Mahmoud ElGizawy, Ross Lowdon, Darren Lee Aklestad
Summary A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding a collision with nearby offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying tools and technologies taken individually is insufficient. This high level of wellbore positioning accuracy is achieved by combining two independent wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic measurement-while-drilling (MWD) definitive dynamic surveys (DDS). The accuracy of the MWD DDS can be further improved by minimizing error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, the use of localized geomagnetic reference, using high-accuracy accelerometer sensors, and a high-accuracy gravity reference. Furthermore, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the rotary steerable system. A first wellbore position is calculated from the magnetic MWD DDS after applying in-field referencing (IFR), multistation analysis (MSA), bottomhole assembly (BHA), sag correction (SAG), and dual-inclination (DI) corrections to improve both azimuth and inclination accuracy. A second wellbore position is calculated using gyro-MWD (GWD) technology. The results and comparisons of multiple combined survey runs are presented. The highest accuracy of wellbore positioning had been proved in this successful case study by penetrating a very small reservoir target on an extended-reach well that was unfeasible using either the most accurate enhanced MWD DDS or GWD technology individually. The presented case study shows how the wellbore objectives of penetrating a very small reservoir target had been confirmed by logging-while-drilling images and the reservoir mapping interpretation of the client subsurface team. This gave a high-accuracy wellbore position during drilling and provided higher confidence in wellbore placement to maximize reservoir production without colliding with nearby offset wells. Wellbore survey accuracy limits a borehole’s lateral and true vertical depth (TVD) spacing, constraining reservoir production in those sections. In the top and intermediate sections, wellbore survey accuracy limits how close the wellbore can be drilled to other offset wells due to collision concerns. This directly impacts the complexity of the directional work and the cost per section. Combining independent wellbore surveys unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy that can be achieved to date
{"title":"Combining Magnetic and Gyroscopic Surveys Provides the Best Possible Accuracy","authors":"Mahmoud ElGizawy, Ross Lowdon, Darren Lee Aklestad","doi":"10.2118/212547-pa","DOIUrl":"https://doi.org/10.2118/212547-pa","url":null,"abstract":"Summary A survey program is designed for every well drilled to meet the well objective of penetrating the target reservoir and avoiding a collision with nearby offset wells. The selection of the wellbore survey tools within the survey program is limited in number and accuracy by the current surveying technologies available in the industry. This article demonstrates how a higher level of accuracy can be achieved to meet challenging well objectives when the accuracy of the most accurate wellbore surveying tools and technologies taken individually is insufficient. This high level of wellbore positioning accuracy is achieved by combining two independent wellbore positions of the same wellbore trajectory. The first wellbore position is calculated using the latest technology of magnetic measurement-while-drilling (MWD) definitive dynamic surveys (DDS). The accuracy of the MWD DDS can be further improved by minimizing error sources such as misalignment of the survey package from the borehole, drillstring magnetic interference, the use of localized geomagnetic reference, using high-accuracy accelerometer sensors, and a high-accuracy gravity reference. Furthermore, the MWD DDS inclination accuracy is improved using an independent inclination measurement from the rotary steerable system. A first wellbore position is calculated from the magnetic MWD DDS after applying in-field referencing (IFR), multistation analysis (MSA), bottomhole assembly (BHA), sag correction (SAG), and dual-inclination (DI) corrections to improve both azimuth and inclination accuracy. A second wellbore position is calculated using gyro-MWD (GWD) technology. The results and comparisons of multiple combined survey runs are presented. The highest accuracy of wellbore positioning had been proved in this successful case study by penetrating a very small reservoir target on an extended-reach well that was unfeasible using either the most accurate enhanced MWD DDS or GWD technology individually. The presented case study shows how the wellbore objectives of penetrating a very small reservoir target had been confirmed by logging-while-drilling images and the reservoir mapping interpretation of the client subsurface team. This gave a high-accuracy wellbore position during drilling and provided higher confidence in wellbore placement to maximize reservoir production without colliding with nearby offset wells. Wellbore survey accuracy limits a borehole’s lateral and true vertical depth (TVD) spacing, constraining reservoir production in those sections. In the top and intermediate sections, wellbore survey accuracy limits how close the wellbore can be drilled to other offset wells due to collision concerns. This directly impacts the complexity of the directional work and the cost per section. Combining independent wellbore surveys unlocks the potential to improve the wellbore positioning accuracy significantly. It demonstrates the highest wellbore positioning accuracy that can be achieved to date","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135298507","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}
Michael Mendez, Ramadan Ahmed, Hamidreza Karami, Mustafa Nasser, Ibnelwaleed A. Hussein, Sergio Garcia, Andres Gonzalez
Summary Machine learning (ML) has become a robust method for modeling field operations based on measurements. For example, wellbore cleanout is a critical operation that needs to be optimized to enhance the removal of solids to reduce problems associated with poor hole cleaning. However, as wellbore geometry becomes more complicated, predicting the cleaning performance of fluids becomes more challenging. As a result, optimization is often difficult. Therefore, this research focuses on developing a data-driven model for predicting hole cleaning in deviated wells to optimize drilling performance. More than 500 flow loop measurements from eight studies are used to formulate a suitable ML model to forecast hole cleanout in directional wells. Measurements were obtained from hole-cleaning experiments that were conducted using different loop configurations. Experiments ranged in test-section length from 22 to 100 ft, in hole diameter from 4 to 8 in., and in pipe diameter from 2 to 4.5 in. The experiments provided measured equilibrium bed height at a specific flow rate for various fluids, including water-based and synthetic-based fluids and fluids containing fibers. Several relevant test parameters, including fluid and cutting properties, well inclination, and drillstring rotation speed (drillpipe rev/min), were also considered in the analysis. The collected data have been analyzed using the Cross-Industry Standard Process for