Kuhaneswaren Ramah Moorthy, Nik Mohd Mokhzani Mohd Zainudin, Nazri Nor, Nabilla Arief Tham, Pin Y Huang, Eliza Ishak, A. M. Ismail, D. A. Wijoseno, I. Sorman, Nigel Yong, Hai Liu, C. Nwafor, Kong Teng Ling, Rahmat Wibisono
Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention. An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety. A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.
{"title":"Integrated Engineered Solution for Realtime Through-Tubing Remedial Sand Control","authors":"Kuhaneswaren Ramah Moorthy, Nik Mohd Mokhzani Mohd Zainudin, Nazri Nor, Nabilla Arief Tham, Pin Y Huang, Eliza Ishak, A. M. Ismail, D. A. Wijoseno, I. Sorman, Nigel Yong, Hai Liu, C. Nwafor, Kong Teng Ling, Rahmat Wibisono","doi":"10.2118/197212-ms","DOIUrl":"https://doi.org/10.2118/197212-ms","url":null,"abstract":"\u0000 Coiled tubing (CT) sand cleanout has been a normal practice for offshore wells, and repeated cleanout runs will have to be done over the years to sustain production. It has been observed that the production period of these offshore wells has shortened significantly after each cleanout due to sand particles loading up in the production tubing at a faster rate. This production trend is typical for wells with no downhole sand control in the original completion. Various aspects in terms of well design and reservoir conditions have significantly increased the complexity of sand cleanout. This, for example, includes the large 9 5/8-in. casing section with small dual upper completions of 2 7/8-in. production tubing, a high angle with a long horizontal section, and severely drawn-down reservoirs. There were also previous findings on the well where cement pebbles were found on the production choke at surface contributing to higher risk during intervention.\u0000 An integrated engineered solution was brought forward to successfully execute the CT sand cleanout job by capitalizing on both engineering and operational efficiencies. In terms of technical and engineering design, real-time fiber-optic downhole telemetry system, nitrified cleanout with a shear-thinning gel fluid that has superior suspension ability, and a milling tool for cement pebble cleanout were utilized. Operationally, an electrical submersible pumping (ESP) system capable of providing continuous supply of seawater and custom-built skidding beams for sand screen deployment purposes were also introduced for the first time for CT operations in southeast Asia that successfully improved operational efficiency and job safety.\u0000 A remedial sand control solution was also used to improve production longevity after sand cleanout, without doing any major pull-tubing workover or sidetrack drilling. Either through-tubing sand screens or a sand agglomeration treatment technique was carefully chosen and deployed to address the sand load-up issue in these wells. This paper discusses the operations, challenges, and the key success factors that have contributed to a well-engineered CT cleanout and deployment of sand screen and sand agglomeration treatment.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89507259","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}
Wenyang Zhao, Ahmed Khaleefa Al-Neaimi, Arlen Sarsekov, O. Saif, A. Abed, Mohamed Helmy Al-feky
With an increased maturity and complexity of the reservoir, an optimized field development plan implementation is critical to achieve the planned target and to ensure an optimum field recovery. The paper presents an optimized process with uncertainty analysis based on Monte Carlo Simulation for the purpose of optimizing the Medium Term Development Plan (MTDP) implementation. The five year development plan of this giant offshore field has been successfully assessed based on this optimized approach. The integrated workflow consists of four main parts, including actual field technical rate tracking, DBC optimization, simulation results, and effective capacity with Monte Carlo simulation embedded. The dynamic situations could be taken care with these seamless coupled tools. The actual field technical rate has been tracked on a monthly base through a systematic and automated process. The reference decline ratio has been assumed based on historical production decline analysis. Besides, a floating decline based on simulation results is also added in order to capture the well closure due to gas production limitation. Field technical rate is the fundamental input for field development plan to derive the field sustainable oil production rate. It is dependent on both existing wells' performance and future wells' planning. Both the expected gain and drilling schedule of the planned wells are crucial to achieve the production target with reservoir pressure appropriately supported. Voidage Replacement Ratio has been applied to balance production and injection. Drilling plan could be revised accordingly. The production and injection balance can be visualized in the effective capacity tool, which will be used to further optimize the producer and injector plans. The requirements of producers and injectors are summarized and imported into the DBC optimization tool to evaluate new drilling schedule, which will be used in the effective capacity tool for an iteration loop. Uncertainty analysis is critical to assure a field development plan. Uncertainties have been evaluated based on the factors' most probable range. Five major assumptions, including expected gain from new wells, drilling duration, decline ratio, put-on-production time, and operating efficiency, have been evaluated to assess the uncertainty. Mitigation actions could be proposed to assure the production plan.
