Abdur Rahman Shah, K. Ghorayeb, Hussein Mustapha, Samat Ramatullayev, Nour El Droubi, C. Kloucha
One of the most important aspects of any dynamic model is relative permeability. To unlock the potential of large relative permeability data bases, the proposed workflow integrates data analysis, machine learning, and artificial intelligence (AI). The workflow allows for the automated generation of a clean database and a digital twin of relative permeability data. The workflow employs artificial intelligence to identify analogue data from nearby fields by extending the rock typing scheme across multiple fields for the same formation. We created a fully integrated and intelligent tool for extracting SCAL data from laboratory reports, then processing and modeling the data using AI and automation. After the endpoints and Corey coefficients have been extracted, the quality of the relative permeability samples is checked using an automated history match and simulation of core flood experiments. An AI model that has been trained is used to identify analogues for various rock types from other fields that produce from the same formations. Finally, based on the output of the AI model, the relative permeabilities are calculated using data from the same and analog fields. The workflow solution offers a solid and well-integrated methodology for creating a clean database for relative permeability. The workflow made it possible to create a digital twin of the relative permeability data using the Corey and LET methods in a systematic manner. The simulation runs were designed so that the pressure measurements are history matched with the adjustment and refinement of the relative permeability curve. The AI workflow enabled us to realize the full potential of the massive database of relative permeability samples from various fields. To ensure utilization in the dynamic model, high, mid, and low cases were created in a robust manner. The workflow solution employs artificial intelligence models to identify rock typing analogues from the same formation across multiple fields. The AI-generated analogues, combined with a robust workflow for quickly QC’ing the relative permeability data, allow for the creation of a fully integrated relative permeability database. The proposed solution is agile and scalable, and it can adapt to any data and be applied to any field.
{"title":"Unleashing the Potential of Relative Permeability Using Artificial Intelligence","authors":"Abdur Rahman Shah, K. Ghorayeb, Hussein Mustapha, Samat Ramatullayev, Nour El Droubi, C. Kloucha","doi":"10.2118/207855-ms","DOIUrl":"https://doi.org/10.2118/207855-ms","url":null,"abstract":"\u0000 One of the most important aspects of any dynamic model is relative permeability. To unlock the potential of large relative permeability data bases, the proposed workflow integrates data analysis, machine learning, and artificial intelligence (AI). The workflow allows for the automated generation of a clean database and a digital twin of relative permeability data. The workflow employs artificial intelligence to identify analogue data from nearby fields by extending the rock typing scheme across multiple fields for the same formation.\u0000 We created a fully integrated and intelligent tool for extracting SCAL data from laboratory reports, then processing and modeling the data using AI and automation. After the endpoints and Corey coefficients have been extracted, the quality of the relative permeability samples is checked using an automated history match and simulation of core flood experiments. An AI model that has been trained is used to identify analogues for various rock types from other fields that produce from the same formations. Finally, based on the output of the AI model, the relative permeabilities are calculated using data from the same and analog fields. The workflow solution offers a solid and well-integrated methodology for creating a clean database for relative permeability. The workflow made it possible to create a digital twin of the relative permeability data using the Corey and LET methods in a systematic manner. The simulation runs were designed so that the pressure measurements are history matched with the adjustment and refinement of the relative permeability curve.\u0000 The AI workflow enabled us to realize the full potential of the massive database of relative permeability samples from various fields. To ensure utilization in the dynamic model, high, mid, and low cases were created in a robust manner. The workflow solution employs artificial intelligence models to identify rock typing analogues from the same formation across multiple fields. The AI-generated analogues, combined with a robust workflow for quickly QC’ing the relative permeability data, allow for the creation of a fully integrated relative permeability database. The proposed solution is agile and scalable, and it can adapt to any data and be applied to any field.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89611901","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}
Saqer Saleh Al-Messabi, Anouar Abdul Qader Zebidi, Khaled Abdullah Al Hosani
