O. M. Perelman, A. S. Fadeikin, M. Gelfgat, Aleksandr Sergeevich Geraskin, Ziyadhan Abdusalamovich Emirov
The purpose of this work is to analyze the prospects for efficiency increasing of high-tech wells construction using a drilling complex based on downhole permanent magnet motor. For the first time, the article provides information about new drilling complex. Considered technology could provide a breakthrough in drilling high-tech wells. This technology combines advantages of drill string with electric wire and an ideal downhole motor with a wide rotational speed range, regardless of the type and flow rate of circulating agent. The article provides a brief comparative analysis of electrodrilling implementation results "generation 70s", the composition of new electric drilling complex and its difference from the previous one are considered in details. Complex meets the requirements of high-tech wells construction and allows automating drilling process using ultra-high-speed bi-directional data transmission channel and quickly assessing the parameters of drilling regime and direction of drilling, characteristics of rocks, pressure and temperature distribution along the wellbore. Permanent magnet motor ensures optimum drilling parameters for rock destruction at the bottomhole, regardless of the well profile and the type of circulating agent, including managed pressured drilling. Effectiveness of accidents prevention and mitigation is increased. Authors propose to discuss the prospects of electrodrilling technology using downhole permanent magnet motor, which is currently at TRL-3 level, to assess and specify adopted concept of electrical drilling complex development.
{"title":"Prospects of Electric Drilling for the Development of Well Construction Technologies","authors":"O. M. Perelman, A. S. Fadeikin, M. Gelfgat, Aleksandr Sergeevich Geraskin, Ziyadhan Abdusalamovich Emirov","doi":"10.2118/206463-ms","DOIUrl":"https://doi.org/10.2118/206463-ms","url":null,"abstract":"\u0000 The purpose of this work is to analyze the prospects for efficiency increasing of high-tech wells construction using a drilling complex based on downhole permanent magnet motor.\u0000 For the first time, the article provides information about new drilling complex. Considered technology could provide a breakthrough in drilling high-tech wells. This technology combines advantages of drill string with electric wire and an ideal downhole motor with a wide rotational speed range, regardless of the type and flow rate of circulating agent.\u0000 The article provides a brief comparative analysis of electrodrilling implementation results \"generation 70s\", the composition of new electric drilling complex and its difference from the previous one are considered in details. Complex meets the requirements of high-tech wells construction and allows automating drilling process using ultra-high-speed bi-directional data transmission channel and quickly assessing the parameters of drilling regime and direction of drilling, characteristics of rocks, pressure and temperature distribution along the wellbore. Permanent magnet motor ensures optimum drilling parameters for rock destruction at the bottomhole, regardless of the well profile and the type of circulating agent, including managed pressured drilling. Effectiveness of accidents prevention and mitigation is increased.\u0000 Authors propose to discuss the prospects of electrodrilling technology using downhole permanent magnet motor, which is currently at TRL-3 level, to assess and specify adopted concept of electrical drilling complex development.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80414439","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}
Allan Rojas, C. Yuan, D. Emelianov, E. Saifullin, S. Mehrabi-Kalajahi, M. Varfolomeev, V. Sudakov, Bulat R. Lotfullin, D. Shevchenko, B. Ganiev, A. Lutfullin, A. Zaripov
In-situ combustion (ISC) is an effective thermal enhanced oil recovery method. However, it is still not widely implemented in oilfields. One of the factors limiting the wide application of ISC is the challenge in its simulation and prediction. In this work, the oxidation experiments of maltenes and asphaltenes in reservoir rock were performed in the porous media thermo-effect cell (PMTEC) to establish a simplified reaction model based on non-isothermal measurements and to use it in numerical simulation of ISC process. It was found that the oxidation reaction process of oil fractions can be divided into different regions depending on generated self-energy rate and oxygen consumption rates that is up to the temperature. In order to propagate reactions from one mode to another, a specific oxygen consumption per unit mass of oil fractions is required. The average oxygen requirement for crossing LTOad (low temperature oxidation, oxygen addition reactions) boundary into LTC (low temperature combustion) mode was 64 mgO2/g(maltenes) and 10.4 mgO2/g(asphaltenes). To propagate reactions into HTO mode from the LTC mode, it requires about 646 mgO2/g(asphaltenes) for asphaltenes fraction. Moreover, this characterization seems to be a key tool when designing air injection in field pilots. Additionally, it was revealed that asphaltenes are more exothermic and require lower oxygen uptake per unit of temperature increment in comparison to maltenes. Furthermore, the mass conversion data obtained from non-isothermal measurements of oil fractions allow for the estimation of the stoichiometry coefficients of two low temperature oxidation reactions, i.e. oxidation and cocking processes, which can be included into a numerical simulation model to replicate combustion tube (CT) results. The numerical simulation model reveals that the simplified reaction model from a 6-step into a 3-step reaction scheme can reproduce ignition process, temperature profiles, combustion velocity, and fluid production, which thus makes it suitable for the upscaled modelling of ISC.
