E. Othman, Dalila Gomes, Tengku Ezharuddin Tengku Bidin, M. M. H. Meor Hashim, M. H. Yusoff, M. Arriffin, Rohaizat Ghazali
Wellbore geometry stuck pipe mechanism occurs when the string and the well are incompatible with each other. This issue is commonly related to changes in hole diameter, angle, and direction associated with symptoms such as mobile/swelling formation, undergauged hole, key seating, ledges, and high doglegs. An internal study identified that many stuck pipe incidents were associated with mechanical sticking, specifically wellbore geometry sticking with high-cost impact, which warrants proactive prevention. Throughout this paper, we provide and demonstrate how machine learning solutions can foresee the potential stuck pipe related to wellbore geometry issues based on two signs: hookload signature and dogleg severity. The application is based on the Artificial Neural Network (ANN) approach that reads the surface parameters sequence of hookload real-time data and learns with historical wells data. Machine learning (ML) then determines how the hookload behaves for each type of activity (tripping and drilling). The machine learning predictions can then be streamed on a web-based application accessible to the operations and project team. The neural network design for hookload prediction while tripping in/out considers a drag when the string moves towards a region with doglegs severity higher than the threshold chosen based on engineering judgment. This paper also discusses applications beyond real-time estimation, such as predicting the trend of the few subsequent expected hook loads up to 6 to 10 stands ahead based on case studies from previous live wells obtained from the real-time monitoring center where the product is used. The output from the machine learning solution provided a basis for risk identification and further analysis by the monitoring specialist in a proactive intervention effort to prevent stuck pipe incidents. The implementation of applications described in this paper could detect an early symptom of wellbore geometry issue; hence proactive action can be taken to avoid a potential stuck pipe event.
{"title":"Application of Machine Learning to Augment Wellbore Geometry-Related Stuck Pipe Risk Identification in Real Time","authors":"E. Othman, Dalila Gomes, Tengku Ezharuddin Tengku Bidin, M. M. H. Meor Hashim, M. H. Yusoff, M. Arriffin, Rohaizat Ghazali","doi":"10.4043/31695-ms","DOIUrl":"https://doi.org/10.4043/31695-ms","url":null,"abstract":"\u0000 Wellbore geometry stuck pipe mechanism occurs when the string and the well are incompatible with each other. This issue is commonly related to changes in hole diameter, angle, and direction associated with symptoms such as mobile/swelling formation, undergauged hole, key seating, ledges, and high doglegs. An internal study identified that many stuck pipe incidents were associated with mechanical sticking, specifically wellbore geometry sticking with high-cost impact, which warrants proactive prevention. Throughout this paper, we provide and demonstrate how machine learning solutions can foresee the potential stuck pipe related to wellbore geometry issues based on two signs: hookload signature and dogleg severity. The application is based on the Artificial Neural Network (ANN) approach that reads the surface parameters sequence of hookload real-time data and learns with historical wells data. Machine learning (ML) then determines how the hookload behaves for each type of activity (tripping and drilling). The machine learning predictions can then be streamed on a web-based application accessible to the operations and project team. The neural network design for hookload prediction while tripping in/out considers a drag when the string moves towards a region with doglegs severity higher than the threshold chosen based on engineering judgment. This paper also discusses applications beyond real-time estimation, such as predicting the trend of the few subsequent expected hook loads up to 6 to 10 stands ahead based on case studies from previous live wells obtained from the real-time monitoring center where the product is used. The output from the machine learning solution provided a basis for risk identification and further analysis by the monitoring specialist in a proactive intervention effort to prevent stuck pipe incidents. The implementation of applications described in this paper could detect an early symptom of wellbore geometry issue; hence proactive action can be taken to avoid a potential stuck pipe event.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81382962","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}
Peng Li, Yang Zeng, Engao Tang, Zhijie Wei, Shiqing Cheng
The current research on interference well test technology is based on water flooding reservoir, but the analysis method of interference well test in polymer flooding reservoir has not been reported, which leads to unclear understanding of the physical property changes between wells in polymer flooding reservoir. Considering the characteristics of polymer flow, a two-phase interference well test model of polymer flooding multi-layer reservoir is established. The pressure, water saturation and polymer concentration are all implicitly solved to improve the stability of the numerical solution, and the typical curve is drawn. The results show that: the water phase viscosity is greater during the polymer flooding process, the pressure fluctuation of the active well is later, which affects the observation well, and the pressure fluctuation received by the observation well is greater. The results show that the interference well test curve of polymer flooding is farther to the right than that of water flooding in the early stage and higher than that of water flooding in the middle and late stage. The application example shows that coincidence rate with commercial software well test interpretation is over 90% when the model is degenerated to conventional water flooding, which proves the accuracy of polymer flooding interference well test model, and provides technical support for the improvement of well test method of polymer flooding reservoir.
