The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well. CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production. CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body. This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.
{"title":"The First Application of Permanent Tubing Patch Milling With Very Narrow Clearance in a Slimhole well with a Newly Engineered Pilot Mill Bit Design for Coiled Tubing, Offshore Thailand","authors":"Monchai Nimsuk, Treepun Tipapong, Surapong Somjai, Thanawee Kreethapon, Nophadol Jiemsawat, Tuanangkoon Daohmareeyor, Arweephan Kangsadarn, Reawat Wattanasuwankorn, Prapas Phayakrangsee","doi":"10.2118/209881-ms","DOIUrl":"https://doi.org/10.2118/209881-ms","url":null,"abstract":"\u0000 The permanent tubing patch is a primary method widely used to isolate water production zones, especially in slim-hole wells. As the name implies, the permanent tubing patch is non-retrievable equipment and presents a significant challenge when removal is needed. None of the global records of permanent tubing patches installed in slim-hole wells demonstrate successful removal. This paper will discuss the methods used to achieve the first-ever Coiled Tubing (CT) milling of a permanent tubing patch in a slim-hole well.\u0000 CT was selected to convey the BHA for milling the tubing patch sealing section. An eccentric pilot milling bit (2.780 in OD) was carefully designed as it needed to pass an ID restriction (2.813 in) in the Downhole Safety Valve (DHSV) while still being able to peel off the tubing patch sealing ID (2.250 in) until reaching the full drift of tubing ID (2.992 in) and ensure that the tubing wall would not be damaged during the milling operation. Once the tubing patch sealing section was removed, a braided-line (WL) operation was run to pull free and retrieve the tubing patch body to surface. The well was then restored to enable further intervention and production.\u0000 CT performed the milling operation flawlessly, and a carefully designed surface equipment stack-up design provided downhole tool deployment accessibility and convenience for both CT and WL intervention. Nitrified fluid was used with CT to mitigate loss problems in several depleted zones above the milling depth. As a result, the tubing patch seal was successfully milled without jeopardizing the tubing integrity. Once the tubing patch seal element was successfully removed and the patch body became free, the WL was deployed through the CT stack to fish the tubing patch body.\u0000 This is the first-ever operation to remove and retrieve a permanent tubing patch to the surface in this way without damaging the primary completion. Its success results from a well-thought-out pilot mill bit design and careful execution. This case study can now be shared across the industry to improve intervention efficiency and minimize the chance of early plug and abandonment due to permanent tubing patch removal issues.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115997102","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}
Olabode Ajibola, J. Sheng, E. Unal, Christopher Armistead, James Rutley, J. Smitherman
The reservoir pressure trend prediction for the potash area of Delaware Basin would enhance its optimum producible depths selection. It is significant for safe drilling, effective, and efficient governmental drilling permits approval in the area. Avoiding kicks, blowouts, fluid loss, pipe differential sticking, and heaving shales prevention improved wellbore control. This also leads to dependable wellbore integrity and better reservoir or well fluids control which are some of the benefits of proper reservoir pressure trend prediction. This study used the reservoir pressures predicted by Multilinear Regression machine learning model to verify the reservoir pressures calculated using drilling data from the potash area. Then, pressure trends are built for the area with Petra using geophysical log cross-sections. The results from these pressure trends are presented in 2-Dimensional and 3-Dimensional forms for the area to connect permitting optimum safely producible depths with hydrocarbon production. The study utilized drilling and well logs data from about 229 wells. All the wells were drilled and completed within the Potash Area to at least the base of Wolfcamp formation. The geophysical log cross-sections were created in 2- and 3-Dimensional forms using Petra, Matlab, and R machine languages. For the Multilinear Regression model over 330,000 data points from model parameters such as Deep & Shallow Laterolog Resistivities, Gamma Ray log, Neutron & Density Porosity Limestone logs, Sonic logs, caliper log, depth, lithology, mud weight, Photoelectric Cross-section, average porosity, water saturation, corrected bulk density log, and bulk density log were used. The datasets were grouped into 70 percent training and 30 percent testing randomly. The Multilinear Regression model predicted the reservoir pressures with high accuracy where the coefficient of determination (R2) is greater than 0.990. The Root Mean Square Error (RMSE) ranges from 0.0086 to 0.034 psi/ft between the predicted and the measured reservoir pressure data. The validation of the Regression model was done using another dataset. The reservoir pressures were predicted by the model with high accuracy using the validation dataset. The coefficient of determination (R2) is 0.99. This study shows that the regression model is reliable and can predict the reservoir pressures for the area accurately using well logs, drilling data, and geophysical data. Furthermore, verified reservoir pressures is used to build reservoir pressure trends for the area. The reservoir pressure trend can then be used to select the optimum producible depths in the area in order to promote safe, cost efficient, and optimum hydrocarbon recovery in the area. This study will also promote concurrent operations in prospecting for, developing, and producing oil and gas and potash deposits owned by the United States within the Designated Potash Area (DPA) (BLM Secretary Order, 2012).