The objective of the paper is to present the success story of carrying out an in-line inspection (ILI) on a 50 years old offshore subsea flare line. The project was particularly challenging because the 30" flare line had no pigging facilities, a reducer, a subsea tie-in connection, as well as other restrictions. The paper shall outline the approach and methodology adopted to conduct the inspection in a safe and successful manner while adhering to the company and government health, safety, and environmental regulations and meeting the shutdown window. The 1 km long 30" flare line runs from a collector-separator platform to a flare tower. A site survey was conducted to identify process, space, and rigging related requirements. The shutdown window was allotted and fixed by the production teams. The line was first flushed to remove the hydrocarbons using a pumping spread mounted on a support vessel. This was followed by various modification works in addition to rigging up the temporary pigging traps. The works enlisted the help of support vessels and scaffolding teams. Extra controls were implemented due to the low maximum allowable operating pressure and the dirty pigging water in order to safeguard the property and environment. Eventually, 22 cleaning pigs were launched a in a train fashion. An Ultrasonic (UT) ILI tool was then used to gather information on the pipeline. Finally, the pipeline was dried using foam pigs. The operation was a success mainly because of the planning factor. Many activities were integrated including the availability of a maintenance barge which played a huge role in the operation. This was the first pigging operation on the flare line which was commissioned in 1971 - a total of 185 kg of debris was collected. Moreover, the UT inspection provided quantitative data which enabled an accurate assessment of the subsea pipeline integrity status. It is estimated that USD 4 million were saved by completing the works mainly through efficient planning and utilization of in-house available resources. The inspection results will form a cornerstone in development of future asset replacement plans for this category of flare lines. The success has created potential savings for another 21 challenging flare lines planned to be inspected for the next 5 years. The approach highlights the steps taken to conduct the quantitative ILI of an aged flare line (50 years old), with various inherent challenges, to explore the possibility of accurately inspecting and extending the remnant life of aged assets that are un-piggable, in a safe and environmentally friendly manner. Thus, resulting in positive impacts in savings and further optimizations in the asset replacement plans
{"title":"In-Line Inspection of Offshore Non-Piggable and Challenging 30\" Subsea Flare Line","authors":"Saqer Saleh Al-Messabi, Anouar Abdul Qader Zebidi, Khaled Abdullah Al Hosani","doi":"10.2118/208000-ms","DOIUrl":"https://doi.org/10.2118/208000-ms","url":null,"abstract":"\u0000 The objective of the paper is to present the success story of carrying out an in-line inspection (ILI) on a 50 years old offshore subsea flare line. The project was particularly challenging because the 30\" flare line had no pigging facilities, a reducer, a subsea tie-in connection, as well as other restrictions. The paper shall outline the approach and methodology adopted to conduct the inspection in a safe and successful manner while adhering to the company and government health, safety, and environmental regulations and meeting the shutdown window.\u0000 The 1 km long 30\" flare line runs from a collector-separator platform to a flare tower. A site survey was conducted to identify process, space, and rigging related requirements. The shutdown window was allotted and fixed by the production teams. The line was first flushed to remove the hydrocarbons using a pumping spread mounted on a support vessel. This was followed by various modification works in addition to rigging up the temporary pigging traps. The works enlisted the help of support vessels and scaffolding teams. Extra controls were implemented due to the low maximum allowable operating pressure and the dirty pigging water in order to safeguard the property and environment. Eventually, 22 cleaning pigs were launched a in a train fashion. An Ultrasonic (UT) ILI tool was then used to gather information on the pipeline. Finally, the pipeline was dried using foam pigs.\u0000 The operation was a success mainly because of the planning factor. Many activities were integrated including the availability of a maintenance barge which played a huge role in the operation. This was the first pigging operation on the flare line which was commissioned in 1971 - a total of 185 kg of debris was collected. Moreover, the UT inspection provided quantitative data which enabled an accurate assessment of the subsea pipeline integrity status. It is estimated that USD 4 million were saved by completing the works mainly through efficient planning and utilization of in-house available resources. The inspection results will form a cornerstone in development of future asset replacement plans for this category of flare lines. The success has created potential savings for another 21 challenging flare lines planned to be inspected for the next 5 years.\u0000 The approach highlights the steps taken to conduct the quantitative ILI of an aged flare line (50 years old), with various inherent challenges, to explore the possibility of accurately inspecting and extending the remnant life of aged assets that are un-piggable, in a safe and environmentally friendly manner. Thus, resulting in positive impacts in savings and further optimizations in the asset replacement plans","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78058787","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}
Hydrogen holds enormous potential in helping the world achieve its decarbonization goals and is set to play a key role in the Energy Transition. However, two central building blocks are needed to make the hydrogen economy a reality: 1) a sufficient source of emissions-free (i.e., blue or green) hydrogen production and 2) a needs-based transportation and storage network that can reliably and cost-effectively supply hydrogen to end-users. Given the high costs associated with developing new transportation infrastructure, many governments, pipeline operators, and regulatory bodies have begun exploring if it is both possible and economical to convert existing natural gas (i.e., methane) infrastructure for hydrogen operation. This paper outlines opportunities and technical challenges associated with such an endeavor – with a particular focus on adaptation requirements for rotating equipment/compressor drive trains and metallurgical and integrity considerations for pipelines.
