The global oil market remains uncertain in terms of the potential risk factors affecting the project deliverability targets. Therefore, the operators and service providers should continuously strive to enhance operational efficiency. The Tembikai field is a marginal field in shallow waters offshore Malaysia. Meeting the operational efficiency targets was paramount to develop and make the field economically viable. To achieve the aggressive targets, a fully offline cementing operation was introduced, which resulted in an average savings of 24 hours by offline cementing alone and 14% improved operational efficiency for each well. The five Tembikai Gas development wells were batch drilled using a jack-up rig. All wells consisted of 9 5/8 in. surface casings, 7 in. intermediate casings, and 3 1/2 in. cemented monobore completion tubing. Offline cementing for all three casing strings was planned. The offline cementing operation was performed after landing the casing at desired depth, then the rig is immediately skidded to the next well slot. While the casing is cemented offline, the rig drills the next well section, thus creating simultaneous operation efficiencies. After completing the surface section of each batch drilled well, the rig is positioned to the first well again to drill the intermediate section and the same process is repeated. Offline cementing eliminates wait on cement time (WOC) and enables the operator to perform other activities offline like running the gyro on the slickline to survey the inside of the previous casing, running cement bond logs etc. To perform the offline cementing, a separate high-pressure cementing line was rigged up to the platform. A custom-made offline cementing assembly was used. A special compact cement head, preloaded with cement plugs, was rigged up above the wellhead compact housing. This compact cement head is 33% shorter and lighter than conventional cement heads, which helped improve the safety aspects of this operation. Providing a dependable zonal isolation barrier is key for the success of an offline cementing operation. Tailored cement slurries for each section were designed to meet well requirements and advanced three-dimensional (3D) modeling software was used to simulate hole cleaning and cement slurry placement. All risks and mitigations for offline cementing such as shallow gas hazards, losses, gas kick etc. were covered in the cementing design of service (DOS) document. As a result of detailed planning and focused execution, 24 hours were saved per well by offline cementing alone, resulting in an average of seven days per well from drilling to completion of all wells in the campaign. The collaboration between the operator and cementing service provider for offline operations has proven to be a significant shift in operational efficiency in Malaysia, with time and cost savings achieved. These wells have achieved the lowest well cost per foot for current development wells in Malaysia.
{"title":"A Paradigm Shift in Well Cementing Operation - How Offline Cementing Improved Well Economics and Significant Shift in Operational Efficiency","authors":"Rama Anggarawinata, Jorge Vasquez, Ninh Nga, Brendon Tan, Aizat Noh, Azrynizam Mohamad Nor, M. Yusof","doi":"10.4043/31606-ms","DOIUrl":"https://doi.org/10.4043/31606-ms","url":null,"abstract":"\u0000 The global oil market remains uncertain in terms of the potential risk factors affecting the project deliverability targets. Therefore, the operators and service providers should continuously strive to enhance operational efficiency. The Tembikai field is a marginal field in shallow waters offshore Malaysia. Meeting the operational efficiency targets was paramount to develop and make the field economically viable. To achieve the aggressive targets, a fully offline cementing operation was introduced, which resulted in an average savings of 24 hours by offline cementing alone and 14% improved operational efficiency for each well.\u0000 The five Tembikai Gas development wells were batch drilled using a jack-up rig. All wells consisted of 9 5/8 in. surface casings, 7 in. intermediate casings, and 3 1/2 in. cemented monobore completion tubing. Offline cementing for all three casing strings was planned. The offline cementing operation was performed after landing the casing at desired depth, then the rig is immediately skidded to the next well slot. While the casing is cemented offline, the rig drills the next well section, thus creating simultaneous operation efficiencies. After completing the surface section of each batch drilled well, the rig is positioned to the first well again to drill the intermediate section and the same process is repeated. Offline cementing eliminates wait on cement time (WOC) and enables the operator to perform other activities offline like running the gyro on the slickline to survey the inside of the previous casing, running cement bond logs etc.\u0000 To perform the offline cementing, a separate high-pressure cementing line was rigged up to the platform. A custom-made offline cementing assembly was used. A special compact cement head, preloaded with cement plugs, was rigged up above the wellhead compact housing. This compact cement head is 33% shorter and lighter than conventional cement heads, which helped improve the safety aspects of this operation. Providing a dependable zonal isolation barrier is key for the success of an offline cementing operation. Tailored cement slurries for each section were designed to meet well requirements and advanced three-dimensional (3D) modeling software was used to simulate hole cleaning and cement slurry placement. All risks and mitigations for offline cementing such as shallow gas hazards, losses, gas kick etc. were covered in the cementing design of service (DOS) document. As a result of detailed planning and focused execution, 24 hours were saved per well by offline cementing alone, resulting in an average of seven days per well from drilling to completion of all wells in the campaign.\u0000 The collaboration between the operator and cementing service provider for offline operations has proven to be a significant shift in operational efficiency in Malaysia, with time and cost savings achieved. These wells have achieved the lowest well cost per foot for current development wells in Malaysia.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89634942","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. A. Patil, Asyraf M Hamimi, M. A. Bakar, D. Das, P. Tiwari, P. Chidambaram, M. A. B. A. Jalil
Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project. Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells. This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score <10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security. Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.