{"title":"An Integrated Approach to Optimize Field Development Plan Based on Uncertainty Analysis in a Giant Offshore Field","authors":"Wenyang Zhao, Ahmed Khaleefa Al-Neaimi, Arlen Sarsekov, O. Saif, A. Abed, Mohamed Helmy Al-feky","doi":"10.2118/197280-ms","DOIUrl":"https://doi.org/10.2118/197280-ms","url":null,"abstract":"\u0000 With an increased maturity and complexity of the reservoir, an optimized field development plan implementation is critical to achieve the planned target and to ensure an optimum field recovery. The paper presents an optimized process with uncertainty analysis based on Monte Carlo Simulation for the purpose of optimizing the Medium Term Development Plan (MTDP) implementation.\u0000 The five year development plan of this giant offshore field has been successfully assessed based on this optimized approach. The integrated workflow consists of four main parts, including actual field technical rate tracking, DBC optimization, simulation results, and effective capacity with Monte Carlo simulation embedded. The dynamic situations could be taken care with these seamless coupled tools. The actual field technical rate has been tracked on a monthly base through a systematic and automated process. The reference decline ratio has been assumed based on historical production decline analysis. Besides, a floating decline based on simulation results is also added in order to capture the well closure due to gas production limitation. Field technical rate is the fundamental input for field development plan to derive the field sustainable oil production rate. It is dependent on both existing wells' performance and future wells' planning. Both the expected gain and drilling schedule of the planned wells are crucial to achieve the production target with reservoir pressure appropriately supported. Voidage Replacement Ratio has been applied to balance production and injection. Drilling plan could be revised accordingly. The production and injection balance can be visualized in the effective capacity tool, which will be used to further optimize the producer and injector plans. The requirements of producers and injectors are summarized and imported into the DBC optimization tool to evaluate new drilling schedule, which will be used in the effective capacity tool for an iteration loop.\u0000 Uncertainty analysis is critical to assure a field development plan. Uncertainties have been evaluated based on the factors' most probable range. Five major assumptions, including expected gain from new wells, drilling duration, decline ratio, put-on-production time, and operating efficiency, have been evaluated to assess the uncertainty. Mitigation actions could be proposed to assure the production plan.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84838678","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}
Osama Al Khatib, Jane Mason, D. Beaman, J. Wills, A. Brodie
The Extended Reach Drilling (ERD) field re-development of a giant offshore field in United Arab Emirates (UAE) from four artificial islands predominantly requires the use of artificial lift (gas lift) to assist in unloading the wells post-completion operations and enhance reservoir production recovery rates. The vision was to achieve a well completion that allows for intervention-less unloading via gas lift using shearable Gas Lift Valves (GLV) and Remote Actuated Barrier Devices (RABD). The key principals in developing a solution to achieve this vision were to reduce rig time by avoiding critical path unloading, minimize post-rig activity to install live gas lift valves, and eliminate HSE exposures. Historically producer wells were completed with dummy gas lift valves and a frangible barrier device to facilitate the required completion pressure testing and provide barriers for rigging down from well. Coil Tubing (CT) was used to break the barrier device and kick off the wells with nitrogen. Once gas lift is available, the wells would be shut in, and a series of wireline interventions carried out to replace the dummy valves with live GLVs. This time consuming and costly process increases in cost when subsequent rig location covers the well that needs intervention; critical path rig time has been needed to unload wells with CT, in some cases requiring up to seven (7) rig days. This resulted in increased construction cost of each well and additional HSE exposure associated with the rig-less interventions required. A method was developed to deploy the upper completion with live, barrier qualified Tubing Pressure Shearable GLV’s (TSGLV) and a RABD, which enables all necessary well-construction integrity tests to be performed, and subsequently convert to a production configuration to allow unloading, gas lift and production of wells. Post-completion, well unloading and gas lift is immediately available without incurring critical path rig time or rig-less interventions. In this paper, the authors will demonstrate the technology that was developed, the qualification and testing program that was implemented, and final solution that enabled the Company to deliver wells successfully with remotely actuated unloading and production without the need for intervention.
