H. Izadi, Morteza Roostaei, M. Soroush, M. Mohammadtabar, S. A. Hosseini, Mahdi Mahmoudi, J. Leung, Vahidoddin Fattahpour
Intelligent systems are becoming more and more popular in the petroleum industry. Particle Size Distribution (PSD) based on sieve size is a key signature of the unconsolidated/weakly consolidated sandstone formations and is commonly the main parameter in the sand control design. With available extensive PSD measurement techniques and a large number of measurements, especially for horizontal wells, it is necessary to classify the PSDs prior to further analysis for the sand control design. On the other hand, PSD analysis is not enough for sand control design, and particle shapes need to be taken into account as well. A successful clustering algorithm for the mentioned purposes needs to be a cascade, multi-label, unsupervised and self-adaptive approach since the particles can be assigned to more than one group and there is no prior idea on how many clusters should be formed after the clustering process. Besides, due to the differences between sieve size and shape features, they should be used separately for clustering the particles. In the current study, a cascade approach is used for clustering the particles. In the first level of the cascade, an unsupervised and self-adaptive algorithm is introduced based on the sieve size features. The algorithm optimizes the number of clusters through a self-adaptive and incremental approach. The proposed clustering method uses a minimum similarity threshold (δ) as the only input parameter to start the clustering and tries to minimize the number of clusters during the clustering. In the second level of the cascade, the similarity between all particles in each cluster with their corresponding cluster-center is measured, and those particles that do not respect the δ in terms of the shape similarity, are moved out of the cluster. The novelty of the proposed method is in three folds. The first one is to provide a particle clustering algorithm, which works based on the whole range of the sizes and shape descriptors rather than focusing on certain points in the size graph (D-values). The second one is the dynamic nature of the clustering, which tends to optimize the number of clusters during the clustering process. The third one is that we have used a cascade approach for involving both size and shape parameters for the clustering. Our proposed method can be applied in field application for downhole monitoring and sand screen design.
{"title":"An Intelligent System for Multi-Label Classification Based on Particle Size and Shape Features using a Cascade Approach","authors":"H. Izadi, Morteza Roostaei, M. Soroush, M. Mohammadtabar, S. A. Hosseini, Mahdi Mahmoudi, J. Leung, Vahidoddin Fattahpour","doi":"10.2118/200949-ms","DOIUrl":"https://doi.org/10.2118/200949-ms","url":null,"abstract":"\u0000 Intelligent systems are becoming more and more popular in the petroleum industry. Particle Size Distribution (PSD) based on sieve size is a key signature of the unconsolidated/weakly consolidated sandstone formations and is commonly the main parameter in the sand control design.\u0000 With available extensive PSD measurement techniques and a large number of measurements, especially for horizontal wells, it is necessary to classify the PSDs prior to further analysis for the sand control design. On the other hand, PSD analysis is not enough for sand control design, and particle shapes need to be taken into account as well. A successful clustering algorithm for the mentioned purposes needs to be a cascade, multi-label, unsupervised and self-adaptive approach since the particles can be assigned to more than one group and there is no prior idea on how many clusters should be formed after the clustering process. Besides, due to the differences between sieve size and shape features, they should be used separately for clustering the particles.\u0000 In the current study, a cascade approach is used for clustering the particles. In the first level of the cascade, an unsupervised and self-adaptive algorithm is introduced based on the sieve size features. The algorithm optimizes the number of clusters through a self-adaptive and incremental approach. The proposed clustering method uses a minimum similarity threshold (δ) as the only input parameter to start the clustering and tries to minimize the number of clusters during the clustering. In the second level of the cascade, the similarity between all particles in each cluster with their corresponding cluster-center is measured, and those particles that do not respect the δ in terms of the shape similarity, are moved out of the cluster.\u0000 The novelty of the proposed method is in three folds. The first one is to provide a particle clustering algorithm, which works based on the whole range of the sizes and shape descriptors rather than focusing on certain points in the size graph (D-values). The second one is the dynamic nature of the clustering, which tends to optimize the number of clusters during the clustering process. The third one is that we have used a cascade approach for involving both size and shape parameters for the clustering. Our proposed method can be applied in field application for downhole monitoring and sand screen design.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88668996","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}
Lease Operatorship block WD-8, lies within the Forest Reserve oilfield. Forest Reserve is known for having the ENE-WSW trending, south easterly verging Forest Reserve anticline which plunges into NW-SE trending Los Bajos Fault. Regionally to the south of the Forest Reserve anticline lies the south westerly plunging Siparia syncline and to the north of the Forest Reserve anticline is the Morne L′ Enfer syncline. WD-8 is situated on the northern flank of the Forest Reserve anticline with the axis of the anticline occurring within the southern part of the block. Prior to 2018, TETL last drilled within the WD-8 block in the year 2014. Drilling within the WD-8 block pre-2018 was mainly in the southern portion of the block. The year 2018 saw TETL drill five wells in the northern part of the WD-8 block. The results from these wells prompted an evaluation within the Northern portion of the WD-8 block to determine the structure and extent of the Lower Cruse and Navet reservoirs. Field wide mapping post 2018 drills within the block highlighted the sand trend at the Cruse level is in a WSW-ENE direction and that these sands in northern WD-8 are very narrow with maximum widths ranging between 100 ft – 150 ft. Additionally, it showed that by using a smaller well spacing, wells would encounter different producing sand bodies not seen in adjacent wells. Differences in the sand character between wells in the Southern part of the block to wells in the northern part of the block at the Lower Cruse level were also seen. The Lower Cruse section in the southern part of the WD-8 block tends to have thick stacked slope channel sand deposits, while the northern part of WD-8 has relatively thin stacked slope/base of slope channel deposits. Structurally, the presence of an ENE-WSW fault which separates the southern wells from the northern wells was also revealed. Abnormal stratigraphy was also found in Northern WD-8 where the Eocene Navet formation was encountered below the Late Miocene Lower Cruse formation. Two (2) wells in the northern portion of the block found the Navet formation resistive with only one well testing this reservoir. This then presents a new under exploited target reservoir with the block. Mapping of the Navet Formation indicates that this reservoir trends in a WSW-ENE direction. This updated geological model for the WD-8 block resulted in six infill developmental wells being identified to further exploit the remaining reserves within the Lower Cruse and Navet Formations in the WD-8 block.