{"title":"Determining Long-Term Fate of a CO2 Sequestration Project Utilizing Rigorous Well Integrity Risk Assessment Strategy","authors":"P. A. Patil, Asyraf M Hamimi, M. A. Bakar, D. Das, P. Tiwari, P. Chidambaram, M. A. B. A. Jalil","doi":"10.4043/31463-ms","DOIUrl":"https://doi.org/10.4043/31463-ms","url":null,"abstract":"\u0000 Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project.\u0000 Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells.\u0000 This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score <10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security.\u0000 Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90342940","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}
F. Gathier, Cao Xulong, Ming Yukun, Yuan Fuqing, Gong Jun, Zhao Fangjian, Li Bingxian, Dorian Rotier, Changfa Zhu, Kemin Xie
The number of polymer injection projects has greatly increased worldwide in the past decade, with more and more full-field implementations. More recently, the focus has shifted towards deploying such technologies offshore, which presents specific constraints regarding facilities, logistics, or even produced water treatment. Polymer flooding is an EOR technique that has been widely implemented in China. The oil & gas company SINOPEC has gained extensive experience with polymer while developing the Shengli oil fields. The implementation of polymer flooding in the Chengdao offshore oil field was sanctioned in 2019. This large-scale project has seen polymer injection in 43 wells since October 2020. Polymer flooding helps increase oil production and accelerate recovery by providing a better sweep efficiency as a tertiary oil recovery method. It also results in unique environmental benefits with a reduction in CO2 emissions by 52 to 64% per produced barrel of oil. This project consists in injecting polymer solution in 43 wells with an overall injection rate of 32, 000 bbls/d. Polymer concentration is 3, 000 ppm, and well head injection pressure ranges from 90 barg to 130 barg. Considering the significant polymer volumes, a development with powder form has been selected with f 12 tons/day of nominal consumption. While requiring a larger footprint and slightly more CAPEX, it helped significantly reduce OPEX and transportation costs. In addition, specific equipment and technologies have been selected and implemented to prepare a highly viscous polymer solution, reduce maturation time and prevent any form of chemical or mechanical degradation. This paper will also present recent developments with the use of non-shearing choke valves to avoid significant drop in polymer viscosity. This project is now in operation for 18 months (April 2022) with more than 2, 8 million m3 of polymer solution injection. High injection reliability has been achieved (>98%) for all logistics, operations, and topside equipments. The Chengdao 22F EOR polymer flood pilot project drains an oil-bearing area of 3.21 square kilometers with an estimated initial oil in place (STOIIP) of 80.7 million bbls (12.04 million tons) of which 28.8 million bbls (4.3 million tons) are located within the central producing area. A total of 22 injection and 57 production wells have been drilled. It is predicted that cumulative oil production will reach 28.2 million bbls (4.21 million tons) after 15 years, with an estimated incremental oil recovery factor of 11.6% from polymer injection. Following polymer injection, the water cut start to drop from 90.2% down to 85.0% at few production wells and should continue to drop down to 80%. This paper will provide guidelines to help implementing successfully large-scale chemical EOR projects in an offshore environment. It will also present recent developments in non-shearing choke valves and specific equipment to optimize the injection-facilities’ over
{"title":"Offshore Large Scale Polymer Flood Implementation at Chengdao Field","authors":"F. Gathier, Cao Xulong, Ming Yukun, Yuan Fuqing, Gong Jun, Zhao Fangjian, Li Bingxian, Dorian Rotier, Changfa Zhu, Kemin Xie","doi":"10.4043/31527-ms","DOIUrl":"https://doi.org/10.4043/31527-ms","url":null,"abstract":"\u0000 The number of polymer injection projects has greatly increased worldwide in the past decade, with more and more full-field implementations. More recently, the focus has shifted towards deploying such technologies offshore, which presents specific constraints regarding facilities, logistics, or even produced water treatment.\u0000 Polymer flooding is an EOR technique that has been widely implemented in China. The oil & gas company SINOPEC has gained extensive experience with polymer while developing the Shengli oil fields. The implementation of polymer flooding in the Chengdao offshore oil field was sanctioned in 2019. This large-scale project has seen polymer injection in 43 wells since October 2020.\u0000 Polymer flooding helps increase oil production and accelerate recovery by providing a better sweep efficiency as a tertiary oil recovery method. It also results in unique environmental benefits with a reduction in CO2 emissions by 52 to 64% per produced barrel of oil.\u0000 This project consists in injecting polymer solution in 43 wells with an overall injection rate of 32, 000 bbls/d. Polymer concentration is 3, 000 ppm, and well head injection pressure ranges from 90 barg to 130 barg.\u0000 Considering the significant polymer volumes, a development with powder form has been selected with f 12 tons/day of nominal consumption. While requiring a larger footprint and slightly more CAPEX, it helped significantly reduce OPEX and transportation costs. In addition, specific equipment and technologies have been selected and implemented to prepare a highly viscous polymer solution, reduce maturation time and prevent any form of chemical or mechanical degradation.\u0000 This paper will also present recent developments with the use of non-shearing choke valves to avoid significant drop in polymer viscosity.\u0000 This project is now in operation for 18 months (April 2022) with more than 2, 8 million m3 of polymer solution injection. High injection reliability has been achieved (>98%) for all logistics, operations, and topside equipments.\u0000 The Chengdao 22F EOR polymer flood pilot project drains an oil-bearing area of 3.21 square kilometers with an estimated initial oil in place (STOIIP) of 80.7 million bbls (12.04 million tons) of which 28.8 million bbls (4.3 million tons) are located within the central producing area. A total of 22 injection and 57 production wells have been drilled. It is predicted that cumulative oil production will reach 28.2 million bbls (4.21 million tons) after 15 years, with an estimated incremental oil recovery factor of 11.6% from polymer injection. Following polymer injection, the water cut start to drop from 90.2% down to 85.0% at few production wells and should continue to drop down to 80%.\u0000 This paper will provide guidelines to help implementing successfully large-scale chemical EOR projects in an offshore environment. It will also present recent developments in non-shearing choke valves and specific equipment to optimize the injection-facilities’ over","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"112 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87826468","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}