{"title":"Intervention-Less Unloading Gas Lift Well Completion Design Using Shearable GLVs and Remote Actuated Barrier Device","authors":"Osama Al Khatib, Jane Mason, D. Beaman, J. Wills, A. Brodie","doi":"10.2118/197605-ms","DOIUrl":"https://doi.org/10.2118/197605-ms","url":null,"abstract":"\u0000 The Extended Reach Drilling (ERD) field re-development of a giant offshore field in United Arab Emirates (UAE) from four artificial islands predominantly requires the use of artificial lift (gas lift) to assist in unloading the wells post-completion operations and enhance reservoir production recovery rates. The vision was to achieve a well completion that allows for intervention-less unloading via gas lift using shearable Gas Lift Valves (GLV) and Remote Actuated Barrier Devices (RABD). The key principals in developing a solution to achieve this vision were to reduce rig time by avoiding critical path unloading, minimize post-rig activity to install live gas lift valves, and eliminate HSE exposures. Historically producer wells were completed with dummy gas lift valves and a frangible barrier device to facilitate the required completion pressure testing and provide barriers for rigging down from well. Coil Tubing (CT) was used to break the barrier device and kick off the wells with nitrogen. Once gas lift is available, the wells would be shut in, and a series of wireline interventions carried out to replace the dummy valves with live GLVs. This time consuming and costly process increases in cost when subsequent rig location covers the well that needs intervention; critical path rig time has been needed to unload wells with CT, in some cases requiring up to seven (7) rig days. This resulted in increased construction cost of each well and additional HSE exposure associated with the rig-less interventions required.\u0000 A method was developed to deploy the upper completion with live, barrier qualified Tubing Pressure Shearable GLV’s (TSGLV) and a RABD, which enables all necessary well-construction integrity tests to be performed, and subsequently convert to a production configuration to allow unloading, gas lift and production of wells. Post-completion, well unloading and gas lift is immediately available without incurring critical path rig time or rig-less interventions.\u0000 In this paper, the authors will demonstrate the technology that was developed, the qualification and testing program that was implemented, and final solution that enabled the Company to deliver wells successfully with remotely actuated unloading and production without the need for intervention.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75592968","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}
Luca Cadei, A. Corneo, D. Milana, D. Loffreno, Lorenzo Lancia, M. Montini, Gianmarco Rossi, Elisabetta Purlalli, Piero Fier, Francesco Carducci, Riccardo Nizzolo
The use of advanced analytics techniques has become pivotal for the Digital Transformation of the Oil and Gas Industry. Most of these models are used to predict and avoid the off-spec behaviors of both equipment and functional units of the plant and also for predicting overshooting events in advance allows plant’s operators to avoid production down-time. From a Machine Learning perspective, predicting off-specs situation and peaks in time signal is a complex task, due to the great rarity of events. For the very same reason, using standard data science measures – like Area Under the Curve (AUC), Recall and Precision – can lead to misleading performance indicators. In fact, a model that predicts no off-spec would have a high AUC just because of the unbalanced classes, leading to many false alarms. In this paper we present a business-oriented validation framework for big data analytics and machine learning models applied to a upstream production plant. This allow to evaluate both the effort required to operators and the expected benefit that could be achieved. The validation metrics defined take the classical Data Science measures to the business domain. This allow to adapt the model to the very specific use case and end user addressing the specific upstream plants constraints. This framework allows to define the optimal tradeoff between effort required and preventable events, providing statistics and KPIs to evaluate it. Normalized Recall (NR) takes into account both the percentage of events intercepted and the effort required, in terms of Attention Time (AT), when the operator should pay attention to the equipment involved. Plant operators can now have an idea of the results they can achieve with respect to the maximum effort required. Moreover, to prove the goodness of the model, we defined the lift in the NR as the ratio of the model NR and the NR that would be obtained by randomly distributing the same number of alarms. We applied this framework to specific use cases obtaining an expected recall of 40-50% with an expected effort of 5-10% of the time (considering more than 6 months). The effort is actually lower, since the operator is not requested to be fully committed to the alarm. The innovative framework developed is able to demonstrate the real operating capability of the analytics implemented on field, highlighting both the effort required to operators and the accuracy of machine learning tools.