{"title":"A 3-Step Reaction Model For Numerical Simulation of In-Situ Combustion","authors":"Allan Rojas, C. Yuan, D. Emelianov, E. Saifullin, S. Mehrabi-Kalajahi, M. Varfolomeev, V. Sudakov, Bulat R. Lotfullin, D. Shevchenko, B. Ganiev, A. Lutfullin, A. Zaripov","doi":"10.2118/206430-ms","DOIUrl":"https://doi.org/10.2118/206430-ms","url":null,"abstract":"\u0000 In-situ combustion (ISC) is an effective thermal enhanced oil recovery method. However, it is still not widely implemented in oilfields. One of the factors limiting the wide application of ISC is the challenge in its simulation and prediction. In this work, the oxidation experiments of maltenes and asphaltenes in reservoir rock were performed in the porous media thermo-effect cell (PMTEC) to establish a simplified reaction model based on non-isothermal measurements and to use it in numerical simulation of ISC process. It was found that the oxidation reaction process of oil fractions can be divided into different regions depending on generated self-energy rate and oxygen consumption rates that is up to the temperature. In order to propagate reactions from one mode to another, a specific oxygen consumption per unit mass of oil fractions is required. The average oxygen requirement for crossing LTOad (low temperature oxidation, oxygen addition reactions) boundary into LTC (low temperature combustion) mode was 64 mgO2/g(maltenes) and 10.4 mgO2/g(asphaltenes). To propagate reactions into HTO mode from the LTC mode, it requires about 646 mgO2/g(asphaltenes) for asphaltenes fraction. Moreover, this characterization seems to be a key tool when designing air injection in field pilots. Additionally, it was revealed that asphaltenes are more exothermic and require lower oxygen uptake per unit of temperature increment in comparison to maltenes. Furthermore, the mass conversion data obtained from non-isothermal measurements of oil fractions allow for the estimation of the stoichiometry coefficients of two low temperature oxidation reactions, i.e. oxidation and cocking processes, which can be included into a numerical simulation model to replicate combustion tube (CT) results. The numerical simulation model reveals that the simplified reaction model from a 6-step into a 3-step reaction scheme can reproduce ignition process, temperature profiles, combustion velocity, and fluid production, which thus makes it suitable for the upscaled modelling of ISC.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74054822","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}
Yu. A. Rogov, K. Rymarenko, Alexei Mironositskii, S. Grishenko, A. Golubtsov, V. Kabanov, Tatyana Gusachenko, M. Nukhaev
Environmental stability and safety are becoming increasingly important in the world. Used to be mainly until recently under state control, the release and distribution of hazardous substances, wastes, and by-products is now monitored and regulated everywhere by enterprises, forced to establish special services that record and transmit information in the dispatch centers of the MES and other regulatory authorities of the Russian Federation. All the measures taken in this respect focus on safety improvement, ensuring occupational safety and accident prevention at enterprises, and safety of people, animals, and natural environmental location, which can be exposed to harmful and dangerous anthropogenic and natural factors. Aiming to provide a comprehensive solution to the problem, the authors proposed the concept of environmental monitoring and control over oil and gas wells using automated control and regulation systems and presented the concept on the example of the Orenburgskoe oil and gas condensate field
{"title":"Environmental Monitoring and Control Over Production Wells Using Automated Control and Regulation Systems for Orenburgskoe Oil and Gas Field","authors":"Yu. A. Rogov, K. Rymarenko, Alexei Mironositskii, S. Grishenko, A. Golubtsov, V. Kabanov, Tatyana Gusachenko, M. Nukhaev","doi":"10.2118/206604-ms","DOIUrl":"https://doi.org/10.2118/206604-ms","url":null,"abstract":"\u0000 Environmental stability and safety are becoming increasingly important in the world. Used to be mainly until recently under state control, the release and distribution of hazardous substances, wastes, and by-products is now monitored and regulated everywhere by enterprises, forced to establish special services that record and transmit information in the dispatch centers of the MES and other regulatory authorities of the Russian Federation. All the measures taken in this respect focus on safety improvement, ensuring occupational safety and accident prevention at enterprises, and safety of people, animals, and natural environmental location, which can be exposed to harmful and dangerous anthropogenic and natural factors.\u0000 Aiming to provide a comprehensive solution to the problem, the authors proposed the concept of environmental monitoring and control over oil and gas wells using automated control and regulation systems and presented the concept on the example of the Orenburgskoe oil and gas condensate field","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82213693","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}
Today, one of the most modern and successful geosteering methods in terms of net to gross value (NTG) is a proactive geosteering. The purpose of this article is to share the experience of using Remote Boundary Detection Tools to solve various geological problems and describe the ways of using the data from it. The method provides the ability to detect the approaching boundary (usually reservoir top) with resistivity contrast before entering it with the bit or BHA sensors. It allows to adjust well trajectory proactively and, therefore, increase Net to gross ratio. The article shows the ways to implement global experience in horizontal wells drilling and proposes ways to reduce the cost of well construction without elimination of High-Tech equipment in BHA. The article explains the methods of interpreting the output data from the tool that can determine the approach to one or several boundaries with resistivity contrast.
