M oilfield is complex carbonate reservoirs in the Middle East, with strong heterogeneity, high permeability zones, local dissolution fracture area, high viscosity oil area and asphalt layer, etc. Strong heterogeneity leads to early water-out, rapid water cut rise and large production decline for horizontal wells, slow reservoir pressure restoring by water injection and inefficient utilization of horizontal section. Because of great difference in the production performance of single well and unclear development law, it is difficult to achieve multiple goals and good waterflooding effect. In this paper, big data-driven strategy module, and Capacitance Resistance Modeling(CRM), multi-objective optimization modelling are used to establish a technical process and platform for real-time waterflooding optimization on the complex reservoir, which hasn't been put forward in previous research for horizontal well pattern and already successfully applied in M oilfield. Big data driven analysis was adopted to quickly process the geological characteristics and production dynamic data from database set, used for cluster analysis based on neural networks to describe the distribution of dominant water flowing channels and residual oil distribution, evaluated waterflooding law and optimized rational production-injection strategies for its main controlling factor areas. CRM were established through simple geological data, PVT data and prodcution history data, which was an equivalent simplified model to caculate injection allocation factors matched with liquid rates. Real-time connection network has been established to determine injection allocation factors from injectors to producers for large number of horizontal wells. Multi-objective optimization modelling was established to solve the realization conditions for super-achieveing the lowest water cut rising, the slowest production decline, the most reasonable pressure restoring, the highest cummulative oil production and the balanced Voidage Replacement Ratio(VRR) for each main controlling factor area. Integrated continuous, dynamic and quantitative adjustment will be output and implemented during weekly and monthly cycle, and comprehensive monitoring, timely warning and accurate diagnosis are realized for the oilfield. M oilfield has been adjusted about 634 wells to rational performance, and then water cut was controlled from 67.1% to 64.7%, water cut rising rate was decreased from 7.9% to −13.84%, yearly production decline rate was reduced from 25% to 7%, reservoir pressure was built up by 158 psi, and total incremental oil is 5.48 million barrels, which indicated that the waterflooding performance has been greatly improved. This novel methodology and platform provide important reference significance for the waterflooding optimization in Middle East. It can rapidly realize waterflooding optimization in balancing reservoir pressure, controlling water cut rise, slowing down production decline and so on, and
{"title":"Data-Driven Injection/Production Optimization for Horizontal Well Pattern in a Complex Carbonate Oilfield","authors":"D. Hu, Yong Li, Songhao Hu, Qianyao Li, Yi-hang Chen, Yuanbing Wu, Yuanlei Hou","doi":"10.4043/31428-ms","DOIUrl":"https://doi.org/10.4043/31428-ms","url":null,"abstract":"M oilfield is complex carbonate reservoirs in the Middle East, with strong heterogeneity, high permeability zones, local dissolution fracture area, high viscosity oil area and asphalt layer, etc. Strong heterogeneity leads to early water-out, rapid water cut rise and large production decline for horizontal wells, slow reservoir pressure restoring by water injection and inefficient utilization of horizontal section. Because of great difference in the production performance of single well and unclear development law, it is difficult to achieve multiple goals and good waterflooding effect. In this paper, big data-driven strategy module, and Capacitance Resistance Modeling(CRM), multi-objective optimization modelling are used to establish a technical process and platform for real-time waterflooding optimization on the complex reservoir, which hasn't been put forward in previous research for horizontal well pattern and already successfully applied in M oilfield. Big data driven analysis was adopted to quickly process the geological characteristics and production dynamic data from database set, used for cluster analysis based on neural networks to describe the distribution of dominant water flowing channels and residual oil distribution, evaluated waterflooding law and optimized rational production-injection strategies for its main controlling factor areas. CRM were established through simple geological data, PVT data and prodcution history data, which was an equivalent simplified model to caculate injection allocation factors matched with liquid rates. Real-time connection network has been established to determine injection allocation factors from injectors to producers for large number of horizontal wells. Multi-objective optimization modelling was established to solve the realization conditions for super-achieveing the lowest water cut rising, the slowest production decline, the most reasonable pressure restoring, the highest cummulative oil production and the balanced Voidage Replacement Ratio(VRR) for each main controlling