WD-8区块位于森林储备油田内。森林保护区以ne - wsw走向而闻名，东南边缘的森林保护区背斜落入NW-SE走向的洛斯巴霍斯断层。从区域上看，森林保护区背斜的南部是向西南倾斜的Siparia向斜，森林保护区背斜的北部是Morne L ' Enfer向斜。WD-8位于森林保护区背斜的北侧，背斜的轴线位于地块的南部。在2018年之前，TETL最后一次在WD-8区块内钻探是在2014年。2018年之前，WD-8区块内的钻井主要集中在区块南部。2018年，TETL在WD-8区块北部钻了5口井。这些井的结果促使对WD-8区块北部进行评估，以确定Lower Cruse和Navet油藏的结构和范围。2018年在该区块内进行的现场宽测显示，Cruse层的砂体趋势为WSW-ENE方向，WD-8北部的砂体非常窄，最大宽度在100英尺至150英尺之间。此外，研究表明，使用较小的井距，井会遇到相邻井中未见的不同产砂体。南段与北段下部井砂体特征也存在差异。WD-8块体南部下河段倾向于形成较厚的斜坡河道堆积砂体，而北部则倾向于形成较薄的斜坡河道堆积砂体。构造上还发现南井与北井之间存在一条ENE-WSW断裂。在WD-8北部，在晚中新世Lower Cruse组下方发现始新统Navet组地层异常。该区块北部的两口井发现了Navet地层的抗阻性，只有一口井对该储层进行了测试。这就提出了一个新的未开发目标储层。通过对Navet组的测图可知，该储层走向为WSW-ENE方向。通过更新WD-8区块的地质模型，确定了6口开发井，以进一步开发WD-8区块Lower Cruse和Navet地层的剩余储量。
{"title":"Evaluating the Lower Cruse and Navet Formations Within the Wd-8 Lease Operatorship Block","authors":"Mark Emmanuel Bishop, W. Lalla, X. Moonan","doi":"10.2118/200925-ms","DOIUrl":"https://doi.org/10.2118/200925-ms","url":null,"abstract":"\u0000 Lease Operatorship block WD-8, lies within the Forest Reserve oilfield. Forest Reserve is known for having the ENE-WSW trending, south easterly verging Forest Reserve anticline which plunges into NW-SE trending Los Bajos Fault. Regionally to the south of the Forest Reserve anticline lies the south westerly plunging Siparia syncline and to the north of the Forest Reserve anticline is the Morne L′ Enfer syncline. WD-8 is situated on the northern flank of the Forest Reserve anticline with the axis of the anticline occurring within the southern part of the block. Prior to 2018, TETL last drilled within the WD-8 block in the year 2014. Drilling within the WD-8 block pre-2018 was mainly in the southern portion of the block. The year 2018 saw TETL drill five wells in the northern part of the WD-8 block. The results from these wells prompted an evaluation within the Northern portion of the WD-8 block to determine the structure and extent of the Lower Cruse and Navet reservoirs. Field wide mapping post 2018 drills within the block highlighted the sand trend at the Cruse level is in a WSW-ENE direction and that these sands in northern WD-8 are very narrow with maximum widths ranging between 100 ft – 150 ft. Additionally, it showed that by using a smaller well spacing, wells would encounter different producing sand bodies not seen in adjacent wells. Differences in the sand character between wells in the Southern part of the block to wells in the northern part of the block at the Lower Cruse level were also seen. The Lower Cruse section in the southern part of the WD-8 block tends to have thick stacked slope channel sand deposits, while the northern part of WD-8 has relatively thin stacked slope/base of slope channel deposits. Structurally, the presence of an ENE-WSW fault which separates the southern wells from the northern wells was also revealed. Abnormal stratigraphy was also found in Northern WD-8 where the Eocene Navet formation was encountered below the Late Miocene Lower Cruse formation. Two (2) wells in the northern portion of the block found the Navet formation resistive with only one well testing this reservoir. This then presents a new under exploited target reservoir with the block. Mapping of the Navet Formation indicates that this reservoir trends in a WSW-ENE direction. This updated geological model for the WD-8 block resulted in six infill developmental wells being identified to further exploit the remaining reserves within the Lower Cruse and Navet Formations in the WD-8 block.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72559398","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}
Jorge Alberto Martinez Lozano, Ediberto Cruz Torres, Nadia Maoly Hernandez Castro, J. A. Avila, T. Soltys, Gustavo Andres Ariza Gonzalez
A solution for extend run life with no intervention in a high sand cut and high viscous fluid application for La Hocha field (Huila, Colombia) is presented through the installation of Progressing Cavity Pumps (PCP) designed with aggressive geometries including low rotor swept angle and minimum geometry index concepts. This application has 100-300 BFPD flow rate, sand cut up to 40%, 16°API fluid and 850 cp @ 100°F. This document shows the methodology applied in the selection of well candidates with high frequency of interventions due pump failures associated to sand production and well sanded. The effect of the PCP geometry design, cross sectional area, pitch length, helix angle, pump fit, and elastomer were evaluated consistently as selection criteria in order to verify their impact on PCP run life for sand production applications. The document aims to validate the PCP theoretical design principles with the statistic and results gathered from field during the past 3 years in La Hocha field application. The "Fat Boy project" resulted in less intervention, well services, minimizing production delays and associated costs. The project started on mid-2012, due to successful results has been expanded and nowadays represents the 85 percent of the wells in La Hocha field. This is all part of a combined effort looking for reliable and cost-effective solutions for challenging applications. Progressing Cavity Pumps are used in a variety of oil and gas applications where their beneficial characteristics such as positive displacement, high efficiency, low internal shear rates and pulseless flow provide advantages over other artificial lift systems. PC pumps are available in several geometries which determine their suitability for specific applications assuring optimal performance and extended run life.
