T. Akhmetov, J. Barreiro, Carl Johnson, J. Knowles
An operator had a need to cement a 13⅜-in. casing to act as a secondary barrier against a reservoir with the top of cement 100 m above a sand formation. In a subsequent section, the operator required installing and cementing a 9⅝-in. liner as the primary barrier element prior to drilling into the reservoir and placing the top of cement up to the 13 ⅜-in. casing shoe. The operation required placing a minimum 30 m of isolating cement in the cemented interval, where verification of the barrier was to be obtained by using logging tools. To comprehend the operating environment the cement would experience, it was necessary to determine an optimal cement system for the anticipated pressure and temperature cycles in the well. The service company performed a cement integrity evaluation using specialized cement sheath stress analysis software. The simulation software determined which cement system was best suited for exposure to the anticipated pressure and temperature cycles during injection and production. Based on the simulation results, the operator decided to use an environmentally compliant flexible (ECF) cement system. This novel system also significantly reduced the CO2 emissions (CO2e) footprint vs. conventional cement. The operator drilled the 17½-in. open hole to 1888 m measured depth (MD) without any issues using a proprietary flat rheology drilling fluid system. A total of 18.9 m3 of 1.60 specific gravity (SG) ECF cement slurry was pumped. During displacement, no losses were observed as the spacer entered the annulus, and consistent lift pressure was observed as the cement entered the annulus. The job signature pressure match conducted using proprietary zonal isolation software indicated that the openhole size was near gauge hole. The 12¼-in. open hole was drilled, and the 9⅝-in. liner was successfully run to total depth without incident. A total of 16.1 m3 of 1.60 SG ECF cement slurry was pumped. No losses were observed during the cementing operation, and consistent lift pressure was recorded during displacement. The liner was logged using ultrasonic imaging tools, with the top-of-cement bond identified at the 13⅜-in. casing shoe with a total 248 m of isolating cement. The operation achieved the required isolation to install the cemented liner as the primary barrier element prior to drilling into the reservoir, in addition to the exceptional logging results. The ECF cement system provided outstanding bond quality from 1882 to 2130 m. Remarkably, as an energy transition technology when compared with a conventional foamed cement system, the ECF cement system reduced CO2 emissions by 44% and simplified the operation by eliminating the use of foamed cement. Furthermore, the ECF cement is environmentally rated as PLONOR (poses little or no risk) and eliminates the use of polymeric materials to impart flexibility.
{"title":"Environmentally Compliant Flexible Cement System Achieves Customer Zonal Isolation Objectives: A Case History from the Norwegian Continental Shelf","authors":"T. Akhmetov, J. Barreiro, Carl Johnson, J. Knowles","doi":"10.2118/212474-ms","DOIUrl":"https://doi.org/10.2118/212474-ms","url":null,"abstract":"An operator had a need to cement a 13⅜-in. casing to act as a secondary barrier against a reservoir with the top of cement 100 m above a sand formation. In a subsequent section, the operator required installing and cementing a 9⅝-in. liner as the primary barrier element prior to drilling into the reservoir and placing the top of cement up to the 13 ⅜-in. casing shoe. The operation required placing a minimum 30 m of isolating cement in the cemented interval, where verification of the barrier was to be obtained by using logging tools. To comprehend the operating environment the cement would experience, it was necessary to determine an optimal cement system for the anticipated pressure and temperature cycles in the well. The service company performed a cement integrity evaluation using specialized cement sheath stress analysis software. The simulation software determined which cement system was best suited for exposure to the anticipated pressure and temperature cycles during injection and production. Based on the simulation results, the operator decided to use an environmentally compliant flexible (ECF) cement system. This novel system also significantly reduced the CO2 emissions (CO2e) footprint vs. conventional cement. The operator drilled the 17½-in. open hole to 1888 m measured depth (MD) without any issues using a proprietary flat rheology drilling fluid system. A total of 18.9 m3 of 1.60 specific gravity (SG) ECF cement slurry was pumped. During displacement, no losses were observed as the spacer entered the annulus, and consistent lift pressure was observed as the cement entered the annulus. The job signature pressure match conducted using proprietary zonal isolation software indicated that the openhole size was near gauge hole. The 12¼-in. open hole was drilled, and the 9⅝-in. liner was successfully run to total depth without incident. A total of 16.1 m3 of 1.60 SG ECF cement slurry was pumped. No losses were observed during the cementing operation, and consistent