://doi.org/10.2118/199821-pa","url":null,"abstract":"\u0000 To minimize fluid loss and the associated formation damage, foam is a preferred fluid to perform cleanout operations and reestablish communication with an open completion interval. Because of their high viscosity and structure, foams are suitable cleanout fluids when underbalanced well-cleanout operations are applied. Although several studies have been conducted to better understand foam-flow behavior and hydraulics, investigations performed on foam stability are very limited. Specifically, very little is known regarding the impact of wellbore inclination on the stability of foams. Unstable foams do not possess high viscosity, and as a result, they are not effective in cleanout operations, especially in inclined wellbores. Predicting the downhole instability of foam could reduce the number of drilling problems associated with excessive liquid drainage, such as temporary overbalance, formation damage, and wellbore instability. The objectives of this study are to investigate the effects of wellbore inclination on the stability of various types of foams and develop a method to account for the effect of inclination on foam stability in inclined wells.\u0000 In this study, foam-drainage experiments were performed using a flow loop that consists of a foam-drainage-measurement section and pipe viscometers. To verify proper foam generation, foam viscosity was measured using pipe viscometers and compared with previous measurements. Drainage experiments were performed with aqueous, polymer-based, and oil-based foams in concentric annulus and pipe under pressurized conditions. Tests were also conducted in vertical and inclined orientations to examine the effect of wellbore inclination on the stability of foams. The foam-bubble structure was examined and monitored in real time using a microscopic camera to study bubble coarsening. The foam quality (i.e., gas volume fraction) was varied from 40 to 80%.\u0000 Results show that the drainage rates in the pipe and annular section were approximately the same, indicating a minor effect of column geometry. More importantly, the drainage rate of foam in an inclined configuration was significantly higher than that observed in a vertical orientation. The inclination exacerbated foam drainage and instability substantially. The mechanisms of foam drainage are different in an inclined configuration. In inclined wellbores, drainage occurs not only axially but also laterally. As a result, the drained liquid quickly reaches a wellbore wall before reaching the bottom of foam column. Then, a layer of liquid forms on the low side of the wellbore. The liquid layer flows downward because of gravity and reaches the bottom of the test section without facing the major hydraulic resistance of the foam network. This phenomenon aggravates the drainage process considerably.\u0000 Although foam-drainage experiments have been reported in the literature, there exists only limited information on the effects of geometry and inclination on foam drainage a","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199821-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"44254675","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}
Tariq Almubarak, M. Alkhaldi, J. H. Ng, H. Nasr-El-Din
Hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in tight carbonate formations (10 to 50 md). The use of these acids, however, can cause instances of complete production loss. This is especially common due to incompatibilities of the acidizing fluid and oil, which can lead to the formation of acid/oil emulsions and sludge formation. Consequently, it is necessary to properly identify and remove such emulsions or precipitations without causing any further damage. Compatibility studies were conducted using representative crude samples and hydrochloric acid (HCl). The experiments were conducted at various temperatures up to 240°F using high-pressure/high-temperature (HP/HT) aging cells for both live and spent acid samples, in which some of the experiments included an antisludge, an iron-control agent, and a demulsifier. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments was varied between 0 and1,000 ppm. The results showed that commonly used acid systems were not compatible with representative oil field samples. The amount of sludge formed and the stability of formed emulsions increased significantly in the presence of ferric ions and was more severe in the presence of hydrogen sulfide (H2S). Using a field case, this paper will cover the methodology used to ascertain the source of formation damage from acidizing, study the different factors that influence the formation of acid/oil emulsion and sludge formation mechanism, and show how they can be removed. In this example, acid/oil emulsions, sludge formation, and improper drilling mud filter-cake removal were the reasons behind the production loss. However, the methodology can be expanded to cater the many acidizing failure cases faced in the industry worldwide.