{"title":"Remote Bed Boundary Detection Tool Data Interpretation Without Special Geosteering Support to Drill Horizontal Wells","authors":"D. Nazipov, P. Shpakov","doi":"10.2118/206631-ms","DOIUrl":"https://doi.org/10.2118/206631-ms","url":null,"abstract":"\u0000 Today, one of the most modern and successful geosteering methods in terms of net to gross value (NTG) is a proactive geosteering.\u0000 The purpose of this article is to share the experience of using Remote Boundary Detection Tools to solve various geological problems and describe the ways of using the data from it.\u0000 The method provides the ability to detect the approaching boundary (usually reservoir top) with resistivity contrast before entering it with the bit or BHA sensors. It allows to adjust well trajectory proactively and, therefore, increase Net to gross ratio.\u0000 The article shows the ways to implement global experience in horizontal wells drilling and proposes ways to reduce the cost of well construction without elimination of High-Tech equipment in BHA.\u0000 The article explains the methods of interpreting the output data from the tool that can determine the approach to one or several boundaries with resistivity contrast.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75103853","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}
E. Yudin, N. Markov, V. Kotezhekov, Svetlana O. Kraeva, A. Makhnov, N. Trubnikov, L. Gorbushin
The presented paper is devoted to the development and testing of a computational tool for assessment of the reservoir pressure and prompt generation of the pressure maps of collectors. The tool is based on a proxy model that allows to solve the two-dimensional diffusion equation for unsteady liquid filtration using the boundary element method. To expand the applicability of the proxy model, an algorithm for automated parameter adaptation was developed. This algorithm allows to exclude knowingly unreliable data or low-quality data from modeling. This is achieved due to analyzing the correlation between the injection, production and bottom-hole pressures for the entire well stock over the history of the reservoir development. In addition, this paper describes an approach to modeling two-phase oil and gas filtration based on the use of pseudofunctions. This approach considers the influence of gas on the oil filtration process. The use of pseudofunctions allows us to linearize the diffusion equation for two-phase filtration and to solve it using the boundary element method in the same manner as for the case of oil filtration without gas. To demonstrate the results of the proxy model validation, examples of its use for generating the pore pressure maps for two real collectors are given. The average values of the reservoir pressure at the wells calculated using the proxy model are compared with the results of the corresponding well tests and with the traditional isobar maps. The analysis showed that the average deviation of the proxy model from the real reservoir pressures is less than 10%.
{"title":"Efficiency of Using a Proxy Model for Modeling of Reservoir Pressure","authors":"E. Yudin, N. Markov, V. Kotezhekov, Svetlana O. Kraeva, A. Makhnov, N. Trubnikov, L. Gorbushin","doi":"10.2118/206553-ms","DOIUrl":"https://doi.org/10.2118/206553-ms","url":null,"abstract":"\u0000 The presented paper is devoted to the development and testing of a computational tool for assessment of the reservoir pressure and prompt generation of the pressure maps of collectors. The tool is based on a proxy model that allows to solve the two-dimensional diffusion equation for unsteady liquid filtration using the boundary element method. To expand the applicability of the proxy model, an algorithm for automated parameter adaptation was developed. This algorithm allows to exclude knowingly unreliable data or low-quality data from modeling. This is achieved due to analyzing the correlation between the injection, production and bottom-hole pressures for the entire well stock over the history of the reservoir development. In addition, this paper describes an approach to modeling two-phase oil and gas filtration based on the use of pseudofunctions. This approach considers the influence of gas on the oil filtration process. The use of pseudofunctions allows us to linearize the diffusion equation for two-phase filtration and to solve it using the boundary element method in the same manner as for the case of oil filtration without gas. To demonstrate the results of the proxy model validation, examples of its use for generating the pore pressure maps for two real collectors are given. The average values of the reservoir pressure at the wells calculated using the proxy model are compared with the results of the corresponding well tests and with the traditional isobar maps. The analysis showed that the average deviation of the proxy model from the real reservoir pressures is less than 10%.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"32 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79348499","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}
T. Lapteva, L. A. Kopaeva, M. Mansurov, Vladimir Ivanovich Efremov, Viktor Nikolayevich Ilyuhin
The creation of an effective system of rescue support (the abbreviation ASO is adopted on the territory of the Russian Federation) in the implementation of the processes of oil and gas production and transportation in the Arctic seas of Russia is an urgent and difficult task. The feasibility of creating such a system for offshore oil and gas production facilities is due to the statistics of accidents and incidents at such facilities, as well as the fact that the Merchant Shipping Code of the Russian Federation, in essence, does not consider the applicability of the existing system of rescue operations on platforms that are exploring and developing mineral and other non-living resources the seabed and its bowels. The successful solution of numerous problems of rescue support, including the requirements for the quality of the system, indicators and criteria for the effectiveness of the operations carried out, can be significantly increased by using mathematical models that make it possible to identify patterns in the processes of performing urgent work, improve the quality of planning, and, consequently, the efficiency of management of various organizational systems. Applied in many areas of activity, the scientific direction "research of operations" is advisable to use when system generation of rescue support within the framework of improving the system of technical regulation of oil and gas enterprises. Determining the effectiveness of a purposeful process quantitatively will allow, on a scientific basis, with the involvement of modern mathematical methods, to solve the problem of increasing the effectiveness of the use of forces and means of the marine rescue support, including the functioning of the emergency support system in the mode of daily and emergency activities, as well as the preparation of the necessary forces and means. The novelty of the presented work lies in the application of the provisions of the theory and the apparatus of operations research to assessing the effectiveness of the system of the marine rescue support, which will further serve as a methodological basis for the development of a number of documents and provisions that are of practical importance: methods, requirements for the system of rescue support, documents in the field of control over the rescue system, etc.