{"title":"Evaluating Reservoir Pressure Gradient Trend for the Delaware Basin’s Potash Area Using Machine Learning & Geophysical Log Cross-Sections Approach","authors":"Olabode Ajibola, J. Sheng, E. Unal, Christopher Armistead, James Rutley, J. Smitherman","doi":"10.2118/209899-ms","DOIUrl":"https://doi.org/10.2118/209899-ms","url":null,"abstract":"\u0000 The reservoir pressure trend prediction for the potash area of Delaware Basin would enhance its optimum producible depths selection. It is significant for safe drilling, effective, and efficient governmental drilling permits approval in the area. Avoiding kicks, blowouts, fluid loss, pipe differential sticking, and heaving shales prevention improved wellbore control. This also leads to dependable wellbore integrity and better reservoir or well fluids control which are some of the benefits of proper reservoir pressure trend prediction.\u0000 This study used the reservoir pressures predicted by Multilinear Regression machine learning model to verify the reservoir pressures calculated using drilling data from the potash area. Then, pressure trends are built for the area with Petra using geophysical log cross-sections. The results from these pressure trends are presented in 2-Dimensional and 3-Dimensional forms for the area to connect permitting optimum safely producible depths with hydrocarbon production. The study utilized drilling and well logs data from about 229 wells. All the wells were drilled and completed within the Potash Area to at least the base of Wolfcamp formation.\u0000 The geophysical log cross-sections were created in 2- and 3-Dimensional forms using Petra, Matlab, and R machine languages. For the Multilinear Regression model over 330,000 data points from model parameters such as Deep & Shallow Laterolog Resistivities, Gamma Ray log, Neutron & Density Porosity Limestone logs, Sonic logs, caliper log, depth, lithology, mud weight, Photoelectric Cross-section, average porosity, water saturation, corrected bulk density log, and bulk density log were used. The datasets were grouped into 70 percent training and 30 percent testing randomly. The Multilinear Regression model predicted the reservoir pressures with high accuracy where the coefficient of determination (R2) is greater than 0.990. The Root Mean Square Error (RMSE) ranges from 0.0086 to 0.034 psi/ft between the predicted and the measured reservoir pressure data. The validation of the Regression model was done using another dataset. The reservoir pressures were predicted by the model with high accuracy using the validation dataset. The coefficient of determination (R2) is 0.99. This study shows that the regression model is reliable and can predict the reservoir pressures for the area accurately using well logs, drilling data, and geophysical data. Furthermore, verified reservoir pressures is used to build reservoir pressure trends for the area.\u0000 The reservoir pressure trend can then be used to select the optimum producible depths in the area in order to promote safe, cost efficient, and optimum hydrocarbon recovery in the area. This study will also promote concurrent operations in prospecting for, developing, and producing oil and gas and potash deposits owned by the United States within the Designated Potash Area (DPA) (BLM Secretary Order, 2012).","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"32 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116324961","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}
Alif Shamir Baharudin, Beng Seow Chai, Nik Fahusnaza Nik Mohd Najmi, Elias Bayking, Khabilashini Ravendrnathan
With more wells planned in the future to be drilled in challenging formations, directional casing while drilling technology need to be on par with the demand. In Malaysia, there is a need to utilize directional casing while drilling to mitigate the risk of losses from the offset wells and when there is wellbore stability which will affect the drilling operation, especially when we drill deeper near the hydrocarbon zone. The main challenge in this field is the abrasive formation with interbedded stringer. To further optimize the well engineering by eliminating one casing design, the plan is to drill with directional casing while drilling with long 12-1/4" hole interval for the well design. Thus, there is a need to have a robust underreamer design to meet the well design’s objective, which is the new block type high ratio underreamer technology. With anti-collision issue, the Directional Casing Drilling Bottom Hole Assembly was planned to be run with motor. This will be the first assembly run globally. Thus, the pre-job planning is essential in order to deliver flawless execution. As part of the method to make this operation a success, the main challenges were identified and solved. The main challenge is the technology maturity for the underreamer from arm type high ratio underreamer to block type high ratio underreamer with more cutter density that can enlarge the hole with higher durability, and the cutting structure technology that can withstand both impact damage (from interbedded formation) and wear (from abrasive formation) with long interval of drilling footage. With the offset data obtained, the deep leech technology was applied to the cutting structure which increase the impact and wear resistance. The Cutter density per arm of block type high ratio underreamer is 200% more than the arm type high ratio underreamer, which provide more durability in drilling challenging formation. The compatibility of the block type high ratio underreamer with the motor assembly was studied for risk assessment and mitigation plan. The drilling parameter road map have been studied with the previous track record of Directional Casing Drilling as a baseline to minimize the damage to the cutting structure. With the careful planning for the first block type high ratio underreamer, the longest interval for 9-5/8" Directional Casing Drilling have been performed back-to-back for two wells in East Malaysia with challenging formation. The well design successfully eliminates 1 string by having 13-3/8" casing only as a conduit, which save approximately USD 400,000 and 48 hours in the flat time per well compared with the conventional well design cost from the offset well. The introduction of block type high ratio underreamer expand the directional casing drilling application into more challenging formation with longer interval. This will greatly change the well engineering design and reduce the carbon footprint by eliminating surface casing requirement.