Data Mining. This paper is unique because it systematically evaluates various ML models for their ability to describe hole cleanout processes. Six different ML techniques: boosted decision tree (BDT), random forest (RF), linear regression, multivariate adaptive regression spline (MARS), neural networks, and support vector machine (SVM) have been evaluated to select the most appropriate method for predicting bed thickness in a wellbore. Also, we compared the predictions of the selected ML method with those of a mechanistic model for cases without drillstring rotation. Finally, using the ML model, a parametric study has been conducted to examine the impact of various parameters on the cleanout performance of selected fluids. The results show the relative influence of different variables on the prediction of cuttings bed. Accordingly, flow rate, drillpipe rev/min, and fluid behavior index have a strong impact on dimensionless bed thickness, while other parameters such as fluid consistency index, solids density and diameter, fiber concentration, and well inclination angle have a moderate effect. The BDT algorithm has provided the most accurate prediction with an R2 of 92%, a root-mean-square error (RMSE) of 0.06, and a mean absolute error (MAE) of roughly 0.05. A comparison between a mechanistic model and the selected ML technique shows that the ML model provided better predictions.
{"title":"Applications of Machine Learning Methods to Predict Hole Cleaning in Horizontal and Highly Deviated Wells","authors":"Michael Mendez, Ramadan Ahmed, Hamidreza Karami, Mustafa Nasser, Ibnelwaleed A. Hussein, Sergio Garcia, Andres Gonzalez","doi":"10.2118/212912-pa","DOIUrl":"https://doi.org/10.2118/212912-pa","url":null,"abstract":"Summary Machine learning (ML) has become a robust method for modeling field operations based on measurements. For example, wellbore cleanout is a critical operation that needs to be optimized to enhance the removal of solids to reduce problems associated with poor hole cleaning. However, as wellbore geometry becomes more complicated, predicting the cleaning performance of fluids becomes more challenging. As a result, optimization is often difficult. Therefore, this research focuses on developing a data-driven model for predicting hole cleaning in deviated wells to optimize drilling performance. More than 500 flow loop measurements from eight studies are used to formulate a suitable ML model to forecast hole cleanout in directional wells. Measurements were obtained from hole-cleaning experiments that were conducted using different loop configurations. Experiments ranged in test-section length from 22 to 100 ft, in hole diameter from 4 to 8 in., and in pipe diameter from 2 to 4.5 in. The experiments provided measured equilibrium bed height at a specific flow rate for various fluids, including water-based and synthetic-based fluids and fluids containing fibers. Several relevant test parameters, including fluid and cutting properties, well inclination, and drillstring rotation speed (drillpipe rev/min), were also considered in the analysis. The collected data have been analyzed using the Cross-Industry Standard Process for Data Mining. This paper is unique because it systematically evaluates various ML models for their ability to describe hole cleanout processes. Six different ML techniques: boosted decision tree (BDT), random forest (RF), linear regression, multivariate adaptive regression spline (MARS), neural networks, and support vector machine (SVM) have been evaluated to select the most appropriate method for predicting bed thickness in a wellbore. Also, we compared the predictions of the selected ML method with those of a mechanistic model for cases without drillstring rotation. Finally, using the ML model, a parametric study has been conducted to examine the impact of various parameters on the cleanout performance of selected fluids. The results show the relative influence of different variables on the prediction of cuttings bed. Accordingly, flow rate, drillpipe rev/min, and fluid behavior index have a strong impact on dimensionless bed thickness, while other parameters such as fluid consistency index, solids density and diameter, fiber concentration, and well inclination angle have a moderate effect. The BDT algorithm has provided the most accurate prediction with an R2 of 92%, a root-mean-square error (RMSE) of 0.06, and a mean absolute error (MAE) of roughly 0.05. A comparison between a mechanistic model and the selected ML technique shows that the ML model provided better predictions.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136184745","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}
Veerabhadra S. Denduluri, George Ulerio, Moneeb Genedy, Maria Juenger, Eric van Oort
Summary With recurrent calls for a reduction in carbon emissions, geothermal (GT) energy has received increasing attention in recent years as a prominent source of clean energy. With current drilling technology, GT wells are being constructed in extremely challenging temperature environments, which could reach more than 600°F (315°C) in situ. However, GT well-cementing technology has not changed much over the past few decades, with ordinary Portland cement (OPC) still being the primary choice of cementing material. OPC has several drawbacks, including brittle behavior, shrinkage upon setting, poor bond strength to formation and casing, susceptibility to an acid gas attack, temperature-induced strength retrogression, and low tolerance toward drilling fluid contamination. These factors could lead to a poor cementing job, thus compromising well integrity and not ensuring proper zonal isolation for the life of the GT well. Thus, there is a need to develop an alternative material that is compatible with the GT environment and able to provide long-term zonal isolation. With a low carbon footprint, self-healing ability, and low shrinkage sensitivity, geopolymers or alkali-activated materials could be a suitable option to augment or even replace OPC. Some of the previous studies on geopolymers have shown that they could be a potential candidate for oil and gas well cementing and civil engineering applications, with some being stable at very high temperatures [up to 1,470°F (800°C)]. Geopolymers are formed by mixing an aluminosilicate source such as fly ash (FA) with an alkali-activating solution, such as sodium or potassium hydroxide or silicate. The aim of the study reported here is to demonstrate the applicability of geopolymers for GT well cementing. An experimental investigation was carried out to understand the behavior of geopolymer formulations made from FA, metakaolin (MK), and blast furnace slag in a high-temperature environment. The material properties such as porosity, viscosity, thickening/pump time, compressive strength, tensile strength, and bond strength were tested in the laboratory. It was found that geopolymer can be formulated to have the desired rheological properties with adequate pump time and resistance to drilling fluid contamination. In addition, the formulations can exceed the required compressive and tensile strength for GT cementing operations, while obtaining excellent bond strength values. These findings indicate that geopolymers are well-suited to provide long-term zonal isolation in high-temperature GT wells.