{"title":"Sand Handling Solutions Through the Use of Low Geometric Index Progressing Cavity Pumps, La Hocha Field, Colombia","authors":"Jorge Alberto Martinez Lozano, Ediberto Cruz Torres, Nadia Maoly Hernandez Castro, J. A. Avila, T. Soltys, Gustavo Andres Ariza Gonzalez","doi":"10.2118/200899-ms","DOIUrl":"https://doi.org/10.2118/200899-ms","url":null,"abstract":"\u0000 A solution for extend run life with no intervention in a high sand cut and high viscous fluid application for La Hocha field (Huila, Colombia) is presented through the installation of Progressing Cavity Pumps (PCP) designed with aggressive geometries including low rotor swept angle and minimum geometry index concepts. This application has 100-300 BFPD flow rate, sand cut up to 40%, 16°API fluid and 850 cp @ 100°F.\u0000 This document shows the methodology applied in the selection of well candidates with high frequency of interventions due pump failures associated to sand production and well sanded. The effect of the PCP geometry design, cross sectional area, pitch length, helix angle, pump fit, and elastomer were evaluated consistently as selection criteria in order to verify their impact on PCP run life for sand production applications. The document aims to validate the PCP theoretical design principles with the statistic and results gathered from field during the past 3 years in La Hocha field application.\u0000 The \"Fat Boy project\" resulted in less intervention, well services, minimizing production delays and associated costs. The project started on mid-2012, due to successful results has been expanded and nowadays represents the 85 percent of the wells in La Hocha field. This is all part of a combined effort looking for reliable and cost-effective solutions for challenging applications. Progressing Cavity Pumps are used in a variety of oil and gas applications where their beneficial characteristics such as positive displacement, high efficiency, low internal shear rates and pulseless flow provide advantages over other artificial lift systems. PC pumps are available in several geometries which determine their suitability for specific applications assuring optimal performance and extended run life.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"130 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82219035","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}
Zhao-peng Yang, Xingmin Li, Xinxia Xu, Y. Shen, Xiaoxing Shi
The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area of block M has been put into production more than 10 years. And the development features of cold production in foamy extra-heavy oil reservoirs are different from the conventional oil field. It is necessary to investigate the development features of this kind reservoir and analyze its influence factors. Combining the production data with the reservoir geological characteristics of the research area, the cold production features of foamy extra-heavy oil using horizontal wells are analyzed. Then numerical simulations were adopted to study the influence factors of cold production performance. In the early stage of cold production, the oil production rate is high and the producing GOR is low. With the process of cold production, the reservoir pressure decreases gradually, the producing GOR increases gradually, and the oil production rate decreases gradually. When the bottom hole flowing pressure drops to below the bubble point pressure, the flow of extra-heavy oil in the reservoir can be divided into two zones: far well zone and near well area. In the far well zone, the pressure is higher than the bubble point pressure. The flow of oil is a single-phase flow, and the displacement mode is elastic driving. In the near well area, the pressure is lower than the bubble point pressure, and the oil flow is foamy oil flow, and the displacement mode is the dissolving gas drive driven by foamy oil. There exists many factors that influence the cold production performance of foamy extra-heavy oil, including reservoir depth, reservoir thickness, reservoir physical property and heterogeneity. The oil recovery factor per unit pressure drop can evaluate the cold production performance of foamy extra-heavy oil reservoirs. The effectiveness of cold production is closely related to reservoir parameters. Larger reservoir thickness, deeper reservoir depth and greater reservoir permeability will enhance the performance of cold production. Closer, larger and more interlayers above the horizontal well will hinder the performance of cold production. This research provides certain guidance and reference for further development adjustment and new project evaluation for foamy extra-heavy oil reservoirs in the Eastern Orinoco Belt.