{"title":"Efficiency Criteria of Operations in the Marine Resuce Support for Hydrocarbons Production and Transportation in the Arctic Zone of the Russian Federation","authors":"T. Lapteva, L. A. Kopaeva, M. Mansurov, Vladimir Ivanovich Efremov, Viktor Nikolayevich Ilyuhin","doi":"10.2118/206605-ms","DOIUrl":"https://doi.org/10.2118/206605-ms","url":null,"abstract":"\u0000 The creation of an effective system of rescue support (the abbreviation ASO is adopted on the territory of the Russian Federation) in the implementation of the processes of oil and gas production and transportation in the Arctic seas of Russia is an urgent and difficult task. The feasibility of creating such a system for offshore oil and gas production facilities is due to the statistics of accidents and incidents at such facilities, as well as the fact that the Merchant Shipping Code of the Russian Federation, in essence, does not consider the applicability of the existing system of rescue operations on platforms that are exploring and developing mineral and other non-living resources the seabed and its bowels.\u0000 The successful solution of numerous problems of rescue support, including the requirements for the quality of the system, indicators and criteria for the effectiveness of the operations carried out, can be significantly increased by using mathematical models that make it possible to identify patterns in the processes of performing urgent work, improve the quality of planning, and, consequently, the efficiency of management of various organizational systems. Applied in many areas of activity, the scientific direction \"research of operations\" is advisable to use when system generation of rescue support within the framework of improving the system of technical regulation of oil and gas enterprises.\u0000 Determining the effectiveness of a purposeful process quantitatively will allow, on a scientific basis, with the involvement of modern mathematical methods, to solve the problem of increasing the effectiveness of the use of forces and means of the marine rescue support, including the functioning of the emergency support system in the mode of daily and emergency activities, as well as the preparation of the necessary forces and means.\u0000 The novelty of the presented work lies in the application of the provisions of the theory and the apparatus of operations research to assessing the effectiveness of the system of the marine rescue support, which will further serve as a methodological basis for the development of a number of documents and provisions that are of practical importance: methods, requirements for the system of rescue support, documents in the field of control over the rescue system, etc.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85770824","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}
Muhamad Aizat B Kamaruddin, Muhammad Haniff Suhaimi, Firdaus Azwardy B. Salleh, N. Hardikar, N. Nathesan, Hilarion Millan, Fadzilazri Shapiei, Manh Hung Nguyen, Ivan Y. Nugraha Putra, Jos Pragt, Olufemi A. Adegbola, Adnan Ibrahim Khan
A brown field, offshore Sarawak, Malaysia, with multiple sub-layered laminated sands of varied pressure regimes and mobility ranges, was challenged by depletion, low mobility and uncertainty in the current fluid types and contacts. Optimal dynamic fluid characterization and testing techniques comprising both Wireline and Logging While Drilling (LWD) were applied in nine development wells to acquire reliable formation pressure data and collect representative fluid samples including fluid scanning. Some of the latest technologies were deployed during the dual crises of falling oil price and the Covid-19 pandemic. The S-profile wells were drilled using oil-base mud (OBM) with an average deviation of 60 degrees. Formation Pressure While Drilling (FPWD), Fluid Sampling While Drilling (FSWD) and wireline formation testing, and sampling were all utilized allowing appropriate assessment of zones of interest. Various probe types such as Conventional Circular, Reinforced Circular, Elongated, Extra-Elongated and Extended Range Focused were used successfully, ensuring that the right technology was deployed for the right job. Formation pressure and fluid samples were secured in a timely manner to minimize reservoir damage and optimize rig time without jeopardizing the data quality. As a classified crisis due to the pandemic, rather than delaying the operations, a Remote Operations Monitoring and Control Center was set-up in town to aid the limited crew at rig site. A high success rate was achieved in acquiring the latest formation pressure regimes, fluid gradients, scanning and sampling, allowing the best completion strategy to be implemented. With the selection of the appropriate probe type at individual sands, 336 pressure tests were conducted, 44 fluid gradients were established, 27 fluid identification (fluid-id / scanning) pump-outs were performed, and 20 representative formation fluid samples (oil, gas, water) were collected. Amongst the Layer-III, Layer-II and Layer-I sands, Layer-I was tight, with mobility < 1.0 mD/cP. Wireline focused probe sampling provided clean oil samples with 1.4 to-3.7 wt. % OBM filtrate contamination. The water samples collected from Layer-II during FSWD proved to be formation water and not injection water. The wells were thus completed as oil producers. Reliable fluid typing and PVT quality sampling at discrete depths saved rig time and eliminated the requirement of additional runs or services including Drill Stem Testing (DST). This case study has many firsts. It is the first time where latest fluid characterization and testing technologies in both Wireline and LWD were deployed for an alliance project in Malaysia and that too during dual crises of falling oil price and the pandemic aftermath. Overcoming various challenges including limited rig site manpower, there was no delay in completing the highly deviated wells with tight formations in a single drilling campaign and provided rig time savings. For the purpose of t