{"title":"A Business-Oriented Framework to Evaluate Advanced Analytics for Predictive Maintenance: Measuring Benefits-Effort Tradeoff","authors":"Luca Cadei, A. Corneo, D. Milana, D. Loffreno, Lorenzo Lancia, M. Montini, Gianmarco Rossi, Elisabetta Purlalli, Piero Fier, Francesco Carducci, Riccardo Nizzolo","doi":"10.2118/197626-ms","DOIUrl":"https://doi.org/10.2118/197626-ms","url":null,"abstract":"\u0000 The use of advanced analytics techniques has become pivotal for the Digital Transformation of the Oil and Gas Industry. Most of these models are used to predict and avoid the off-spec behaviors of both equipment and functional units of the plant and also for predicting overshooting events in advance allows plant’s operators to avoid production down-time.\u0000 From a Machine Learning perspective, predicting off-specs situation and peaks in time signal is a complex task, due to the great rarity of events. For the very same reason, using standard data science measures – like Area Under the Curve (AUC), Recall and Precision – can lead to misleading performance indicators. In fact, a model that predicts no off-spec would have a high AUC just because of the unbalanced classes, leading to many false alarms. In this paper we present a business-oriented validation framework for big data analytics and machine learning models applied to a upstream production plant. This allow to evaluate both the effort required to operators and the expected benefit that could be achieved.\u0000 The validation metrics defined take the classical Data Science measures to the business domain. This allow to adapt the model to the very specific use case and end user addressing the specific upstream plants constraints. This framework allows to define the optimal tradeoff between effort required and preventable events, providing statistics and KPIs to evaluate it. Normalized Recall (NR) takes into account both the percentage of events intercepted and the effort required, in terms of Attention Time (AT), when the operator should pay attention to the equipment involved. Plant operators can now have an idea of the results they can achieve with respect to the maximum effort required. Moreover, to prove the goodness of the model, we defined the lift in the NR as the ratio of the model NR and the NR that would be obtained by randomly distributing the same number of alarms.\u0000 We applied this framework to specific use cases obtaining an expected recall of 40-50% with an expected effort of 5-10% of the time (considering more than 6 months). The effort is actually lower, since the operator is not requested to be fully committed to the alarm. The innovative framework developed is able to demonstrate the real operating capability of the analytics implemented on field, highlighting both the effort required to operators and the accuracy of machine learning tools.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75660779","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}
Wenyuan Liu, Jinqiu Hu, Fengrui Sun, Zheng Sun, Xiangfang Li
Hydrate formation and blockage in pipelines are serious problems in the oil-gas production and transportation. The current research is limited to the prediction of pipeline hydrate formation. However, the small hydrate generation often does not form obvious pipeline flow-barriers. Therefore, compared with hydrate formation, hydrate growth rate and deposition rate is equally important for the emergence of flow barriers. Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flowloop, the characteristics of hydrate formation-growth-deposition in pipelines under different gas-liquid flow patterns was studied. The results show: Different flow patterns show different hydrate formation and deposition characteristics due to different phase distribution and interface distribution. The bubble flow, cluster flow and slug flow have some similarities in flow patterns. It can be seen that the gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare; accordingly, the similarity of laminar flow, wave flow and annular-mist flow shows that thin liquid film or gas-liquid-pipe wall three-phase interface will always appear in the flow process, which will make the hydrate formation and deposition risk of the latter three flow patterns significantly greater than the former three flow patterns. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of annular-mist flow > laminar flow and wave flow > slug flow > cluster flow and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage, which is quite common in the oil and gas industry. In this case, special attention should be paid to hydrate prevention and control. It is hoped that the research in this paper can provide some theoretical guidance for field construction and related researchers.
{"title":"Study on the Correlation Between the Hydrate Formation-Blockage Risk and Gas-Liquid Flow Pattern in Horizontal Pipelines","authors":"Wenyuan Liu, Jinqiu Hu, Fengrui Sun, Zheng Sun, Xiangfang Li","doi":"10.2118/197534-ms","DOIUrl":"https://doi.org/10.2118/197534-ms","url":null,"abstract":"\u0000 Hydrate formation and blockage in pipelines are serious problems in the oil-gas production and transportation. The current research is limited to the prediction of pipeline hydrate formation. However, the small hydrate generation often does not form obvious pipeline flow-barriers. Therefore, compared with hydrate formation, hydrate growth rate and deposition rate is equally important for the emergence of flow barriers. Based on the hydrate formation-growth-deposition mechanism and combined with the hydrate experiment in the flowloop, the characteristics of hydrate formation-growth-deposition in pipelines under different gas-liquid flow patterns was studied. The results show: Different flow patterns show different hydrate formation and deposition characteristics due to different phase distribution and interface distribution. The bubble flow, cluster flow and slug flow have some similarities in flow patterns. It can be seen that the gas phase in the flow system exists in the form of bubbles, and the occurrence of thin liquid film on the tube wall under these three flow patterns is relatively rare; accordingly, the similarity of laminar flow, wave flow and annular-mist flow shows that thin liquid film or gas-liquid-pipe wall three-phase interface will always appear in the flow process, which will make the hydrate formation and deposition risk of the latter three flow patterns significantly greater than the former three flow patterns. Comprehensive analysis shows that the hydrate risk of each flow pattern is in the order of annular-mist flow > laminar flow and wave flow > slug flow > cluster flow and bubble flow. The annular-mist flow is the most dangerous flow pattern for hydrate formation and blockage, which is quite common in the oil and gas industry. In this case, special attention should be paid to hydrate prevention and control.\u0000 It is hoped that the research in this paper can provide some theoretical guidance for field construction and related researchers.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72948548","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}
Antoanela Andreea Chiriac, Latif Saqib, J. Sauter, M. Albu