{"title":"Future of Directional Casing Drilling with the New Block Type High Ratio Underreamer Technology to Further Optimize the well Engineering Design and Reduce Carbon Foot Print","authors":"Alif Shamir Baharudin, Beng Seow Chai, Nik Fahusnaza Nik Mohd Najmi, Elias Bayking, Khabilashini Ravendrnathan","doi":"10.2118/209907-ms","DOIUrl":"https://doi.org/10.2118/209907-ms","url":null,"abstract":"\u0000 With more wells planned in the future to be drilled in challenging formations, directional casing while drilling technology need to be on par with the demand. In Malaysia, there is a need to utilize directional casing while drilling to mitigate the risk of losses from the offset wells and when there is wellbore stability which will affect the drilling operation, especially when we drill deeper near the hydrocarbon zone.\u0000 The main challenge in this field is the abrasive formation with interbedded stringer. To further optimize the well engineering by eliminating one casing design, the plan is to drill with directional casing while drilling with long 12-1/4\" hole interval for the well design. Thus, there is a need to have a robust underreamer design to meet the well design’s objective, which is the new block type high ratio underreamer technology. With anti-collision issue, the Directional Casing Drilling Bottom Hole Assembly was planned to be run with motor. This will be the first assembly run globally. Thus, the pre-job planning is essential in order to deliver flawless execution.\u0000 As part of the method to make this operation a success, the main challenges were identified and solved. The main challenge is the technology maturity for the underreamer from arm type high ratio underreamer to block type high ratio underreamer with more cutter density that can enlarge the hole with higher durability, and the cutting structure technology that can withstand both impact damage (from interbedded formation) and wear (from abrasive formation) with long interval of drilling footage. With the offset data obtained, the deep leech technology was applied to the cutting structure which increase the impact and wear resistance.\u0000 The Cutter density per arm of block type high ratio underreamer is 200% more than the arm type high ratio underreamer, which provide more durability in drilling challenging formation. The compatibility of the block type high ratio underreamer with the motor assembly was studied for risk assessment and mitigation plan. The drilling parameter road map have been studied with the previous track record of Directional Casing Drilling as a baseline to minimize the damage to the cutting structure.\u0000 With the careful planning for the first block type high ratio underreamer, the longest interval for 9-5/8\" Directional Casing Drilling have been performed back-to-back for two wells in East Malaysia with challenging formation. The well design successfully eliminates 1 string by having 13-3/8\" casing only as a conduit, which save approximately USD 400,000 and 48 hours in the flat time per well compared with the conventional well design cost from the offset well.\u0000 The introduction of block type high ratio underreamer expand the directional casing drilling application into more challenging formation with longer interval. This will greatly change the well engineering design and reduce the carbon footprint by eliminating surface casing requirement.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"13 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122390473","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}
Saurabh Anand, Nusheena Mat Khair, Khairul Azhar B. Abu Bakar, B. Madon, Kok Kin Chun, M. S. M. Adib, M. Rahim
Majority of wells completed offshore Malaysia have downhole screens installed for sand and fines control. It is however observed that the PI of most of these wells drop multifold times within first few years of production. This paper illustrates the workflow with novel technique of screening such wells for stimulation to restore well production. This paper will also illustrate a few examples of actual implementation of the stimulation jobs and the excellent results from these jobs. Hundreds of strings operated by PETRONAS in Malaysia Offshore across various fields have some form of downhole screen (standalone or as part of the gravel pack) installed to control sand and fines. Although these completions remain effective initially, but water break through results in significant PI decrease. It has been established that the predominant cause of this decline is the screen or gravel pack plugging by the fines mobilized by water which is followed in many cases by deposition of inorganic or organic scales. A workflow was developed using data from existing digital production monitoring system to identify wells showing the plugging behaviour. The workflow used several factors such as liquid rate decline, GOR, water cut, reservoir pressure, artificial lift performance etc to shortlist a list of wells on which a detailed nodal analysis was applied to estimate gains assuming 70% skin reduction. The wells which passed the workflow and showed maximum benefit from stimulation were then grouped together such that a campaign-based execution could be done to optimize cost. Detailed customized stimulation recipe for each well was prepared and optimized well level operation program was prepared. Optimization such as using bullheading technique instead of using coil tubing in some cases was done. Stimulation treatment in 4 of the wells has been pumped successfully with excellent results and an estimated 1,000 bopd total gains. The post job oil rate is double the initial rate in many cases and even 200% more in some of the cases. Post job nodal analysis suggests up to 90% damage skin removal in these wells. Optimized operation program and campaign-based execution coupled with other cost saving measures implied that the payback time was less than 1 month. PDG data from one of the wells was used extensively to evaluate pre & post stimulation well behavior. The high damage skin in the screen completed wells is one of the most pertinent issues which leads to significant production loss in wells offshore Malaysia. This paper details a quick and robust method to identify such wells for stimulation. The results from these stimulation jobs on candidate wells are very encouraging particularly considering the economics of the jobs. Following the success of the initial jobs, many more candidate wells have been lined up for execution in near future.
{"title":"Novel Candidate Screening and Successful Implementation of Stimulation in Screen Completed Wells to Double Production in Brown Fields – A Case Study from Offshore Malaysia","authors":"Saurabh Anand, Nusheena Mat Khair, Khairul Azhar B. Abu Bakar, B. Madon, Kok Kin Chun, M. S. M. Adib, M. Rahim","doi":"10.2118/209844-ms","DOIUrl":"https://doi.org/10.2118/209844-ms","url":null,"abstract":"\u0000 Majority of wells completed offshore Malaysia have downhole screens installed for sand and fines control. It is however observed that the PI of most of these wells drop multifold times within first few years of production. This paper illustrates the workflow with novel technique of screening such wells for stimulation to restore well production. This paper will also illustrate a few examples of actual implementation of the stimulation jobs and the excellent results from these jobs.\u0000 Hundreds of strings operated by PETRONAS in Malaysia Offshore across various fields have some form of downhole screen (standalone or as part of the gravel pack) installed to control sand and fines. Although these completions remain effective initially, but water break through results in significant PI decrease. It has been established that the predominant cause of this decline is the screen or gravel pack plugging by the fines mobilized by water which is followed in many cases by deposition of inorganic or organic scales. A workflow was developed using data from existing digital production monitoring system to identify wells showing the plugging behaviour.