{"title":"Experimental Investigation of Geopolymers for Application in High-Temperature and Geothermal Well Cementing","authors":"Veerabhadra S. Denduluri, George Ulerio, Moneeb Genedy, Maria Juenger, Eric van Oort","doi":"10.2118/212491-pa","DOIUrl":"https://doi.org/10.2118/212491-pa","url":null,"abstract":"Summary With recurrent calls for a reduction in carbon emissions, geothermal (GT) energy has received increasing attention in recent years as a prominent source of clean energy. With current drilling technology, GT wells are being constructed in extremely challenging temperature environments, which could reach more than 600°F (315°C) in situ. However, GT well-cementing technology has not changed much over the past few decades, with ordinary Portland cement (OPC) still being the primary choice of cementing material. OPC has several drawbacks, including brittle behavior, shrinkage upon setting, poor bond strength to formation and casing, susceptibility to an acid gas attack, temperature-induced strength retrogression, and low tolerance toward drilling fluid contamination. These factors could lead to a poor cementing job, thus compromising well integrity and not ensuring proper zonal isolation for the life of the GT well. Thus, there is a need to develop an alternative material that is compatible with the GT environment and able to provide long-term zonal isolation. With a low carbon footprint, self-healing ability, and low shrinkage sensitivity, geopolymers or alkali-activated materials could be a suitable option to augment or even replace OPC. Some of the previous studies on geopolymers have shown that they could be a potential candidate for oil and gas well cementing and civil engineering applications, with some being stable at very high temperatures [up to 1,470°F (800°C)]. Geopolymers are formed by mixing an aluminosilicate source such as fly ash (FA) with an alkali-activating solution, such as sodium or potassium hydroxide or silicate. The aim of the study reported here is to demonstrate the applicability of geopolymers for GT well cementing. An experimental investigation was carried out to understand the behavior of geopolymer formulations made from FA, metakaolin (MK), and blast furnace slag in a high-temperature environment. The material properties such as porosity, viscosity, thickening/pump time, compressive strength, tensile strength, and bond strength were tested in the laboratory. It was found that geopolymer can be formulated to have the desired rheological properties with adequate pump time and resistance to drilling fluid contamination. In addition, the formulations can exceed the required compressive and tensile strength for GT cementing operations, while obtaining excellent bond strength values. These findings indicate that geopolymers are well-suited to provide long-term zonal isolation in high-temperature GT wells.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-04-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136222941","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}
Summary Because the use of adaptive drilling processes, such as managed pressure drilling (MPD), facilitate drilling of otherwise nondrillable wells with faster corrective action, the drilling industry should include the effect of gas dispersion, bubble suspension, fluid compressibility, and riser ballooning to avoid the overestimation of riser pressure and to produce more efficient well control methods. The IADC Deepwater Well Control Guideline recommends always addressing riser gas first, before proceeding to control the well in a well control situation. The intent is to remove the risk of gas reaching the surface and the rig floor, putting personnel and assets at risk. However, with the availability of equipment on the rig dedicated to handling riser gas and the fact that the riser is isolated from the wellbore, the atmosphere reduces the level of risk of gas in the riser, whereas the well below the subsea blowout preventer (SSBOP) poses a greater risk. In this paper, we discuss the results from full-scale experiments recently conducted in an extensively instrumented test well (LSU Well-2) and demonstrate that the riser pressures resulting from upward transport or aggregation of riser gas are much lower than the values estimated using the single-bubble model and industry thumb rules. We explain the danger of using an open-top riser top during the monitoring of gas-in-riser and how the situation can get out of control due to the potential dynamic unloading situation. Our research also demonstrates the minimal fluid bleedoff volumes required to reduce pressure buildup consequences of free gas migration in a fully closed riser containing low-compressibility liquid. A differential pressure methodology used in this paper for analysis was also used for detecting the presence, position, void fraction, and lead and tail velocity of the gas column in real time during each of the tests to make decisions during the tests. The results from a successful application of the fixed choke constant outflow (FCCO) method as a new method for circulating out gas from the riser by staying within the gas-handling capacity of the existing mud gas separator (MGS) on the rig are presented. This is the industry’s first test of the FCCO method.