{"title":"Two-Phase Interference Well Testing Interpretation Method for Polymer Flooding Multilayer Reservoir","authors":"Peng Li, Yang Zeng, Engao Tang, Zhijie Wei, Shiqing Cheng","doi":"10.4043/31575-ms","DOIUrl":"https://doi.org/10.4043/31575-ms","url":null,"abstract":"\u0000 The current research on interference well test technology is based on water flooding reservoir, but the analysis method of interference well test in polymer flooding reservoir has not been reported, which leads to unclear understanding of the physical property changes between wells in polymer flooding reservoir. Considering the characteristics of polymer flow, a two-phase interference well test model of polymer flooding multi-layer reservoir is established. The pressure, water saturation and polymer concentration are all implicitly solved to improve the stability of the numerical solution, and the typical curve is drawn. The results show that: the water phase viscosity is greater during the polymer flooding process, the pressure fluctuation of the active well is later, which affects the observation well, and the pressure fluctuation received by the observation well is greater. The results show that the interference well test curve of polymer flooding is farther to the right than that of water flooding in the early stage and higher than that of water flooding in the middle and late stage. The application example shows that coincidence rate with commercial software well test interpretation is over 90% when the model is degenerated to conventional water flooding, which proves the accuracy of polymer flooding interference well test model, and provides technical support for the improvement of well test method of polymer flooding reservoir.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"63 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76599828","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}
Apoorv Tandon, Fahad Khan, R. Shukla, Anika Saxena, Shivanjali Sharma, K. Biswas
Oil recovery is a complex process involving physical and chemical interactions within the pore spaces of the reservoir. The oil recovery improves by injecting viscous and wettability-altering fluids into the reservoir. The present work aims to study the improvement in the recovery using surfactant polymer (SP) slug and discuss the mechanisms behind the oil mobilization process by visualizing the oil recovery using a glass tube filled with glass beads. Fluids were injected using a syringe pump, and the interaction of the fluid was visualized using a high-speed camera. Initially, the oil was displaced using brine which was followed by the injection of SP slug formulated using Sodium Dodecyl Sulphate (SDS) and Poly Acrylamide (PAM). The effect of the composition of the slug was studied at different concentrations 125ppm, 250ppm, 375ppm, and 500ppm. After that, the effect of flow rate of SP slug on the oil recovery process was explored. Colored non-interacting dyes aided the visualization in the glass model. Images of the oil recovery process were captured to examine the fluid displacement mechanism during SP flooding. The total oil recovery increases from 73.33% to 83.33%, as the polymer concentration was increased gradually from 125 ppm to 500 ppm at a flow rate of 100 µL/min which further increases to 90% for 500 ppm slug at 500 µL/min of flow rate. High-quality magnified images from the camera captured the flow path of each fluid injected through the glass bead-packed channel. The effect of various forces like capillary, gravity, and viscous forces were visualized and analyzed. The pore throat and pore-diameter calculations were done using the software. The low viscous slug was subjected to higher gravity force, rendering it ineffective in displacing the oil present at the channel's top. The gravity segregation was overpowered by high viscous slugs that mobilized the oil present in the channel. The understanding and analysis of the fluid motion under oil-brine interaction and SP slug-oil interactions was studied. The study helps improve the techno-economic feasibility of the whole recovery process by limiting the use of chemicals and maximizing the oil recovery in a controlled manner.
{"title":"3-D Micromodel for Visualization & Experimental Analysis of Flow Behavior, Surface Tension and Polymer Concentration on Enhanced Oil Recovery","authors":"Apoorv Tandon, Fahad Khan, R. Shukla, Anika Saxena, Shivanjali Sharma, K. Biswas","doi":"10.4043/31352-ms","DOIUrl":"https://doi.org/10.4043/31352-ms","url":null,"abstract":"\u0000 Oil recovery is a complex process involving physical and chemical interactions within the pore spaces of the reservoir. The oil recovery improves by injecting viscous and wettability-altering fluids into the reservoir. The present work aims to study the improvement in the recovery using surfactant polymer (SP) slug and discuss the mechanisms behind the oil mobilization process by visualizing the oil recovery using a glass tube filled with glass beads. Fluids were injected using a syringe pump, and the interaction of the fluid was visualized using a high-speed camera. Initially, the oil was displaced using brine which was followed by the injection of SP slug formulated using Sodium Dodecyl Sulphate (SDS) and Poly Acrylamide (PAM). The effect of the composition of the slug was studied at different concentrations 125ppm, 250ppm, 375ppm, and 500ppm. After that, the effect of flow rate of SP slug on the oil recovery process was explored. Colored non-interacting dyes aided the visualization in the glass model. Images of the oil recovery process were captured to examine the fluid displacement mechanism during SP flooding.\u0000 The total oil recovery increases from 73.33% to 83.33%, as the polymer concentration was increased gradually from 125 ppm to 500 ppm at a flow rate of 100 µL/min which further increases to 90% for 500 ppm slug at 500 µL/min of flow rate. High-quality magnified images from the camera captured the flow path of each fluid injected through the glass bead-packed channel. The effect of various forces like capillary, gravity, and viscous forces were visualized and analyzed. The pore throat and pore-diameter calculations were done using the software. The low viscous slug was subjected to higher gravity force, rendering it ineffective in displacing the oil present at the channel's top. The gravity segregation was overpowered by high viscous slugs that mobilized the oil present in the channel. The understanding and analysis of the fluid motion under oil-brine interaction and SP slug-oil interactions was studied. The study helps improve the techno-economic feasibility of the whole recovery process by limiting the use of chemicals and maximizing the oil recovery in a controlled manner.","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":"74406197","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}