{"title":"Opportunities and Challenges in Converting Existing Natural Gas Infrastructure for Hydrogen Operation","authors":"P. Adam","doi":"10.2118/208033-ms","DOIUrl":"https://doi.org/10.2118/208033-ms","url":null,"abstract":"\u0000 Hydrogen holds enormous potential in helping the world achieve its decarbonization goals and is set to play a key role in the Energy Transition. However, two central building blocks are needed to make the hydrogen economy a reality: 1) a sufficient source of emissions-free (i.e., blue or green) hydrogen production and 2) a needs-based transportation and storage network that can reliably and cost-effectively supply hydrogen to end-users.\u0000 Given the high costs associated with developing new transportation infrastructure, many governments, pipeline operators, and regulatory bodies have begun exploring if it is both possible and economical to convert existing natural gas (i.e., methane) infrastructure for hydrogen operation. This paper outlines opportunities and technical challenges associated with such an endeavor – with a particular focus on adaptation requirements for rotating equipment/compressor drive trains and metallurgical and integrity considerations for pipelines.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81900331","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}
CO2 capture & storage is foreseen as a necessity to limit global warming, as indicated by the recent reports from International Energy Agency. Major initiatives have to be initiated in a near future with concrete actions to get efficient results in limiting global warming. Based on its decades of experience in gas sweetening AXENS has developed an expertise in CO2 removal technologies. While conventional amine based processes can be used for some CO2 capture applications like for instance the treatment of process gas streams under pressure, other applications for low pressure gas streams like flue gases will require innovative advanced solutions. AXENS has studied various options for the removal of CO2 in SMR based hydrogen schemes, including the treatment of the process gas or the treatment of the flue gases from the SMR furnace, evaluating the respective merits of those options. For the treatment of the flue gases a new technology developed by IFPEN and AXENS based on a second generation amine solvent is considered : DMX™ DMX™ process, is foreseen as a key contributor for the removal of CO2 from all kind of low pressure gas streams. This process allows drastic reduction of CO2 capture cost in comparison to more conventional solvent such as MEA and others available solvents. The specific features of this solvent allows significant reduction of the heat requirements for the regeneration of the solvent. It also allows regenerating the solvent directly under pressure up to 6 bara, reducing the costs for downstream CO2 compression Preliminary techno-economic studies show significant advantage of DMX™ technology relatively to MEA : up to 30 % reduction in OPEX can be obtained for lower or similar CAPEX, depending on the condition. This process has been developed at the lab scale and is now going to be demonstrated in an industrial pilot unit installed in ArcelorMittal's steel mill plant in Dunkirk (France). This demonstration benefits from the support of EU's H2020 programme, under 3D project.
{"title":"Optimized CO2 Capture Solutions for Carbon Free Hydrogen Production with Development of New Demixing Solvent Technology DMX™","authors":"Clément Salais, L. Normand, C. Streicher","doi":"10.2118/207875-ms","DOIUrl":"https://doi.org/10.2118/207875-ms","url":null,"abstract":"\u0000 CO2 capture & storage is foreseen as a necessity to limit global warming, as indicated by the recent reports from International Energy Agency. Major initiatives have to be initiated in a near future with concrete actions to get efficient results in limiting global warming. Based on its decades of experience in gas sweetening AXENS has developed an expertise in CO2 removal technologies. While conventional amine based processes can be used for some CO2 capture applications like for instance the treatment of process gas streams under pressure, other applications for low pressure gas streams like flue gases will require innovative advanced solutions.\u0000 AXENS has studied various options for the removal of CO2 in SMR based hydrogen schemes, including the treatment of the process gas or the treatment of the flue gases from the SMR furnace, evaluating the respective merits of those options. For the treatment of the flue gases a new technology developed by IFPEN and AXENS based on a second generation amine solvent is considered : DMX™\u0000 DMX™ process, is foreseen as a key contributor for the removal of CO2 from all kind of low pressure gas streams. This process allows drastic reduction of CO2 capture cost in comparison to more conventional solvent such as MEA and others available solvents. The specific features of this solvent allows significant reduction of the heat requirements for the regeneration of the solvent. It also allows regenerating the solvent directly under pressure up to 6 bara, reducing the costs for downstream CO2 compression\u0000 Preliminary techno-economic studies show significant advantage of DMX™ technology relatively to MEA : up to 30 % reduction in OPEX can be obtained for lower or similar CAPEX, depending on the condition.