{"title":"Analysis of Riser Gas Pressure from Full-Scale Gas-in-Riser Experiments with Instrumentation","authors":"Mahendra R. Kunju, Mauricio A. Almeida","doi":"10.2118/206389-pa","DOIUrl":"https://doi.org/10.2118/206389-pa","url":null,"abstract":"Summary Because the use of adaptive drilling processes, such as managed pressure drilling (MPD), facilitate drilling of otherwise nondrillable wells with faster corrective action, the drilling industry should include the effect of gas dispersion, bubble suspension, fluid compressibility, and riser ballooning to avoid the overestimation of riser pressure and to produce more efficient well control methods. The IADC Deepwater Well Control Guideline recommends always addressing riser gas first, before proceeding to control the well in a well control situation. The intent is to remove the risk of gas reaching the surface and the rig floor, putting personnel and assets at risk. However, with the availability of equipment on the rig dedicated to handling riser gas and the fact that the riser is isolated from the wellbore, the atmosphere reduces the level of risk of gas in the riser, whereas the well below the subsea blowout preventer (SSBOP) poses a greater risk. In this paper, we discuss the results from full-scale experiments recently conducted in an extensively instrumented test well (LSU Well-2) and demonstrate that the riser pressures resulting from upward transport or aggregation of riser gas are much lower than the values estimated using the single-bubble model and industry thumb rules. We explain the danger of using an open-top riser top during the monitoring of gas-in-riser and how the situation can get out of control due to the potential dynamic unloading situation. Our research also demonstrates the minimal fluid bleedoff volumes required to reduce pressure buildup consequences of free gas migration in a fully closed riser containing low-compressibility liquid. A differential pressure methodology used in this paper for analysis was also used for detecting the presence, position, void fraction, and lead and tail velocity of the gas column in real time during each of the tests to make decisions during the tests. The results from a successful application of the fixed choke constant outflow (FCCO) method as a new method for circulating out gas from the riser by staying within the gas-handling capacity of the existing mud gas separator (MGS) on the rig are presented. This is the industry’s first test of the FCCO method.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-22","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136195775","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}
Summary Studies have shown that achieving a consistent perforation hole size in casing (i.e., entry hole) and zero-phase perforation gun orientation led to improved treatment distribution among multiple perforation clusters in plug-and-perf limited entry treatments. In addition to reducing variation in the perforation entry hole by establishing uniformity in gun clearance and the angle of incidence of the perforation jet at the wall of the casing, oriented perforating has been shown to minimize the tendency of proppant to separate from the fracturing fluid while traveling across the perforated intervals (inertial effect) and mitigate nonuniform entry hole erosion due to gravity-induced proppant stratification. The primary goal of this study was to determine the controllable perforating gun elements and accessories that effect the accuracy of gun orientation and entry hole dimensions. Surface tests were conducted at manufacturing facilities for determining the characteristics of the entry holes in pipe produced by shaped explosive charges using various system configurations and the robustness of various gun orientation devices. Promising perforating systems were then used in wellbores to create calibration entry holes (downhole tests) that were measured for equivalent diameter and orientation accuracy using high-resolution acoustic imaging before conducting treatments. This process enabled components of the perforating system influencing entry hole size and gun orientation to be evaluated and modified, as necessary. Elements of the perforating system and downhole environment that influenced entry hole size and consistency included casing type, cement sheath characteristics, perforating gun clearance and orientation, perforating charge type and density, packing arrangement of multiple charges, charge tube and charge carrier design, gun detonation system, hydrostatic pressure, and locking devices. Achieving tight control of these elements significantly reduced variation in entry hole size. Deviations from surface and downhole testing results were commonly attributed to using perforating system elements in the field that differed from those used by the manufacturer in surface testing. Factors affecting gun orientation accuracy and consistency included weight bar type, gun string length, weight, and stiffness, the presence of modified standoff bands, progressive gun deformation during firing, wellbore tortuosity, and self-orienting devices. Several orientation systems were found that achieved orientation within the target 20°-window. To assess the value of this workflow process, the paper includes information on the results of diagnostic tests for evaluating the accuracy of the ultrasonic measuring device, the derivation process used for determining coefficients for a two-component perforation erosion model, and the use of the derived erosion rate coefficients for computing the mass of proppant that enters each perforation and perforation cluster duri