Bin Wang, Devesh Bhaisora, Francois Missiaen, Chi Zhang, Yue Ming, Lipeng Shan, Le Qin, Jianting Liu
The Fuling shale gas field in China was discovered in 2012 and is a quality high pressure natural shale gas reservoir in the Longmaxi formation. Since then, more than 500 wells have been drilled and are being produced. However, over the period there has been a reduction in production and therefore refracturing is needed to maintain production. A new casing-in-casing method of re-constructing a new wellbore inside the legacy wellbore for re-fracturing was introduced and successfully executed. The producing wellbore has a series of perforations along the casing of the horizontal section. Wellbore re-construction is required to isolate all these perforations and allow a plug-and-perf fracturing process in the new wellbore. It was planned to run a 3.5 inch casing into the existing 5.5 inch casing and cement it. A dependable cement barrier in this extremely tight annulus is required to carry on future re-frac operations. Computational fluid dynamics and stress modelling were performed to optimize the slurry density, rheology, mechanical properties and based on various iterations tailored ceramic centralizers were proposed to achieve zonal isolation objectives. The top of cement (TOC) in the annulus is required to be above the topmost planned perforation. The remaining 3.5 inch casing above the designed depth was disconnected and pulled out. A new 5.5 inch X 3.5 inch wellbore without any leaks to the existing perforation was constructed. The wellbore was reamed to bottom, and the losses were treated prior to cementing. Tailored ceramic centralizers were installed on the casing to achieve optimum stand off along with a low friction factor which helped casing to run to the bottom successfully. A low rheology slurry tailored for optimum mechanical properties to withstand the fracturing operation was pumped and the cement returns to designed depth were noted. Cement bond log showed excellent results and the stage fracturing operation was performed with no issues with wellbore integrity. A tailored slurry and centralizer design helped to achieve zonal isolation objectives in the low clearance casing-in-casing (CiC) cementing configuration. The critical wellbore re-construction objectives were achieved, and the well was re-fractured with substantial increase in production.
{"title":"The First Successful Casing in Casing Cementing for Re-Fracturing Treatment in China: Case Study from China’s First Shale Gas Field","authors":"Bin Wang, Devesh Bhaisora, Francois Missiaen, Chi Zhang, Yue Ming, Lipeng Shan, Le Qin, Jianting Liu","doi":"10.4043/31688-ms","DOIUrl":"https://doi.org/10.4043/31688-ms","url":null,"abstract":"\u0000 The Fuling shale gas field in China was discovered in 2012 and is a quality high pressure natural shale gas reservoir in the Longmaxi formation. Since then, more than 500 wells have been drilled and are being produced. However, over the period there has been a reduction in production and therefore refracturing is needed to maintain production. A new casing-in-casing method of re-constructing a new wellbore inside the legacy wellbore for re-fracturing was introduced and successfully executed.\u0000 The producing wellbore has a series of perforations along the casing of the horizontal section. Wellbore re-construction is required to isolate all these perforations and allow a plug-and-perf fracturing process in the new wellbore. It was planned to run a 3.5 inch casing into the existing 5.5 inch casing and cement it. A dependable cement barrier in this extremely tight annulus is required to carry on future re-frac operations. Computational fluid dynamics and stress modelling were performed to optimize the slurry density, rheology, mechanical properties and based on various iterations tailored ceramic centralizers were proposed to achieve zonal isolation objectives. The top of cement (TOC) in the annulus is required to be above the topmost planned perforation. The remaining 3.5 inch casing above the designed depth was disconnected and pulled out. A new 5.5 inch X 3.5 inch wellbore without any leaks to the existing perforation was constructed.\u0000 The wellbore was reamed to bottom, and the losses were treated prior to cementing. Tailored ceramic centralizers were installed on the casing to achieve optimum stand off along with a low friction factor which helped casing to run to the bottom successfully. A low rheology slurry tailored for optimum mechanical properties to withstand the fracturing operation was pumped and the cement returns to designed depth were noted. Cement bond log showed excellent results and the stage fracturing operation was performed with no issues with wellbore integrity.\u0000 A tailored slurry and centralizer design helped to achieve zonal isolation objectives in the low clearance casing-in-casing (CiC) cementing configuration. The critical wellbore re-construction objectives were achieved, and the well was re-fractured with substantial increase in production.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74788943","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}