\u0000 This process has been developed at the lab scale and is now going to be demonstrated in an industrial pilot unit installed in ArcelorMittal's steel mill plant in Dunkirk (France). This demonstration benefits from the support of EU's H2020 programme, under 3D project.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84120566","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}
Giorgio Arcangeletti, Daniele Scarsciafratte, M. Leporini, Benedetto Orselli, Angelo Santicchia, E. Torselletti, E. Aloigi
COVID-19 pandemic is accelerating the transition to decarbonized energy systems. In this context, major Operators and Contractors are bound to promote innovation and technological development. The paper describes how this is being applied to the design of offshore pipelines that are now required to transport not only Hydrocarbons but also anthropogenic CO2 and low-carbon Hydrogen. In order to evaluate all the new technical challenges presented in designing CO2 and H2 pipelines, a state of art has been carried out and is here presented focusing on all the new technical aspects associated to the main disciplines involved in the pipeline network design. Different technical aspects (such as performances evaluation of Equation of State in CCS, Design Standards application to both CO2 and hydrogen pipelines, energy capacity of hydrogen pipelines and others) have been also analytically or numerically addressed simulating credible pipeline operating scenarios. To achieve that, an intensive engineering effort is being dedicated to the development of knowledge, engineering tools, methods and procedures that will be the basis for the execution of future projects concerning H2 and CO2 transportation and storage. A particular focus has been dedicated to offshore pipeline design both for new installation and repurposing of existing ones. In parallel, the cooperation started between Operators, Contractors, Manufacturers, Institutions and Universities, as described in the present paper, acts as a "booster" for the consolidation of knowledge and for the advancing of technology to put in place to overcome those new challenges. Recommendations are made in relation to the gaps found in experimental evidence present in literature and gaps in Standards coverage for the proper pipeline design in those new scenarios.
{"title":"The New Technological Frontiers of CO2 and Hydrogen Transportation Via Pipelines","authors":"Giorgio Arcangeletti, Daniele Scarsciafratte, M. Leporini, Benedetto Orselli, Angelo Santicchia, E. Torselletti, E. Aloigi","doi":"10.2118/207936-ms","DOIUrl":"https://doi.org/10.2118/207936-ms","url":null,"abstract":"\u0000 COVID-19 pandemic is accelerating the transition to decarbonized energy systems. In this context, major Operators and Contractors are bound to promote innovation and technological development. The paper describes how this is being applied to the design of offshore pipelines that are now required to transport not only Hydrocarbons but also anthropogenic CO2 and low-carbon Hydrogen. In order to evaluate all the new technical challenges presented in designing CO2 and H2 pipelines, a state of art has been carried out and is here presented focusing on all the new technical aspects associated to the main disciplines involved in the pipeline network design. Different technical aspects (such as performances evaluation of Equation of State in CCS, Design Standards application to both CO2 and hydrogen pipelines, energy capacity of hydrogen pipelines and others) have been also analytically or numerically addressed simulating credible pipeline operating scenarios. To achieve that, an intensive engineering effort is being dedicated to the development of knowledge, engineering tools, methods and procedures that will be the basis for the execution of future projects concerning H2 and CO2 transportation and storage. A particular focus has been dedicated to offshore pipeline design both for new installation and repurposing of existing ones. In parallel, the cooperation started between Operators, Contractors, Manufacturers, Institutions and Universities, as described in the present paper, acts as a \"booster\" for the consolidation of knowledge and for the advancing of technology to put in place to overcome those new challenges. Recommendations are made in relation to the gaps found in experimental evidence present in literature and gaps in Standards coverage for the proper pipeline design in those new scenarios.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80727135","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