Samba Ba, Joshua Zhang, Yueling Shen, Wei Chen, B. Jeffryes, H. Sahli
It is often essential that the behavior of certain tools inside of the bottomhole assembly (BHA) be understood, prior to automating the well construction process. The mud motor is one of the most frequently used BHA components worldwide. This paper presents several digital well construction procedures in which a mud motor is located inside of the BHA. Mud motors can be directly used in a steering mode or can be combined with the most advanced rotary steerable system (RSS) tools in power only mode because their downhole power ability is unrivaled, and their usage reduces the power needed from surface, making the well construction more sustainable. When considering the six primary surface measurements of well construction (hookload, block position, torque, rpm, pressure, and flow), the interpretation of four of the measurements is directly affected by the presence or not of a mud motor inside the BHA, whether the mud motor is in steering mode or in power only mode. To understand these measurements, a basic understanding of the mud motor physics is required. This paper will present some of the kinematics of the mud motor power section and how it relates to the monitoring, advising, or controlling of the drilling process. In particular, some key equations will be shown that correlate surface measurements to the downhole drill-bit motion through the motor physics. It will be shown that when a mud motor is present, there is a torque discontinuity between the upper portion (above the motor) of the BHA and drillstring and the lower portion of the BHA (below the motor). In addition, equations to fit mud motor power curves are derived, which enables interpretation of the motor power section performance based on the chosen configuration. The acoustic impedance theory for the mud motor will also be shown, which enables understanding the transient effect of flow fluctuations when different torque demands from the drill-bit exist. All these derivations are included in a new mechanical specific energy (MSE) calculation which will be used to derive an autonomous well construction scheme. A novel approach to understanding the monitoring, advising, and controlling of the drilling process when a mud motor is present within the BHA is presented. This approach, which is based on the careful understanding of the mud motor physics and enables automation of the well construction, would be a forerunner for most artificial intelligence (AI) and machine learning (ML) algorithms used to optimize drilling operations when a hydromechanical power generator is present in the BHA.
{"title":"Digital Well Construction with Mud Motor Applications","authors":"Samba Ba, Joshua Zhang, Yueling Shen, Wei Chen, B. Jeffryes, H. Sahli","doi":"10.4043/31486-ms","DOIUrl":"https://doi.org/10.4043/31486-ms","url":null,"abstract":"\u0000 It is often essential that the behavior of certain tools inside of the bottomhole assembly (BHA) be understood, prior to automating the well construction process. The mud motor is one of the most frequently used BHA components worldwide. This paper presents several digital well construction procedures in which a mud motor is located inside of the BHA. Mud motors can be directly used in a steering mode or can be combined with the most advanced rotary steerable system (RSS) tools in power only mode because their downhole power ability is unrivaled, and their usage reduces the power needed from surface, making the well construction more sustainable.\u0000 When considering the six primary surface measurements of well construction (hookload, block position, torque, rpm, pressure, and flow), the interpretation of four of the measurements is directly affected by the presence or not of a mud motor inside the BHA, whether the mud motor is in steering mode or in power only mode. To understand these measurements, a basic understanding of the mud motor physics is required. This paper will present some of the kinematics of the mud motor power section and how it relates to the monitoring, advising, or controlling of the drilling process.\u0000 In particular, some key equations will be shown that correlate surface measurements to the downhole drill-bit motion through the motor physics. It will be shown that when a mud motor is present, there is a torque discontinuity between the upper portion (above the motor) of the BHA and drillstring and the lower portion of the BHA (below the motor). In addition, equations to fit mud motor power curves are derived, which enables interpretation of the motor power section performance based on the chosen configuration. The acoustic impedance theory for the mud motor will also be shown, which enables understanding the transient effect of flow fluctuations when different torque demands from the drill-bit exist. All these derivations are included in a new mechanical specific energy (MSE) calculation which will be used to derive an autonomous well construction scheme.\u0000 A novel approach to understanding the monitoring, advising, and controlling of the drilling process when a mud motor is present within the BHA is presented. This approach, which is based on the careful understanding of the mud motor physics and enables automation of the well construction, would be a forerunner for most artificial intelligence (AI) and machine learning (ML) algorithms used to optimize drilling operations when a hydromechanical power generator is present in the BHA.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73650845","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}
Nurul Ezween Binti Hasbi, Junnyaruin Barat, L. Maluan, Sharon Ellen Lidwin