A floating Normally Unmanned/Unattended Installation (NUI) or "utility buoy" can provide key services to overcome flow assurance and control constraints directly at the well site. The objective of this paper is to explore how implementing an NUI can enable development of a typical Southeast Asian subsea tieback that could otherwise be considered uneconomical. The approach is based on using Buoyant Production Technologies Ltd. (BPT) floating NUI solution to provide power, chemicals, and control to subsea developments. This removes the need for a long umbilical and potentially costly host modification to accommodate a subsea tieback. A case study is presented to explore the benefits of the NUI. A low power utility buoy is sized to cater for well control and chemical injection. This simple subsea tieback is compared to a conventional approach with an umbilical to a host facility. An assessment of procurement, fabrication, installation, and operation phases is performed to identify the advantages of the utility buoy. The floating NUI design is such that fabrication location is flexible allowing for local fabrication near to the field. In addition, the transportation and installation can be performed by small locally available vessels, resulting in a cost-effective solution, and reduced environmental emissions. Material and equipment selection are focussed on high reliability and low maintenance requirements. This allows for less frequent inspection and maintenance visits, which reduces personnel risk and results in low lifecycle cost. A low power utility buoy shows significant benefits compared to a long umbilical. Combined with the flexibility and re-deployment capabilities, the buoy solution can benefit long tiebacks, as well as early production schemes. An NUI is seen as an enabler for mature regions dominated by subsea tiebacks to feed existing hubs. The improved economics, local fabrication opportunity and reusable profile all adds to the flexibility which will be needed as tiebacks become longer and developments more technically challenging and complex.
{"title":"Pioneer Design of Unmanned Utility Buoy to Unlock Challenging Subsea Tiebacks in Asia","authors":"Cecilie Clark, Fikri Anwar Emran, D. Steed","doi":"10.4043/31358-ms","DOIUrl":"https://doi.org/10.4043/31358-ms","url":null,"abstract":"\u0000 A floating Normally Unmanned/Unattended Installation (NUI) or \"utility buoy\" can provide key services to overcome flow assurance and control constraints directly at the well site. The objective of this paper is to explore how implementing an NUI can enable development of a typical Southeast Asian subsea tieback that could otherwise be considered uneconomical.\u0000 The approach is based on using Buoyant Production Technologies Ltd. (BPT) floating NUI solution to provide power, chemicals, and control to subsea developments. This removes the need for a long umbilical and potentially costly host modification to accommodate a subsea tieback.\u0000 A case study is presented to explore the benefits of the NUI. A low power utility buoy is sized to cater for well control and chemical injection. This simple subsea tieback is compared to a conventional approach with an umbilical to a host facility. An assessment of procurement, fabrication, installation, and operation phases is performed to identify the advantages of the utility buoy.\u0000 The floating NUI design is such that fabrication location is flexible allowing for local fabrication near to the field. In addition, the transportation and installation can be performed by small locally available vessels, resulting in a cost-effective solution, and reduced environmental emissions.\u0000 Material and equipment selection are focussed on high reliability and low maintenance requirements. This allows for less frequent inspection and maintenance visits, which reduces personnel risk and results in low lifecycle cost.\u0000 A low power utility buoy shows significant benefits compared to a long umbilical. Combined with the flexibility and re-deployment capabilities, the buoy solution can benefit long tiebacks, as well as early production schemes.\u0000 An NUI is seen as an enabler for mature regions dominated by subsea tiebacks to feed existing hubs. The improved economics, local fabrication opportunity and reusable profile all adds to the flexibility which will be needed as tiebacks become longer and developments more technically challenging and complex.","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":"80421601","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}
The paper presents Alkaline, Surfactant and Polymer (ASP) flooding optimization work under the uncertainties in chemical components’ properties in order to assess the risk in simulated incremental oil recovery value associated to uncertainties in chemical components’ properties. Uncertain chemical properties for ASP were identified from published coreflood works and were defined in range instead of as discrete value in the simulation model. 100 chemical properties realizations were generated in the study based on the range of these key uncertain chemical properties and nine representative chemical properties realizations were selected based on the total oil recovery. Robust optimization work was performed using Markov Chain Monte Carlo (MCMC) algorithm to determine the optimum ASP flooding design parameters, namely time to start ASP injection, main ASP slug size, post-flush polymer slug size and ASP concentration that gave highest Net Present Value (NPV) for all the nine selected chemical realizations. Optimized ASP design parameters was eventually run on 100 initially generated chemical properties realizations to generate NPV cumulative probability plot. Nominal optimization workflow that based on single chemical properties realization was used to generate another set of optimized ASP design parameters and the NPV cumulative probability plot generation was followed on the same 100 chemical properties realizations for comparison purpose. The sensitivity of identified uncertain chemical properties on incremental oil recovery is demonstrated in the paper. Both nominal & robust optimization workflows improve the project NPV value compared to base case ASP design, with robust optimization showing further improvement over nominal optimization in all chemical realizations as expected. The spread in NPV clearly illustrated the risk of ASP flooding design related to uncertainties in ASP chemical properties. In this project, the exclusion of chemical properties uncertainties in optimization work led to the underestimation of ASP oil recovery performance. The study is novel as while there were uncertainties in ASP chemical properties reported from laboratory core flood tests or core flood history matching simulations and presence of dynamic chemical adsorption behaviour under different chemical concentration combination, most of the published ASP optimization simulation studies has considered single chemical properties realization in their simulation models. The impact of uncertainties in chemical properties on simulated ASP oil recovery profile is demonstrated in this paper.