{"title":"Matrix Acidizing: A Laboratory and Field Investigation of Sludge Formation and Removal of Oil-Based Drilling Mud Filter Cake","authors":"Tariq Almubarak, M. Alkhaldi, J. H. Ng, H. Nasr-El-Din","doi":"10.2118/178034-PA","DOIUrl":"https://doi.org/10.2118/178034-PA","url":null,"abstract":"\u0000 Hydrochloric and organic acids have been extensively used to enhance well productivity or injectivity in tight carbonate formations (10 to 50 md). The use of these acids, however, can cause instances of complete production loss. This is especially common due to incompatibilities of the acidizing fluid and oil, which can lead to the formation of acid/oil emulsions and sludge formation. Consequently, it is necessary to properly identify and remove such emulsions or precipitations without causing any further damage.\u0000 Compatibility studies were conducted using representative crude samples and hydrochloric acid (HCl). The experiments were conducted at various temperatures up to 240°F using high-pressure/high-temperature (HP/HT) aging cells for both live and spent acid samples, in which some of the experiments included an antisludge, an iron-control agent, and a demulsifier. In addition, another set of experiments was performed in the presence of ferric ions (Fe3+). The total iron concentration in these experiments was varied between 0 and1,000 ppm. The results showed that commonly used acid systems were not compatible with representative oil field samples. The amount of sludge formed and the stability of formed emulsions increased significantly in the presence of ferric ions and was more severe in the presence of hydrogen sulfide (H2S).\u0000 Using a field case, this paper will cover the methodology used to ascertain the source of formation damage from acidizing, study the different factors that influence the formation of acid/oil emulsion and sludge formation mechanism, and show how they can be removed. In this example, acid/oil emulsions, sludge formation, and improper drilling mud filter-cake removal were the reasons behind the production loss. However, the methodology can be expanded to cater the many acidizing failure cases faced in the industry worldwide.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-10-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/178034-PA","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41278089","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
Drilling in the offshore environment involves high risk, mainly caused by uncertainties in the reservoir conditions. Unplanned events such as the influx of reservoir fluids (i.e., kick) can lead to catastrophic accidents. Therefore, mitigation of kick is extremely crucial to enhance the safety and efficiency of drilling. In the current study, an unscented-Kalman-filter (UKF)-based estimator is used to simultaneously estimate the bit-flow rate and kick in a managed-pressure-drilling (MPD) system. The proposed estimator uses sigma-point transformations to determine the true mean and covariance of the Gaussian random variable and captures the posterior mean and covariance accurately up to the third order (Taylor-series expansion) for any nonlinearity. In the proposed UKF formulation, hidden states and unknown inputs were concatenated to an augmented state vector. The magnitude of the kick is estimated using only available topside measurements. The applied method was validated by estimating the gas-kick magnitude in a laboratory-scale setup and data set from a field operation. The proposed estimation method was found robust for the MPD system under different noisy scenarios.