C. Fabbri, H. A. Al Saadi, Ke-hui Wang, F. Maire, C. Romero, P. Cordelier, C. Prinet, S. Jouenne, O. Garnier, Siqing Xu, J. Leon, M. Baslaib, S. Masalmeh
Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir. This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results. A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints. The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high s
{"title":"Polymer Injection to Unlock Bypassed Oil in a Giant Carbonate Reservoir: Bridging the Gap Between Laboratory and Large Scale Polymer Project","authors":"C. Fabbri, H. A. Al Saadi, Ke-hui Wang, F. Maire, C. Romero, P. Cordelier, C. Prinet, S. Jouenne, O. Garnier, Siqing Xu, J. Leon, M. Baslaib, S. Masalmeh","doi":"10.2118/208121-ms","DOIUrl":"https://doi.org/10.2118/208121-ms","url":null,"abstract":"\u0000 Polymer flooding has long been proposed to improve sweep efficiency in heterogeneous reservoirs where polymer enhances cross flow between layers and forces water into the low permeability layers, leading to more homogeneous saturation profile. Although this approach could unlock large volumes of by-passed oil in layered carbonate reservoirs, compatibility of polymer solutions with high salinity - high temperature carbonate reservoirs has been hindering polymer injection projects in such harsh conditions. The aim of this paper is to present the laboratory work, polymer injection field test results and pilot design aimed to unlock target tertiary oil recovery in a highly heterogeneous mixed to oil-wet giant carbonate reservoir.\u0000 This paper focuses on a highly layered limestone reservoir with various levels of cyclicity in properties. This reservoir may be divided in two main bodies, i.e., an Upper zone and a Lower zone with permeability contrast of up to two orders of magnitude. The main part of the reservoir is currently under peripheral and mid-flank water injection. Field observations show that injected water tends to channel quickly through the Upper zone along the high permeability layers and bypass the oil in the Lower zone. Past studies have indicated that this water override phenomenon is caused by a combination of high permeability contrast and capillary forces which counteract gravity forces. In this setting, adequate polymer injection strategy to enhance cross-flow between these zones is investigated, building on laboratory and polymer injection test field results.\u0000 A key prerequisite for defining such EOR development scenario is to have representative static and dynamic models that captures the geological heterogeneity of this kind of reservoirs. This is achieved by an improved and integrated reservoir characterization, modelling and water injection history matching procedure. The history matched model was used to investigate different polymer injection schemes and resulted in an optimum pilot design. The injection scheme is defined based on dynamic simulations to maximize value, building on results from single-well polymer injection test, laboratory work and on previous published work, which have demonstrated the potential of polymer flooding for this reservoir. Our study evidences the positive impact of polymer propagation at field scale, improving the water-front stability, which is a function of pressure gradient near producer wells. Sensitivities to the position and number of polymer injectors have been performed to identify the best injection configuration, depending on the existing water injection scheme and the operating constraints.\u0000 The pilot design proposed builds on laboratory work and field monitoring data gathered during single-well polymer injection field test. Together, these elements represent building blocks to enable tertiary polymer recovery in giant heterogeneous carbonate reservoirs with high temperature - high s","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90767120","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. K. Singh, Pruthvi Raju Vegesna, Dhruva Prasad, Saideep Chandrashekar Kachodi, Sumit Lohiya, Deeksha Srivastava, R. Raj, Nitish Koduru, S. Mishra, Debaditya Barua, A. Pandey
The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project. The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance. Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved. Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.