{"title":"Robust ASP Flooding Optimization Under Chemical Properties Uncertainty Using Markov Chain Monte Carlo Optimizer","authors":"Wee Wei Wa, Vazquez Oscar","doi":"10.4043/31561-ms","DOIUrl":"https://doi.org/10.4043/31561-ms","url":null,"abstract":"\u0000 The paper presents Alkaline, Surfactant and Polymer (ASP) flooding optimization work under the uncertainties in chemical components’ properties in order to assess the risk in simulated incremental oil recovery value associated to uncertainties in chemical components’ properties.\u0000 Uncertain chemical properties for ASP were identified from published coreflood works and were defined in range instead of as discrete value in the simulation model. 100 chemical properties realizations were generated in the study based on the range of these key uncertain chemical properties and nine representative chemical properties realizations were selected based on the total oil recovery. Robust optimization work was performed using Markov Chain Monte Carlo (MCMC) algorithm to determine the optimum ASP flooding design parameters, namely time to start ASP injection, main ASP slug size, post-flush polymer slug size and ASP concentration that gave highest Net Present Value (NPV) for all the nine selected chemical realizations. Optimized ASP design parameters was eventually run on 100 initially generated chemical properties realizations to generate NPV cumulative probability plot. Nominal optimization workflow that based on single chemical properties realization was used to generate another set of optimized ASP design parameters and the NPV cumulative probability plot generation was followed on the same 100 chemical properties realizations for comparison purpose.\u0000 The sensitivity of identified uncertain chemical properties on incremental oil recovery is demonstrated in the paper. Both nominal & robust optimization workflows improve the project NPV value compared to base case ASP design, with robust optimization showing further improvement over nominal optimization in all chemical realizations as expected. The spread in NPV clearly illustrated the risk of ASP flooding design related to uncertainties in ASP chemical properties. In this project, the exclusion of chemical properties uncertainties in optimization work led to the underestimation of ASP oil recovery performance.\u0000 The study is novel as while there were uncertainties in ASP chemical properties reported from laboratory core flood tests or core flood history matching simulations and presence of dynamic chemical adsorption behaviour under different chemical concentration combination, most of the published ASP optimization simulation studies has considered single chemical properties realization in their simulation models. The impact of uncertainties in chemical properties on simulated ASP oil recovery profile is demonstrated in this paper.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75501525","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}
Wang Chunpeng, Zhu Weiyao, Cui Weixiang, Zhang Min, H. Xueqin, Shi Shuzhe, Nie Zhen
In order to extend the life cycle of the developed oilfield and ensure the stable production of the oilfield, the exploration and practice of supplementary energy refracturing has been carried out in a small block in eastern China which is on the verge of shutdown since 2017. All of the well in this block are vertical wells. This technology breaks the injection production relationship of the original well pattern. The injection wells and production wells are fractured at the same time. Fracturing fluid is not only used for fracturing, but also for supplementing formation energy. In order to produce more new fractures and make them more complex, low viscosity slippery water is used in hydraulic fracturing. It ensures that the material cost is reduced while the amount of fracturing fluid is increased. In addition, the multi-stage proppant combination is used to support all levels of fractures, which improves the conductivity of all levels of fractures. During the implementation of refracturing, the amount of fluid used in single layer is gradually increased, from 2300 to 3500 cubic meters, the maximum amount of fracturing fluid injected in single layer is 10000 cubic meters, and the proportion of slippery water is increased from 80% to 95%. The proppant is composed of 100/140 mesh and 40/70 mesh ceramic proppant, with an average sand content of 97.7 cubic meters per layer. From the perspective of construction data, after increasing the amount of fracturing fluid used in single well, the average pump stopping pressure of the later batch of construction wells is increased by 3.5 Mpa and the construction pressure is increased by 4.5MPa. After adding temporary plugging agent, the average construction pressure increased by 1.8 MPa, and the opening characteristics of new joints were obvious. After refracturing, all test wells are produced by automatic injection production, the total number of automatic injection production days is 5.2 times of the initial fracturing, and the cumulative oil production is 1.5 times of the initial fracturing. Through practice, the original injection production relationship is broken. Increasing the amount of fracturing fluid can not only supplement the formation energy, but also improve the complexity of fractures. The multi-stage proppant slug can significantly improve the conductivity of fractures at all levels, prolong the life cycle of old wells, and provide technical support for multi thin layer reconstruction.