{"title":"Early Detection and Estimation of Kick in Managed Pressure Drilling","authors":"M. Habib, S. Imtiaz, F. Khan, Salim Ahmed, J. Baker","doi":"10.2118/203819-pa","DOIUrl":"https://doi.org/10.2118/203819-pa","url":null,"abstract":"\u0000 Drilling in the offshore environment involves high risk, mainly caused by uncertainties in the reservoir conditions. Unplanned events such as the influx of reservoir fluids (i.e., kick) can lead to catastrophic accidents. Therefore, mitigation of kick is extremely crucial to enhance the safety and efficiency of drilling. In the current study, an unscented-Kalman-filter (UKF)-based estimator is used to simultaneously estimate the bit-flow rate and kick in a managed-pressure-drilling (MPD) system. The proposed estimator uses sigma-point transformations to determine the true mean and covariance of the Gaussian random variable and captures the posterior mean and covariance accurately up to the third order (Taylor-series expansion) for any nonlinearity. In the proposed UKF formulation, hidden states and unknown inputs were concatenated to an augmented state vector. The magnitude of the kick is estimated using only available topside measurements. The applied method was validated by estimating the gas-kick magnitude in a laboratory-scale setup and data set from a field operation. The proposed estimation method was found robust for the MPD system under different noisy scenarios.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/203819-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"42309459","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}
Separation factor (SF) is a widely used parameter for specifying the safe distance between two wells, and for monitoring safe distance while drilling. A variety of SF formulas is commonly applied in the industry. This paper demonstrates that different SF formulas may give significantly different results when applied to the same scenarios. This may create confusion about the interpretation and validity of the various SF definitions. More worryingly, the application of an incorrect SF formula may lead to wrong decisions with respect to well placement. A valid SF formula must adhere to fundamental principles of mathematical statistics, as elucidated in this paper. The paper further reviews commonly used SF formulas against these principles. The evaluation shows that several SF formulas may give either overly optimistic or unnecessarily pessimistic results, and, therefore, should not be used. These conclusions are supported by numeric examples. SF formulas in common use apply to a point-to-point model. However, an important application of the SF parameter is the monitoring of changes in SF along a wellbore. This implies the calculation of SF for successive point pairs, resulting in an SF listing or graph. Notable conclusions of the study are that none of the currently used formulas produces both intuitive and correct SF graphs, and that the validity of an SF graph cannot in general be assessed from its visual appearance alone. Furthermore, the current common practice of selecting the point pairs by solely geometric-distance criteria should be changed, because it frequently leads to optimistic SF values. All these findings should be of major concern to the industry.
{"title":"Evaluation of Separation Factors Used in Wellbore Collision Avoidance","authors":"Jon Bang, Erik Nyrnes, H. Wilson","doi":"10.2118/200475-pa","DOIUrl":"https://doi.org/10.2118/200475-pa","url":null,"abstract":"\u0000 Separation factor (SF) is a widely used parameter for specifying the safe distance between two wells, and for monitoring safe distance while drilling. A variety of SF formulas is commonly applied in the industry. This paper demonstrates that different SF formulas may give significantly different results when applied to the same scenarios. This may create confusion about the interpretation and validity of the various SF definitions. More worryingly, the application of an incorrect SF formula may lead to wrong decisions with respect to well placement.\u0000 A valid SF formula must adhere to fundamental principles of mathematical statistics, as elucidated in this paper. The paper further reviews commonly used SF formulas against these principles. The evaluation shows that several SF formulas may give either overly optimistic or unnecessarily pessimistic results, and, therefore, should not be used. These conclusions are supported by numeric examples.\u0000 SF formulas in common use apply to a point-to-point model. However, an important application of the SF parameter is the monitoring of changes in SF along a wellbore. This implies the calculation of SF for successive point pairs, resulting in an SF listing or graph. Notable conclusions of the study are that none of the currently used formulas produces both intuitive and correct SF graphs, and that the validity of an SF graph cannot in general be assessed from its visual appearance alone. Furthermore, the current common practice of selecting the point pairs by solely geometric-distance criteria should be changed, because it frequently leads to optimistic SF values. All these findings should be of major concern to the industry.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200475-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"45646505","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}
Freestanding drilling riser (FSDR), a new type of riser in deepwater drilling, though not in commercial use, can significantly reduce the engineering sensitivity to severe weather compared to the conventional risers. The optimal installation depth of the near surface disconnection package (NSDP) and the optimal number of buoyancy cans are two important parameters in the FSDR system. In this paper, the key mechanical problems of the FSDR system have been proposed and the mechanics of the FSDR system in normal drilling mode and freestanding mode have been studied. The above two optimal parameters have been calculated on the basis of a specific marine environment and system configuration. The operating envelope of the FSDR system has been figured out through parameter sensitivity analysis. Analysis results show that the NSDP should be installed 200 m below the sea surface to avoid strong wave-current profile and enhance the performance of the FSDR in freestanding mode. From the mechanical point of view, the weakest section of the FSDR is located at the junction between the buoyancy cans and the riser joints, where stress joint should be equipped to improve the stress condition of the system. Further, the maximum von Mises stress of the FSDR in normal drilling mode is the dominant factor restricting the increase of the number of buoyancy cans. The normal operating envelope of the FSDR is mainly limited by the deflection angle of the upper flexible joint (UFJ) and the von Mises stress. On the basis of the mechanics and operating criteria of the FSDR, the optimal number of buoyancy cans is six and the vessel offset should be less than 2% of the water depth to ensure the safety of the FSDR in normal drilling mode. Finally, suggestions on the future study on the FSDR system have been proposed.