factor area. Integrated continuous, dynamic and quantitative adjustment will be output and implemented during weekly and monthly cycle, and comprehensive monitoring, timely warning and accurate diagnosis are realized for the oilfield. M oilfield has been adjusted about 634 wells to rational performance, and then water cut was controlled from 67.1% to 64.7%, water cut rising rate was decreased from 7.9% to −13.84%, yearly production decline rate was reduced from 25% to 7%, reservoir pressure was built up by 158 psi, and total incremental oil is 5.48 million barrels, which indicated that the waterflooding performance has been greatly improved. This novel methodology and platform provide important reference significance for the waterflooding optimization in Middle East. It can rapidly realize waterflooding optimization in balancing reservoir pressure, controlling water cut rise, slowing down production decline and so on, and ","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74631308","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 provides a literature review of the research work done on floating offshore wind turbines, while discussing their technical, economic and environmental aspects. Through this study, research work in this technology is reviewed and future work recommendations are suggested. Centuries before, wind energy paved our way into the vast oceans. Its efficient utilization in the form of sails, helped us conquer the oceans with ships. Unfortunately, wind energy lost its charm in the oil era. But now as we realign our priorities for a greener future, wind energy is yet again turning out to be a reliable energy source. It can be our tool to shift to a cleaner energy supply and realize global renewable energy targets. To make the fossil-to-wind transition possible, the innovative concept of floating offshore wind energy is providing a sophisticated mechanism to harness the wind energy exponentially and will definitely help the mankind to reinforce a sustainable grip on the oceans once again. Floating wind turbines present an economical and technically feasible approach to access the deeper water sites to obtain the rich resource of wind power. Therefore, they have the potential to be the next generation of wind technology. With the installed floating wind power capacity to increase to 250 GW by 2050 (DNV GL Report- Floating Wind: The Power to Commercialize, 2020)[23], it is safe to say, the future is floating.
{"title":"Review on Floating Offshore Wind Turbines","authors":"Shweta Jodha, Vibha Dinesh Sharma, Arundhathi Arul","doi":"10.4043/31391-ms","DOIUrl":"https://doi.org/10.4043/31391-ms","url":null,"abstract":"\u0000 This paper provides a literature review of the research work done on floating offshore wind turbines, while discussing their technical, economic and environmental aspects. Through this study, research work in this technology is reviewed and future work recommendations are suggested.\u0000 Centuries before, wind energy paved our way into the vast oceans. Its efficient utilization in the form of sails, helped us conquer the oceans with ships. Unfortunately, wind energy lost its charm in the oil era. But now as we realign our priorities for a greener future, wind energy is yet again turning out to be a reliable energy source. It can be our tool to shift to a cleaner energy supply and realize global renewable energy targets. To make the fossil-to-wind transition possible, the innovative concept of floating offshore wind energy is providing a sophisticated mechanism to harness the wind energy exponentially and will definitely help the mankind to reinforce a sustainable grip on the oceans once again. Floating wind turbines present an economical and technically feasible approach to access the deeper water sites to obtain the rich resource of wind power. Therefore, they have the potential to be the next generation of wind technology. With the installed floating wind power capacity to increase to 250 GW by 2050 (DNV GL Report- Floating Wind: The Power to Commercialize, 2020)[23], it is safe to say, the future is floating.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79362605","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}
Edward Kawos @ Bartholomew, E. Lim, I. Toloue, M. S. Liew, K. U. Danyaro, Kar Mun Chan, Seng Wah Ling
An Autonomous Structural Health Monitoring (SHM) System for Fixed Offshore Structures is a tool used to monitor the state or the health of a structure in terms of its integrity and strength in an automated manner. An SHM system framework comprises of software and hardware integration equipped with IoT capability to collect raw data, online data transmittal to onshore, a back-end engine to process data into useful engineering information and display the monitoring results through engineering parameters and digital twinning, which emulates the real condition of the structure offshore. The prominent monitoring method for a structure's strength is through global monitoring, using structural modal properties as the measuring parameter to indentify a certain structure's global integrity, specifically using its natural frequency. This paper aims to layout the framework of an autonomous SHM system for global monitoring which is implemented onto a seismically vulnerable fixed offshore structure.