\u0000 The workflow used several factors such as liquid rate decline, GOR, water cut, reservoir pressure, artificial lift performance etc to shortlist a list of wells on which a detailed nodal analysis was applied to estimate gains assuming 70% skin reduction. The wells which passed the workflow and showed maximum benefit from stimulation were then grouped together such that a campaign-based execution could be done to optimize cost. Detailed customized stimulation recipe for each well was prepared and optimized well level operation program was prepared. Optimization such as using bullheading technique instead of using coil tubing in some cases was done. Stimulation treatment in 4 of the wells has been pumped successfully with excellent results and an estimated 1,000 bopd total gains. The post job oil rate is double the initial rate in many cases and even 200% more in some of the cases. Post job nodal analysis suggests up to 90% damage skin removal in these wells. Optimized operation program and campaign-based execution coupled with other cost saving measures implied that the payback time was less than 1 month. PDG data from one of the wells was used extensively to evaluate pre & post stimulation well behavior.\u0000 The high damage skin in the screen completed wells is one of the most pertinent issues which leads to significant production loss in wells offshore Malaysia. This paper details a quick and robust method to identify such wells for stimulation. The results from these stimulation jobs on candidate wells are very encouraging particularly considering the economics of the jobs. Following the success of the initial jobs, many more candidate wells have been lined up for execution in near future.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123234149","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}
Rodrigo Chamusca Machado, Juan Rizzi, Cristiano Xavier, Leandro Diniz Brandão Rocha, Lucas Oliveira Souza, Paloma Ferreira, Raphael Crespo, Daniel Martins, Victor Chaves, Vinícius Oliveira
The drop on the daily rates for the Drilling Rigs in the recent years has pushed Drilling Contractors in the industry for innovative solutions. Industry 4.0 is bringing many features and technologies to overcome these challenges and help the companies to meet this new scenario. This paper will present how a partnership between Ocyan, an ultra-deep-water Drilling Contractor and RIO Analytics, an A.I. technology company that develops solutions for failure prediction of industrial assets, is using artificial intelligence and Data Analytics to manage and control drill pipes operation and prevent failures, correlating different sources of information. Drill pipe is one of the most critical equipment on a deepwater Drilling Rig and Drill pipes incidents are one of the biggest causes of nonproductive time and unplanned costs in the drilling industry. In most cases, the lack of information about the drill pipes, such as historical and operational efforts related to their individual use make it very hard to investigate an incident that occurred, and consequently, to predict a pipe failure. Also, some operational limits (such as make-up torque and elevator capacity) that are driven by dimensional inspection results are often not used correctly for operational planning, leading to unnecessary risks. To be able to apply failure prediction algorithms and correlate operational and historical information for each individual drill pipe, a web-based software was developed building a valuable database and management system, allowing users to easily navigate for drill pipes information, generate reports, and simulate operational scenarios by providing operation planned tally (list of drill pipes). Warnings are generated as the results for the simulations indicating any risk for operations. Critical situations are made available to the rig crew, immediately transmitted to the Ocyan's Decision Support Center (CSD) and management team onshore, while less critical alerts are recorded in the system for further investigation. Software integrates with different inspection reports formats and automatically updates critical information on drill pipe's database, allowing also to identify invalid or wrong information on these reports, upon inspection criteria used. With the implementation of this predictive maintenance solution, companies aim to increase Operational and Process Safety, avoid NPT and reduce maintenance cost regarding the Drill Pipes. Based on the integration with real-time data from rig sensors and identification of active operational tally, it has been possible to automatically control drilled meters and rotating hours for each drill pipe, which triggers inspection requirements, generating automated work orders for the CMMS. Also, an algorithm was developed to calculate real-time damage in each drill pipe during operation, considering the most significant parameters (such as torque, tension, drilling depth, wear, pressure, dog leg s
{"title":"Development of Drill Pipes Failure Prediction Models and Operational Management System Using Real-Time Data Analytics and Ai","authors":"Rodrigo Chamusca Machado, Juan Rizzi, Cristiano Xavier, Leandro Diniz Brandão Rocha, Lucas Oliveira Souza, Paloma Ferreira, Raphael Crespo, Daniel Martins, Victor Chaves, Vinícius Oliveira","doi":"10.2118/209858-ms","DOIUrl":"https://doi.org/10.2118/209858-ms","url":null,"abstract":"\u0000 \u0000 \u0000 The drop on the daily rates for the Drilling Rigs in the recent years has pushed Drilling Contractors in the industry for innovative solutions. Industry 4.0 is bringing many features and technologies to overcome these challenges and help the companies to meet this new scenario. This paper will present how a partnership between Ocyan, an ultra-deep-water Drilling Contractor and RIO Analytics, an A.I. technology company that develops solutions for failure prediction of industrial assets, is using artificial intelligence and Data Analytics to manage and control drill pipes operation and prevent failures, correlating different sources of information. Drill pipe is one of the most critical equipment on a deepwater Drilling Rig and Drill pipes incidents are one of the biggest causes of nonproductive time and unplanned costs in the drilling industry. In most cases, the lack of information about the drill pipes, such as historical and operational efforts related to their individual use make it very hard to investigate an incident that occurred, and consequently, to predict a pipe failure. Also, some operational limits (such as make-up torque and elevator capacity) that are driven by dimensional inspection results are often not used correctly for operational planning, leading to unnecessary risks.\u0000 \u0000 \u0000 \u0000 To be able to apply failure prediction algorithms and correlate operational and historical information for each individual drill pipe, a web-based software was developed building a valuable database and management system, allowing users to easily navigate for drill pipes information, generate reports, and simulate operational scenarios by providing operation planned tally (list of drill pipes). Warnings are generated as the results for the simulations indicating any risk for operations. Critical situations are made available to the rig crew, immediately transmitted to the Ocyan's Decision Support Center (CSD) and management team onshore, while less critical alerts are recorded in the system for further investigation. Software integrates with different inspection reports formats and automatically updates critical information on drill pipe's database, allowing also to identify invalid or wrong information on these reports, upon inspection criteria used.\u0000 \u0000 \u0000 \u0000 With the implementation of this predictive maintenance solution, companies aim to increase Operational and Process Safety, avoid NPT and reduce maintenance cost regarding the Drill Pipes.\u0000 \u0000 \u0000 \u0000 Based on the integration with real-time data from rig sensors and identification of active operational tally, it has been possible to automatically control drilled meters and rotating hours for each drill pipe, which triggers inspection requirements, generating automated work orders for the CMMS. Also, an algorithm was developed to calculate real-time damage in each drill pipe during operation, considering the most significant parameters (such as torque, tension, drilling depth, wear, pressure, dog leg s","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132184785","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}