{"title":"Correlating Surface and Downhole Perforation Entry Hole Measurements Leads to Development of Improved Perforating Systems","authors":"David Cramer, Matt White, Cody Douglas","doi":"10.2118/212335-pa","DOIUrl":"https://doi.org/10.2118/212335-pa","url":null,"abstract":"Summary Studies have shown that achieving a consistent perforation hole size in casing (i.e., entry hole) and zero-phase perforation gun orientation led to improved treatment distribution among multiple perforation clusters in plug-and-perf limited entry treatments. In addition to reducing variation in the perforation entry hole by establishing uniformity in gun clearance and the angle of incidence of the perforation jet at the wall of the casing, oriented perforating has been shown to minimize the tendency of proppant to separate from the fracturing fluid while traveling across the perforated intervals (inertial effect) and mitigate nonuniform entry hole erosion due to gravity-induced proppant stratification. The primary goal of this study was to determine the controllable perforating gun elements and accessories that effect the accuracy of gun orientation and entry hole dimensions. Surface tests were conducted at manufacturing facilities for determining the characteristics of the entry holes in pipe produced by shaped explosive charges using various system configurations and the robustness of various gun orientation devices. Promising perforating systems were then used in wellbores to create calibration entry holes (downhole tests) that were measured for equivalent diameter and orientation accuracy using high-resolution acoustic imaging before conducting treatments. This process enabled components of the perforating system influencing entry hole size and gun orientation to be evaluated and modified, as necessary. Elements of the perforating system and downhole environment that influenced entry hole size and consistency included casing type, cement sheath characteristics, perforating gun clearance and orientation, perforating charge type and density, packing arrangement of multiple charges, charge tube and charge carrier design, gun detonation system, hydrostatic pressure, and locking devices. Achieving tight control of these elements significantly reduced variation in entry hole size. Deviations from surface and downhole testing results were commonly attributed to using perforating system elements in the field that differed from those used by the manufacturer in surface testing. Factors affecting gun orientation accuracy and consistency included weight bar type, gun string length, weight, and stiffness, the presence of modified standoff bands, progressive gun deformation during firing, wellbore tortuosity, and self-orienting devices. Several orientation systems were found that achieved orientation within the target 20°-window. To assess the value of this workflow process, the paper includes information on the results of diagnostic tests for evaluating the accuracy of the ultrasonic measuring device, the derivation process used for determining coefficients for a two-component perforation erosion model, and the use of the derived erosion rate coefficients for computing the mass of proppant that enters each perforation and perforation cluster duri","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"136156450","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}
W. Watson, F. Dupriest, Y. Witt-Doerring, P. Pastusek, J. Sugiura, R. Procter, D. Daechsel, R. Abbas, D. Shackleton, M. Amish
Summary This paper establishes uniform recommended industry practices for photo documentation of polycrystalline diamond compact (PDC) bits and bottomhole assemblies (BHAs). These recommended practices were developed by a subcommittee of the joint International Association of Drilling Contactors (IADC)/Society of Petroleum Engineers (SPE) industry in an effort to upgrade the IADC dull grading practices. Effective field photographic documentation and training to identify the causes of damage enables the team to modify parameters used and make other immediate changes in the BHA/drilling system with a higher degree of confidence that they will increase drill rate or extend bit life. The field documentation also provides the basis for more detailed post-drill shop grading and extensive redesign, if needed. The recommended photographic documentation consists of a specific set of photos of each blade, a top view, a side view, and views of each contact point in the BHA (i.e., kick pads, stabilizer blades, and reamers). It is common for rigsite teams to take photos of bits pulled, but these have not historically provided the detail required to distinguish one potential cause from another. There are proven changes in practices or BHA configuration that can be made to mitigate each type of dysfunction, but this cannot occur unless the cause is identified correctly. Appropriate photographic documentation, when coupled along with an understanding of the different PDC cutter and bit damage mechanisms which may occur, enables the rigsite team to identify the dysfunction and implement the changes needed. While other data sources, such as digital drilling data, should be analyzed to estimate the event timing and confirm the cause, the damage that is observed in the photographic documentation plays a critical role in directing the actual redesign effort. For example, downhole accelerometer data may indicate the presence of BHA whirl, but whether this damages the bit in a given situation is dependent on formation hardness and other factors. Whirl may not be the priority of redesign unless the photographic documentation shows a pattern of damage that is known to be specifically due to BHA whirl. These photographic documentation practices were developed specifically to support drilling forensics. The guidelines were compiled from the practices of multiple operators, bit manufacturers, and service companies with significant experience in utilizing similar photographic documentation to support timely rigsite decisions. The photographic documentation is not complex and experience has shown that within a short period of training and daily discussions, the collection of high-quality photos becomes a routine, sustainable practice. To obtain the greatest value from photographic documentation, operators must also develop training for field personnel in how to recognize the dysfunction that caused the damage. This document is intended to both standardize field photographic d