{"title":"Physics-Based Structural Health Monitoring Digital Twin for Seismically Vulnerable Fixed Offshore Structures","authors":"Edward Kawos @ Bartholomew, E. Lim, I. Toloue, M. S. Liew, K. U. Danyaro, Kar Mun Chan, Seng Wah Ling","doi":"10.4043/31377-ms","DOIUrl":"https://doi.org/10.4043/31377-ms","url":null,"abstract":"\u0000 An Autonomous Structural Health Monitoring (SHM) System for Fixed Offshore Structures is a tool used to monitor the state or the health of a structure in terms of its integrity and strength in an automated manner. An SHM system framework comprises of software and hardware integration equipped with IoT capability to collect raw data, online data transmittal to onshore, a back-end engine to process data into useful engineering information and display the monitoring results through engineering parameters and digital twinning, which emulates the real condition of the structure offshore. The prominent monitoring method for a structure's strength is through global monitoring, using structural modal properties as the measuring parameter to indentify a certain structure's global integrity, specifically using its natural frequency. This paper aims to layout the framework of an autonomous SHM system for global monitoring which is implemented onto a seismically vulnerable fixed offshore structure.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79218723","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}
Muhammad Hanif Khan, Warda Yousaf, Bilal Sadaqat, Naila Javed, Abdulrahman Olukade
This article aims to give an outline of an integrated geoscience approach that may apply in the initial identification of the shale play, address complex unconventional reservoirs, their associated challenges and finalise the pilot vertical wells to evaluate their potential. Shale exploration depends on the proven source rock within the basin, so the availability of the required data, well data and seismic data in public domain for initial study and basin screening is usually easy. The investigation may start after knowing the well developed proven source rock in the basin. An extensive study of structure, tectono-stratigraphy, source rock and reservoir characterization, thermal maturity models and exploration strategy is required by using the regional tectonic history, drilled wells with multiple penerations in source rock, open-hole logs, mud samples and cores of the source rock to get the answers to the critical questions on the attributes that influence shale plays. Once these attribute questions have been satisfactorily confirmed to be in the required range or with an analog, that data can be utilized to locate possible sweet spots to drill pilot vertical wells with the goal of acquiring extensive coring, open hole logging and formation pressure testing data to identify the best candidates for further horizontal well evaluation. This article highlights and demonstrates a possible step by step workflow for the selection of the shale play area, sweet spot and pilot vertical wells locations by using the schematic data maps, published material examples and building possible cut offs essential for exploration decision process.
{"title":"A Workflow for Shale Play Exploration and Exploitation","authors":"Muhammad Hanif Khan, Warda Yousaf, Bilal Sadaqat, Naila Javed, Abdulrahman Olukade","doi":"10.4043/31504-ms","DOIUrl":"https://doi.org/10.4043/31504-ms","url":null,"abstract":"\u0000 This article aims to give an outline of an integrated geoscience approach that may apply in the initial identification of the shale play, address complex unconventional reservoirs, their associated challenges and finalise the pilot vertical wells to evaluate their potential.\u0000 Shale exploration depends on the proven source rock within the basin, so the availability of the required data, well data and seismic data in public domain for initial study and basin screening is usually easy. The investigation may start after knowing the well developed proven source rock in the basin. An extensive study of structure, tectono-stratigraphy, source rock and reservoir characterization, thermal maturity models and exploration strategy is required by using the regional tectonic history, drilled wells with multiple penerations in source rock, open-hole logs, mud samples and cores of the source rock to get the answers to the critical questions on the attributes that influence shale plays. Once these attribute questions have been satisfactorily confirmed to be in the required range or with an analog, that data can be utilized to locate possible sweet spots to drill pilot vertical wells with the goal of acquiring extensive coring, open hole logging and formation pressure testing data to identify the best candidates for further horizontal well evaluation.\u0000 This article highlights and demonstrates a possible step by step workflow for the selection of the shale play area, sweet spot and pilot vertical wells locations by using the schematic data maps, published material examples and building possible cut offs essential for exploration decision process.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78993416","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}