Surface Controlled Subsurface Safety Valves (SCSSV) is a critical completion accessory to maintain the Safe Operation Envelope (SOE) of the well and ensuring the production sustainability. In PCSB, it is a requirement that SCSSVs are tested on specific periods to ensure this safety device meet the acceptance requirement as per company guideline. Monitoring and maintaining the SCSSVs is proven to be challenging for E1 gas fields, located in Offshore Malaysia. Wells in E1 field, recently transferred operatorship, is an aging field producing since August 1982. The wells are equipped with Wireline Retrievable SCSSV (WRSCSSV). Within few months after operating this well, few cases of SCSSVs inoperability were encountered, resulted in significant gas production loss from E1. The main problems with SCSSV are: Control line hydraulic pressure unable to build up and maintain, hence unable to flow the well as SCSSV unable to open. Abnormal hydraulic return observed. E11 wells tripped due to Wellhead Control Panel Hydraulic pressure header hit low-ow trip setpoint. Inoperable after well close in, indication of control line leak. Immediate action taken to rectify include retrieving the WRSCSSV and installing redressed old WRSCSSV, injecting and displacing of Pressure Activated Sealant through control line to patch leak point. Root Cause Failure Analysis (RCFA) conducted on the wells identified preliminary factors that lead to E1 SCSSV issues: Frequent SCSSV cycling with high control line pressure in depleted well pressure (Frequent well tripping and monthly Corrosion Inhibitor batching activity requires close in and opening of SCSSV). Non-compatible SCSSV elastomeric parts with production & CI batching chemical. Wear & tear and corrosion due to valve age (manufactured in 1982 & 1985). Worn out seal bore of BP-6 landing nipple. Short term solution such as reviewing the recommended hydraulic line opening pressure, downhole visual inspection, pressure activated sealant and caliper survey to confirm BP-6 Landing Nipple seal bore damage, Swellable Packer/O-ring (External) and re-dress using non-upgraded Elastomers (Internal) had been planned. Contingency for subsurface controlled SSV and replacement using new WRSCSSV had been put in place as long-term solution. This paper describes operator experience in managing the challenges in maintaining SCSSV operability, diagnostic and solution recommended to avoid production deferment due to this issue.
{"title":"Challenges in Managing Surface Controlled Subsurface Safety Valve SCSSV Integrity Issue in Gas Field, Offshore Malaysia","authors":"Nurul Ezween Binti Hasbi, Junnyaruin Barat, L. Maluan, Sharon Ellen Lidwin","doi":"10.4043/31619-ms","DOIUrl":"https://doi.org/10.4043/31619-ms","url":null,"abstract":"\u0000 Surface Controlled Subsurface Safety Valves (SCSSV) is a critical completion accessory to maintain the Safe Operation Envelope (SOE) of the well and ensuring the production sustainability. In PCSB, it is a requirement that SCSSVs are tested on specific periods to ensure this safety device meet the acceptance requirement as per company guideline.\u0000 Monitoring and maintaining the SCSSVs is proven to be challenging for E1 gas fields, located in Offshore Malaysia. Wells in E1 field, recently transferred operatorship, is an aging field producing since August 1982. The wells are equipped with Wireline Retrievable SCSSV (WRSCSSV). Within few months after operating this well, few cases of SCSSVs inoperability were encountered, resulted in significant gas production loss from E1. The main problems with SCSSV are:\u0000 Control line hydraulic pressure unable to build up and maintain, hence unable to flow the well as SCSSV unable to open. Abnormal hydraulic return observed. E11 wells tripped due to Wellhead Control Panel Hydraulic pressure header hit low-ow trip setpoint. Inoperable after well close in, indication of control line leak.\u0000 Immediate action taken to rectify include retrieving the WRSCSSV and installing redressed old WRSCSSV, injecting and displacing of Pressure Activated Sealant through control line to patch leak point. Root Cause Failure Analysis (RCFA) conducted on the wells identified preliminary factors that lead to E1 SCSSV issues:\u0000 Frequent SCSSV cycling with high control line pressure in depleted well pressure (Frequent well tripping and monthly Corrosion Inhibitor batching activity requires close in and opening of SCSSV). Non-compatible SCSSV elastomeric parts with production & CI batching chemical. Wear & tear and corrosion due to valve age (manufactured in 1982 & 1985). Worn out seal bore of BP-6 landing nipple.\u0000 Short term solution such as reviewing the recommended hydraulic line opening pressure, downhole visual inspection, pressure activated sealant and caliper survey to confirm BP-6 Landing Nipple seal bore damage, Swellable Packer/O-ring (External) and re-dress using non-upgraded Elastomers (Internal) had been planned. Contingency for subsurface controlled SSV and replacement using new WRSCSSV had been put in place as long-term solution. This paper describes operator experience in managing the challenges in maintaining SCSSV operability, diagnostic and solution recommended to avoid production deferment due to this issue.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"76 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78687241","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 describes a new offshore CO2 sequestration concept: The Floating Hub Solution for Offshore CO2 Injection and Sequestration called in this paper Offshore C-Hub, proposes a flexible transport and storage solution for captured and liquefied carbon dioxide. The Offshore C-Hub allows permanent CO2 sequestration in an offshore geological reservoir from multiple CO2 emitters via an offshore floating storage and injection facility. The paper details key elements of the concept, tested in different case studies, and shares results on technical, economic and carbon footprint assessments. Carbon Capture and Storage (CCS) is circa 10% of the total expected reduction for global Green House Gas (GHG) emissions in the next 30 years (IEA, 2018). Therefore, the contemplated unit will enable a significant CO2 injection capacity (several Million tons per annum) to provide an industrial scale solution. The Offshore C-Hub concept is a novel floating facility allowing temporary storage and processing of CO2 prior to its continuous injection into a geological reservoir. It is part of a global CO2 management chain comprising the following steps: Onshore CO2 capture, liquefaction, and temporary storage (or from offshore oil and gas production facilities) Liquid CO2 transportation by ships Offshore CO2 offloading to the Offshore C-Hub Offshore C-Hub injection process and storage Subsea systems to inject the CO2 in the geological reservoir The generic studies demonstrate the Offshore C-Hub technical and economic feasibility considering a logistical approach and based on the main technological choices for some of the key components. The paper also assesses the technology maturity of the proposed system. The carbon footprint assessment finally allows identification of alternate means to ensure a low carbon solution and reinforces the performance of the solution. Until today, projects involving CO2 injection in geological reservoirs have been based on onshore or offshore pipelines. This work describes a new floating solution for offshore CO2 continuous injection and sequestration. The paper explains the key benefits of this solution, such as adaptability to project specifics (capacity, distances, etc.) and the ability to receive CO2 from multiple emitters in various locations. The floating concept also provides strategic advantage by allowing rapid deployment and potential future relocation.