{"title":"IADC Code Upgrade: PDC Bit and BHA Forensics Using Rig-Based Photographic Documentation Practices","authors":"W. Watson, F. Dupriest, Y. Witt-Doerring, P. Pastusek, J. Sugiura, R. Procter, D. Daechsel, R. Abbas, D. Shackleton, M. Amish","doi":"10.2118/208707-pa","DOIUrl":"https://doi.org/10.2118/208707-pa","url":null,"abstract":"Summary This paper establishes uniform recommended industry practices for photo documentation of polycrystalline diamond compact (PDC) bits and bottomhole assemblies (BHAs). These recommended practices were developed by a subcommittee of the joint International Association of Drilling Contactors (IADC)/Society of Petroleum Engineers (SPE) industry in an effort to upgrade the IADC dull grading practices. Effective field photographic documentation and training to identify the causes of damage enables the team to modify parameters used and make other immediate changes in the BHA/drilling system with a higher degree of confidence that they will increase drill rate or extend bit life. The field documentation also provides the basis for more detailed post-drill shop grading and extensive redesign, if needed. The recommended photographic documentation consists of a specific set of photos of each blade, a top view, a side view, and views of each contact point in the BHA (i.e., kick pads, stabilizer blades, and reamers). It is common for rigsite teams to take photos of bits pulled, but these have not historically provided the detail required to distinguish one potential cause from another. There are proven changes in practices or BHA configuration that can be made to mitigate each type of dysfunction, but this cannot occur unless the cause is identified correctly. Appropriate photographic documentation, when coupled along with an understanding of the different PDC cutter and bit damage mechanisms which may occur, enables the rigsite team to identify the dysfunction and implement the changes needed. While other data sources, such as digital drilling data, should be analyzed to estimate the event timing and confirm the cause, the damage that is observed in the photographic documentation plays a critical role in directing the actual redesign effort. For example, downhole accelerometer data may indicate the presence of BHA whirl, but whether this damages the bit in a given situation is dependent on formation hardness and other factors. Whirl may not be the priority of redesign unless the photographic documentation shows a pattern of damage that is known to be specifically due to BHA whirl. These photographic documentation practices were developed specifically to support drilling forensics. The guidelines were compiled from the practices of multiple operators, bit manufacturers, and service companies with significant experience in utilizing similar photographic documentation to support timely rigsite decisions. The photographic documentation is not complex and experience has shown that within a short period of training and daily discussions, the collection of high-quality photos becomes a routine, sustainable practice. To obtain the greatest value from photographic documentation, operators must also develop training for field personnel in how to recognize the dysfunction that caused the damage. This document is intended to both standardize field photographic d","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-02-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135006661","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}
Jibin Shi, Laetitia Dourthe, Denis Li, Li Deng, Leonardo Louback, Fei Song, Nick Abolins, Fernando Verano, Pusheng Zhang, Joshua Groover, Diego Gomez Falla, Ke Li
Summary In hole enlargement while drilling (HEWD) operations, underreamers are used extensively to enlarge the pilot hole. Reamer wipeout failure can cause additional bottomhole assembly (BHA) trips, which can cost operators millions of dollars. Excessive reamer shock and vibration are leading causes of reamer wipeout; therefore, careful monitoring of reamer vibration is important in mitigating such a risk. Currently, downhole vibration sensors and drilling dynamics simulations (DDSs) are used to comprehend and reduce downhole vibration, but vibration sensors cannot be placed exactly at the reamer to monitor the vibrations in real time. DDSs are difficult to calibrate and are computationally expensive for use in real time; therefore, the real-time reamer vibration status is typically unknown during drilling operations. A process digital twin using a hybrid modeling approach is proposed and tested to address the vibration issue. Large amounts of field data are used in advanced DDSs to calibrate the HEWD runs. For each HEWD section, calibrated DDSs are performed to comprehend the downhole vibration at the reamer and downhole vibration sensors. A surrogate regression model between reamer vibration and sensor vibration is built using machine learning. This surrogate model is implemented in a drilling monitoring software platform as a process digital twin. During drilling, the surrogate model uses downhole measurement while drilling (MWD) data as inputs to predict reamer vibration. Wipeout risk levels are calculated and sent to the operators for real-time decision-making to reduce the possibility of reamer wipeout. Large volumes of reamer field data, including field recorded vibration and reamer dull conditions were used to validate the digital twin workflow. Then, the process digital twin was implemented and tested in two reamer runs in the Gulf of Mexico. A downhole high-frequency sensor was placed 8 ft above the reamer cutting structure in one field run, and the recorded sensor vibration data and corresponding reamer dull conditions showed a very good match with the real-time digital twin predictions in a low-vibration scenario. Cases in high vibration are needed to fully validate the feasibility and accuracy of the digital twin. State-of-the-art downhole sensors, DDS packages, large amounts of field data, and a hybrid approach are the solutions to building, calibrating, and field testing the reamer digital twin to ensure its effectiveness and accuracy. Such a hybrid modeling approach can not only be applied to reamers but also to other critical BHA components.