{"title":"Successful Reservoir Fluid Characterization and Testing While Overcoming the Challenges of Falling Oil Price and a Pandemic: A First for an Integrated Brown Field Alliance Project in Sarawak, Malaysia","authors":"Muhamad Aizat B Kamaruddin, Muhammad Haniff Suhaimi, Firdaus Azwardy B. Salleh, N. Hardikar, N. Nathesan, Hilarion Millan, Fadzilazri Shapiei, Manh Hung Nguyen, Ivan Y. Nugraha Putra, Jos Pragt, Olufemi A. Adegbola, Adnan Ibrahim Khan","doi":"10.2118/205778-ms","DOIUrl":"https://doi.org/10.2118/205778-ms","url":null,"abstract":"\u0000 A brown field, offshore Sarawak, Malaysia, with multiple sub-layered laminated sands of varied pressure regimes and mobility ranges, was challenged by depletion, low mobility and uncertainty in the current fluid types and contacts. Optimal dynamic fluid characterization and testing techniques comprising both Wireline and Logging While Drilling (LWD) were applied in nine development wells to acquire reliable formation pressure data and collect representative fluid samples including fluid scanning. Some of the latest technologies were deployed during the dual crises of falling oil price and the Covid-19 pandemic.\u0000 The S-profile wells were drilled using oil-base mud (OBM) with an average deviation of 60 degrees. Formation Pressure While Drilling (FPWD), Fluid Sampling While Drilling (FSWD) and wireline formation testing, and sampling were all utilized allowing appropriate assessment of zones of interest. Various probe types such as Conventional Circular, Reinforced Circular, Elongated, Extra-Elongated and Extended Range Focused were used successfully, ensuring that the right technology was deployed for the right job. Formation pressure and fluid samples were secured in a timely manner to minimize reservoir damage and optimize rig time without jeopardizing the data quality. As a classified crisis due to the pandemic, rather than delaying the operations, a Remote Operations Monitoring and Control Center was set-up in town to aid the limited crew at rig site.\u0000 A high success rate was achieved in acquiring the latest formation pressure regimes, fluid gradients, scanning and sampling, allowing the best completion strategy to be implemented. With the selection of the appropriate probe type at individual sands, 336 pressure tests were conducted, 44 fluid gradients were established, 27 fluid identification (fluid-id / scanning) pump-outs were performed, and 20 representative formation fluid samples (oil, gas, water) were collected. Amongst the Layer-III, Layer-II and Layer-I sands, Layer-I was tight, with mobility < 1.0 mD/cP. Wireline focused probe sampling provided clean oil samples with 1.4 to-3.7 wt. % OBM filtrate contamination. The water samples collected from Layer-II during FSWD proved to be formation water and not injection water. The wells were thus completed as oil producers. Reliable fluid typing and PVT quality sampling at discrete depths saved rig time and eliminated the requirement of additional runs or services including Drill Stem Testing (DST).\u0000 This case study has many firsts. It is the first time where latest fluid characterization and testing technologies in both Wireline and LWD were deployed for an alliance project in Malaysia and that too during dual crises of falling oil price and the pandemic aftermath. Overcoming various challenges including limited rig site manpower, there was no delay in completing the highly deviated wells with tight formations in a single drilling campaign and provided rig time savings.\u0000 For the purpose of t","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80389568","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ahmad Uzair Zubbir, Hani Mohd Said, Muhammad Abdulhadi, Evelyn Ling, Paul Sanchez, Nazri Nor, Nurhanim Ismail, A. M. Ismail