{"title":"A Floating Hub Solution for Offshore CO2 Injection and Sequestration","authors":"A. Lopez, Cyrille Dechiron, Morvan Favennec","doi":"10.4043/31566-ms","DOIUrl":"https://doi.org/10.4043/31566-ms","url":null,"abstract":"\u0000 This paper describes a new offshore CO2 sequestration concept: The Floating Hub Solution for Offshore CO2 Injection and Sequestration called in this paper Offshore C-Hub, proposes a flexible transport and storage solution for captured and liquefied carbon dioxide.\u0000 The Offshore C-Hub allows permanent CO2 sequestration in an offshore geological reservoir from multiple CO2 emitters via an offshore floating storage and injection facility.\u0000 The paper details key elements of the concept, tested in different case studies, and shares results on technical, economic and carbon footprint assessments.\u0000 Carbon Capture and Storage (CCS) is circa 10% of the total expected reduction for global Green House Gas (GHG) emissions in the next 30 years (IEA, 2018). Therefore, the contemplated unit will enable a significant CO2 injection capacity (several Million tons per annum) to provide an industrial scale solution.\u0000 The Offshore C-Hub concept is a novel floating facility allowing temporary storage and processing of CO2 prior to its continuous injection into a geological reservoir. It is part of a global CO2 management chain comprising the following steps:\u0000 Onshore CO2 capture, liquefaction, and temporary storage (or from offshore oil and gas production facilities) Liquid CO2 transportation by ships Offshore CO2 offloading to the Offshore C-Hub Offshore C-Hub injection process and storage Subsea systems to inject the CO2 in the geological reservoir\u0000 The generic studies demonstrate the Offshore C-Hub technical and economic feasibility considering a logistical approach and based on the main technological choices for some of the key components. The paper also assesses the technology maturity of the proposed system.\u0000 The carbon footprint assessment finally allows identification of alternate means to ensure a low carbon solution and reinforces the performance of the solution.\u0000 Until today, projects involving CO2 injection in geological reservoirs have been based on onshore or offshore pipelines.\u0000 This work describes a new floating solution for offshore CO2 continuous injection and sequestration.\u0000 The paper explains the key benefits of this solution, such as adaptability to project specifics (capacity, distances, etc.) and the ability to receive CO2 from multiple emitters in various locations.\u0000 The floating concept also provides strategic advantage by allowing rapid deployment and potential future relocation.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78661579","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}
Abdoulelah Naji Al-Hannabi, A. Rehman, Yousef A. Al-Munif, Kazem Hussain Al-Musabbeh
Autonomous inspection robots have emerged as a theme in the digital transformation era, under the umbrella of industrial smart plants for their claimed superiority, safe operation, and cost-effectiveness. Autonomous inspection robots play an essential role in inspecting inaccessible pipelines and process piping, due to their great maneuverability to traverse various bends and geometries, e.g., elbows and T-joints. Saudi Aramco Inspection Department, in collaboration with Shaybah Producing Department, conducted a field trial of an autonomous robot to apply multiple inspection methods simultaneously, in an inaccessible 30" gas pipeline. The robotic system is equipped with motored magnetic wheels to enable movement inside the pipe and can hold the inspection system at certain pre-defined coordinates. The pilot study concluded that the autonomous robot provides accurate corrosion mapping and performs different inspection simultaneously. In addition, the robot has demonstrated great maneuverability inside the pipe in all orientations, i.e. axial, circumferential, and in between. The system has shown a strong potential to inspect inaccessible piping system while minimizing extremely expensive practices, e.g. scaffold erections, excavations, in a timely manner, with ease on logistics and labor. The use of autonomous robotic scanner provides the operating facility with an option, which is cost-effective and requires a single deployment to complete multiple inspection tasks. The system is capable of replacing the current practice of deploying multiple technologies for a complete inspection inside the pipeline. The system is a self-contained inspection robot that conduct various inspection functions simultaneously, including: Optical Video System, Ultrasonic Guided Waves, Ultrasonic Shear Wave and Ultrasonic Corrosion Mapping with dry-point contact transducers. The system will detect flaws, identify their type and measure the parameters of the pipeline's base metal, welding defects, and provided detailed information and data on the condition of the examined assets, while internally scanning the pipeline. The robot requires, minimum clean-up, and has great maneuverability to go through various bends and geometries, i.e. elbows, T-joints, etc. The autonomous robot can be inserted through the available manhole hatches. The robot is wireless capable and can reach up to 1,000 — 1,500 meters inside the pipe, while being controlled and inspection data is received continuously in outside control room.