The paper / presentation objective is to describe the achievement of the first gas lift well completed for multistage, hydraulically propped stimulation in a Romanian offshore field. The scope of the paper is to present the challenges and learnings associated with this well concept / design, engineering, modelling, equipment selection, yard testing, final design / program and offshore installation, operation, and results. Reservoir depletion modelling indicated artificial lift would be required as early as 6 months within initial well start up. In order to effectively optimise production from the well for a longer range of well life cycle, a multi-stage stimulation sandface completion was selected and plans were made to install gas lift equipment during initial completion installation, prior to rig release. To meet the concept requirements, risks were assessed and case histories were investigated / incorporated during the planning phase to ensure reliability of performing high-pressure stimulations through gas lift (dummy) valves. The material selection and specifications of the lower and upper completion equipment were defined considering:Artificial lift designReservoir characteristics, Casing size, High pressure stimulation, Life of well operations Equipment suitability and compatibility considerations resulted in a few equipment selection changes, requiring yard trials to define optimum pulling / running tool string components and configurations, which were then applied offshore. The final upper completion design consisted of gas lift mandrels (Gas lift dummies were replaced with gas lift valves following the HP stimulation), safety valve, permanent downhole pressure gauge and chemical injection mandrel. The lower completion consisted of hydraulic open hole packers, open hole anchor and open-close stimulation sleeves (all HP rated). Collaboration within the multi-discipline and with multiple service providers was vital in developing the final, tested design and implementation in the offshore well. The current design in the well is showing great benefits in terms of production (a higher rate than expected) and cost (initial completion includes gas lift equipment already available for future potential use). The concept proof is considered to be of great success for upcoming projects and is increasing the confidence of the operator to develop and approach the upcoming wells with multistage stimulation gas lift completions. This is the first well constructed in Romania that was hydraulically stimulated using proppant through an upper completion already having gas lift capability. A review of literature indicates this is an industry first. The success and communication of this well could provide benefit to the industry and could increase confidence when combining life-of-well requirements early in the well construction process.
{"title":"Successful Multistage, Hydraulically-Propped Stimulation through Gas Lift Completion Leads to Remarkable Capex Savings Offshore","authors":"Antoanela Andreea Chiriac, Latif Saqib, J. Sauter, M. Albu","doi":"10.2118/197544-ms","DOIUrl":"https://doi.org/10.2118/197544-ms","url":null,"abstract":"\u0000 The paper / presentation objective is to describe the achievement of the first gas lift well completed for multistage, hydraulically propped stimulation in a Romanian offshore field. The scope of the paper is to present the challenges and learnings associated with this well concept / design, engineering, modelling, equipment selection, yard testing, final design / program and offshore installation, operation, and results.\u0000 Reservoir depletion modelling indicated artificial lift would be required as early as 6 months within initial well start up. In order to effectively optimise production from the well for a longer range of well life cycle, a multi-stage stimulation sandface completion was selected and plans were made to install gas lift equipment during initial completion installation, prior to rig release. To meet the concept requirements, risks were assessed and case histories were investigated / incorporated during the planning phase to ensure reliability of performing high-pressure stimulations through gas lift (dummy) valves.\u0000 The material selection and specifications of the lower and upper completion equipment were defined considering:Artificial lift designReservoir characteristics, Casing size, High pressure stimulation, Life of well operations\u0000 Equipment suitability and compatibility considerations resulted in a few equipment selection changes, requiring yard trials to define optimum pulling / running tool string components and configurations, which were then applied offshore.\u0000 The final upper completion design consisted of gas lift mandrels (Gas lift dummies were replaced with gas lift valves following the HP stimulation), safety valve, permanent downhole pressure gauge and chemical injection mandrel. The lower completion consisted of hydraulic open hole packers, open hole anchor and open-close stimulation sleeves (all HP rated).\u0000 Collaboration within the multi-discipline and with multiple service providers was vital in developing the final, tested design and implementation in the offshore well. The current design in the well is showing great benefits in terms of production (a higher rate than expected) and cost (initial completion includes gas lift equipment already available for future potential use). The concept proof is considered to be of great success for upcoming projects and is increasing the confidence of the operator to develop and approach the upcoming wells with multistage stimulation gas lift completions.\u0000 This is the first well constructed in Romania that was hydraulically stimulated using proppant through an upper completion already having gas lift capability. A review of literature indicates this is an industry first. The success and communication of this well could provide benefit to the industry and could increase confidence when combining life-of-well requirements early in the well construction process.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74275724","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. Dell’Aversana, R. Servodio, F. Bottazzi, C. Carniani, G. Gallino, C. Molaschi, C. Sanasi
In this paper, we introduce a new technology permanently installed on the well completion and addressed to a real time reservoir fluid mapping through time-lapse electric/electromagnetic tomography while producing and/or injecting. Our technology consists of electrodes and coils installed on the casing/liner in the borehole/reservoir section of the well. We measure the variations of the electromagnetic fields caused by changes of the fluid distribution in a wide range of distances from the well, from few meters up to hundreds meters. The data acquired by our technology are processed and interpreted through an integrated software platform that combines 3D and 4D geophysical data inversion with a Machine Learning platform equipped with a complete suite of classification/prediction algorithms. Every time new data are acquired, they are fully integrated with the previous database, and used for decreasing the level of uncertainty about the dynamic model of the reservoir. In order to clarify the potential impact of such system on reservoir management, we apply this methodology to a synthetic data set. We discuss a simulation of a scenario where the waterfront approaches the wells during oil production. The goal of our test is to show how to combine our technology with Machine Learning to make robust predictions about the water table variations around the production wells.