High Contaminants fields in Malaysia though forms large part of resource encounter challenges to monetize economically by convectional means that needs higher footprint, complex and heavy structure. Going forward, trending observed is much higher in Carbon dioxide (CO2) (15-40%) for sizeable fields and higher than 40% for some of the prospects. As prudent operator it is imperative to innovate novel methodologies to convert these resources into reserves. Study intent is to develop the asset network into simulation environment, and leverage on modeling to optimize the monetization of these high CO2 fields by multiple approaches such as opportunity to comingle with sweet fields, conceptualization for clustering of sour fields with common CO2 management, to opt for dedicated corridor for the sour gas (high CO2), aligning feed quality as per customer requirements while adhering system obligations. High CO2 feeders needs to be aligned in a strategic way that meets the technical and commercial contracts. An independent system was designed, developed, and implemented (syndication with portfolio management) to not only predict the resultant compositions but also to cater for system hydraulics, effective envelope and adhering the operational safety. The network model consisting of multiple feeders, export pipelines, gas highways and various terminals were built in thermodynamic environment, implanted with appropriate flow correlations to replicate the situ conditions. It was further validated with Plant Information (data) to minimize the simulation tolerance values. Vendor inputs for rotating equipment were also added for representative outlook at the same time minor details such as fitting, bends were ignored to optimize the simulation run time. Inputs were classified as variable inputs (priority of supply, demand center operation precedence, production profile) and fixed inputs (engineering details). Model developed was comprehensive to account for CO2 specifications along with other compositional hydrocarbons including other contaminants such as Nitrogen(N2), Hydrogen sulphide (H2S). Multilevel diagnostics could be achieved to generate heat maps as per CO2 concentration across various sections of the network. Modeling could decipher the opportunity to recognize sweet and sour concentrations at various sections of the network along with potential risk to the downstream. Strategies could be planned to evacuate high CO2 fields at intended customer that could handle these CO2 levels, at the same time vigilance was achieved in terms of hydraulics and system safety features. The information was also leveraged for project sequencing and approach of clustering of much higher CO2 fields (>20 mol%) to common facilities with contamination management instead of individual facilities with optimized blended CO2 levels. Opportunities were identified for maximum utilization of sweet fields by necessary amendment in the network, distribution of sweet and sour fields
{"title":"A Shift in a Paradigm for Monetization of High CO2 Fields by Leveraging Simulation Modelling Approach for Malaysian Gas Network","authors":"Sukrut Shridhar Kulkarni","doi":"10.4043/31490-ms","DOIUrl":"https://doi.org/10.4043/31490-ms","url":null,"abstract":"High Contaminants fields in Malaysia though forms large part of resource encounter challenges to monetize economically by convectional means that needs higher footprint, complex and heavy structure. Going forward, trending observed is much higher in Carbon dioxide (CO2) (15-40%) for sizeable fields and higher than 40% for some of the prospects. As prudent operator it is imperative to innovate novel methodologies to convert these resources into reserves. Study intent is to develop the asset network into simulation environment, and leverage on modeling to optimize the monetization of these high CO2 fields by multiple approaches such as opportunity to comingle with sweet fields, conceptualization for clustering of sour fields with common CO2 management, to opt for dedicated corridor for the sour gas (high CO2), aligning feed quality as per customer requirements while adhering system obligations. High CO2 feeders needs to be aligned in a strategic way that meets the technical and commercial contracts. An independent system was designed, developed, and implemented (syndication with portfolio management) to not only predict the resultant compositions but also to cater for system hydraulics, effective envelope and adhering the operational safety. The network model consisting of multiple feeders, export pipelines, gas highways and various terminals were built in thermodynamic environment, implanted with appropriate flow correlations to replicate the situ conditions. It was further validated with Plant Information (data) to minimize the simulation tolerance values. Vendor inputs for rotating equipment were also added for representative outlook at the same time minor details such as fitting, bends were ignored to optimize the simulation run time. Inputs were classified as variable inputs (priority of supply, demand center operation precedence, production profile) and fixed inputs (engineering details). Model developed was comprehensive to account for CO2 specifications along with other compositional