在工业智能工厂的保护伞下，自主检测机器人因其标榜的优越性、安全性和成本效益而成为数字化转型时代的一个主题。自主检测机器人在检测难以接近的管道和工艺管道方面发挥着至关重要的作用，因为它们具有很强的可操作性，可以穿越各种弯道和几何形状，例如弯头和t形接头。Saudi Aramco Inspection Department与Shaybah production Department合作，对一种自动机器人进行了现场试验，该机器人可以在一条难以接近的30英寸天然气管道中同时应用多种检测方法。机器人系统配备了机动磁轮，可以在管道内移动，并可以将检测系统保持在特定的预定坐标上。初步研究的结论是，自主机器人提供了准确的腐蚀测绘，并同时执行不同的检测。此外，该机器人在管道内的所有方向(即轴向，周向以及两者之间)都表现出了很强的可操作性。该系统显示出强大的潜力，可以检查难以接近的管道系统，同时最大限度地减少极其昂贵的操作，例如脚手架的安装，挖掘，及时，易于后勤和劳动力。自动机器人扫描仪的使用为操作设施提供了一种选择，这种选择具有成本效益，并且只需一次部署即可完成多个检查任务。该系统能够取代目前部署多种技术对管道内部进行全面检查的做法。该系统是一个独立的检测机器人，可同时进行多种检测功能，包括:光学视频系统、超声导波、超声剪切波和超声腐蚀测绘，配有干点接触换能器。该系统将检测缺陷，识别其类型并测量管道母材的参数，焊接缺陷，并提供有关被检查资产状况的详细信息和数据，同时内部扫描管道。该机器人需要最少的清理，并且具有很强的机动性，可以通过各种弯曲和几何形状，例如肘部，t形接头等。自动机器人可以通过可用的人孔舱口插入。该机器人具有无线能力，可以到达管道内部1000 - 1500米，同时在外部控制室连续接收控制和检测数据。
{"title":"Autonomous Robot in the Field of Inaccessible Piping System Inspection","authors":"Abdoulelah Naji Al-Hannabi, A. Rehman, Yousef A. Al-Munif, Kazem Hussain Al-Musabbeh","doi":"10.4043/31542-ms","DOIUrl":"https://doi.org/10.4043/31542-ms","url":null,"abstract":"\u0000 Autonomous inspection robots have emerged as a theme in the digital transformation era, under the umbrella of industrial smart plants for their claimed superiority, safe operation, and cost-effectiveness. Autonomous inspection robots play an essential role in inspecting inaccessible pipelines and process piping, due to their great maneuverability to traverse various bends and geometries, e.g., elbows and T-joints. Saudi Aramco Inspection Department, in collaboration with Shaybah Producing Department, conducted a field trial of an autonomous robot to apply multiple inspection methods simultaneously, in an inaccessible 30\" gas pipeline. The robotic system is equipped with motored magnetic wheels to enable movement inside the pipe and can hold the inspection system at certain pre-defined coordinates. The pilot study concluded that the autonomous robot provides accurate corrosion mapping and performs different inspection simultaneously. In addition, the robot has demonstrated great maneuverability inside the pipe in all orientations, i.e. axial, circumferential, and in between. The system has shown a strong potential to inspect inaccessible piping system while minimizing extremely expensive practices, e.g. scaffold erections, excavations, in a timely manner, with ease on logistics and labor.\u0000 The use of autonomous robotic scanner provides the operating facility with an option, which is cost-effective and requires a single deployment to complete multiple inspection tasks. The system is capable of replacing the current practice of deploying multiple technologies for a complete inspection inside the pipeline. The system is a self-contained inspection robot that conduct various inspection functions simultaneously, including: Optical Video System, Ultrasonic Guided Waves, Ultrasonic Shear Wave and Ultrasonic Corrosion Mapping with dry-point contact transducers. The system will detect flaws, identify their type and measure the parameters of the pipeline's base metal, welding defects, and provided detailed information and data on the condition of the examined assets, while internally scanning the pipeline. The robot requires, minimum clean-up, and has great maneuverability to go through various bends and geometries, i.e. elbows, T-joints, etc. The autonomous robot can be inserted through the available manhole hatches. The robot is wireless capable and can reach up to 1,000 — 1,500 meters inside the pipe, while being controlled and inspection data is received continuously in outside control room.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78832184","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}
Dmitry N Pleshkov, B. Corella, Luis Paredes, Angel Vicente Silva Ortiz, Augusto Huaca, F. Chicaiza, Gustavo Ariel Marin, Carlos Andres Corella Moya, Raul Armando Valencia Tapia
Most of the fields in Ecuador are considered "mature." Water injection is a well-known solution for mature fields. Water injection projects require a source of clean water. Traditionally, minimum specifications are achieved by surface treatment facilities. However, in the Ecuadorian Oriente Basin, the Hollin reservoir is an active aquifer with water meeting the requirements for use in waterflooding. But in other cases, water from production wells and from traditional surface facilities requires high investment costs because of associated facilities, chemical treatments, water production lines, and other requirements. A novel completion design has been developed. This proposed completion is called "modified dumpflooding" and represents a cost-effective solution for Ecuadorian mature fields. Dumpflooding is a modified version of dual concentric completion using most of its configuration pieces. It also takes advantage of extensive local experience in dual concentric completion design. Modified dumpflooding completion enables companies to use just one well for water production, injecting it into the depleted reservoir as a closed loop. Additionally, it helps to save costs in surface facilities by reducing human exposure to high pressure lines over large distances and eliminating operational expenditures for chemicals and equipment maintenance. Nodal analysis is foundational to helping companies understand how current design of waterflooding projects is behaving. It also provides a basis for mechanical configuration optimization to reduce bottlenecking points and improve completion performance.