lift pressure was recorded during displacement. The liner was logged using ultrasonic imaging tools, with the top-of-cement bond identified at the 13⅜-in. casing shoe with a total 248 m of isolating cement. The operation achieved the required isolation to install the cemented liner as the primary barrier element prior to drilling into the reservoir, in addition to the exceptional logging results. The ECF cement system provided outstanding bond quality from 1882 to 2130 m. Remarkably, as an energy transition technology when compared with a conventional foamed cement system, the ECF cement system reduced CO2 emissions by 44% and simplified the operation by eliminating the use of foamed cement. Furthermore, the ECF cement is environmentally rated as PLONOR (poses little or no risk) and eliminates the use of polymeric materials to impart flexibility.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"38 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133735712","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Y. Witt-Doerring, P. Pastusek, Aaron Lacey, Pablo E. Barajas, Michael Bergeron, David Clayton, Steven F. Sowers
Drilling dysfunction causes premature failure of bits and motors in hard formations. Dysfunctions may be influenced by; bit design, bottom hole assembly (BHA) design, rig control systems, connection practices, and rotating head use. Sensors that record weight, torque, and vibration in the bit can offer insights that are not detectable further up the BHA. By understanding the root causes before the next bit run, it is possible to rapidly improve performance and prolong bit life. The formation being drilled in this study is a hard extremely abrasive shale, requiring 35+ runs per lateral section. The primary cause of polycrystalline diamond cutter (PDC) failure was smooth wear and thermal damage. The wear flats are attributed to abrasion and mechanical chipping that rapidly progress to thermal damage. Higher weights were not effective and it was hypothesized that buckling was occurring, causing insufficient weight transfer and increased lateral vibration. In-bit sensors that measure weight, torque, revolutions per minute (RPM), and lateral, axial and torsional vibration were run in hole to evaluate the weight transfer issues and dysfunction. High frequency downhole and surface data were combined with forensic images of the bit and BHA to confirm the weight transfer issues. In total, three major problems were identified and rectified during this study: drill string buckling, rate of penetration (ROP) loss due to the use of rotating control devices (RCDs) and WOB and differential pressure (DIFP) tare inconsistencies. Drill string buckling resulted in the downhole WOB being much less than surface WOB (DWOB<
{"title":"Drilling Dysfunction Demystified Using In-Bit Strain Sensors","authors":"Y. Witt-Doerring, P. Pastusek, Aaron Lacey, Pablo E. Barajas, Michael Bergeron, David Clayton, Steven F. Sowers","doi":"10.2118/212504-ms","DOIUrl":"https://doi.org/10.2118/212504-ms","url":null,"abstract":"\u0000 Drilling dysfunction causes premature failure of bits and motors in hard formations. Dysfunctions may be influenced by; bit design, bottom hole assembly (BHA) design, rig control systems, connection practices, and rotating head use. Sensors that record weight, torque, and vibration in the bit can offer insights that are not detectable further up the BHA. By understanding the root causes before the next bit run, it is possible to rapidly improve performance and prolong bit life.\u0000 The formation being drilled in this study is a hard extremely abrasive shale, requiring 35+ runs per lateral section. The primary cause of polycrystalline diamond cutter (PDC) failure was smooth wear and thermal damage. The wear flats are attributed to abrasion and mechanical chipping that rapidly progress to thermal damage. Higher weights were not effective and it was hypothesized that buckling was occurring, causing insufficient weight transfer and increased lateral vibration. In-bit sensors that measure weight, torque, revolutions per minute (RPM), and lateral, axial and torsional vibration were run in hole to evaluate the weight transfer issues and dysfunction.\u0000 High frequency downhole and surface data were combined with forensic images of the bit and BHA to confirm the weight transfer issues. In total, three major problems were identified and rectified during this study: drill string buckling, rate of penetration (ROP) loss due to the use of rotating control devices (RCDs) and WOB and differential pressure (DIFP) tare inconsistencies.\u0000 Drill string buckling resulted in the downhole WOB being much less than surface WOB (DWOB<<SWOB) in early runs. Heavy weight drill pipe (HWDP) was run across the buckling zone to correct this. Subsequent runs showed a significant improvement in DWOB, reduction in lateral bit vibration, and improved performance and dull condition.\u0000 Significant decreases in DWOB, DIFP, and ROP were noted when running tool joints through the RCD. Although observed before, in-bit accelerometers showed an increased lateral vibration that was a result of the loss in ROP and this continued long after the ROP recovered.