Shunchao Zhao, Yugang Zhou, Jian-hua Bai, T. Fang, Baobing Shang
This paper proposes an integrated technology of chemical sand control and stratified water injection in water injection well, which enlarge the inner diameter of injection well after sand control and achieve flexible stratification of injection layer. Mechanical sand control is the main method for injection wells in offshore oilfields. After sand control, the inner diameter of injection well is small and the number of injection layers is generally 3-4 layers. For reservoirs with strong longitudinal heterogeneity, it's difficult to get higher longitudinal sweep coefficient of driving and better effect of injection. The technology realizes completion by chemical sand control, without screens downhole. The ceramsite whose surface has been treated by crosslinking agent is injected into the well and heated. The crosslinking reaction occurs on the surface of the ceramsite, forming a cement layer with a thickness of 3-5cm and a certain compressive strength of 7.2MPa and a permeability of 5000mD on the wellbore. This cement layer not only can be used as a barrier to retain formation, but also can provide flow channels for fluids. Then, the stratified injection pipe string is run. The developed multi-functional packer contacts and seals the cemented layer to realize the stratification of the injection reservoir. The position and quantity of the packer are designed according to the target injection horizon to achieve flexible stratification. This technology has been successfully applied to 4 wells in the Bohai Oilfield, all of which have the characteristics of large reservoir thickness and strong vertical heterogeneity. The conventional sand control and injection technology makes it difficult for the actual injection volume to reach the target volume, and the water cut of the benefit well continues to rise. After applying the integrated technology, for a directional well with a bore diameter of 9.625 in, the maximum inner diameter can reach 9.625 in, while the inner diameter of traditional sand control methods is only 4.75 in. The number of injection layers exceeds 5, and the actual injection volume meets the designed requirement. The validity period has exceeded 40 months and continues to be effective. The water cut of the benefiting well decreases from 85% to 78%, and the oil production rate increased from 56 m3/d to 72 m3/d. The successful application of the integrated technology provides a new idea for subdivision water injection in offshore oilfields. The increase in the internal diameter of well can reduce the difficulty of operation and increase the water injection rate. The flexible stratification can improve the vertical production degree of reservoir water flooding and the overall effect of water injection.
{"title":"Research and Application of Integrated Technology of Chemical Sand Control and Stratified Water Injection in Offshore Oilfields Injection Well","authors":"Shunchao Zhao, Yugang Zhou, Jian-hua Bai, T. Fang, Baobing Shang","doi":"10.2118/209885-ms","DOIUrl":"https://doi.org/10.2118/209885-ms","url":null,"abstract":"\u0000 This paper proposes an integrated technology of chemical sand control and stratified water injection in water injection well, which enlarge the inner diameter of injection well after sand control and achieve flexible stratification of injection layer. Mechanical sand control is the main method for injection wells in offshore oilfields. After sand control, the inner diameter of injection well is small and the number of injection layers is generally 3-4 layers. For reservoirs with strong longitudinal heterogeneity, it's difficult to get higher longitudinal sweep coefficient of driving and better effect of injection.\u0000 The technology realizes completion by chemical sand control, without screens downhole. The ceramsite whose surface has been treated by crosslinking agent is injected into the well and heated. The crosslinking reaction occurs on the surface of the ceramsite, forming a cement layer with a thickness of 3-5cm and a certain compressive strength of 7.2MPa and a permeability of 5000mD on the wellbore. This cement layer not only can be used as a barrier to retain formation, but also can provide flow channels for fluids. Then, the stratified injection pipe string is run. The developed multi-functional packer contacts and seals the cemented layer to realize the stratification of the injection reservoir. The position and quantity of the packer are designed according to the target injection horizon to achieve flexible stratification.\u0000 This technology has been successfully applied to 4 wells in the Bohai Oilfield, all of which have the characteristics of large reservoir thickness and strong vertical heterogeneity. The conventional sand control and injection technology makes it difficult for the actual injection volume to reach the target volume, and the water cut of the benefit well continues to rise. After applying the integrated technology, for a directional well with a bore diameter of 9.625 in, the maximum inner diameter can reach 9.625 in, while the inner diameter of traditional sand control methods is only 4.75 in. The number of injection layers exceeds 5, and the actual injection volume meets the designed requirement. The validity period has exceeded 40 months and continues to be effective. The water cut of the benefiting well decreases from 85% to 78%, and the oil production rate increased from 56 m3/d to 72 m3/d.\u0000 The successful application of the integrated technology provides a new idea for subdivision water injection in offshore oilfields. The increase in the internal diameter of well can reduce the difficulty of operation and increase the water injection rate. The flexible stratification can improve the vertical production degree of reservoir water flooding and the overall effect of water injection.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"29 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133998996","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}
Sunisa Watcharasing, Chularat Wattanakit, Anawat Thivasasith, P. Kiattikomol
This project targets to convert sand waste from oil & gas production, which is typically disposed as landfill, to be the higher-value products, called "Hierarchical Zeolites". This project also explores opportunities to lower amount of sand waste to landfill and try to convert CO2 to CNTs, as part of Sustainable Development Goals. Hierarchical Zeolites is developed with nanosheets morphology to overcome limitation of conventional zeolites in terms of, 1) microporous structure improvement to enhance the mass transport through active sites, 2) longer catalyst lifetime, and 3) higher surface area. With these superior characteristics, it is popularly used in wide range of applications ranging from adsorption, separation, and ion-exchange to catalysis. In this work, the Hierarchical Zeolites are utilized as catalysts for CO2 conversion to CNTs, which is the futuristic materials. Methods, The procedure to produce hierarchical zeolites with nanosheet morphology for ZSM-5, and Faujasite (FAU) topologies have been developed. Production sand waste is used as a silica source; after it is passed sand pretreatment and silica extraction steps, for hierarchical zeolites synthesis, to reduce their production cost. Physicochemical properties of the synthesized hierarchical zeolites are analyzed, such as surface area, porosity, topology, and textural properties. These physicochemical properties will be compared with the one obtained