{"title":"Study on the Mechanical Characteristics and Operating Envelope of Freestanding Drilling Riser in Deepwater Drilling","authors":"Yanbin Wang, D. Gao","doi":"10.2118/199894-pa","DOIUrl":"https://doi.org/10.2118/199894-pa","url":null,"abstract":"\u0000 Freestanding drilling riser (FSDR), a new type of riser in deepwater drilling, though not in commercial use, can significantly reduce the engineering sensitivity to severe weather compared to the conventional risers. The optimal installation depth of the near surface disconnection package (NSDP) and the optimal number of buoyancy cans are two important parameters in the FSDR system. In this paper, the key mechanical problems of the FSDR system have been proposed and the mechanics of the FSDR system in normal drilling mode and freestanding mode have been studied. The above two optimal parameters have been calculated on the basis of a specific marine environment and system configuration. The operating envelope of the FSDR system has been figured out through parameter sensitivity analysis. Analysis results show that the NSDP should be installed 200 m below the sea surface to avoid strong wave-current profile and enhance the performance of the FSDR in freestanding mode. From the mechanical point of view, the weakest section of the FSDR is located at the junction between the buoyancy cans and the riser joints, where stress joint should be equipped to improve the stress condition of the system. Further, the maximum von Mises stress of the FSDR in normal drilling mode is the dominant factor restricting the increase of the number of buoyancy cans. The normal operating envelope of the FSDR is mainly limited by the deflection angle of the upper flexible joint (UFJ) and the von Mises stress. On the basis of the mechanics and operating criteria of the FSDR, the optimal number of buoyancy cans is six and the vessel offset should be less than 2% of the water depth to ensure the safety of the FSDR in normal drilling mode. Finally, suggestions on the future study on the FSDR system have been proposed.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199894-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43923602","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}
A. Ibrahim, M. Al-Mujalhem, H. Nasr-El-Din, M. Al-Bagoury
Solids found in drilling fluids, particularly weighting materials, can cause significant formation damage by plugging of formation pores. This study investigates formation damage caused by using oil-based drilling fluid systems weighted by micronized ilmenite or micronized barite. Rheological properties of the oil-based-mud (OBM) systems were measured. High-pressure/high-temperature (HP/HT) static filtration experiments were conducted. A coreflood system was used to simulate dynamic conditions, allowing for drilling fluid circulation at the face of the core and measuring permeability damage. Computed-tomography (CT) scan analysis revealed formation damage and depth of solid invasion. The paper presents field applications of nondamaging micronized-ilmenite-based OBM, illustrating its advantages.