\u0000 DWOB and downhole torque (DTOR) were often much higher than SWOB and DIFP (converted to torque). Plots of hookload and stand pipe pressure tare values were used as indicators of inconsistent tares. Although premature motor failure were not noted in these runs, premature PDC cutter failure were.\u0000 High frequency in-bit load sensing was used to identify persistent lateral vibration after a ROP loss event due to tool joints interacting with RCDs. A team based, continuous improvement, process was used to evaluate the root cause of downhole dysfunction and recommend bit/BHA design and operating procedure changes before the next bit was on bottom. This rapid analysis and joint recommendation process significantly prolonged bit life and improved drilling performance.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123215344","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Samantha Beim, M. Givens, Bruce Boulanger, M. Olson
Conventional BOP systems have used hydraulic operation for decades which limits both the performance and provides limited feedback on operational conditions. Electrically actuated BOP systems replace these complex hydraulic circuits with simplified components that improve overall system reliability. This paper will discuss the ambition to pivot from conventional hydraulic BOP systems to electrically enabled ones, with specific focus on the development of an electric bonnet for ram BOPs. The new electric components are designed to be backwards compatible, such that major components like ram blocks and ram BOP bodies do not need to be replaced. The electric BOP system features a battery powered control skid that replaces traditional accumulators, while electrically actuated BOP components replace the conventional hydraulic versions. Verification and validation of this new technology includes shear modeling, system simulation, and laboratory testing. The equipment is designed to meet the intent and exceed the performance requirements of the latest industry and regulatory standards. During development of the electric bonnet, the design team has shown that electric actuation of BOPs will provide equivalent shear force to existing hydraulic bonnets. The controlled actuation results in a more consistent and efficient shearing action. This improved shearing performance is achieved in the same BOP footprint as existing hydraulic BOPs. Additionally, the electric bonnet can perform as both a shear ram bonnet and a pipe ram bonnet which simplifies customer maintenance and spares stocking plans. As a result of these efforts, the electric BOP system development will provide greater operational latitude to meet a broader range of shearables, improve reliability, lower total cost of ownership, and reduce size and weight of the BOP system.
{"title":"Improving Performance – Electrification of Well Control Equipment","authors":"Samantha Beim, M. Givens, Bruce Boulanger, M. Olson","doi":"10.2118/212506-ms","DOIUrl":"https://doi.org/10.2118/212506-ms","url":null,"abstract":"\u0000 Conventional BOP systems have used hydraulic operation for decades which limits both the performance and provides limited feedback on operational conditions. Electrically actuated BOP systems replace these complex hydraulic circuits with simplified components that improve overall system reliability. This paper will discuss the ambition to pivot from conventional hydraulic BOP systems to electrically enabled ones, with specific focus on the development of an electric bonnet for ram BOPs.\u0000 The new electric components are designed to be backwards compatible, such that major components like ram blocks and ram BOP bodies do not need to be replaced. The electric BOP system features a battery powered control skid that replaces traditional accumulators, while electrically actuated BOP components replace the conventional hydraulic versions. Verification and validation of this new technology includes shear modeling, system simulation, and laboratory testing. The equipment is designed to meet the intent and exceed the performance requirements of the latest industry and regulatory standards.\u0000 During development of the electric bonnet, the design team has shown that electric actuation of BOPs will provide equivalent shear force to existing hydraulic bonnets. The controlled actuation results in a more consistent and efficient shearing action. This improved shearing performance is achieved in the same BOP footprint as existing hydraulic BOPs. Additionally, the electric bonnet can perform as both a shear ram bonnet and a pipe ram bonnet which simplifies customer maintenance and spares stocking plans. As a result of these efforts, the electric BOP system development will provide greater operational latitude to meet a broader range of shearables, improve reliability, lower total cost of ownership, and reduce size and weight of the BOP system.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"16 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128033317","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Yuandao Chi, V. Kemajou, Anil Rajan, Robello Samuel