{"title":"Development Features of Cold Production with Horizontal Wells in a Foamy Extra-Heavy Oil Reservoir","authors":"Zhao-peng Yang, Xingmin Li, Xinxia Xu, Y. Shen, Xiaoxing Shi","doi":"10.2118/200974-ms","DOIUrl":"https://doi.org/10.2118/200974-ms","url":null,"abstract":"\u0000 The block M as a foamy extra-heavy oil field in the Carabobo Area, the eastern Orinoco Belt, has been exploited by foamy oil cold production utilizing horizontal wells. The early producing area of block M has been put into production more than 10 years. And the development features of cold production in foamy extra-heavy oil reservoirs are different from the conventional oil field. It is necessary to investigate the development features of this kind reservoir and analyze its influence factors.\u0000 Combining the production data with the reservoir geological characteristics of the research area, the cold production features of foamy extra-heavy oil using horizontal wells are analyzed. Then numerical simulations were adopted to study the influence factors of cold production performance.\u0000 In the early stage of cold production, the oil production rate is high and the producing GOR is low. With the process of cold production, the reservoir pressure decreases gradually, the producing GOR increases gradually, and the oil production rate decreases gradually. When the bottom hole flowing pressure drops to below the bubble point pressure, the flow of extra-heavy oil in the reservoir can be divided into two zones: far well zone and near well area. In the far well zone, the pressure is higher than the bubble point pressure. The flow of oil is a single-phase flow, and the displacement mode is elastic driving. In the near well area, the pressure is lower than the bubble point pressure, and the oil flow is foamy oil flow, and the displacement mode is the dissolving gas drive driven by foamy oil. There exists many factors that influence the cold production performance of foamy extra-heavy oil, including reservoir depth, reservoir thickness, reservoir physical property and heterogeneity. The oil recovery factor per unit pressure drop can evaluate the cold production performance of foamy extra-heavy oil reservoirs. The effectiveness of cold production is closely related to reservoir parameters. Larger reservoir thickness, deeper reservoir depth and greater reservoir permeability will enhance the performance of cold production. Closer, larger and more interlayers above the horizontal well will hinder the performance of cold production.\u0000 This research provides certain guidance and reference for further development adjustment and new project evaluation for foamy extra-heavy oil reservoirs in the Eastern Orinoco Belt.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81673862","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This paper presents the methodology used by the Offshore Business Unit of Heritage Petroleum Company Limited (HPCL), to reorganize its future development portfolio. This methodology enabled us to re-organize and rank future projects in order of 1) Developability, 2) Subsurface, Drilling, Flow Assurance and HSSE risks, 3) Financial indicators such as CAPEX and $/BOE, as an approach to maximizing return on investment whilst maintaining the stated goals of the company of monetizing our oil reserves and resources. Following the incorporation of HPCL, the organization attempted to embark on a production stabilization and growth strategy but faced challenges regarding financial and human resource allocation as well as understanding project development best suited for the mature 70 year kit it currently operates. There was a sizable Forward Drilling Campaign (FDP) that remained to be executed from the Legacy company, but there was a need to determine how best to proceed with it. The question was how can we optimize this FDP to attain Heritage’s goals in the short and near term. The answer resided in holding a Pre-Appraisal workshop. A Pre-Appraise Level-1 workshop was held analyzing risk and uncertainty for all future drilling projects. Key to understanding and quantifying inherent risks and opportunities was the presence of a full multidisciplinary team, which included subsurface, facilities, drilling, finance, planning and HSSE personnel. This approach yielded a list of future opportunities that best fit HPCL’s debt-to-capital ratio or debt service coverage position. It also helped to identify projects better suited for joint venture or external capital expenditure options. This workshop resulted in upper management having clear line-of sight regarding the project portfolio, and resource assignment. Once the projects were ranked and grouped, the