using the commercial silica sources. Then, the developed Hierarchical zeolites are applied as catalyst for CNTs production from CO2. The fixed bed Chemical Vapor Deposition (CVD) technique is introduced for CNTs synthesis, as its low energy cost consumption, high quality of CNTs synthesis. The physical properties of CNTs, including tube diameter, graphitic structure (ID/IG). To prove of concept for extracting silica source as a substance for hierarchical zeolite synthesis and use as catalyst for CNTs production from CO2. Two types of hierarchical zeolites nanosheet (ZSM-5, and FAU) have been successfully synthesized from nano silica obtained froms and waste, with high yield more than 75%. The hierarchical-FAU, and hierarchical -FAU-5's performance on CNTs production from CO2 are compared together. It was found that the hierarchical-FAU provide the best catalyst for CNT production with the CNTs yield of 28.9%, the average diameter of 22.8 nm and ID/IGof 0.68. The optimal condition for hierarchical zeolites synthesis will be further applied in the prototype phase, in the 50X up-scaling. This technology is expected to lower an amount of production sand waste disposal to landfill. Moreover, the synthesized hierarchical zeolites will be further explored in other advanced reactions apart from CNTs synthesis, such as catalytic cracking. Hierarchical zeolites from production sand waste are firstly initiated and successfully achieved in PTTEP. From these findings, information will be applied to the process design of Hierarchical zeolites s
{"title":"Hierarchical Zeolites from Production Sand Waste as Catalysts for CO2 to Carbon Nanotubes CNTs: Exploration and Production Sustainability","authors":"Sunisa Watcharasing, Chularat Wattanakit, Anawat Thivasasith, P. Kiattikomol","doi":"10.2118/209923-ms","DOIUrl":"https://doi.org/10.2118/209923-ms","url":null,"abstract":"\u0000 This project targets to convert sand waste from oil & gas production, which is typically disposed as landfill, to be the higher-value products, called \"Hierarchical Zeolites\". This project also explores opportunities to lower amount of sand waste to landfill and try to convert CO2 to CNTs, as part of Sustainable Development Goals. Hierarchical Zeolites is developed with nanosheets morphology to overcome limitation of conventional zeolites in terms of, 1) microporous structure improvement to enhance the mass transport through active sites, 2) longer catalyst lifetime, and 3) higher surface area. With these superior characteristics, it is popularly used in wide range of applications ranging from adsorption, separation, and ion-exchange to catalysis. In this work, the Hierarchical Zeolites are utilized as catalysts for CO2 conversion to CNTs, which is the futuristic materials. Methods,\u0000 The procedure to produce hierarchical zeolites with nanosheet morphology for ZSM-5, and Faujasite (FAU) topologies have been developed. Production sand waste is used as a silica source; after it is passed sand pretreatment and silica extraction steps, for hierarchical zeolites synthesis, to reduce their production cost. Physicochemical properties of the synthesized hierarchical zeolites are analyzed, such as surface area, porosity, topology, and textural properties. These physicochemical properties will be compared with the one obtained using the commercial silica sources. Then, the developed Hierarchical zeolites are applied as catalyst for CNTs production from CO2. The fixed bed Chemical Vapor Deposition (CVD) technique is introduced for CNTs synthesis, as its low energy cost consumption, high quality of CNTs synthesis. The physical properties of CNTs, including tube diameter, graphitic structure (ID/IG).\u0000 To prove of concept for extracting silica source as a substance for hierarchical zeolite synthesis and use as catalyst for CNTs production from CO2. Two types of hierarchical zeolites nanosheet (ZSM-5, and FAU) have been successfully synthesized from nano silica obtained froms and waste, with high yield more than 75%. The hierarchical-FAU, and hierarchical -FAU-5's performance on CNTs production from CO2 are compared together. It was found that the hierarchical-FAU provide the best catalyst for CNT production with the CNTs yield of 28.9%, the average diameter of 22.8 nm and ID/IGof 0.68. The optimal condition for hierarchical zeolites synthesis will be further applied in the prototype phase, in the 50X up-scaling. This technology is expected to lower an amount of production sand waste disposal to landfill. Moreover, the synthesized hierarchical zeolites will be further explored in other advanced reactions apart from CNTs synthesis, such as catalytic cracking.\u0000 Hierarchical zeolites from production sand waste are firstly initiated and successfully achieved in PTTEP. From these findings, information will be applied to the process design of Hierarchical zeolites s","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"112 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132278022","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}
Ainul Azuan Masngot, Suman Kumar, Nurul Iffah M Garib, Mior Yusni Ahmad, Juhari Yang, Tunku Ahmad Farhan Tunku Kamaruddin, Mohd Zubair Mohd Azkah, Abdul Hakim Basri
A 500m open hole horizontal well with 2 segmented sections was completed with Single Trip Completion with RFID technology in July 2021. This is the first application in Petronas asset which resulted into 21% of cost saving in well completion element against conventional two trips completion. Despite successful of well completion, well unloading phase is distressing to meet the expected production target. This paper elaborates on single-trip completion operation with RFID application and challenges faced during well unloading job to deliver one of the highest oil producers in Malaysia Petronas Carigali asset. Radio-frequency identification (RFID) technology offers interventionless in both activation and contingency in well completion activity. The technology utilized the optimal completion activation solution in minimizing the well cost and reducing operational risk, thus, resulted into significant rig time saving. The RFID has facilitated well completion deployment in high angle well in one trip. As conventional new infill well completion phase, well unloading is the vital stage to demonstrate the well completion is upright placed at desired depth and the well completion accessories are fully operated. KX reservoir in PR field was discovered via exploration well and essential downhole tests were deployed namely DST, PBU, Downhole and Surface sampling to obtain as much as reservoir & crude oil data due to its green field reservoir. The FDP team forecasted the production rate as per proven acquired data. Unfortunately, one of the reservoir parameters was predicted undervalued which constrained 3 kbopd additional oil production to be commercially produced. RFID tool of completion accessories has the actuation mechanism which enables for single trip completion, and it eliminates well intervention job, negates the needs of tractor service, and reduces the risk of stuck of tools. The RFID suite of tools offers three activation mechanism which provide utmost flexibility in both downhole equipment activation and contingency methods to optimize the cost further particularly in marginal PR field development. Though getting the achievement of first application of single trip completion with RFID, this project has suffered irresolute GOR during well unloading phase. Higher actual GOR against tested data during DST and PVT sampling caused high flowing pressure at surface which exceeded the PSV (Pressure Safety Valve) setting pressure, thus, hindered the actual technical potential of the promised oil producer in Petronas Carigali asset. RFID is technology enabler for single-trip completion project in PR field which indirectly improves economics of marginal field development. Decent downhole and surface data acquisition during exploration doesn't assure guaranteed reservoir & crude property data to be used during field development plan.