Surface hookload and torque values serve as good indicators for some undesirable scenarios or anomalies during drilling, such as stuck pipe, buckling, and inadequate hole cleaning. However, to detect these risks, it requires drilling engineers to perform the friction factor calibration manually and regularly, which costs more effort and poses significant uncertainties on the detection. In this paper, a cloud-based real-time well engineering webapp has been developed to monitor and forecast tripping frictions and drilling performance. Results of field tests were presented to prove the successful testing of this cloud- based real-time workflow. Real-time hookload and torque values were streamed smoothly to the web application interface. Rig activity, friction factor, and mechanical specific energy (MSE) were also evaluated and displayed in real-time with predicted uncertainty zone. It has been demonstrated that this cloud-based web application supports a multi-tenancy architecture and multiple wells can stream simultaneously with no down time. This new workflow made it possible for drilling engineers to monitor live drilling wells anywhere and anytime while enabling the rig personnel to make significant improvements to operations and make timely and accurate decisions.
{"title":"Cloud-Based Real-Time Well Engineering: Coupling Torque-And-Drag and Uncertainty Modeling","authors":"Yuandao Chi, V. Kemajou, Anil Rajan, Robello Samuel","doi":"10.2118/212476-ms","DOIUrl":"https://doi.org/10.2118/212476-ms","url":null,"abstract":"\u0000 Surface hookload and torque values serve as good indicators for some undesirable scenarios or anomalies during drilling, such as stuck pipe, buckling, and inadequate hole cleaning. However, to detect these risks, it requires drilling engineers to perform the friction factor calibration manually and regularly, which costs more effort and poses significant uncertainties on the detection. In this paper, a cloud-based real-time well engineering webapp has been developed to monitor and forecast tripping frictions and drilling performance. Results of field tests were presented to prove the successful testing of this cloud- based real-time workflow. Real-time hookload and torque values were streamed smoothly to the web application interface. Rig activity, friction factor, and mechanical specific energy (MSE) were also evaluated and displayed in real-time with predicted uncertainty zone. It has been demonstrated that this cloud-based web application supports a multi-tenancy architecture and multiple wells can stream simultaneously with no down time. This new workflow made it possible for drilling engineers to monitor live drilling wells anywhere and anytime while enabling the rig personnel to make significant improvements to operations and make timely and accurate decisions.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"37 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116196494","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
By 2026, USD 5.05 billion will be spent per year on logging while drilling (LWD) according to the market report from Fortune Business Insights (2020). Logging tools and wireline tools are costly services for operators to pay for, and the companies providing the services also have a high cost of service delivery. They are, however, an essential service for drilling wells efficiently. The ability to computationally generate logs in real time using known relationships between the rock formations and drilling parameters provides an alternative method to generate formation evaluation information. This paper describes an approach to creating a digital formation evaluation log generator using a novel physics-informed machine learning (PIML) approach that combines physics-based approaches with machine learning (ML) algorithms. The designed PIML approach learns the relationships between drilling parameters and the gamma ray (GR) logs using the data from the offset wells. The decomposition of the model into multiple stages enables the model to learn the relationship between drilling parameters data and formation evaluation data. It makes it easier for the model to generate GR measurements consistent with the rock formations of the subject well being drilled. Since the computationally generated GR by the model is not just dependent on the relationships between drilling parameters and GR logs, this model is also generalizable and capable of being deployed into the application with only retraining on the offset wells and no change in the model structure or complexity. For this paper, the drilling of the horizontal section will not be discussed as this was done as a separate body of work. Historically collected data from the US Land Permian Basin wells is the primary dataset for this work. Results from the experiments based on the data collected from five different wells have been presented. Leave-one-out validation for each of the wells was performed. In the leave-one-out validation process, four of the wells represent the set of offset wells and the remaining one becomes the subject well. The same process is repeated for each of the wells as they are in turn defined as a subject well. Results show that the framework can infer and generate logs such as GR logs in real time.