{"title":"Asset Value Maximization through a Novel Well Completion System for 3d Time Lapse Electromagnetic Tomography Supported by Machine Learning","authors":"P. Dell’Aversana, R. Servodio, F. Bottazzi, C. Carniani, G. Gallino, C. Molaschi, C. Sanasi","doi":"10.2118/197573-ms","DOIUrl":"https://doi.org/10.2118/197573-ms","url":null,"abstract":"\u0000 In this paper, we introduce a new technology permanently installed on the well completion and addressed to a real time reservoir fluid mapping through time-lapse electric/electromagnetic tomography while producing and/or injecting. Our technology consists of electrodes and coils installed on the casing/liner in the borehole/reservoir section of the well. We measure the variations of the electromagnetic fields caused by changes of the fluid distribution in a wide range of distances from the well, from few meters up to hundreds meters. The data acquired by our technology are processed and interpreted through an integrated software platform that combines 3D and 4D geophysical data inversion with a Machine Learning platform equipped with a complete suite of classification/prediction algorithms. Every time new data are acquired, they are fully integrated with the previous database, and used for decreasing the level of uncertainty about the dynamic model of the reservoir. In order to clarify the potential impact of such system on reservoir management, we apply this methodology to a synthetic data set. We discuss a simulation of a scenario where the waterfront approaches the wells during oil production. The goal of our test is to show how to combine our technology with Machine Learning to make robust predictions about the water table variations around the production wells.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74362600","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}
Ahmad Abdul Azizurrofi, Edward Erwanto, A. Asnidar, Rikky Rahmat Firdaus
During the period from 2005 to 2018, the oil prices had reached the highest level in 2008 (99.67 US$/bbl) and the lowest level in 2016 (43 US$/bbl). The fluctuation in oil prices will affects the cost of investment (drilling and surface facilities) worlwide. Based on this condition, the standardization of the Investment Cost is needed to help the government and contractor in estimating the cost of investment in an oil and gas project. As per December 2018, there were 471 projects approved by the government of Indonesia and the 266 of them are projects that producing oil (oil projects) and gas (gas projects). In these projects, there are details of investment costs that are included in the economic evaluation. This paper will calculate and produce the Maximum Allowable Cost ("MAC") of surface facilities per boe (US$/boe) based on statistical analysis of 266 projects. Hopefully, this method can be used as a reference (guidance) in giving approval for the cost of surface facilities and providing an overview to contractors regarding the estimated MAC of surface facilities in an oil and gas project. For the purpose of this paper is, to divide the areas of Indonesia into 2 areas (Onshore and Offshore) which in each of these areas has 2 different types of projects (oil project and gas project). Then, to collect the data that related to cost of surface facilities and reserves and then the MAC of surface facilities per boe are calculated and produced using the Control Chart Analysis method. Lastly, the result will be distributed to those aforementioned areas. Based on the analysis of 266 Projects in Indonesia, the MAC of surface facilities per boe in Onshore area are 20.80 US$/boe (oil project) and 18.59 US$/boe (gas project), while the MAC of surface facilities per boe in Offshore area are 14.32 US$/boe (oil project) and 27.62 US$/boe (gas projects). In general, the MAC of surface facilities per boe still far bellow the oil price. Finally, this paper will show how to produce MAC of surface facilities per boe by using control chart analysis. This paper also expected to provide references for the government of Indonesia in giving approval to the cost of surface facilities proposed by contractors and provide contractors a quick look at oil and gas industry in Indonesia especially to those who plan to invest in Indonesia, and also help them create their petroleum exploration and exploitation strategy in Indonesia by considering on this information that will provide benefits for both government and contractor.