process of calculating the associated investment to capitalize production across the entire lifecycle was undertaken. A matrix showing Dollar/BOE vs. Project Risk was then built for the new growth strategy. This tool allowed HPCL to select those opportunities that required minimum investment coupled with low HSSE risks. The Pre-Appraise Level-1 workshop guided HPCL to initiate the Shallow Forest Main Field re-development and the East Field drilling development projects as developments to undertake with least risk. The Main Field Shallow Forest Development requires the lowest CAPEX (Drilling and Facilities) and is capital efficient. The proved to non-proven reserves ratio is small (0.05) indicating a high developable remaining resource which will be accessible through secondary or tertiary methods. This approach to understanding development portfolios is new within HPCL; although it has been tried and tested by many operators worldwide when reviewing their capital projects. The Shallow Forest Main Field development carries a low risk profile and is being managed using the Capital Value Process. This proje
{"title":"Applying Front End Loading FEL Approach to Rationalizing Heritage Petroleum Company Limited Forward Development Strategy","authors":"Cherise M Ransome, R. Jackman","doi":"10.2118/200891-ms","DOIUrl":"https://doi.org/10.2118/200891-ms","url":null,"abstract":"\u0000 This paper presents the methodology used by the Offshore Business Unit of Heritage Petroleum Company Limited (HPCL), to reorganize its future development portfolio. This methodology enabled us to re-organize and rank future projects in order of 1) Developability, 2) Subsurface, Drilling, Flow Assurance and HSSE risks, 3) Financial indicators such as CAPEX and $/BOE, as an approach to maximizing return on investment whilst maintaining the stated goals of the company of monetizing our oil reserves and resources.\u0000 Following the incorporation of HPCL, the organization attempted to embark on a production stabilization and growth strategy but faced challenges regarding financial and human resource allocation as well as understanding project development best suited for the mature 70 year kit it currently operates. There was a sizable Forward Drilling Campaign (FDP) that remained to be executed from the Legacy company, but there was a need to determine how best to proceed with it. The question was how can we optimize this FDP to attain Heritage’s goals in the short and near term.\u0000 The answer resided in holding a Pre-Appraisal workshop. A Pre-Appraise Level-1 workshop was held analyzing risk and uncertainty for all future drilling projects. Key to understanding and quantifying inherent risks and opportunities was the presence of a full multidisciplinary team, which included subsurface, facilities, drilling, finance, planning and HSSE personnel. This approach yielded a list of future opportunities that best fit HPCL’s debt-to-capital ratio or debt service coverage position. It also helped to identify projects better suited for joint venture or external capital expenditure options. This workshop resulted in upper management having clear line-of sight regarding the project portfolio, and resource assignment.\u0000 Once the projects were ranked and grouped, the process of calculating the associated investment to capitalize production across the entire lifecycle was undertaken. A matrix showing Dollar/BOE vs. Project Risk was then built for the new growth strategy. This tool allowed HPCL to select those opportunities that required minimum investment coupled with low HSSE risks.\u0000 The Pre-Appraise Level-1 workshop guided HPCL to initiate the Shallow Forest Main Field re-development and the East Field drilling development projects as developments to undertake with least risk. The Main Field Shallow Forest Development requires the lowest CAPEX (Drilling and Facilities) and is capital efficient. The proved to non-proven reserves ratio is small (0.05) indicating a high developable remaining resource which will be accessible through secondary or tertiary methods. This approach to understanding development portfolios is new within HPCL; although it has been tried and tested by many operators worldwide when reviewing their capital projects. The Shallow Forest Main Field development carries a low risk profile and is being managed using the Capital Value Process. This proje","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86857837","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel. Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects. The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation. This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.