{"title":"Lesson Learnt from First Application of Single Trip Completion with RFID and Unexpected Well Unloading Challenges Against Proven DST Data in Offshore Peninsular Malaysia","authors":"Ainul Azuan Masngot, Suman Kumar, Nurul Iffah M Garib, Mior Yusni Ahmad, Juhari Yang, Tunku Ahmad Farhan Tunku Kamaruddin, Mohd Zubair Mohd Azkah, Abdul Hakim Basri","doi":"10.2118/209867-ms","DOIUrl":"https://doi.org/10.2118/209867-ms","url":null,"abstract":"\u0000 A 500m open hole horizontal well with 2 segmented sections was completed with Single Trip Completion with RFID technology in July 2021. This is the first application in Petronas asset which resulted into 21% of cost saving in well completion element against conventional two trips completion. Despite successful of well completion, well unloading phase is distressing to meet the expected production target. This paper elaborates on single-trip completion operation with RFID application and challenges faced during well unloading job to deliver one of the highest oil producers in Malaysia Petronas Carigali asset.\u0000 Radio-frequency identification (RFID) technology offers interventionless in both activation and contingency in well completion activity. The technology utilized the optimal completion activation solution in minimizing the well cost and reducing operational risk, thus, resulted into significant rig time saving. The RFID has facilitated well completion deployment in high angle well in one trip. As conventional new infill well completion phase, well unloading is the vital stage to demonstrate the well completion is upright placed at desired depth and the well completion accessories are fully operated. KX reservoir in PR field was discovered via exploration well and essential downhole tests were deployed namely DST, PBU, Downhole and Surface sampling to obtain as much as reservoir & crude oil data due to its green field reservoir. The FDP team forecasted the production rate as per proven acquired data. Unfortunately, one of the reservoir parameters was predicted undervalued which constrained 3 kbopd additional oil production to be commercially produced.\u0000 RFID tool of completion accessories has the actuation mechanism which enables for single trip completion, and it eliminates well intervention job, negates the needs of tractor service, and reduces the risk of stuck of tools. The RFID suite of tools offers three activation mechanism which provide utmost flexibility in both downhole equipment activation and contingency methods to optimize the cost further particularly in marginal PR field development. Though getting the achievement of first application of single trip completion with RFID, this project has suffered irresolute GOR during well unloading phase. Higher actual GOR against tested data during DST and PVT sampling caused high flowing pressure at surface which exceeded the PSV (Pressure Safety Valve) setting pressure, thus, hindered the actual technical potential of the promised oil producer in Petronas Carigali asset. RFID is technology enabler for single-trip completion project in PR field which indirectly improves economics of marginal field development. Decent downhole and surface data acquisition during exploration doesn't assure guaranteed reservoir & crude property data to be used during field development plan.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"113 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117165695","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}
C. Tan, M. S. Razak, Siti Shahara Zakaria, Abiabhar Abitalhah, Wan Nur Safawati Wan Mohd Zainudin
Fracture gradient enhancementtechnology has been developed for drilling mud compounds based on comprehensive large scale laboratory test data which can widen the stable mud weight window for safe and efficient drilling in depleted reservoirs. Based on the laboratory test data, correlations were developed between optimum compound particle size against Young's modulus of the rock and generated fracture width for maximising the wellbore strengthening performance of the compounds. In addition, Enhanced Fracture Gradient (EFG) concept and criteria were developed for the compounds to widen the stable mud weight window. The niche workflow developed for utilisation of the wellbore strengthening design criteria and guidelines was deployedand validated in the pilot deployment of the optimum compound particle size correlations and Enhanced Fracture Gradient criteria in two wellsfor drilling through a depleted reservoir in the Malay Basin.The enhanced fracture gradient was predicted and incorporated into the mud weight programme and mud loss contingency plan of the wells. The wells were drilled with 10 ppb of the optimum mud compounds and the concentration was monitored and maintained throughout the drilling. In the first well, the maximum ECD exceeded the in-situ fracture gradient of the depleted reservoir by 1 ppg without any losses. Following TD of the hole section, an openhole leak-off test was conducted which validated the predicted average EFG of 1.8 ppg above the in-situ fracture gradient. The predicted EFG was within 0.2-0.3 ppg from the openhole leak-off test value. In the second well, the depleted reservoir was exposed to 0.6 ppg above the in-situ fracture gradient and no losses was observed.