{"title":"Designing the Maximum Allowable Cost of Surface Facilities Using the Control Chart Analysis: A Case Study in Indonesia","authors":"Ahmad Abdul Azizurrofi, Edward Erwanto, A. Asnidar, Rikky Rahmat Firdaus","doi":"10.2118/197644-ms","DOIUrl":"https://doi.org/10.2118/197644-ms","url":null,"abstract":"\u0000 During the period from 2005 to 2018, the oil prices had reached the highest level in 2008 (99.67 US$/bbl) and the lowest level in 2016 (43 US$/bbl). The fluctuation in oil prices will affects the cost of investment (drilling and surface facilities) worlwide. Based on this condition, the standardization of the Investment Cost is needed to help the government and contractor in estimating the cost of investment in an oil and gas project.\u0000 As per December 2018, there were 471 projects approved by the government of Indonesia and the 266 of them are projects that producing oil (oil projects) and gas (gas projects). In these projects, there are details of investment costs that are included in the economic evaluation. This paper will calculate and produce the Maximum Allowable Cost (\"MAC\") of surface facilities per boe (US$/boe) based on statistical analysis of 266 projects. Hopefully, this method can be used as a reference (guidance) in giving approval for the cost of surface facilities and providing an overview to contractors regarding the estimated MAC of surface facilities in an oil and gas project.\u0000 For the purpose of this paper is, to divide the areas of Indonesia into 2 areas (Onshore and Offshore) which in each of these areas has 2 different types of projects (oil project and gas project). Then, to collect the data that related to cost of surface facilities and reserves and then the MAC of surface facilities per boe are calculated and produced using the Control Chart Analysis method. Lastly, the result will be distributed to those aforementioned areas.\u0000 Based on the analysis of 266 Projects in Indonesia, the MAC of surface facilities per boe in Onshore area are 20.80 US$/boe (oil project) and 18.59 US$/boe (gas project), while the MAC of surface facilities per boe in Offshore area are 14.32 US$/boe (oil project) and 27.62 US$/boe (gas projects). In general, the MAC of surface facilities per boe still far bellow the oil price.\u0000 Finally, this paper will show how to produce MAC of surface facilities per boe by using control chart analysis. This paper also expected to provide references for the government of Indonesia in giving approval to the cost of surface facilities proposed by contractors and provide contractors a quick look at oil and gas industry in Indonesia especially to those who plan to invest in Indonesia, and also help them create their petroleum exploration and exploitation strategy in Indonesia by considering on this information that will provide benefits for both government and contractor.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74080184","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}
Hussain A. Almajid, Salman Al Gamber, Saleh M. Abou Zeid, Marcelo Ramos
Electrical submersible pumps (ESP's) have become a necessity to support reservoir pressure and sustain production. ESP failure and replacement is a major concern for wells with high gas oil ratio (GOR) and erosion related issues due to the nature of the wear & tear that these ESP's undergo through its life time. Consequently, these ESP failures have an important economic implications for oil and gas operators, including non-productive time, high cost of ESP replacements and production deferral. The objective of this paper is to provide a comprehensive and systematic approach to maximize the ESP run life by optimizing both the design process and operation standards in which sand production and erosion are growing concerns. The improved design will integrate best practices from several field applications and downhole technology including new concepts, features, and materials that were specifically designed and tested to withstand challenging downhole conditions. Furthermore, this paper will employ i-field data as a proactive means to safeguard ESP health based on a numerical model of the production system which served as a decision support tool to determine ESP frequencies that maximize oil production while honoring multiple operational constraints and minimize preventable trips that can lead to undesired failures. A comprehensive engineering thought process including initial installations, subsequent well interventions, operation standards, completion improvements, ESP configuration enhancements and equipment Dismantle Inspection and Failure Analysis (DIFA) were conducted for several cases to assemble improved ESP components that were specifically designed, fabricated, and tested to meet well requirements. These components were integrated and subjected to a rigorous performance based tests prior to field application. After the comprehensive manufacturer tests, field applications were implemented for the newly developed system and was carefully monitored to measure its effectiveness. Additionally, an analytical framework software utilizing smart field applications was developed towards proactive ESP performance monitoring based on data-driven predictive modeling and analysis. This framework was utilized to automatically identify patterns and assess ESP condition in real time, thus offering detection of impending problems before they occur for mitigation and prevention of ESP service interruptions and consequently preserving the ESP health. This paper will provide a detailed step by step process to create a robust ESP system that will adopt to challenging wellbore conditions where high GOR and erosion have resulted in premature ESP failures and offer firm enhancements to operation standards by leveraging real-time data obtained from downhole sensors for predicting and preventing ESP shutdowns using data analytics. Field application performance data will be shared in which these methods were successfully implemented to extend ESP run life.