{"title":"Successful Implementation of Polymer Flood in Aishwariya Field, Rajasthan, India - Concept to Full Field","authors":"A. K. Singh, Pruthvi Raju Vegesna, Dhruva Prasad, Saideep Chandrashekar Kachodi, Sumit Lohiya, Deeksha Srivastava, R. Raj, Nitish Koduru, S. Mishra, Debaditya Barua, A. Pandey","doi":"10.2118/207943-ms","DOIUrl":"https://doi.org/10.2118/207943-ms","url":null,"abstract":"\u0000 The Aishwariya Oil Field located in Barmer Basin of Rajasthan India having STOIIP of ∼300 MMBBLS was initially developed with down-dip edge water injection. The main reservoir unit, Fatehgarh Formation, has excellent reservoir characteristics with porosities of 20-30% and permeability of 1 to 5 Darcys. The Fatehgarh Formation is subdivided into Lower Fatehgarh (LF) and Upper Fatehgarh (UF) Formations, of which LF sands are more homogenous and have slightly better reservoir properties. The oil has in-situ viscosity of 10-30 cP. Given its adverse waterflood mobility ratio, the importance of EOR was recognised very early. Initial screening studies identified that chemical EOR (polymer and ASP) was preferred choice of EOR process. Extensive lab studies and simulation work was conducted to develop the polymer flood concept. A polymer flood development plan was prepared targeting the LF sands of the field utilizing the lessons learnt from nearby Mangala Field polymer implementation project.\u0000 The polymer flood in Aishwariya Field was implemented in two stages. In the first stage, a polymer injectivity test was conducted in 3 wells to establish the potential for polymer injection in these wells. The injection was extended to 3 more wells and continued for ∼4 years. Significant water cut drop was observed in nearby wells during this phase of polymer injection. In the next stage, polymer flooding was extended to the entire LF sands with drilling of 14 new infill wells and conversion of 8 existing wells to polymer injectors. A ∼14 km long pipeline was laid from the Mangala Central Polymer Facility to well pads in the field to cater to the requirement of 6-8 KBPD of ∼15000 ppm polymer mother solution. The philosophy of pre-production for extended periods was considered prior to start of polymer injection for all wells as it significantly improved injection (reduced skin) and conformance.\u0000 Full field polymer flood project was implemented, and injection was ramped up to the planned 40-50 KBPD of polymerized water within a month owing to good injectivity and polymer solution quality. A detailed laboratory, well and reservoir surveillance program has been implemented and the desired wellhead viscosity of 25-30 cP has been achieved.\u0000 Initial response shows significant increase in oil production rate and decrease in water-cut. This paper presents the polymer laboratory studies, initial long term injectivity test results, polymer flood development concept and planning, simulation studies and field implementation in LF Formation in Aishwariya Field.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"23 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89620354","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}
Diogo Camara Salim, M. Etchebes, M. Alexander, T. Akindipe
Historically, reservoir characterization in horizontal wells is accomplished through an integrated approach, combining geophysical evaluation and geomodelling with petrophysical assessment. However, the challenge consists of decreasing geomodels’ uncertainties to enable optimal trajectory to reach the sweet spots. Moreover, the main inputs of subsurface representation derived from measurements have their own spatial resolution and scale. For an effective multiphysics integrated approach, a technology capable to bridge from high-resolution borehole data to large scale seismic is required. This communication describes an innovative method to improve the delineation of reservoir geometry and properties surrounding high-angle wells. The novel procedure is divided into three stages. The first focuses on structural delineation using seismic attributes. The second uses advanced resistivity inversions from LWD very-deep directional resistivity tool to provide 3D mapping of the structure and fluid distribution. The third stage integrates the previous steps to build a comprehensive 3D reservoir model with high accuracy, tens of feet away from wellbore, while honoring the geological context and actual spatial resolution of measurements from borehole level up to seismic scale. The three-step methodology was successfully conducted on the horizontal section of an appraisal well. The automated seismic extraction workflow on the near and far angle-stack seismic cubes is used to interpret the main stratigraphic and tectonic events around the well vicinity. Within the drilling operation, the high-definition resistivity volumes are obtained from a special 3D interpolation of the 2D LWD EM azimuthal inversions, derived from the measurements of the very-deep directional resistivity tool. Such 3D resistivity mapping is used to determine lithological and structural features over tens of feet away from the wellbore. Then, by applying an integrated approach, key geological structures and detailed internal reservoir architectures were revealed, such as the throw and azimuth of a main fault and the spatial variations in lithologies within the reservoir zone. Finally, the respective workflow can be fully applied while drilling, enabling both the complete 3D reservoir mapping but also supporting strategic geosteering decisions to optimize the extension of the net-pay exposure.