Cement Packer is a cost-effective alternative to workover for monetizing hydrocarbon reservoirs above the well top packer. While conventional cement packer utilizes coil tubing for cement placement, an innovative and more cost-effective approach was successfully implemented with only slickline and pumping unit, without utilizing coil tubing. This reduced the overall cost of the well intervention by 60%, significantly reduced operational safety risks and is exceptionally suitable in the current challenging environment. Similar to conventional cement packer, the operation begins with setting a plug inside the tubing below the targeted perforation depth and punching the tubing to create tubing-casing communication. The tubing was then flushed with surfactant and weak acid to remove any potential contaminants. The cement was then bullheaded from the surface through the tubing and into the casing while being chased by two foam wiper balls. The foam wiper balls were subsequently pushed with inhibited sea water mixed with cement retarder to prevent any leftover cement from hardening in the tubing. The hardened cement column in the production casing then acts as a barrier to satisfy operating guideline for two pressure barriers in a well. Two cement packer jobs were performed during this campaign; one via conventional method with coil tubing unit (CTU) and a fit-for-purpose version without the CTU. Pressure test from the tubing and casing after the cement hardened indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool demonstrated thick column of good cement thus confirming the cement integrity of the non-CTU method. It was able to achieve similar pressure isolation as the conventional CTU method at 60% lower cost which allowed for significant cost saving. It also reduced the operation time by 50% since the cement was pumped at a higher rate through the well tubing. The turbulent flow regime via high rate pumping also resulted in thicker column of good cement (200m vs 120m) compared to conventional method. The only drawback encountered was the unexpected obstruction caused by leftover cement behind the foam ball. However, this can be removed through milling or fine-tuning the retarded sea water recipe. Post perforation, there was a sharp increase in the tubing pressure while the casing pressure remained low, further confirming the success of this method. This innovative method will be the standard method for any future cement packer operations while the conventional method with coil tubing will only be applied in complex situations. This new Cement Packer technique has introduced substantial cost saving compared to the conventional cement packer method. It will enable monetization of more minor reservoirs. The method is exceptionally relevant to a mature field especially in the current challenging business environment.
水泥封隔器是一种具有成本效益的修井替代方案，可实现井顶封隔器上方油气储层的货币化。传统的水泥封隔器使用螺旋管进行固井，而一种创新的、更具成本效益的方法成功实施，仅使用钢丝绳和抽油机，而不使用螺旋管。这使得修井作业的总成本降低了60%，显著降低了作业安全风险，非常适合当前充满挑战的环境。与传统水泥封隔器类似，作业开始时，在目标射孔深度以下的油管内放置一个桥塞，然后冲孔油管，形成油管-套管连通。然后用表面活性剂和弱酸冲洗油管，以去除任何潜在的污染物。然后，在两个泡沫雨刷球的追逐下，将水泥从地面通过油管送入套管。随后，将泡沫刮水球与掺入水泥缓凝剂的抑制海水一起推进，以防止任何剩余的水泥在油管中硬化。然后，生产套管中的硬化水泥柱作为一个屏障，以满足井中两个压力屏障的操作指南。在该作业中进行了两次水泥封隔器作业;一种是采用常规方法，带有螺旋管单元(CTU)，另一种是不带CTU的专用版本。水泥硬化后对油管和套管进行的压力测试表明，水泥有效地隔离了两根管。随后的水泥胶结测井和超声成像工具显示了厚的良好水泥柱，从而证实了非ctu方法的水泥完整性。它能够实现与传统CTU方法相似的压力隔离，成本降低60%，从而显著节省成本。由于水泥通过油管的速度更快，因此作业时间缩短了50%。与常规方法相比，通过高速率泵送的湍流流态也产生了更厚的优质水泥柱(200m vs 120m)。唯一的缺点是泡沫球后面残留的水泥会造成意想不到的阻塞。然而，这可以通过研磨或微调缓凝海水配方来消除。射孔后，油管压力急剧上升，而套管压力保持在较低水平，进一步证实了该方法的成功。这种创新的方法将成为未来任何水泥封隔器作业的标准方法，而传统的螺旋管方法只适用于复杂的情况。与传统的水泥封隔器方法相比，这种新型水泥封隔器技术大大节省了成本。它将使更多小型油藏货币化。该方法特别适用于成熟油田，尤其是在当前充满挑战的商业环境中。
{"title":"First Application of Non-Coiled Tubing Cement Packer Solution in the Region: A Game Changer in Revolutionizing an Enabling Solution During Low Price Environment","authors":"Ahmad Uzair Zubbir, Hani Mohd Said, Muhammad Abdulhadi, Evelyn Ling, Paul Sanchez, Nazri Nor, Nurhanim Ismail, A. M. Ismail","doi":"10.2118/205719-ms","DOIUrl":"https://doi.org/10.2118/205719-ms","url":null,"abstract":"\u0000 Cement Packer is a cost-effective alternative to workover for monetizing hydrocarbon reservoirs above the well top packer. While conventional cement packer utilizes coil tubing for cement placement, an innovative and more cost-effective approach was successfully implemented with only slickline and pumping unit, without utilizing coil tubing. This reduced the overall cost of the well intervention by 60%, significantly reduced operational safety risks and is exceptionally suitable in the current challenging environment.\u0000 Similar to conventional cement packer, the operation begins with setting a plug inside the tubing below the targeted perforation depth and punching the tubing to create tubing-casing communication. The tubing was then flushed with surfactant and weak acid to remove any potential contaminants. The cement was then bullheaded from the surface through the tubing and into the casing while being chased by two foam wiper balls. The foam wiper balls were subsequently pushed with inhibited sea water mixed with cement retarder to prevent any leftover cement from hardening in the tubing. The hardened cement column in the production casing then acts as a barrier to satisfy operating guideline for two pressure barriers in a well.