{"title":"Extending the Life Cycle of Old Wells: Fracturing and Replenishing Formation Energy at the Same Time","authors":"Wang Chunpeng, Zhu Weiyao, Cui Weixiang, Zhang Min, H. Xueqin, Shi Shuzhe, Nie Zhen","doi":"10.4043/31560-ms","DOIUrl":"https://doi.org/10.4043/31560-ms","url":null,"abstract":"\u0000 In order to extend the life cycle of the developed oilfield and ensure the stable production of the oilfield, the exploration and practice of supplementary energy refracturing has been carried out in a small block in eastern China which is on the verge of shutdown since 2017. All of the well in this block are vertical wells. This technology breaks the injection production relationship of the original well pattern. The injection wells and production wells are fractured at the same time. Fracturing fluid is not only used for fracturing, but also for supplementing formation energy. In order to produce more new fractures and make them more complex, low viscosity slippery water is used in hydraulic fracturing. It ensures that the material cost is reduced while the amount of fracturing fluid is increased. In addition, the multi-stage proppant combination is used to support all levels of fractures, which improves the conductivity of all levels of fractures. During the implementation of refracturing, the amount of fluid used in single layer is gradually increased, from 2300 to 3500 cubic meters, the maximum amount of fracturing fluid injected in single layer is 10000 cubic meters, and the proportion of slippery water is increased from 80% to 95%. The proppant is composed of 100/140 mesh and 40/70 mesh ceramic proppant, with an average sand content of 97.7 cubic meters per layer. From the perspective of construction data, after increasing the amount of fracturing fluid used in single well, the average pump stopping pressure of the later batch of construction wells is increased by 3.5 Mpa and the construction pressure is increased by 4.5MPa. After adding temporary plugging agent, the average construction pressure increased by 1.8 MPa, and the opening characteristics of new joints were obvious. After refracturing, all test wells are produced by automatic injection production, the total number of automatic injection production days is 5.2 times of the initial fracturing, and the cumulative oil production is 1.5 times of the initial fracturing. Through practice, the original injection production relationship is broken. Increasing the amount of fracturing fluid can not only supplement the formation energy, but also improve the complexity of fractures. The multi-stage proppant slug can significantly improve the conductivity of fractures at all levels, prolong the life cycle of old wells, and provide technical support for multi thin layer reconstruction.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90463827","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}
The objective of this paper is to provide an approach in mitigating the adverse effects of mercury found in production fields which include the evaluation on the requirement for mercury treatment facility and suitable technology and best location for the production fields and onshore LNG facilities. The evaluation included assessment of pipeline integrity and managing unexpected increase in mercury content to ensure Mercury Removal Unit (MRU) is capable to treat the gas within the design specification The method includes mercury mapping and analysis of the results. Evaluation of technology and type at various streams in gas, condensate and water streams. There is no method to predict mercury production forecast and sizing cannot be based on one exploration well data only. Subsurface data might not be representative due to improper procedure, sampling, preservation and timing. Rigorous technology evaluation was evaluated for various mercury species covering its vulnerability to operations abnormalities such as entrainment of moisture, spikes of mercury content, changes to feed gas, hydrogen sulfide content, historical experience of mercury contamination and its impact to operations and performance of cryogenic systems and chemical injection for pipelines. Review of effectiveness of mercury removal technology for gas stream cover metal sulfide based adsorbent and metal oxide based with H2S in-situ sulfiding. In view that there is no proven technology for condensates stream, particulates mercury removal using filtration and hydrocyclones of the multiphase condensate /water and water streams were considered Mercury has exceeded downstream design specification and pose threats to existing LNG facilities aluminum cryogenic heat exchanger. Speciation, particle size distribution and the use of a practical size test rig on site, adsorbent -condensate compatibility test are approaches to determine the capacity of the MRU. Based on the selected technology, concepts were derived for gas and condensate to ascertain the feasibility of mercury removal, particulate filtration, mercury impact to pipeline integrity and the basis for the onshore mercury removal facility. This yielded seven (7) different concepts or options addressing both MRU gas and condensate either at offshore platform or onshore facilities. The concept select ascertained the optimum requirement to install the mercury removal unit onshore upstream of an Acid Gas Removal Unit in the LNG facilities. A two-stage filtration to remove mercury particulates above 1 micron was selected for offshore facility. Understanding the behaviour of mercury and the distribution tendencies into the various streams and factors that influence this distribution would provide insight on the integrity of production and pipeline system and management of mercury for operations.