{"title":"Unlocking Idle Production in an Offshore Sandstone Oil Field With Gas Hydrate Issues","authors":"B. Daramola","doi":"10.2118/200904-ms","DOIUrl":"https://doi.org/10.2118/200904-ms","url":null,"abstract":"\u0000 This publication presents how an oil asset unlocked idle production after numerous production upsets and a gas hydrate blockage. It also uses economics to justify facilities enhancement projects for flow assurance. Field F is an offshore oil field with eight subsea wells tied back to a third party FPSO vessel.\u0000 Field F was shut down for turnaround maintenance in 2015. After the field was brought back online, one of the production wells (F5) failed to flow. An evaluation of the reservoir, well, and facilities data suggested that there was a gas hydrate blockage in the subsea pipeline between the well head and the FPSO vessel. A subsea intervention vessel was then hired to execute a pipeline clean-out operation, which removed the gas hydrate, and restored F5 well oil production. To minimise oil production losses due to flow assurance issues, the asset team evaluated the viability of installing a test pipeline and a second methanol umbilical as facilities enhancement projects.\u0000 The pipeline clean-out operation delivered 5400 barrels of oil per day production to the asset. The feasibility study suggested that installing a second methanol umbilical and a test pipeline are economically attractive. It is recommended that the new methanol umbilical is installed to guarantee oil flow from F5 and future infill production wells. The test pipeline can be used to clean up new wells, to induce low pressure wells, and for well testing, well sampling, water salinity evaluation, tracer evaluation, and production optimisation.\u0000 This paper presents production upset diagnosis and remediation steps actioned in a producing oil field, and aids the justification of methanol umbilical capacity upgrade and test pipeline installations as facilities enhancement projects. It also indicates that gas hydrate blockage can be prevented by providing adequate methanol umbilical capacity for timely dosing of oil production wells.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87902026","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}
Over the 20 year period from 2001 to 2020, the Ministry of Energy and Energy Industries (MEEI) of Trinidad and Tobago commissioned 19 gas and 3 oil audits conducted by independent consultants. Trinidad and Tobago's natural gas Technically Recoverable Resources (TRR) moved from a P1+C1 TRR to Production Ratio of greater than 30 in 2001 to less than 10 years as production has grown from a low of 1.5 Bcf/d to a high of 4.3 Bcf/d. Despite this, the opening of a new exploration basin in the Deepwater has resulted in greater than 100% technically recoverable resource replacement in the last three years for natural gas and a 770% increase in Prospective Resources for crude oil. The data from these successful audits have served to demonstrate the astute management by the Government and People of Trinidad and Tobago of the country's hydrocarbon resources.
{"title":"20 Years of Independent Oil and Gas Audits: The Trinidad and Tobago Story","authors":"C. Welsh","doi":"10.2118/200985-ms","DOIUrl":"https://doi.org/10.2118/200985-ms","url":null,"abstract":"\u0000 Over the 20 year period from 2001 to 2020, the Ministry of Energy and Energy Industries (MEEI) of Trinidad and Tobago commissioned 19 gas and 3 oil audits conducted by independent consultants. Trinidad and Tobago's natural gas Technically Recoverable Resources (TRR) moved from a P1+C1 TRR to Production Ratio of greater than 30 in 2001 to less than 10 years as production has grown from a low of 1.5 Bcf/d to a high of 4.3 Bcf/d. Despite this, the opening of a new exploration basin in the Deepwater has resulted in greater than 100% technically recoverable resource replacement in the last three years for natural gas and a 770% increase in Prospective Resources for crude oil. The data from these successful audits have served to demonstrate the astute management by the Government and People of Trinidad and Tobago of the country's hydrocarbon resources.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77248248","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}
Incineration is a method of waste management, which is quickly taking a prominent role in munic ipa l authorities all over the world. The introduction of smokeless incinerators aids in decreasing adverse environmental impacts, making this technology a viable alternative to landfills. Modern designs and advancements in incineration processes focus on enhancements in energy efficiency and reductions in emissions of CO2, thus creating an avenue for sustainable energy. It is a means to combat organic substances in waste and separate dangerous gases and particulates from flue gas. Modern incinerators have efficient emission control systems that use multiple techniques for the elimination, at source, of potentially hazardous emissions and automatically control the rate of combustion. Smokeless combustion can be achieved through a combination of temperature, time and turbulence. The range of test incinerators used for this study covers a broad spectrum of usage reduces munic ipa l solid waste to a mere 0.3% of its original state. Reductions in CO2 are directly correlated to decreases in the amount of waste to be transported to off-site landfills, thus reducing the number of trips to and from same. Such reductions are in tandem with the goal of carbon neutrality, or rather, carbon net-zero, which requires the sequestration of an equal amount of CO2 produced. Comparisons are provided for reductions of CO2 as a result of the reduction in the burning of diesel by backload refuse trucks. Case studies are presented for communities with a significant general waste generation where CO2 emission from the waste pickup and transport to and from landfills are compared to that of CO2 emissions after the installation of a smokeless incinerator unit in a central community area. The most significant finding is that CO2 emissions are reduced by approximately 50% in most cases, with the introduction of these units. The introduction of these smokeless incinerator units can combat waste management woes in a shorter space of time, in parallel with achieving environmental targets such as that of Carbon Neutrality.