\u0000 Two cement packer jobs were performed during this campaign; one via conventional method with coil tubing unit (CTU) and a fit-for-purpose version without the CTU. Pressure test from the tubing and casing after the cement hardened indicated that the cement has effectively isolated both tubulars. Subsequent Cement Bond Log and Ultrasonic Imaging Tool demonstrated thick column of good cement thus confirming the cement integrity of the non-CTU method. It was able to achieve similar pressure isolation as the conventional CTU method at 60% lower cost which allowed for significant cost saving. It also reduced the operation time by 50% since the cement was pumped at a higher rate through the well tubing. The turbulent flow regime via high rate pumping also resulted in thicker column of good cement (200m vs 120m) compared to conventional method. The only drawback encountered was the unexpected obstruction caused by leftover cement behind the foam ball. However, this can be removed through milling or fine-tuning the retarded sea water recipe. Post perforation, there was a sharp increase in the tubing pressure while the casing pressure remained low, further confirming the success of this method. This innovative method will be the standard method for any future cement packer operations while the conventional method with coil tubing will only be applied in complex situations.\u0000 This new Cement Packer technique has introduced substantial cost saving compared to the conventional cement packer method. It will enable monetization of more minor reservoirs. The method is exceptionally relevant to a mature field especially in the current challenging business environment.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77211326","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}
Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process. Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated. Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate. Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.
{"title":"Practical Upscaling Process for Enhanced Water Alternating Gas : A Numerical Investigation","authors":"S. Majidaie, L. Hendraningrat, M. Hanifah","doi":"10.2118/205685-ms","DOIUrl":"https://doi.org/10.2118/205685-ms","url":null,"abstract":"\u0000 Water alternating gas (WAG) is a well-known strategy to improve the mobility issues during gas injection. However, WAG was identified still having some challenges during implementation at oilfield with high reservoir heterogeneity and high permeable zones in the reservoir and will cause unfavorable mobility ratio. Enproperties of the selected core samplehancement of WAG (EWAG) using foam and surfactant has been research to solve its issue and has success stories. This paper will describe the work process of EWAG to be Pilot at Malaysian oilfield, focusing on numerical investigation during upscaling process.\u0000 Foam treatment has role for gas mobility control, delaying gas breakthrough and diverting gas to unswept zones. Meanwhile, the surfactant was utilized to reduce the IFT between gas and liquid to enable gas dispersion into liquid phase. An in-house foaming surfactant has been developed and used for coreflooding experiment at harsh environment. It was used to generate stable foam in contact with gas and it caused a mobility reduction which was suitable for mobilizing trapped oil and hence improving oil recovery. Coreflood experiment was performed on native core and all experimental results were consolidated and checked for the quality prior model calibration in the reservoir simulator. Once coreflood model was constructed, base case was run using default foam parameters. It aimed initially to test whether the model run smoothly and to observe the matching quality using the default values. Once satisfactory matchings were achieved, the process continued with foam parameters upscaling. During scale-up process the velocity of the fluids and pressure drop were conserved as laboratory data. The important scale-up parameters and the corresponding scale-up ratio were investigated.\u0000 Mobility Reduction Factor (MRF) was calculated by dividing average DP for each foam cycle with base differential pressure (DP) in the prior gas injection. MRF values for both lower and higher rate show increasing MRF values. Regardless, these values are lower in lower flowrates sequences compared to ones for higher flowrates. This corresponds to MRF values calculated in the laboratory analysis. Therefore, stronger and more stabilized foam were generated using higher injection rates. Lower and higher flowrates had distinctive set of foam parameters. The acceptable matches for differential pressure, oil, water, and gas were achieved. for lower flowrate.\u0000 Based on this study, model was able to capture production trends depicted in the laboratory analysis. The foam parameter set from higher flowrates have more potential for further upscaling and modeling in full-field scale.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78913905","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
P. Ekkawong, Parichat Loboonlert, K. Seusutthiya, K. Wongpattananukul, Nuntanut Laoniyomthai, Jiraphas Thapchim, Rutchanok Nasomsong, Tepporn Satsue, Thanawat Charucharana, Kasidis Lhosupasirirat