{"title":"Management of Mercury Offshore for Onshore Production Facilities","authors":"Mohamed Sopiee Saaibon, Z. Kayat, Fatimah A Karim","doi":"10.4043/31465-ms","DOIUrl":"https://doi.org/10.4043/31465-ms","url":null,"abstract":"\u0000 The objective of this paper is to provide an approach in mitigating the adverse effects of mercury found in production fields which include the evaluation on the requirement for mercury treatment facility and suitable technology and best location for the production fields and onshore LNG facilities. The evaluation included assessment of pipeline integrity and managing unexpected increase in mercury content to ensure Mercury Removal Unit (MRU) is capable to treat the gas within the design specification\u0000 The method includes mercury mapping and analysis of the results. Evaluation of technology and type at various streams in gas, condensate and water streams. There is no method to predict mercury production forecast and sizing cannot be based on one exploration well data only. Subsurface data might not be representative due to improper procedure, sampling, preservation and timing. Rigorous technology evaluation was evaluated for various mercury species covering its vulnerability to operations abnormalities such as entrainment of moisture, spikes of mercury content, changes to feed gas, hydrogen sulfide content, historical experience of mercury contamination and its impact to operations and performance of cryogenic systems and chemical injection for pipelines. Review of effectiveness of mercury removal technology for gas stream cover metal sulfide based adsorbent and metal oxide based with H2S in-situ sulfiding. In view that there is no proven technology for condensates stream, particulates mercury removal using filtration and hydrocyclones of the multiphase condensate /water and water streams were considered\u0000 Mercury has exceeded downstream design specification and pose threats to existing LNG facilities aluminum cryogenic heat exchanger. Speciation, particle size distribution and the use of a practical size test rig on site, adsorbent -condensate compatibility test are approaches to determine the capacity of the MRU. Based on the selected technology, concepts were derived for gas and condensate to ascertain the feasibility of mercury removal, particulate filtration, mercury impact to pipeline integrity and the basis for the onshore mercury removal facility. This yielded seven (7) different concepts or options addressing both MRU gas and condensate either at offshore platform or onshore facilities. The concept select ascertained the optimum requirement to install the mercury removal unit onshore upstream of an Acid Gas Removal Unit in the LNG facilities. A two-stage filtration to remove mercury particulates above 1 micron was selected for offshore facility.\u0000 Understanding the behaviour of mercury and the distribution tendencies into the various streams and factors that influence this distribution would provide insight on the integrity of production and pipeline system and management of mercury for operations.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86327219","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}
Life cycle cost (LCC) evaluation has been a powerful decision-making support tool for assessing different alternatives throughout an asset's life cycle. After having been ushered in by the global awakening of a sustainability conscience, there is a need to upgrade the LCC calculation to include these sustainability factors. This train of thought has also been acknowledged by the oil and gas industry, through the recent update of the ISO 15663:2021 (International Organization for Standardization), which addressed sustainability, in conjunction with other ISO standards, guides and the IOGP (International Association of Oil & Gas Producers) report. Following this trend, the paper aims to present a sustainable LCC efficiency model for oil and gas facilities, particularly in the selection of the optimum equipment or package. To achieve this, the paper drilled down possible cost factors related to these concerns and offers a model that is required to remain relevant in the current conditions. The LCC model presented was developed through a systematic research method, including trials, feedback loops and validation processes. Potential production risks were also factored in, so that the LCC would deliver the best possible value to the business. Finally, a step-by-step process in developing the LCC structure will be illustrated and explained in the paper.