{"title":"Incineration as a Means of CO2 Reduction","authors":"Ashley Renae Chin Aleong, Rodney R. Jagai","doi":"10.2118/200956-ms","DOIUrl":"https://doi.org/10.2118/200956-ms","url":null,"abstract":"\u0000 Incineration is a method of waste management, which is quickly taking a prominent role in munic ipa l authorities all over the world. The introduction of smokeless incinerators aids in decreasing adverse environmental impacts, making this technology a viable alternative to landfills.\u0000 Modern designs and advancements in incineration processes focus on enhancements in energy efficiency and reductions in emissions of CO2, thus creating an avenue for sustainable energy. It is a means to combat organic substances in waste and separate dangerous gases and particulates from flue gas. Modern incinerators have efficient emission control systems that use multiple techniques for the elimination, at source, of potentially hazardous emissions and automatically control the rate of combustion. Smokeless combustion can be achieved through a combination of temperature, time and turbulence.\u0000 The range of test incinerators used for this study covers a broad spectrum of usage reduces munic ipa l solid waste to a mere 0.3% of its original state. Reductions in CO2 are directly correlated to decreases in the amount of waste to be transported to off-site landfills, thus reducing the number of trips to and from same. Such reductions are in tandem with the goal of carbon neutrality, or rather, carbon net-zero, which requires the sequestration of an equal amount of CO2 produced. Comparisons are provided for reductions of CO2 as a result of the reduction in the burning of diesel by backload refuse trucks. Case studies are presented for communities with a significant general waste generation where CO2 emission from the waste pickup and transport to and from landfills are compared to that of CO2 emissions after the installation of a smokeless incinerator unit in a central community area. The most significant finding is that CO2 emissions are reduced by approximately 50% in most cases, with the introduction of these units. The introduction of these smokeless incinerator units can combat waste management woes in a shorter space of time, in parallel with achieving environmental targets such as that of Carbon Neutrality.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84437781","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}
Y. A. Mohamed, Alaa Tawfik El-Gindy, Helal Ahmed El-Agamy, Amr Ismail Moustafa, Ali Mohamed Eissa, Mansour Mohamed Akeel
Invasion of completion fluids to permeable reservoir formations causes different challenges including increase in water saturation, fine migration problems, well control problems and complicated fluid management. Such problems can result in severe reservoir damage leading to delay in production and increase in operation cost. This paper presents newly designed non-damaging, sealing and killing fluids (Salt Plug) customized to solve such challenges and engineered to control fluid invasion of completion fluid into reservoir. Formation damage might occur during subsequent well workover and perforation operations which requires non-damaging, sealing and killing fluids. The salt plug design incorporates a temporary plugging agent that form a physical barrier across formation face or within formation matrix. Consequently, the plug minimizes formation damage and fluids invasion into reservoir formation during well flow back. Due to its water solubility characteristics, the plug can be easily cleaned up using unsaturated brine water after remedial workover operations. Salt plug was used in reservoir formation in a wide fluid density range of 10.3 - 15.0 Pounds per Gallon (ppg) based on brine type and sized particles concentration to prevent fluid loss during remedial completion operations. This plug was applied in field proving its success in more than 10 deep wells and was successful to seal off void spaces around perforation tunnels and holes up to 0.5 inch. It can be customized to meet project requirements through proper selection of the particle-size distribution (PSD) of salt. Filter cake associated with salt was easily removed with start in production phase with a minimal differential pressure of 20-50 Psi to unload the well. This pill was effective replacing conventional water insoluble calcium carbonate (CaCO3) bridging solids with water soluble sized salt bridging solids which are less aggressive breaker systems.
{"title":"Field Application of Newly Designed Non-Damaging Sealing Killing Fluid to Control Losses in Completion and Workover Operations in Western Desert, Egypt","authors":"Y. A. Mohamed, Alaa Tawfik El-Gindy, Helal Ahmed El-Agamy, Amr Ismail Moustafa, Ali Mohamed Eissa, Mansour Mohamed Akeel","doi":"10.2118/200936-ms","DOIUrl":"https://doi.org/10.2118/200936-ms","url":null,"abstract":"\u0000 Invasion of completion fluids to permeable reservoir formations causes different challenges including increase in water saturation, fine migration problems, well control problems and complicated fluid management. Such problems can result in severe reservoir damage leading to delay in production and increase in operation cost. This paper presents newly designed non-damaging, sealing and killing fluids (Salt Plug) customized to solve such challenges and engineered to control fluid invasion of completion fluid into reservoir. Formation damage might occur during subsequent well workover and perforation operations which requires non-damaging, sealing and killing fluids. The salt plug design incorporates a temporary plugging agent that form a physical barrier across formation face or within formation matrix. Consequently, the plug minimizes formation damage and fluids invasion into reservoir formation during well flow back. Due to its water solubility characteristics, the plug can be easily cleaned up using unsaturated brine water after remedial workover operations. Salt plug was used in reservoir formation in a wide fluid density range of 10.3 - 15.0 Pounds per Gallon (ppg) based on brine type and sized particles concentration to prevent fluid loss during remedial completion operations.\u0000 This plug was applied in field proving its success in more than 10 deep wells and was successful to seal off void spaces around perforation tunnels and holes up to 0.5 inch. It can be customized to meet project requirements through proper selection of the particle-size distribution (PSD) of salt. Filter cake associated with salt was easily removed with start in production phase with a minimal differential pressure of 20-50 Psi to unload the well. This pill was effective replacing conventional water insoluble calcium carbonate (CaCO3) bridging solids with water soluble sized salt bridging solids which are less aggressive breaker systems.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84188355","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}