{"title":"Novel 3D Reservoir Characterization Approach in High-Angle Wells by Means of Multiphysics Integration of Seismic and Advanced LWD Ultra-Deep Resistivity Inversions","authors":"Diogo Camara Salim, M. Etchebes, M. Alexander, T. Akindipe","doi":"10.2118/207499-ms","DOIUrl":"https://doi.org/10.2118/207499-ms","url":null,"abstract":"\u0000 Historically, reservoir characterization in horizontal wells is accomplished through an integrated approach, combining geophysical evaluation and geomodelling with petrophysical assessment. However, the challenge consists of decreasing geomodels’ uncertainties to enable optimal trajectory to reach the sweet spots. Moreover, the main inputs of subsurface representation derived from measurements have their own spatial resolution and scale. For an effective multiphysics integrated approach, a technology capable to bridge from high-resolution borehole data to large scale seismic is required. This communication describes an innovative method to improve the delineation of reservoir geometry and properties surrounding high-angle wells. The novel procedure is divided into three stages. The first focuses on structural delineation using seismic attributes. The second uses advanced resistivity inversions from LWD very-deep directional resistivity tool to provide 3D mapping of the structure and fluid distribution. The third stage integrates the previous steps to build a comprehensive 3D reservoir model with high accuracy, tens of feet away from wellbore, while honoring the geological context and actual spatial resolution of measurements from borehole level up to seismic scale.\u0000 The three-step methodology was successfully conducted on the horizontal section of an appraisal well. The automated seismic extraction workflow on the near and far angle-stack seismic cubes is used to interpret the main stratigraphic and tectonic events around the well vicinity. Within the drilling operation, the high-definition resistivity volumes are obtained from a special 3D interpolation of the 2D LWD EM azimuthal inversions, derived from the measurements of the very-deep directional resistivity tool. Such 3D resistivity mapping is used to determine lithological and structural features over tens of feet away from the wellbore. Then, by applying an integrated approach, key geological structures and detailed internal reservoir architectures were revealed, such as the throw and azimuth of a main fault and the spatial variations in lithologies within the reservoir zone. Finally, the respective workflow can be fully applied while drilling, enabling both the complete 3D reservoir mapping but also supporting strategic geosteering decisions to optimize the extension of the net-pay exposure.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89054596","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}
Nasser M. Al-Hajri, Muhammad Imran Javed, Akram R. Barghouti, Hisham I. Al-Shuwaikhat
This paper presents a workflow based on big data analytics to model the reliability of downhole Inflow Control Valves (ICVs) and predict their failures. The paper also offers economic analysis of optimum ICV stroking frequency to maintain valves functionality at the lowest possible cost to the oilfield operator. Installing an ICV in a petroleum well is a costly process and is done by a drilling or workover rig. As such, maintaining a fully functional ICV throughout the lifecycle of a well is important to ensure proper return on investment. ICVs are known to malfunction if not periodically stroked/cycled. The action of stroking ensures that each valve opening is free from obstructing material that would prevent the ICV from operating between one valve opening step to another. When an ICV malfunctions, a costly functionality restoration operation is sometime required without guaranteed results. In other cases, the valve is declared no longer useful and the asset cannot be further utilized due to malfunction. In this paper, an analytical decision making model to predict failures of ICVs is presented that is based on rigorous big data analytics. The model factors in the frequency of stroking before a valve fails. Then, an economic analysis accounting for the CAPEX & OPEX of an ICV is included to optimize the stroking frequency. The utilized techniques include ICV failure and stroking records and classifying the data into pre-defined criteria. Cumulative probability distribution functions are defined for each data set and used to generate failure probability functions. The probability equations are factored into an asset management cost scheme to minimize expected maintenance costs and probability of ICV failure. The results of applying this novel methodology to any smart well clearly showed maximized ICV service life and proper return of investment. The results demonstrate that ICVs lifecycle was prolonged with low maintenance cycling cost. Methodologies similar to the one presented in this paper are true manifestation of the fruitful impact IR4.0 technologies have on oilfields day-to-day operations.
{"title":"Big Data Analytics Maximizes Value from Smart Well Completions","authors":"Nasser M. Al-Hajri, Muhammad Imran Javed, Akram R. Barghouti, Hisham I. Al-Shuwaikhat","doi":"10.2118/207623-ms","DOIUrl":"https://doi.org/10.2118/207623-ms","url":null,"abstract":"\u0000 This paper presents a workflow based on big data analytics to model the reliability of downhole Inflow Control Valves (ICVs) and predict their failures. The paper also offers economic analysis of optimum ICV stroking frequency to maintain valves functionality at the lowest possible cost to the oilfield operator.\u0000 Installing an ICV in a petroleum well is a costly process and is done by a drilling or workover rig. As such, maintaining a fully functional ICV throughout the lifecycle of a well is important to ensure proper return on investment. ICVs are known to malfunction if not periodically stroked/cycled. The action of stroking ensures that each valve opening is free from obstructing material that would prevent the ICV from operating between one valve opening step to another. When an ICV malfunctions, a costly functionality restoration operation is sometime required without guaranteed results. In other cases, the valve is declared no longer useful and the asset cannot be further utilized due to malfunction.