{"title":"Pilot Deployment and Field Validation of Wellbore Strengthening Design Criteria and Enhanced Fracture Gradient in a Depleted Reservoir","authors":"C. Tan, M. S. Razak, Siti Shahara Zakaria, Abiabhar Abitalhah, Wan Nur Safawati Wan Mohd Zainudin","doi":"10.2118/209932-ms","DOIUrl":"https://doi.org/10.2118/209932-ms","url":null,"abstract":"Fracture gradient enhancementtechnology has been developed for drilling mud compounds based on comprehensive large scale laboratory test data which can widen the stable mud weight window for safe and efficient drilling in depleted reservoirs. Based on the laboratory test data, correlations were developed between optimum compound particle size against Young's modulus of the rock and generated fracture width for maximising the wellbore strengthening performance of the compounds. In addition, Enhanced Fracture Gradient (EFG) concept and criteria were developed for the compounds to widen the stable mud weight window. The niche workflow developed for utilisation of the wellbore strengthening design criteria and guidelines was deployedand validated in the pilot deployment of the optimum compound particle size correlations and Enhanced Fracture Gradient criteria in two wellsfor drilling through a depleted reservoir in the Malay Basin.The enhanced fracture gradient was predicted and incorporated into the mud weight programme and mud loss contingency plan of the wells. The wells were drilled with 10 ppb of the optimum mud compounds and the concentration was monitored and maintained throughout the drilling. In the first well, the maximum ECD exceeded the in-situ fracture gradient of the depleted reservoir by 1 ppg without any losses. Following TD of the hole section, an openhole leak-off test was conducted which validated the predicted average EFG of 1.8 ppg above the in-situ fracture gradient. The predicted EFG was within 0.2-0.3 ppg from the openhole leak-off test value. In the second well, the depleted reservoir was exposed to 0.6 ppg above the in-situ fracture gradient and no losses was observed.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123292475","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}
In drilling the reservoir sections of a well, one of the most challenging issues is reducing damage to the reservoir by controlling downhole pressure. Many drilling techniques such as underbalanced drilling (UBD) and managed pressure drilling (MPD) are employed to minimize the risks associated with drilling as well as to minimize damage to the porous rock. Even though chemical and physical damages may be short-term and could be repaired by some stimulation techniques, the long-term effects of mechanical damages in porous and fractured reservoirs have received insufficient attention. Accordingly, not only could the above drilling techniques be applied to solve downhole drilling problems, but they also may be used to reduce induced mechanical damages in fractured rocks. This article presents a new method for modeling changes in fracture permeability caused by drilling in fractured rocks. As part of the approach, the finite element method (FEM) is employed to conduct a thermo-poroelastic analysis of stress distributions around the borehole and the displacement discontinuity method (DDM) is used to model fracture deformations. Based on different fracture spacings and fracture inclination angles, we have considered models of regular fracture networks in the present study. This study focuses on the differences in permeability in underbalanced and overbalanced drilling operations that are compared together in different models. Effective stress differences (over 40 MPa) were found along and around borehole periphery. Shear stresses in the oblique fracture network also governed aperture change. Short-term mechanical stresses and long-term thermal and fluid pressures determine the fracture aperture. In the long run, fluid pressure and thermal stresses contribute to long term permeability change of fractures while mechanical stresses cause a short-term change. Underbalanced drilling was simulated to reduce fracture permeability, while cooling and pressurizing of rock encouraged fracture permeability without considering solid particle plugging. Fracture aperture adopts a seesaw pattern in a small-spaced fracture network. When the fracture aperture increases in a fracture, the neighboring fractures experience decreased apertures. Despite the drilling method, fractures intersecting boreholes have reduced permeability after drilling for a long time, as they choked in a few locations along the fracture length. At present, the industry considers managed pressure and underbalanced drilling to be the priority for resolving drilling problems. This paper investigates stress-induced damages in fractured rocks under overbalanced and underbalanced drilling conditions. It is also of significant interest in geothermal reservoirs, where the temperature difference between the rock and the well bore fluid is large. Furthermore, such an analysis would provide the optimal well location from a geomechanical and reservoir engineering standpoint.
{"title":"Understanding Thermo-Poroelastic Mechanical Stress Induced Damages in Network of Pre-Existing Fractures During Drilling Operation","authors":"Mostafa Gomar, B. Elahifar","doi":"10.2118/209837-ms","DOIUrl":"https://doi.org/10.2118/209837-ms","url":null,"abstract":"\u0000 In drilling the reservoir sections of a well, one of the most challenging issues is reducing damage to the reservoir by controlling downhole pressure. Many drilling techniques such as underbalanced drilling (UBD) and managed pressure drilling (MPD) are employed to minimize the risks associated with drilling as well as to minimize damage to the porous rock. Even though chemical and physical damages may be short-term and could be repaired by some stimulation techniques, the long-term effects of mechanical damages in porous and fractured reservoirs have received insufficient attention. Accordingly, not only could the above drilling techniques be applied to solve downhole drilling problems, but they also may be used to reduce induced mechanical damages in fractured rocks.\u0000 This article presents a new method for modeling changes in fracture permeability caused by drilling in fractured rocks. As part of the approach, the finite element method (FEM) is employed to conduct a thermo-poroelastic analysis of stress distributions around the borehole and the displacement discontinuity method (DDM) is used to model fracture deformations. Based on different fracture spacings and fracture inclination angles, we have considered models of regular fracture networks in the present study. This study focuses on the differences in permeability in underbalanced and overbalanced drilling operations that are compared together in different models.\u0000 Effective stress differences (over 40 MPa) were found along and around borehole periphery. Shear stresses in the oblique fracture network also governed aperture change. Short-term mechanical stresses and long-term thermal and fluid pressures determine the fracture aperture. In the long run, fluid pressure and thermal stresses contribute to long term permeability change of fractures while mechanical stresses cause a short-term change. Underbalanced drilling was simulated to reduce fracture permeability, while cooling and pressurizing of rock encouraged fracture permeability without considering solid particle plugging. Fracture aperture adopts a seesaw pattern in a small-spaced fracture network. When the fracture aperture increases in a fracture, the neighboring fractures experience decreased apertures. Despite the drilling method, fractures intersecting boreholes have reduced permeability after drilling for a long time, as they choked in a few locations along the fracture length.\u0000 At present, the industry considers managed pressure and underbalanced drilling to be the priority for resolving drilling problems. This paper investigates stress-induced damages in fractured rocks under overbalanced and underbalanced drilling conditions. It is also of significant interest in geothermal reservoirs, where the temperature difference between the rock and the well bore fluid is large. Furthermore, such an analysis would provide the optimal well location from a geomechanical and reservoir engineering standpoint.","PeriodicalId":226577,"journal":{"name":"Day 2 Wed, August 10, 2022","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-08-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129606594","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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