Jin Fu, Xi Wang, Guobin Yang, Shunyuan Zhang, Chen Chen, Haochen Han
There are several large carbonate reservoirs that have drawn great attention of researchers in recent years. After optimization of drilling technologies, how to deploy artificial lift technologies to develop them more efficiently is another concern. Conventional zonal water injection technologies require repetitive operation with wirelines and cables, causing extensive tests and low efficiency. However, an intelligent zonal water injection string consisting of several preset cable packers, water injection pressure gauges, formation pressure gauges and downhole flow meters has simply optimized water injection parameters and efficiently developed all reservoirs in some China's mature oilfields, especially when the string is integrated with remote monitoring and control methodologies. With the rapid development of horizontal drilling and extended reach well drilling technologies, borehole conditions are becoming more and more complicated, which has brought more challenges to water adsorption testing of horizontal intervals and deployment of zonal water injection instruments. Compared with vertical wells, the water adsorption test and string running are more challenging for horizontal wells, in which we are faced by many a problem during zonal water injection, such as competitive slack off and tight pull, excessive or inadequate water injection, complicated operation process. Besides, well deviation, dog leg and horizontal section length shall be all taken into consideration during zonal water injection for horizontal wells. Therefore, novel strings and tools should be deployed. Now tight pull, slack off and long operation periods are common problems during zonal water injection of horizontal intervals. After dedicated research, a set of wireless intelligent water injection strings for horizontal wells has been invented. Based on pressure pulse water distribution technique, the water injection string is eligible for 32-stage adjustment, so one strip may accomplish testing, adjusting, injection, measurement and downhole data collection, in addition to automatic error correction during water injection. The field trial shows that this novel string may be tripped in and out smoothly, packers are set securely and released easily, in order to adjust opening of each water injection nozzle in the ground, with an error of no more than ±10%. Therefore, the novel completion and water zonal water injection string is capable of injecting water precisely via remote control methods. The wireless intelligent water injection string for horizontal wells that combines testing, adjusting, injection, measuring and data collection in one trip provides us with many downhole data, such as pressure, flow rate, temperature and so on. Therefore, water injection volume for each zone is monitored and controlled down hole. This technology is applicable for both horizontal and vertical wells that require zonal water injection.
{"title":"An Intelligent Completion and Artificial Lift Technology to Develop Large Carbonate Reservoirs: Novel Completion and Zonal Water Injection via Remote Control Methods to Develop Horizontal Wells","authors":"Jin Fu, Xi Wang, Guobin Yang, Shunyuan Zhang, Chen Chen, Haochen Han","doi":"10.2118/200915-ms","DOIUrl":"https://doi.org/10.2118/200915-ms","url":null,"abstract":"\u0000 There are several large carbonate reservoirs that have drawn great attention of researchers in recent years. After optimization of drilling technologies, how to deploy artificial lift technologies to develop them more efficiently is another concern. Conventional zonal water injection technologies require repetitive operation with wirelines and cables, causing extensive tests and low efficiency. However, an intelligent zonal water injection string consisting of several preset cable packers, water injection pressure gauges, formation pressure gauges and downhole flow meters has simply optimized water injection parameters and efficiently developed all reservoirs in some China's mature oilfields, especially when the string is integrated with remote monitoring and control methodologies.\u0000 With the rapid development of horizontal drilling and extended reach well drilling technologies, borehole conditions are becoming more and more complicated, which has brought more challenges to water adsorption testing of horizontal intervals and deployment of zonal water injection instruments. Compared with vertical wells, the water adsorption test and string running are more challenging for horizontal wells, in which we are faced by many a problem during zonal water injection, such as competitive slack off and tight pull, excessive or inadequate water injection, complicated operation process. Besides, well deviation, dog leg and horizontal section length shall be all taken into consideration during zonal water injection for horizontal wells. Therefore, novel strings and tools should be deployed.\u0000 Now tight pull, slack off and long operation periods are common problems during zonal water injection of horizontal intervals. After dedicated research, a set of wireless intelligent water injection strings for horizontal wells has been invented. Based on pressure pulse water distribution technique, the water injection string is eligible for 32-stage adjustment, so one strip may accomplish testing, adjusting, injection, measurement and downhole data collection, in addition to automatic error correction during water injection. The field trial shows that this novel string may be tripped in and out smoothly, packers are set securely and released easily, in order to adjust opening of each water injection nozzle in the ground, with an error of no more than ±10%. Therefore, the novel completion and water zonal water injection string is capable of injecting water precisely via remote control methods.\u0000 The wireless intelligent water injection string for horizontal wells that combines testing, adjusting, injection, measuring and data collection in one trip provides us with many downhole data, such as pressure, flow rate, temperature and so on. Therefore, water injection volume for each zone is monitored and controlled down hole. This technology is applicable for both horizontal and vertical wells that require zonal water injection.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78691403","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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