{"title":"Real-Time Underreamer Vibration Predicting, Monitoring, and Decision-Making Using Hybrid Modeling and a Process Digital Twin","authors":"Jibin Shi, Laetitia Dourthe, Denis Li, Li Deng, Leonardo Louback, Fei Song, Nick Abolins, Fernando Verano, Pusheng Zhang, Joshua Groover, Diego Gomez Falla, Ke Li","doi":"10.2118/208795-pa","DOIUrl":"https://doi.org/10.2118/208795-pa","url":null,"abstract":"Summary In hole enlargement while drilling (HEWD) operations, underreamers are used extensively to enlarge the pilot hole. Reamer wipeout failure can cause additional bottomhole assembly (BHA) trips, which can cost operators millions of dollars. Excessive reamer shock and vibration are leading causes of reamer wipeout; therefore, careful monitoring of reamer vibration is important in mitigating such a risk. Currently, downhole vibration sensors and drilling dynamics simulations (DDSs) are used to comprehend and reduce downhole vibration, but vibration sensors cannot be placed exactly at the reamer to monitor the vibrations in real time. DDSs are difficult to calibrate and are computationally expensive for use in real time; therefore, the real-time reamer vibration status is typically unknown during drilling operations. A process digital twin using a hybrid modeling approach is proposed and tested to address the vibration issue. Large amounts of field data are used in advanced DDSs to calibrate the HEWD runs. For each HEWD section, calibrated DDSs are performed to comprehend the downhole vibration at the reamer and downhole vibration sensors. A surrogate regression model between reamer vibration and sensor vibration is built using machine learning. This surrogate model is implemented in a drilling monitoring software platform as a process digital twin. During drilling, the surrogate model uses downhole measurement while drilling (MWD) data as inputs to predict reamer vibration. Wipeout risk levels are calculated and sent to the operators for real-time decision-making to reduce the possibility of reamer wipeout. Large volumes of reamer field data, including field recorded vibration and reamer dull conditions were used to validate the digital twin workflow. Then, the process digital twin was implemented and tested in two reamer runs in the Gulf of Mexico. A downhole high-frequency sensor was placed 8 ft above the reamer cutting structure in one field run, and the recorded sensor vibration data and corresponding reamer dull conditions showed a very good match with the real-time digital twin predictions in a low-vibration scenario. Cases in high vibration are needed to fully validate the feasibility and accuracy of the digital twin. State-of-the-art downhole sensors, DDS packages, large amounts of field data, and a hybrid approach are the solutions to building, calibrating, and field testing the reamer digital twin to ensure its effectiveness and accuracy. Such a hybrid modeling approach can not only be applied to reamers but also to other critical BHA components.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2023-01-06","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134968609","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}
Genaro Bolívar, J. Aburto, J. Soltero, E. Mendizábal
The formulation of antiaccretion additives for cleaning the hole in long-range directional or tangential wells in heavy and extraheavy oil reservoirs is considered a technological challenge due to the unconsolidated characteristics of the formations (such as gravel, sand, pea, etc.) as well as the physicochemical properties of the heavy crude oil. In this work, we propose a hole cleaning formulation that can solubilize the asphaltenes present in Mexican heavy crude oil and that is also efficient in eliminating the accretion due to heavy oil fractions. Alkyl-o-glucoside (APG) whose alkyl group has 12 carbons was used as the biosurfactant. The addition of the cosurfactant ethylene glycol butyl ether (EGBE) to the aqueous solution of APG reduced its surface tension. The aqueous APG solutions were able to solubilize the asphaltenes inside the micelles. The addition of EGBE increased the stability of the aspahltenes/APG/water emulsion. The APG/EGBE/Limonene antiaccretion additive proposed in this work for the mobilization of the trapped nonaqueous phase liquid showed a higher cleaning efficiency factor (CEF) than conventional diluents. Higher cleaning efficiency was obtained when the test temperature was increased.
{"title":"Two Environmentally Friendly Alkyl-o-Glucoside-Based Formulations for Hole Cleaning during Heavy and Extra-Heavy Oilfield Drilling","authors":"Genaro Bolívar, J. Aburto, J. Soltero, E. Mendizábal","doi":"10.2118/209200-pa","DOIUrl":"https://doi.org/10.2118/209200-pa","url":null,"abstract":"\u0000 The formulation of antiaccretion additives for cleaning the hole in long-range directional or tangential wells in heavy and extraheavy oil reservoirs is considered a technological challenge due to the unconsolidated characteristics of the formations (such as gravel, sand, pea, etc.) as well as the physicochemical properties of the heavy crude oil. In this work, we propose a hole cleaning formulation that can solubilize the asphaltenes present in Mexican heavy crude oil and that is also efficient in eliminating the accretion due to heavy oil fractions. Alkyl-o-glucoside (APG) whose alkyl group has 12 carbons was used as the biosurfactant. The addition of the cosurfactant ethylene glycol butyl ether (EGBE) to the aqueous solution of APG reduced its surface tension. The aqueous APG solutions were able to solubilize the asphaltenes inside the micelles. The addition of EGBE increased the stability of the aspahltenes/APG/water emulsion. The APG/EGBE/Limonene antiaccretion additive proposed in this work for the mobilization of the trapped nonaqueous phase liquid showed a higher cleaning efficiency factor (CEF) than conventional diluents. Higher cleaning efficiency was obtained when the test temperature was increased.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"49113847","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}
Shubham Mishra, C. Fredd, D. Willberg, Umur Yanbollu
Low recovery, 2 to 15%, in unconventional plays (including tight reservoirs and source rocks) has long been recognized as a business deterrent. The industry applies enhanced oil recovery (EOR) techniques, along with hydraulic fractures in tight/unconventional plays, to improve the recovery. To maximize matrix sweep, the fractures are aligned in a face-to-face assembly. Such an arrangement can be achieved using a vertical or longitudinal hydraulic fracture on horizontal wells, but these, generally, do not provide as effective reservoir contact (hydraulic fracture surface area) as horizontal wells with multistage transverse hydraulic fractures. The multistage transverse hydraulic fracture, however, comes at the costs of conformance issues with early water breakthrough from short-circuiting and inability to achieve fracture face-to-fracture face alignment of the injection and production fractures. The vast majority of wells drilled in unconventional plays are in the transverse configuration; hence, there is a need for an optimal solution for transverse fractures combined with improved oil recovery (IOR)/EOR approaches. In this work, we introduce the multistage enhanced recovery (MS-ER) techniques that enable face-to-face alignment for optimal enhanced hydrocarbon recovery (EHR)/IOR/EOR in horizontal wells with multistage transverse fractures, thereby enabling optimal recovery and mitigating the key risk of fracture short-circuiting.