{"title":"Real-Time Digital Log Generation from Drilling Parameters of Offset Wells Using Physics Informed Machine Learning","authors":"Prasham Sheth, Sailaja Sistla, Indranil Roychoudhury, Mengdi Gao, Crispin Chatar, J. Celaya, Priya Mishra","doi":"10.2118/212445-ms","DOIUrl":"https://doi.org/10.2118/212445-ms","url":null,"abstract":"\u0000 By 2026, USD 5.05 billion will be spent per year on logging while drilling (LWD) according to the market report from Fortune Business Insights (2020). Logging tools and wireline tools are costly services for operators to pay for, and the companies providing the services also have a high cost of service delivery. They are, however, an essential service for drilling wells efficiently. The ability to computationally generate logs in real time using known relationships between the rock formations and drilling parameters provides an alternative method to generate formation evaluation information. This paper describes an approach to creating a digital formation evaluation log generator using a novel physics-informed machine learning (PIML) approach that combines physics-based approaches with machine learning (ML) algorithms.\u0000 The designed PIML approach learns the relationships between drilling parameters and the gamma ray (GR) logs using the data from the offset wells. The decomposition of the model into multiple stages enables the model to learn the relationship between drilling parameters data and formation evaluation data. It makes it easier for the model to generate GR measurements consistent with the rock formations of the subject well being drilled. Since the computationally generated GR by the model is not just dependent on the relationships between drilling parameters and GR logs, this model is also generalizable and capable of being deployed into the application with only retraining on the offset wells and no change in the model structure or complexity. For this paper, the drilling of the horizontal section will not be discussed as this was done as a separate body of work.\u0000 Historically collected data from the US Land Permian Basin wells is the primary dataset for this work. Results from the experiments based on the data collected from five different wells have been presented. Leave-one-out validation for each of the wells was performed. In the leave-one-out validation process, four of the wells represent the set of offset wells and the remaining one becomes the subject well. The same process is repeated for each of the wells as they are in turn defined as a subject well. Results show that the framework can infer and generate logs such as GR logs in real time.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122692904","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. Cayeux, J. Macpherson, D. Pirovolou, Moray L. Laing, F. Florence
Automation and digitalization of drilling requires shared knowledge about the state of the drilling process: is the bit on-bottom drilling or is the driller making a connection; is the borehole in good condition or is it sloughing? Yet there is no shared, clear and usable definition of what a drilling process state is, nor an agreed method to calculate it. In this paper, we propose a method to clarify the concept of drilling process state. A set of partial differential equations, respecting boundary conditions, can describe drilling operations. The set of all possible discrete changes of boundary conditions, therefore, defines the set of all possible drilling process states. Equality or inequality of logical expressions of at most two boundary values characterizes a discrete change of a boundary condition. For instance, if forces applied to the bit by the formation are zero, this corresponds to an off-bottom condition, while forces greater than zero means that the bit is on-bottom. Such simple logical conditions are microstates, and an orthogonal set of microstates defines a drilling process state. An analysis of the drilling process from the perspective of these microstates defines an orthogonal basis of microstates. It is possible to define uniquely any drilling process state in this orthogonal basis. There are a finite number of possibilities to move from one state to a different state by changing only one single microstate, which leads to the construction of an implicit graph of possible states. In this implicit state graph, the change from one state to another state that corresponds to more than one modification of the microstates corresponds to a path in the graph. However, the microstate basis depends on the type of drilling process. The paper will provide examples of different microstate bases for conventional drilling, backpressure managed pressure drilling, and dual-gradient managed pressure drilling. Microstates also cover abnormal drilling conditions, such as hanging on a ledge, or flow obstruction in the annulus by a pack-off. They are, therefore, more powerful descriptors than "rig activity codes". The required fidelity of the drilling process state depends on its use, for example for controlling drilling equipment (process control), for calculating key performance indicators (process statistics), or for user feedback (human factors engineering). This work is part of the D-WIS initiative (Drilling and Wells Interoperability Standard). D-WIS is a cross-industry workgroup providing the industry with solutions facilitating interoperability of computer systems at the rig site. The definition of a microstate is a simple logical statement, easily implemented in computer software. The paper provides an example of a simple algorithm, which will enable others to leverage the work in the commercial, interoperable, environment.