{"title":"Evaluation of Formation Damage of Oil-Based Drilling Fluids Weighted with Micronized Ilmenite or Micronized Barite","authors":"A. Ibrahim, M. Al-Mujalhem, H. Nasr-El-Din, M. Al-Bagoury","doi":"10.2118/200482-pa","DOIUrl":"https://doi.org/10.2118/200482-pa","url":null,"abstract":"\u0000 Solids found in drilling fluids, particularly weighting materials, can cause significant formation damage by plugging of formation pores. This study investigates formation damage caused by using oil-based drilling fluid systems weighted by micronized ilmenite or micronized barite. Rheological properties of the oil-based-mud (OBM) systems were measured. High-pressure/high-temperature (HP/HT) static filtration experiments were conducted. A coreflood system was used to simulate dynamic conditions, allowing for drilling fluid circulation at the face of the core and measuring permeability damage. Computed-tomography (CT) scan analysis revealed formation damage and depth of solid invasion. The paper presents field applications of nondamaging micronized-ilmenite-based OBM, illustrating its advantages.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/200482-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49312319","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}
Following uncontrolled discharge during loss of well control events, fracture initiation occurring during the post-blowout capping stage can lead to reservoir fluids broaching to the seafloor. A classic example is Union Oil's 1969 oil spill in Santa Barbara Channel, where fracture initiation at various locations caused thousands of gallons per hour to broach onto the ocean floor over a month before it could be controlled (Mullineaux 1970; Easton 1972). Disasters such as these could be prevented if the effects of the post-blowout loss of well control stages (uncontrolled discharge and capping) are incorporated into the shut-in procedures, and the wellbore architectures are modified accordingly. In this study, analytical models are used to simulate the loads on the wellbore during the different stages of loss of control. Capping pressure buildup during the shut-in is modeled to indicate fracture initiation points during the capping stage. Using these models, the critical capping pressure for a well is determined, and subsequent critical discharge flow rates are calculated. Fracture initiation would occur if the actual discharge flow rate is below the calculated critical discharge flow rate. A hypothetical case study using typical deepwater Gulf of Mexico (GOM) parameters is performed demonstrating the likelihood of fracture initiation during different discharge flow rates, discharge periods, and capping stack shut-in methods (single-step/“abrupt” or multistep/“incremental”). An abrupt shut-in for this case study leads to fracture initiation at approximately 8 hours after shut-in, while a five-step incremental shut-in is shown to prevent any fracture initiation during the 48 hours after the beginning of the shut-in. Reservoir depletion through longer discharge periods or higher discharge flow rates, despite the adverse environmental effect, can delay or even prevent fracture initiations during post-blowout capping. The ability to model these fracture failures enhances the understanding of wellbore integrity problems induced during loss of control situations and helps create workflows for predicting possible broaching scenarios during the post-blowout capping stage. Dimensionless plots are used to present fracture initiation for different cases—this is useful for drilling and wellbore integrity engineers for making contingency plans for dealing with loss of well control situations.
{"title":"Fracture Prevention Following Offshore Well Blowouts: Selecting the Appropriate Capping Stack Shut-In Strategy","authors":"Andreas Michael, I. Gupta","doi":"10.2118/199673-pa","DOIUrl":"https://doi.org/10.2118/199673-pa","url":null,"abstract":"\u0000 Following uncontrolled discharge during loss of well control events, fracture initiation occurring during the post-blowout capping stage can lead to reservoir fluids broaching to the seafloor. A classic example is Union Oil's 1969 oil spill in Santa Barbara Channel, where fracture initiation at various locations caused thousands of gallons per hour to broach onto the ocean floor over a month before it could be controlled (Mullineaux 1970; Easton 1972). Disasters such as these could be prevented if the effects of the post-blowout loss of well control stages (uncontrolled discharge and capping) are incorporated into the shut-in procedures, and the wellbore architectures are modified accordingly.\u0000 In this study, analytical models are used to simulate the loads on the wellbore during the different stages of loss of control. Capping pressure buildup during the shut-in is modeled to indicate fracture initiation points during the capping stage. Using these models, the critical capping pressure for a well is determined, and subsequent critical discharge flow rates are calculated. Fracture initiation would occur if the actual discharge flow rate is below the calculated critical discharge flow rate. A hypothetical case study using typical deepwater Gulf of Mexico (GOM) parameters is performed demonstrating the likelihood of fracture initiation during different discharge flow rates, discharge periods, and capping stack shut-in methods (single-step/“abrupt” or multistep/“incremental”). An abrupt shut-in for this case study leads to fracture initiation at approximately 8 hours after shut-in, while a five-step incremental shut-in is shown to prevent any fracture initiation during the 48 hours after the beginning of the shut-in. Reservoir depletion through longer discharge periods or higher discharge flow rates, despite the adverse environmental effect, can delay or even prevent fracture initiations during post-blowout capping.