The unique characteristic of gas fields in the Gulf of Thailand is the compartmentalized reservoir that requires a huge number of producing wells. The task of locating platform locations for whole field perspectives that also meet all operational criteria while minimizing the number of needed platforms is challenging. This decisional task has a critical impact on project viability, especially for marginal fields. This paper proposes an innovative solution to strengthen success in this business decision by integrating subsurface domain knowledge and optimization algorithms. This study presents an optimization algorithm for determining the optimal locations of wellhead platforms with limited numbers to maximize hydrocarbon resources. Firstly, the algorithm performs verification matching between wellhead locations and subsurface targets throughout the field under drilling criteria. Next, the optimal platform locations are optimized using mixed-integer linear programming (MILP) with the primary objective of maximizing hydrocarbon resources. The algorithm literally runs with an increment in number of platforms until there is no incremental hydrocarbon resources gain and additionally summarizes the results as the number of platforms vs. coverage resources. The algorithm has proven its viability by recommending more optimal platform locations in an actual field in the Gulf of Thailand. This algorithm-assisted workflow was able to reduce the number of required platforms. The main driver for this improved decision is that the MILP algorithm manage to improve well targeting and platform location selection under a large set of practical constraints. In contrast, manual workflow retains its limitations to consider them all. This optimization also reduces the working time required for the whole process of well targeting and platform selection. Formerly, a typical workflow takes months of equivalent man-days. Conversely, this algorithm succeeded in completing the operation within just a few hours. Further, the subsurface team saved time by eliminating some repetitive tasks, i.e., they could focus on reviewing results extracted from the optimizer. Moreover, this work demonstrated the capability to extend and scaleup to other fields with similar concepts, which ultimately could lead to more benefits. This innovative workflow translates the complicated subsurface procedure to a numerical optimization problem with a solid proven benefit from real field implementation. Apart from the positive business impact, this study shows that we can promote integration between modern data analytics and domain knowledge in oil and gas industry.
{"title":"Algorithm-Assisted Platform Location Optmisation Using Mixed-Integer Programming for Cluster Development Strategy in the Gulf of Thailand","authors":"P. Ekkawong, Parichat Loboonlert, K. Seusutthiya, K. Wongpattananukul, Nuntanut Laoniyomthai, Jiraphas Thapchim, Rutchanok Nasomsong, Tepporn Satsue, Thanawat Charucharana, Kasidis Lhosupasirirat","doi":"10.2118/205765-ms","DOIUrl":"https://doi.org/10.2118/205765-ms","url":null,"abstract":"\u0000 The unique characteristic of gas fields in the Gulf of Thailand is the compartmentalized reservoir that requires a huge number of producing wells. The task of locating platform locations for whole field perspectives that also meet all operational criteria while minimizing the number of needed platforms is challenging. This decisional task has a critical impact on project viability, especially for marginal fields. This paper proposes an innovative solution to strengthen success in this business decision by integrating subsurface domain knowledge and optimization algorithms.\u0000 This study presents an optimization algorithm for determining the optimal locations of wellhead platforms with limited numbers to maximize hydrocarbon resources. Firstly, the algorithm performs verification matching between wellhead locations and subsurface targets throughout the field under drilling criteria. Next, the optimal platform locations are optimized using mixed-integer linear programming (MILP) with the primary objective of maximizing hydrocarbon resources. The algorithm literally runs with an increment in number of platforms until there is no incremental hydrocarbon resources gain and additionally summarizes the results as the number of platforms vs. coverage resources.\u0000 The algorithm has proven its viability by recommending more optimal platform locations in an actual field in the Gulf of Thailand. This algorithm-assisted workflow was able to reduce the number of required platforms. The main driver for this improved decision is that the MILP algorithm manage to improve well targeting and platform location selection under a large set of practical constraints. In contrast, manual workflow retains its limitations to consider them all.\u0000 This optimization also reduces the working time required for the whole process of well targeting and platform selection. Formerly, a typical workflow takes months of equivalent man-days. Conversely, this algorithm succeeded in completing the operation within just a few hours. Further, the subsurface team saved time by eliminating some repetitive tasks, i.e., they could focus on reviewing results extracted from the optimizer. Moreover, this work demonstrated the capability to extend and scaleup to other fields with similar concepts, which ultimately could lead to more benefits.\u0000 This innovative workflow translates the complicated subsurface procedure to a numerical optimization problem with a solid proven benefit from real field implementation. Apart from the positive business impact, this study shows that we can promote integration between modern data analytics and domain knowledge in oil and gas industry.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90630229","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：