{"title":"A General Framework to Describe Drilling Process States","authors":"E. Cayeux, J. Macpherson, D. Pirovolou, Moray L. Laing, F. Florence","doi":"10.2118/212537-ms","DOIUrl":"https://doi.org/10.2118/212537-ms","url":null,"abstract":"\u0000 Automation and digitalization of drilling requires shared knowledge about the state of the drilling process: is the bit on-bottom drilling or is the driller making a connection; is the borehole in good condition or is it sloughing? Yet there is no shared, clear and usable definition of what a drilling process state is, nor an agreed method to calculate it. In this paper, we propose a method to clarify the concept of drilling process state. A set of partial differential equations, respecting boundary conditions, can describe drilling operations. The set of all possible discrete changes of boundary conditions, therefore, defines the set of all possible drilling process states. Equality or inequality of logical expressions of at most two boundary values characterizes a discrete change of a boundary condition. For instance, if forces applied to the bit by the formation are zero, this corresponds to an off-bottom condition, while forces greater than zero means that the bit is on-bottom. Such simple logical conditions are microstates, and an orthogonal set of microstates defines a drilling process state. An analysis of the drilling process from the perspective of these microstates defines an orthogonal basis of microstates. It is possible to define uniquely any drilling process state in this orthogonal basis. There are a finite number of possibilities to move from one state to a different state by changing only one single microstate, which leads to the construction of an implicit graph of possible states. In this implicit state graph, the change from one state to another state that corresponds to more than one modification of the microstates corresponds to a path in the graph. However, the microstate basis depends on the type of drilling process. The paper will provide examples of different microstate bases for conventional drilling, backpressure managed pressure drilling, and dual-gradient managed pressure drilling. Microstates also cover abnormal drilling conditions, such as hanging on a ledge, or flow obstruction in the annulus by a pack-off. They are, therefore, more powerful descriptors than \"rig activity codes\". The required fidelity of the drilling process state depends on its use, for example for controlling drilling equipment (process control), for calculating key performance indicators (process statistics), or for user feedback (human factors engineering). This work is part of the D-WIS initiative (Drilling and Wells Interoperability Standard). D-WIS is a cross-industry workgroup providing the industry with solutions facilitating interoperability of computer systems at the rig site. The definition of a microstate is a simple logical statement, easily implemented in computer software. The paper provides an example of a simple algorithm, which will enable others to leverage the work in the commercial, interoperable, environment.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121081504","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Lim, S. McNeill, Daniel J Kluk, M. Stahl, Konstantin Puskarskij, Kristian Hansen
For decades, it has been known that, as drilling riser deployment depths increase, the potential for excessive hook load response will also increase. Using data collected from a drilling riser deployed to a record-setting water depth, nearly 12,000 ft, this paper provides insight that significantly reduces uncertainty about the severity of this resonant response. The typical drilling riser and blow-out preventer (BOP) stack, disconnected from the well head, has its first axial resonant period at approximately one second for each 2000 feet of deployed length, thus five seconds for 10,000 feet, six seconds for 12,000 feet, etc. Therefore, vessel heave response can incite a significant, adverse axial resonant condition in very deep water. Damping reduces resonant response. Historically, the true amount of damping has been uncertain and therefore conservatively assumed to be less than 1% of critical. The resulting uncertainty in dynamic hook load response can produce significant restrictions on riser configuration (running weight) and sea state for BOP stack deployment as well as storm hang-off of the riser and LMRP. A recent drilling riser deployment to the record-setting water depth of 11,903 ft produced a unique opportunity to collect high-quality data that reduces the damping uncertainty. This paper describes damping ratio and natural frequency identification for the first few axial riser modes for this deployment. The data was collected during deployment and retrieval using Subsea Vibration Data Loggers (SVDLs) installed on the BOP stack, drillship, and riser.