{"title":"Completion Designs in Horizontal Well with Transverse Hydraulic Fractures for Enhanced Recovery in Unconventional or Tight Reservoirs","authors":"Shubham Mishra, C. Fredd, D. Willberg, Umur Yanbollu","doi":"10.2118/206368-pa","DOIUrl":"https://doi.org/10.2118/206368-pa","url":null,"abstract":"\u0000 Low recovery, 2 to 15%, in unconventional plays (including tight reservoirs and source rocks) has long been recognized as a business deterrent. The industry applies enhanced oil recovery (EOR) techniques, along with hydraulic fractures in tight/unconventional plays, to improve the recovery. To maximize matrix sweep, the fractures are aligned in a face-to-face assembly. Such an arrangement can be achieved using a vertical or longitudinal hydraulic fracture on horizontal wells, but these, generally, do not provide as effective reservoir contact (hydraulic fracture surface area) as horizontal wells with multistage transverse hydraulic fractures. The multistage transverse hydraulic fracture, however, comes at the costs of conformance issues with early water breakthrough from short-circuiting and inability to achieve fracture face-to-fracture face alignment of the injection and production fractures. The vast majority of wells drilled in unconventional plays are in the transverse configuration; hence, there is a need for an optimal solution for transverse fractures combined with improved oil recovery (IOR)/EOR approaches.\u0000 In this work, we introduce the multistage enhanced recovery (MS-ER) techniques that enable face-to-face alignment for optimal enhanced hydrocarbon recovery (EHR)/IOR/EOR in horizontal wells with multistage transverse fractures, thereby enabling optimal recovery and mitigating the key risk of fracture short-circuiting.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2022-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48356138","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}
Lost circulation materials (LCMs) are essential to combat fluid loss while drilling and may put the whole operation at risk if a proper LCM design is not used. The focus of this research is understanding the function of LCMs in sealing fractures to reduce fluid loss. One important consideration in the success of fracture sealing is the particle-size distribution (PSD) of LCMs. Various studies have suggested different guidelines for obtaining the best size distribution of LCMs for effective fracture sealing based on limited laboratory experiments or field observations. Hence, there is a need for sophisticated numerical methods to improve the LCM design by providing some predictive capabilities. In this study, computational fluid dynamics (CFD) and discrete element methods (DEM) numerical simulations are coupled to investigate the influence of PSD of granular LCMs on fracture sealing. Dimensionless variables were introduced to compare cases with different PSDs. We validated the CFD-DEM model in reproducing specific laboratory observations of fracture-sealing experiments within the model boundary parameters. Our simulations suggested that a bimodally distributed blend would be the most effective design in comparison to other PSDs tested here.
{"title":"Assessment of Lost Circulation Material Particle-Size Distribution on Fracture Sealing: A Numerical Study","authors":"L. Lee, A. Dahi Taleghani","doi":"10.2118/209201-pa","DOIUrl":"https://doi.org/10.2118/209201-pa","url":null,"abstract":"\u0000 Lost circulation materials (LCMs) are essential to combat fluid loss while drilling and may put the whole operation at risk if a proper LCM design is not used. The focus of this research is understanding the function of LCMs in sealing fractures to reduce fluid loss. One important consideration in the success of fracture sealing is the particle-size distribution (PSD) of LCMs. Various studies have suggested different guidelines for obtaining the best size distribution of LCMs for effective fracture sealing based on limited laboratory experiments or field observations. Hence, there is a need for sophisticated numerical methods to improve the LCM design by providing some predictive capabilities. In this study, computational fluid dynamics (CFD) and discrete element methods (DEM) numerical simulations are coupled to investigate the influence of PSD of granular LCMs on fracture sealing. Dimensionless variables were introduced to compare cases with different PSDs. We validated the CFD-DEM model in reproducing specific laboratory observations of fracture-sealing experiments within the model boundary parameters. Our simulations suggested that a bimodally distributed blend would be the most effective design in comparison to other PSDs tested here.","PeriodicalId":51165,"journal":{"name":"SPE Drilling & Completion","volume":null,"pages":null},"PeriodicalIF":1.4,"publicationDate":"2022-01-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"48955805","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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