{"title":"An Integrated Approach Utilizing ESP Design Improvements and Real Time Monitoring to Ensure Optimum Performance and Maximize Run Life","authors":"Hussain A. Almajid, Salman Al Gamber, Saleh M. Abou Zeid, Marcelo Ramos","doi":"10.2118/197209-ms","DOIUrl":"https://doi.org/10.2118/197209-ms","url":null,"abstract":"\u0000 Electrical submersible pumps (ESP's) have become a necessity to support reservoir pressure and sustain production. ESP failure and replacement is a major concern for wells with high gas oil ratio (GOR) and erosion related issues due to the nature of the wear & tear that these ESP's undergo through its life time. Consequently, these ESP failures have an important economic implications for oil and gas operators, including non-productive time, high cost of ESP replacements and production deferral.\u0000 The objective of this paper is to provide a comprehensive and systematic approach to maximize the ESP run life by optimizing both the design process and operation standards in which sand production and erosion are growing concerns. The improved design will integrate best practices from several field applications and downhole technology including new concepts, features, and materials that were specifically designed and tested to withstand challenging downhole conditions. Furthermore, this paper will employ i-field data as a proactive means to safeguard ESP health based on a numerical model of the production system which served as a decision support tool to determine ESP frequencies that maximize oil production while honoring multiple operational constraints and minimize preventable trips that can lead to undesired failures.\u0000 A comprehensive engineering thought process including initial installations, subsequent well interventions, operation standards, completion improvements, ESP configuration enhancements and equipment Dismantle Inspection and Failure Analysis (DIFA) were conducted for several cases to assemble improved ESP components that were specifically designed, fabricated, and tested to meet well requirements. These components were integrated and subjected to a rigorous performance based tests prior to field application. After the comprehensive manufacturer tests, field applications were implemented for the newly developed system and was carefully monitored to measure its effectiveness. Additionally, an analytical framework software utilizing smart field applications was developed towards proactive ESP performance monitoring based on data-driven predictive modeling and analysis. This framework was utilized to automatically identify patterns and assess ESP condition in real time, thus offering detection of impending problems before they occur for mitigation and prevention of ESP service interruptions and consequently preserving the ESP health.\u0000 This paper will provide a detailed step by step process to create a robust ESP system that will adopt to challenging wellbore conditions where high GOR and erosion have resulted in premature ESP failures and offer firm enhancements to operation standards by leveraging real-time data obtained from downhole sensors for predicting and preventing ESP shutdowns using data analytics. Field application performance data will be shared in which these methods were successfully implemented to extend ESP run life.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84433428","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 article proposes a new approach for dealing with maintenance issues for large industrial processes. The case study is taken from an industrial implementation of a condition-based maintenance project for the heat exchangers from the crude preheating train of a European refinery. The application was developed based reconciled data using the advanced data validation and reconciliation tool, VALI, developed by Belsim. The article proposes the riguroous calculation and monitoring of the fouling factors of heat exchangers as crucial parameter to alert the operator about the condition of the heat exchangers. The calculation of fouling factors is performed automatically by the application with a minimum initial input effort from the part of the modeler: design date for film transfer coefficients for the both sides of the heat exchanger. Industrial data shows that the heat exchangers from the crude preheating train are prone to relatively quick fouling. The financial analysis of the impact of the fouling problem on the normalized daily fuel consumption in the crude furnace has shown that the high initial financial gain of a preheater cleaning can amount to as much as 20% of daily fuel cost. However, the performance degradation sets in very fast and the high initial gains are not sustained for prolonged periods of time. On the other hand, the overall performance degradation slows down in time and the performance of the crude preheating train stabilizes at lower values, making the decision process for heat exchanger cleaning more difficult in situations of pressures to maintain production volumes.
{"title":"Condition Based Maintenance for Oil and Gas Industry Based on Data Reconciliation Techniques","authors":"I. Craciun, F. Lecoq, Suryaprakash Digavalli","doi":"10.2118/197526-ms","DOIUrl":"https://doi.org/10.2118/197526-ms","url":null,"abstract":"\u0000 This article proposes a new approach for dealing with maintenance issues for large industrial processes. The case study is taken from an industrial implementation of a condition-based maintenance project for the heat exchangers from the crude preheating train of a European refinery. The application was developed based reconciled data using the advanced data validation and reconciliation tool, VALI, developed by Belsim.\u0000 The article proposes the riguroous calculation and monitoring of the fouling factors of heat exchangers as crucial parameter to alert the operator about the condition of the heat exchangers. The calculation of fouling factors is performed automatically by the application with a minimum initial input effort from the part of the modeler: design date for film transfer coefficients for the both sides of the heat exchanger. Industrial data shows that the heat exchangers from the crude preheating train are prone to relatively quick fouling. The financial analysis of the impact of the fouling problem on the normalized daily fuel consumption in the crude furnace has shown that the high initial financial gain of a preheater cleaning can amount to as much as 20% of daily fuel cost. However, the performance degradation sets in very fast and the high initial gains are not sustained for prolonged periods of time. On the other hand, the overall performance degradation slows down in time and the performance of the crude preheating train stabilizes at lower values, making the decision process for heat exchanger cleaning more difficult in situations of pressures to maintain production volumes.","PeriodicalId":11091,"journal":{"name":"Day 3 Wed, November 13, 2019","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85058917","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：