{"title":"Damping Identification from Subsea Logger Axial Riser Response Data","authors":"H. Lim, S. McNeill, Daniel J Kluk, M. Stahl, Konstantin Puskarskij, Kristian Hansen","doi":"10.2118/212496-ms","DOIUrl":"https://doi.org/10.2118/212496-ms","url":null,"abstract":"\u0000 For decades, it has been known that, as drilling riser deployment depths increase, the potential for excessive hook load response will also increase. Using data collected from a drilling riser deployed to a record-setting water depth, nearly 12,000 ft, this paper provides insight that significantly reduces uncertainty about the severity of this resonant response.\u0000 The typical drilling riser and blow-out preventer (BOP) stack, disconnected from the well head, has its first axial resonant period at approximately one second for each 2000 feet of deployed length, thus five seconds for 10,000 feet, six seconds for 12,000 feet, etc. Therefore, vessel heave response can incite a significant, adverse axial resonant condition in very deep water. Damping reduces resonant response. Historically, the true amount of damping has been uncertain and therefore conservatively assumed to be less than 1% of critical. The resulting uncertainty in dynamic hook load response can produce significant restrictions on riser configuration (running weight) and sea state for BOP stack deployment as well as storm hang-off of the riser and LMRP.\u0000 A recent drilling riser deployment to the record-setting water depth of 11,903 ft produced a unique opportunity to collect high-quality data that reduces the damping uncertainty. This paper describes damping ratio and natural frequency identification for the first few axial riser modes for this deployment. The data was collected during deployment and retrieval using Subsea Vibration Data Loggers (SVDLs) installed on the BOP stack, drillship, and riser.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"45 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115945735","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents a state-of-the-art bending fatigue model for wire ropes and applies it to optimize slip and cut intervals of drawworks drilling lines. The new model considers many parameters and variables, such as specific line tension, sheave-to-line diameter ratio, optional reverse bending, drum diameter, and excessive bending curvature at the crossover intervals of multilayer drums. The new model transforms block motion and hook load statistics into a high-resolution distribution of cumulative fatigue damage along the drilling line. In turn, the model justifies that the cut length and the energy transfer (in ton-miles) per cut length can be substantially increased relative to common practice today. The calculated fatigue damage distribution can also be used to pick peak fatigue damage line spots, most suited for focused inspection and optional strength testing after it is cut away.
{"title":"Improved Drilling Line Fatigue Model Reveals a Need for Revising Slip and Cut Procedures","authors":"Å. Kyllingstad, Rolf Hørsdal, I. Rajić","doi":"10.2118/212497-ms","DOIUrl":"https://doi.org/10.2118/212497-ms","url":null,"abstract":"\u0000 This paper presents a state-of-the-art bending fatigue model for wire ropes and applies it to optimize slip and cut intervals of drawworks drilling lines. The new model considers many parameters and variables, such as specific line tension, sheave-to-line diameter ratio, optional reverse bending, drum diameter, and excessive bending curvature at the crossover intervals of multilayer drums. The new model transforms block motion and hook load statistics into a high-resolution distribution of cumulative fatigue damage along the drilling line. In turn, the model justifies that the cut length and the energy transfer (in ton-miles) per cut length can be substantially increased relative to common practice today. The calculated fatigue damage distribution can also be used to pick peak fatigue damage line spots, most suited for focused inspection and optional strength testing after it is cut away.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114568847","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Theofilis, Georgios N Rossopoulos, C. Papadopoulos
A study of the shafting system of an 82.000DWT bulk carrier is conducted, comparing the initial alignment of the vessel against the performance corresponding to different bearing offset combinations. The shaft is modelled as a beam and the bearings as single support points. Radial shaft loads, thermal expansion of the engine and propeller thrust eccentricity are taken into account. Simulations are performed for 4 propeller immersion conditions and for various new offset combinations, deviating up to 10mm from the initial offsets. The results are evaluated according to rule requirements and classified as; (i) acceptable, (ii) marginal and (iii) not acceptable.