{"title":"Disruptive Dumpflooding Completion, Case Study Ecuador","authors":"Dmitry N Pleshkov, B. Corella, Luis Paredes, Angel Vicente Silva Ortiz, Augusto Huaca, F. Chicaiza, Gustavo Ariel Marin, Carlos Andres Corella Moya, Raul Armando Valencia Tapia","doi":"10.4043/31533-ms","DOIUrl":"https://doi.org/10.4043/31533-ms","url":null,"abstract":"\u0000 Most of the fields in Ecuador are considered \"mature.\" Water injection is a well-known solution for mature fields. Water injection projects require a source of clean water. Traditionally, minimum specifications are achieved by surface treatment facilities. However, in the Ecuadorian Oriente Basin, the Hollin reservoir is an active aquifer with water meeting the requirements for use in waterflooding. But in other cases, water from production wells and from traditional surface facilities requires high investment costs because of associated facilities, chemical treatments, water production lines, and other requirements. A novel completion design has been developed. This proposed completion is called \"modified dumpflooding\" and represents a cost-effective solution for Ecuadorian mature fields. Dumpflooding is a modified version of dual concentric completion using most of its configuration pieces. It also takes advantage of extensive local experience in dual concentric completion design. Modified dumpflooding completion enables companies to use just one well for water production, injecting it into the depleted reservoir as a closed loop. Additionally, it helps to save costs in surface facilities by reducing human exposure to high pressure lines over large distances and eliminating operational expenditures for chemicals and equipment maintenance. Nodal analysis is foundational to helping companies understand how current design of waterflooding projects is behaving. It also provides a basis for mechanical configuration optimization to reduce bottlenecking points and improve completion performance.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74579787","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}
Nur Izzati Izureen Adnan, Intan Shazlina, A. Sinha, A. Faisal, A. N. M Sobri
One of the key objectives for late field life management is aimed at unlocking production volumes below pipeline turndown rate (TDR). This can be achieved through new subsurface opportunities to keep total hub production above TDR and through operational management strategy to unlock below TDR volumes. This paper presents a reflection of technical studies conducted to extend hub production life and value creation for all stakeholders through technical due diligence, cost compression and operational excellence strategies. Hub-A caters to production from two carbonate gas fields in Sarawak region and needs to maintain total production >120 MMscf/d to meet pipeline TDR. The hub was expected to go below TDR in Year-2022 and to sustain the hub production beyond 2022, attic gas volumes in one of the feeder fields were identified for future development to potentially add incremental gas production to the hub and extend operational life by 2.5 years. However, based on techno-commercial assessment, the project wasn't considered viable for development. Additionally, recent production performance indicated sharp increase in water-gas ratio from existing fields with the outlook indicating an early timeline for hub production to go below TDR. This necessitated several surface studies to be commissioned for hub protection with the primary objective of assessing technical feasibility to continue production below TDR limit. These studies focused on flow assurance studies for main trunkline & satellite pipelines, corrosion study for pipeline remnant life assessment, operating philosophy for production management and capacity assessment for onshore facilities. For long-term roadmap, future gas feeders were also identified for hub sustenance beyond cessation of production from existing fields. With the implementation of short-term and long-term production strategy as part of operation & management philosophy, ~26 MMboe of below TDR volumes from existing fields are expected to be unlocked and the hub producing life is expected to be extended by >6 years with significant reduction in operational expenditure. Additionally, exploration roadmap has been strategized in synergy with hub outlook to provide long-term gas supply until 2040. This is expected to generate significant value through continued revenue generation and keeping the hub in operable conditions for future tie-ins from new feeders and nearby gas field developments. This paper presents novel operational strategy to unlock below pipeline TDR volumes for late field life management and integrated roadmap development for long-term value creation with synergy across exploration and development portfolio in the region.