{"title":"Building a Sustainable Life Cycle Cost Efficiency Model","authors":"Mayang Kusumawardhani, M. Arnhus, T. Markeset","doi":"10.4043/31432-ms","DOIUrl":"https://doi.org/10.4043/31432-ms","url":null,"abstract":"\u0000 Life cycle cost (LCC) evaluation has been a powerful decision-making support tool for assessing different alternatives throughout an asset's life cycle. After having been ushered in by the global awakening of a sustainability conscience, there is a need to upgrade the LCC calculation to include these sustainability factors. This train of thought has also been acknowledged by the oil and gas industry, through the recent update of the ISO 15663:2021 (International Organization for Standardization), which addressed sustainability, in conjunction with other ISO standards, guides and the IOGP (International Association of Oil & Gas Producers) report.\u0000 Following this trend, the paper aims to present a sustainable LCC efficiency model for oil and gas facilities, particularly in the selection of the optimum equipment or package. To achieve this, the paper drilled down possible cost factors related to these concerns and offers a model that is required to remain relevant in the current conditions.\u0000 The LCC model presented was developed through a systematic research method, including trials, feedback loops and validation processes. Potential production risks were also factored in, so that the LCC would deliver the best possible value to the business. Finally, a step-by-step process in developing the LCC structure will be illustrated and explained in the paper.","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":"85412441","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
H. Bakar, Narindran Ravichandran, M. Abu Bakar, Khairul Nizam Idris, R. Masoudi
Restoring formation damage by acid matrix treatment in sandstone formations faces multiple challenges due to variable petrophysical and compositional properties. The S field team had carried out a formation damage study to determine the damage mechanism, evaluate the best acid treatment recipe to treat the formation damage mechanism identified and study the effect on petrophysical properties before and after the treatment. Most of the S field oil producers experienced rapid decline in production, and this is suspected to be due to fines migration and plugging. The formation damage study is divided into three sections: the field background review, the potential formation damage identification, and the evaluation of the best acid treatment recipe for S field formations. Core samples from a wide range of mineralogy, permeability, pore distributions and porosity were evaluated using laboratory testing to describe the elemental and morphological presence of each mineral. Then, four of the core samples were high graded for evaluating the permeability by flooding with brine and oil to examine the fines migration and dispersion potential of clays and siderite. The next phase of this study was continued with the core sample acidization using organic acid and HCl to identify a suitable acid treatment cocktail. This will be discussed in detail in this paper. Fines migration was observed to be resulted from movement of both siderite and aluminosilicate clays under representative conditions. The evidence from the geological analyses and core flooding shows that in brine, there is a tendency for siderite to migrate, potentially even at low flow rates. The effect is expected to be more severe in brine than in oil and possibly in both phases. HCl acid and strong organic acid treatments with and without the presence of an iron control to remove iron carbonates in siderites and iron-silicate gel formation will be outlined in this paper. The result of the HCl treatment was that it was able to remove carbonate material from the core, but it was still not able to substantially improve wellbore permeability. An additional short phase of testing examining a HF-HCl package was demonstrated more effective and is discussed extensively in this paper. This laboratory work is not unusual to the sandstone stimulation however the discussion of the core flood testing findings and acid recipe comparative study provides more comprehensive understanding on the effect of fines migration to the success of the stimulation treatment and its effect on petrophysical properties. The outcome of this work will lead to a reliable design of sandstone matrix acid treatments and, increase the acid stimulation treatment success rate which subsequently optimizes well productivity.
{"title":"First Experience Matters: Evaluation of Acid Treatment Recipe for Fines Migration Control in S Field Sandstone Reservoirs","authors":"H. Bakar, Narindran Ravichandran, M. Abu Bakar, Khairul Nizam Idris, R. Masoudi","doi":"10.4043/31508-ms","DOIUrl":"https://doi.org/10.4043/31508-ms","url":null,"abstract":"\u0000 Restoring formation damage by acid matrix treatment in sandstone formations faces multiple challenges due to variable petrophysical and compositional properties. The S field team had carried out a formation damage study to determine the damage mechanism, evaluate the best acid treatment recipe to treat the formation damage mechanism identified and study the effect on petrophysical properties before and after the treatment. Most of the S field oil producers experienced rapid decline in production, and this is suspected to be due to fines migration and plugging.\u0000 The formation damage study is divided into three sections: the field background review, the potential formation damage identification, and the evaluation of the best acid treatment recipe for S field formations. Core samples from a wide range of mineralogy, permeability, pore distributions and porosity were evaluated using laboratory testing to describe the elemental and morphological presence of each mineral. Then, four of the core samples were high graded for evaluating the permeability by flooding with brine and oil to examine the fines migration and dispersion potential of clays and siderite. The next phase of this study was continued with the core sample acidization using organic acid and HCl to identify a suitable acid treatment cocktail. This will be discussed in detail in this paper.\u0000 Fines migration was observed to be resulted from movement of both siderite and aluminosilicate clays under representative conditions. The evidence from the geological analyses and core flooding shows that in brine, there is a tendency for siderite to migrate, potentially even at low flow rates. The effect is expected to be more severe in brine than in oil and possibly in both phases. HCl acid and strong organic acid treatments with and without the presence of an iron control to remove iron carbonates in siderites and iron-silicate gel formation will be outlined in this paper. The result of the HCl treatment was that it was able to remove carbonate material from the core, but it was still not able to substantially improve wellbore permeability. An additional short phase of testing examining a HF-HCl package was demonstrated more effective and is discussed extensively in this paper.\u0000 This laboratory work is not unusual to the sandstone stimulation however the discussion of the core flood testing findings and acid recipe comparative study provides more comprehensive understanding on the effect of fines migration to the success of the stimulation treatment and its effect on petrophysical properties. The outcome of this work will lead to a reliable design of sandstone matrix acid treatments and, increase the acid stimulation treatment success rate which subsequently optimizes well productivity.","PeriodicalId":11217,"journal":{"name":"Day 4 Fri, March 25, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83442442","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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