\u0000 In this paper, an analytical decision making model to predict failures of ICVs is presented that is based on rigorous big data analytics. The model factors in the frequency of stroking before a valve fails. Then, an economic analysis accounting for the CAPEX & OPEX of an ICV is included to optimize the stroking frequency. The utilized techniques include ICV failure and stroking records and classifying the data into pre-defined criteria. Cumulative probability distribution functions are defined for each data set and used to generate failure probability functions. The probability equations are factored into an asset management cost scheme to minimize expected maintenance costs and probability of ICV failure.\u0000 The results of applying this novel methodology to any smart well clearly showed maximized ICV service life and proper return of investment. The results demonstrate that ICVs lifecycle was prolonged with low maintenance cycling cost. Methodologies similar to the one presented in this paper are true manifestation of the fruitful impact IR4.0 technologies have on oilfields day-to-day operations.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79054067","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}
Avoiding an offshore COVID-19 outbreak while executing an urgent and intricate pipeline repair campaign is a significant challenge, especially in a country that is experiencing a COVID-19 positivity rate of more than 20% on daily basis. Any minor mismanagement of health management on the DSV (diving support vessel) may lead to a COVID-19 outbreak with the risk of shutting down the campaign and significantly impacting the business continuity objectives. Therefore, the major health management challenge is to avoid a COVID-19 outbreak on the DSV to ensure the well-being of personnel during campaign and to achieve the necessary pipeline repair. The approach taken was to deploy the DSV with team and tools/equipment as soon as possible to avoid a prolonged platform shutdown due to the pipeline leak event. In order to carry out the project, a detailed risk assessment taking account of medical, logistics and security considerations was undertaken in order avoid a COVID-19 outbreak on the vessel. The risk assessment enabled an adjustment to the quarantine requirements for the pipeline repair team before departure to the work location. A contingency plan was also developed to manage a scenario in which a member of the offshore team was infected with COVID-19, and in order to comply with applicable government regulation. Through the effective implementation of a detailed risk assessment, the company was able to complete the pipeline repair campaign without any offshore COVID-19 outbreaks. On the DSV there were 65 personnel working on multiple activities to execute the pipeline repair works on time and on budget. The site team made a diligent effort to follow the mitigations identified in the risk assessment, under the direction of company Business Continuity Management Team (BCMT). As a result of this effort, the company was able to resume production from the offshore platform in a timely manner. This paper discusses the effective implementation of detailed risk assessment on a DSV as part of company business continuity management amid COVID-19 pandemic in the country, including medical, logistics and security considerations. This project was implemented in a year-end period, beyond normal conditions and in a tight schedule.
{"title":"Health Management Challenges of the Pandemic - A Case Study from Recent Pipeline Repair Campaign","authors":"Widi Hernowo, Rosif Ridho, S. Sunarto","doi":"10.2118/207324-ms","DOIUrl":"https://doi.org/10.2118/207324-ms","url":null,"abstract":"Avoiding an offshore COVID-19 outbreak while executing an urgent and intricate pipeline repair campaign is a significant challenge, especially in a country that is experiencing a COVID-19 positivity rate of more than 20% on daily basis. Any minor mismanagement of health management on the DSV (diving support vessel) may lead to a COVID-19 outbreak with the risk of shutting down the campaign and significantly impacting the business continuity objectives. Therefore, the major health management challenge is to avoid a COVID-19 outbreak on the DSV to ensure the well-being of personnel during campaign and to achieve the necessary pipeline repair.\u0000 The approach taken was to deploy the DSV with team and tools/equipment as soon as possible to avoid a prolonged platform shutdown due to the pipeline leak event. In order to carry out the project, a detailed risk assessment taking account of medical, logistics and security considerations was undertaken in order avoid a COVID-19 outbreak on the vessel. The risk assessment enabled an adjustment to the quarantine requirements for the pipeline repair team before departure to the work location. A contingency plan was also developed to manage a scenario in which a member of the offshore team was infected with COVID-19, and in order to comply with applicable government regulation.\u0000 Through the effective implementation of a detailed risk assessment, the company was able to complete the pipeline repair campaign without any offshore COVID-19 outbreaks. On the DSV there were 65 personnel working on multiple activities to execute the pipeline repair works on time and on budget. The site team made a diligent effort to follow the mitigations identified in the risk assessment, under the direction of company Business Continuity Management Team (BCMT). As a result of this effort, the company was able to resume production from the offshore platform in a timely manner.\u0000 This paper discusses the effective implementation of detailed risk assessment on a DSV as part of company business continuity management amid COVID-19 pandemic in the country, including medical, logistics and security considerations. This project was implemented in a year-end period, beyond normal conditions and in a tight schedule.","PeriodicalId":10981,"journal":{"name":"Day 4 Thu, November 18, 2021","volume":"12 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-12-09","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81080731","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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