hydrocarbons including other contaminants such as Nitrogen(N2), Hydrogen sulphide (H2S). Multilevel diagnostics could be achieved to generate heat maps as per CO2 concentration across various sections of the network. Modeling could decipher the opportunity to recognize sweet and sour concentrations at various sections of the network along with potential risk to the downstream. Strategies could be planned to evacuate high CO2 fields at intended customer that could handle these CO2 levels, at the same time vigilance was achieved in terms of hydraulics and system safety features. The information was also leveraged for project sequencing and approach of clustering of much higher CO2 fields (>20 mol%) to common facilities with contamination management instead of individual facilities with optimized blended CO2 levels. Opportunities were identified for maximum utilization of sweet fields by necessary amendment in the network, distribution of sweet and sour fields","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82096363","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}
Rahman Setiadi, E. Dharma, S. Jackson, B. Gundemoni, Sakti Dwitama, K. Umar, Edy Suprapto, Gany Gunawan, A. S. Ashfahani, Zulmi Ramadhana, Triantoro Adi Nugroho, Edo Rizky Australianda
Mahakam block has supported Indonesia's Oil and Gas production with over 40 years of deliverability. Presently, along with its maturity cycle, comes the challenge of a steeply declining matured field with indicators of marginal reserves, included unconsolidated sand reservoirs as one of the main contributors which required sand control. In addition, future offshore platform development emerged the urgency of light deployment and robust sand control. Deep dive into the methodology, it was mandatorily to revisit what techniques available on the shelves and what is the current technology has to offer. Mahakam subsurface sand controls were classified into gravel pack, open hole stand-alone screen, chemical sand consolidation (SCON), and thru-tubing metal screen. These also respectively account for the highest to the lowest of operational investment, associated production contribution, and its reliability. Thru tubing screen methodology in cased-hole application showed weakness by plugging and erosion issue resulting on minimum utilization as lowest end subsurface sand control means. Several normative elements factored into it, with the root cause of screen placement. It was avoided to install metallic screen in front perforation due to direct jetting during the natural sand packing (NSP) process, causing an installation at slightly above perforation with the absence of stable NSP and screen size selection complexity. Thru-tubing screen with higher strata of material, silicon carbide or ceramic, was selected as a pioneer on new installation philosophy to tackle erosion issue. It was combined with the developed Mahakam sand grain size map as a screen size selection guideline. A confidence pseudo-straddle thru-tubing ceramic screen (TTCS) installation campaign in front of perforation interval was explored on swamp (Tunu) and offshore (Peciko) gas wells. This technique adopts open hole SAS with retrievable concept optimizing slickline intervention. Perfection of the techniques is a process that continues. However, based on the current study and trial results on wells installation throughout 2020 to 2021, positive results were achieved: Operation simplicity with minimum operation HSE risk, Sand free production delivery addressing highly unconsolidated reservoir with widely distributed sand grain by mitigating the risk of screen erosion, The average cost savings were 66% in delta and 76% in offshore compared to allocated SCON budget, Cummulative gas deliverability increased by more than 200% compared to previous thru-tubing metal screen performance, Performance exceeded average SCON production rate and in-situ gas velocity limit at several installations, The installation method had a 100% retrievability success ratio from all retrieval attempts on inactive wells installation, It had no damaging effect to the reservoir when remedial by SCON was required, The installation concept adoption has been proven on highly deviated and unique completion configura
{"title":"Improved Screen Installation Method by Pseudo-Straddled Ceramic Screen Towards Light and Robust Thru Tubing Sand Control Technique in Competitive Edge of Mature Gas Field Mahakam","authors":"Rahman Setiadi, E. Dharma, S. Jackson, B. Gundemoni, Sakti Dwitama, K. Umar, Edy Suprapto, Gany Gunawan, A. S. Ashfahani, Zulmi Ramadhana, Triantoro Adi Nugroho, Edo Rizky Australianda","doi":"10.4043/31462-ms","DOIUrl":"https://doi.org/10.4043/31462-ms","url":null,"abstract":"Mahakam block has supported Indonesia's Oil and Gas production with over 40 years of deliverability. Presently, along with its maturity cycle, comes the challenge of a steeply declining matured field with indicators of marginal reserves, included unconsolidated sand reservoirs as one of the main contributors which required sand control. In addition, future offshore platform development emerged the urgency of light deployment and robust sand control.