{"title":"Solution Space and Optimality Concerns for the Shafting System Alignment of a Typical Bulk Carrier","authors":"P. Theofilis, Georgios N Rossopoulos, C. Papadopoulos","doi":"10.5957/some-2023-026","DOIUrl":"https://doi.org/10.5957/some-2023-026","url":null,"abstract":"A study of the shafting system of an 82.000DWT bulk carrier is conducted, comparing the initial alignment of the vessel against the performance corresponding to different bearing offset combinations. The shaft is modelled as a beam and the bearings as single support points. Radial shaft loads, thermal expansion of the engine and propeller thrust eccentricity are taken into account. Simulations are performed for 4 propeller immersion conditions and for various new offset combinations, deviating up to 10mm from the initial offsets. The results are evaluated according to rule requirements and classified as; (i) acceptable, (ii) marginal and (iii) not acceptable.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123518714","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Different methods to calculate torque and drag have been used by the oil industry for years. Various assumptions are used in formulating these models. Opinions have often varied as to which model is better and whether the assumptions are valid. This paper discusses the trilemma considerations for an engineer 1. Soft string model vs stiff string model 2. Survey calculation method based on minimum curvature 3. Appearing and vanishing tortuosities after the casings have been run. Because of various underlying assumptions, the friction factor calibration is done often to match the calculated results with the actual results. This results in a wrong conclusion due to the change in the drag forces but on the contrary, it may be due to the exacerbation of the assumptions. The paper presents the pitfalls of the drillstring models, borehole curvature, appearing and vanishing tortuosities and their relationship with related well engineering calculations. Mathematical underpinnings are provided for all the trilemma considerations. Results demonstrate that a string with a large-size section can be very soft in a straight wellbore, and a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is better fit for a stiff string model. Results also confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. It has been observed that the absence or the discontinuity of bending moment results in the underestimate of forces, torque, and stresses when the minimum curvature method is used. This vanishing tortuosity alters the apparent wellpath and the new tortuosity representative of the cased hole path may present new appearing tortuosity and results in over and under estimation of the torque and drag calculations. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered.
{"title":"Engineers’ Trilemma: Use and Limitation of Torque and Drag Models","authors":"Robello Samuel","doi":"10.2118/212552-ms","DOIUrl":"https://doi.org/10.2118/212552-ms","url":null,"abstract":"\u0000 Different methods to calculate torque and drag have been used by the oil industry for years. Various assumptions are used in formulating these models. Opinions have often varied as to which model is better and whether the assumptions are valid. This paper discusses the trilemma considerations for an engineer 1. Soft string model vs stiff string model 2. Survey calculation method based on minimum curvature 3. Appearing and vanishing tortuosities after the casings have been run.\u0000 Because of various underlying assumptions, the friction factor calibration is done often to match the calculated results with the actual results. This results in a wrong conclusion due to the change in the drag forces but on the contrary, it may be due to the exacerbation of the assumptions. The paper presents the pitfalls of the drillstring models, borehole curvature, appearing and vanishing tortuosities and their relationship with related well engineering calculations. Mathematical underpinnings are provided for all the trilemma considerations.\u0000 Results demonstrate that a string with a large-size section can be very soft in a straight wellbore, and a string with small-size section can be very stiff in a wellbore with severe tortuosity, which is better fit for a stiff string model. Results also confirm that the soft string model is a better choice when the string is slimmer, the wellbore is in a lower curvature shape, and the clearance is larger. It has been observed that the absence or the discontinuity of bending moment results in the underestimate of forces, torque, and stresses when the minimum curvature method is used. This vanishing tortuosity alters the apparent wellpath and the new tortuosity representative of the cased hole path may present new appearing tortuosity and results in over and under estimation of the torque and drag calculations. To accurately estimate the drag force, the stiffness, as well as the wellbore shape and its clearance, should be considered.","PeriodicalId":103776,"journal":{"name":"Day 2 Wed, March 08, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-03-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121846180","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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