\u0000 The ability to model these fracture failures enhances the understanding of wellbore integrity problems induced during loss of control situations and helps create workflows for predicting possible broaching scenarios during the post-blowout capping stage. Dimensionless plots are used to present fracture initiation for different cases—this is useful for drilling and wellbore integrity engineers for making contingency plans for dealing with loss of well control situations.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/199673-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"41260724","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}
One of the critical issues that occur in many oil and gas wells is the failure of the cement sheath because of debonding from the casing string or from the formation. This results in the formation of microannuli, which can become pathways for fluid migration. Cement shrinkage during setting is regarded as one of the main causes of the formation of microannuli. In this paper, a new class of polymer-based expandable additives in the form of fibers is incorporated into the cement to compensate for shrinkage and thereby help prevent the formation of microannuli in oil and gas wells. The proposed fiber additives are made from shape-memory polymers (SMPs) and expand when exposed to temperatures above a specific value that is, by design, below the downhole temperature of the cemented zone. Fiber expansion occurs after the placement of the cement slurry but before its setting to avoid the inducement of any microfractures. As a result of the expansion of the cement paste, flow channels and fluid migration may significantly decrease while preserving the mechanical properties required for the mechanical integrity of the cement sheath. The bridging effect of fibers across individual microcracks helps control the propagation and coalescence of small fractures. Considering the inert property of the proposed additive, the water-cement ratio and its chemical properties do not need to be revisited. The measured increase in cement ductility makes the cement system more resistant to cracking. The cement expansion, fluid loss, gel strength, compressive strength, ductility, and tensile strength of the samples containing these fibers are examined using destructive and nondestructive methods, as reported here. The proposed class of expandable additives can help operators reach sustainable well integrity by increasing the contact stress at the cement–casing and the cement–formation interfaces to prevent fluid migration and the propagation of cracks.
{"title":"Smart Expandable Fiber Additive To Prevent Formation of Microannuli","authors":"L. Santos, A. D. Taleghani, Guoqiang Li","doi":"10.2118/201100-pa","DOIUrl":"https://doi.org/10.2118/201100-pa","url":null,"abstract":"\u0000 One of the critical issues that occur in many oil and gas wells is the failure of the cement sheath because of debonding from the casing string or from the formation. This results in the formation of microannuli, which can become pathways for fluid migration. Cement shrinkage during setting is regarded as one of the main causes of the formation of microannuli. In this paper, a new class of polymer-based expandable additives in the form of fibers is incorporated into the cement to compensate for shrinkage and thereby help prevent the formation of microannuli in oil and gas wells. The proposed fiber additives are made from shape-memory polymers (SMPs) and expand when exposed to temperatures above a specific value that is, by design, below the downhole temperature of the cemented zone. Fiber expansion occurs after the placement of the cement slurry but before its setting to avoid the inducement of any microfractures. As a result of the expansion of the cement paste, flow channels and fluid migration may significantly decrease while preserving the mechanical properties required for the mechanical integrity of the cement sheath. The bridging effect of fibers across individual microcracks helps control the propagation and coalescence of small fractures. Considering the inert property of the proposed additive, the water-cement ratio and its chemical properties do not need to be revisited. The measured increase in cement ductility makes the cement system more resistant to cracking. The cement expansion, fluid loss, gel strength, compressive strength, ductility, and tensile strength of the samples containing these fibers are examined using destructive and nondestructive methods, as reported here. The proposed class of expandable additives can help operators reach sustainable well integrity by increasing the contact stress at the cement–casing and the cement–formation interfaces to prevent fluid migration and the propagation of cracks.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2020-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://sci-hub-pdf.com/10.2118/201100-pa","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"43985885","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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