{"title":"Integrated Hub Roadmap Adds 18 Years to Operational Life: Case Study from Gas Hub in Sarawak","authors":"Nur Izzati Izureen Adnan, Intan Shazlina, A. Sinha, A. Faisal, A. N. M Sobri","doi":"10.4043/31598-ms","DOIUrl":"https://doi.org/10.4043/31598-ms","url":null,"abstract":"\u0000 One of the key objectives for late field life management is aimed at unlocking production volumes below pipeline turndown rate (TDR). This can be achieved through new subsurface opportunities to keep total hub production above TDR and through operational management strategy to unlock below TDR volumes. This paper presents a reflection of technical studies conducted to extend hub production life and value creation for all stakeholders through technical due diligence, cost compression and operational excellence strategies.\u0000 Hub-A caters to production from two carbonate gas fields in Sarawak region and needs to maintain total production >120 MMscf/d to meet pipeline TDR. The hub was expected to go below TDR in Year-2022 and to sustain the hub production beyond 2022, attic gas volumes in one of the feeder fields were identified for future development to potentially add incremental gas production to the hub and extend operational life by 2.5 years. However, based on techno-commercial assessment, the project wasn't considered viable for development.\u0000 Additionally, recent production performance indicated sharp increase in water-gas ratio from existing fields with the outlook indicating an early timeline for hub production to go below TDR. This necessitated several surface studies to be commissioned for hub protection with the primary objective of assessing technical feasibility to continue production below TDR limit. These studies focused on flow assurance studies for main trunkline & satellite pipelines, corrosion study for pipeline remnant life assessment, operating philosophy for production management and capacity assessment for onshore facilities.\u0000 For long-term roadmap, future gas feeders were also identified for hub sustenance beyond cessation of production from existing fields.\u0000 With the implementation of short-term and long-term production strategy as part of operation & management philosophy, ~26 MMboe of below TDR volumes from existing fields are expected to be unlocked and the hub producing life is expected to be extended by >6 years with significant reduction in operational expenditure. Additionally, exploration roadmap has been strategized in synergy with hub outlook to provide long-term gas supply until 2040.\u0000 This is expected to generate significant value through continued revenue generation and keeping the hub in operable conditions for future tie-ins from new feeders and nearby gas field developments.\u0000 This paper presents novel operational strategy to unlock below pipeline TDR volumes for late field life management and integrated roadmap development for long-term value creation with synergy across exploration and development portfolio in the region.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78172382","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}
Tomoya Inoue, Yujin Nakagawa, R. Wada, Keisuke Miyoshi, Shungo Abe, Kouhei Kuroda, Masatoshi Nishi, Hakan Bilen, Konda Reddy Mopuri
The early detection of a stuck pipe event is crucial as it is one of the major incidents resulting in nonproductive time. An ordinary supervised machine learning approach has been adopted to achieve the detection of stuck pipe in some previous studies. However, for early detection before stuck occurs with this approach, there are challenging issues such as limited stuck pipe data, various causes of stuck, and the lack of a prior exact "stuck sign" which should be a label in the training dataset. In this study, the surface drilling data is first collected from multiple agencies to enhance the training dataset. Subsequently, a supervised machine learning algorithm with ordinary binary classification methodologies, such as support vector machines and neural networks is adopted. The supervised machine learning approach presents good performance for stuck pipe event detection. However, it detects "stuck has already occurred", and it cannot effectively predict the stuck pipe because there is no exact sign for stuck pipe which is mandatory as label for training data. This study also adopts an unsupervised machine learning algorithm which employs architectures that include an autoencoder with long short-term memory, as well as a multiple prediction model to improve the expressiveness. The unsupervised machine learning process typically involves learning the features of normal activities, whereby the created model can represent only these activities. When stuck occurs or will occur, as such data are not represented by the created model, it should be detected. The performance of the early stuck pipe event detection using supervised and unsupervised machine learning approaches is analyzed, and the results demonstrate that the unsupervised machine learning approach presents a better early stuck pipe detection capability. The proposed machine learning algorithm will be further improved in the future and the prediction result will be validated through actual operation.
{"title":"Early Stuck Detection Using Supervised and Unsupervised Machine Learning Approaches","authors":"Tomoya Inoue, Yujin Nakagawa, R. Wada, Keisuke Miyoshi, Shungo Abe, Kouhei Kuroda, Masatoshi Nishi, Hakan Bilen, Konda Reddy Mopuri","doi":"10.4043/31376-ms","DOIUrl":"https://doi.org/10.4043/31376-ms","url":null,"abstract":"\u0000 The early detection of a stuck pipe event is crucial as it is one of the major incidents resulting in nonproductive time. An ordinary supervised machine learning approach has been adopted to achieve the detection of stuck pipe in some previous studies. However, for early detection before stuck occurs with this approach, there are challenging issues such as limited stuck pipe data, various causes of stuck, and the lack of a prior exact \"stuck sign\" which should be a label in the training dataset.\u0000 In this study, the surface drilling data is first collected from multiple agencies to enhance the training dataset. Subsequently, a supervised machine learning algorithm with ordinary binary classification methodologies, such as support vector machines and neural networks is adopted. The supervised machine learning approach presents good performance for stuck pipe event detection. However, it detects \"stuck has already occurred\", and it cannot effectively predict the stuck pipe because there is no exact sign for stuck pipe which is mandatory as label for training data.\u0000 This study also adopts an unsupervised machine learning algorithm which employs architectures that include an autoencoder with long short-term memory, as well as a multiple prediction model to improve the expressiveness. The unsupervised machine learning process typically involves learning the features of normal activities, whereby the created model can represent only these activities. When stuck occurs or will occur, as such data are not represented by the created model, it should be detected.\u0000 The performance of the early stuck pipe event detection using supervised and unsupervised machine learning approaches is analyzed, and the results demonstrate that the unsupervised machine learning approach presents a better early stuck pipe detection capability. The proposed machine learning algorithm will be further improved in the future and the prediction result will be validated through actual operation.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"43 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79981043","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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