\u0000 Deep dive into the methodology, it was mandatorily to revisit what techniques available on the shelves and what is the current technology has to offer. Mahakam subsurface sand controls were classified into gravel pack, open hole stand-alone screen, chemical sand consolidation (SCON), and thru-tubing metal screen. These also respectively account for the highest to the lowest of operational investment, associated production contribution, and its reliability.\u0000 Thru tubing screen methodology in cased-hole application showed weakness by plugging and erosion issue resulting on minimum utilization as lowest end subsurface sand control means. Several normative elements factored into it, with the root cause of screen placement. It was avoided to install metallic screen in front perforation due to direct jetting during the natural sand packing (NSP) process, causing an installation at slightly above perforation with the absence of stable NSP and screen size selection complexity. Thru-tubing screen with higher strata of material, silicon carbide or ceramic, was selected as a pioneer on new installation philosophy to tackle erosion issue. It was combined with the developed Mahakam sand grain size map as a screen size selection guideline. A confidence pseudo-straddle thru-tubing ceramic screen (TTCS) installation campaign in front of perforation interval was explored on swamp (Tunu) and offshore (Peciko) gas wells. This technique adopts open hole SAS with retrievable concept optimizing slickline intervention.\u0000 Perfection of the techniques is a process that continues. However, based on the current study and trial results on wells installation throughout 2020 to 2021, positive results were achieved:\u0000 Operation simplicity with minimum operation HSE risk, Sand free production delivery addressing highly unconsolidated reservoir with widely distributed sand grain by mitigating the risk of screen erosion, The average cost savings were 66% in delta and 76% in offshore compared to allocated SCON budget, Cummulative gas deliverability increased by more than 200% compared to previous thru-tubing metal screen performance, Performance exceeded average SCON production rate and in-situ gas velocity limit at several installations, The installation method had a 100% retrievability success ratio from all retrieval attempts on inactive wells installation, It had no damaging effect to the reservoir when remedial by SCON was required, The installation concept adoption has been proven on highly deviated and unique completion configura","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86361877","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. R. Abdul Rahman, Raja Sharifuddin Ahmad Raja Badrol, Mohd Hafis Muhammad Daud, Noorizal Nasri Huang
The scope of this paper is to present the issues faced during pile installation for offshore platforms specifically due to early refusal and its implication to the required platform foundation capacities. The scope of the paper will include a discussion on pre-development activities, soil reports, drivability analysis, pile and conductor installation using jack-up rig (JUR) and advantages of drill and drive to mitigate early refusal. Soil parameters obtained from soil boring during pre-development activity are used by the design consultant as upon relied information in developing the foundation design. Pile termination depth is formulated based on required pile capacity than translate into number of piles and size for both operating and storm condition of the platform. Early refusal means that the pile has not reached the termination depth but has met the refusal criteria. This is normally stated in blowcounts per depth at a given measured depth. Meeting the pile refusal criteria does not mean the pile has met the required foundation capacity as per platform design but it only indicates the pile cannot be driven further using the same hammer size. A larger hammer size maybe required provided that the stresses induced during driving is lesser than the allowable stress. During engineering stage, pile driving pattern can be predicted by performing pile drivability analysis and any sign of pile refusal prior to target penetration depth is reported. The outcome can be different for upper bound and lower bound cases that takes into consideration both continuous and set-up case during driving due to equipment breakdown. Mitigation to avoid pile refusal should be deployed to meet pile target penetration depth in ensuring long-term integrity of the platform. If unavoidable due to limited piles and hammers selection, early refusal can be mitigated with planned drill and drive. Refusal can also occur if actual site condition differs from expected drivability analysis report. Internal skin friction contributed by the soil in the pile annulus is removed to reduce the resistance during pile driving. It is also critical to understand how JUR operates in terms of pile installation, handling of hammer and clean out activities to fully appreciate the complexities of drill and drive. Based on two recent JUR-installed light weight structure (LWS) projects which is similar in design at two different locations, this paper will outline the notable difference in soil boring data, drivability analysis, planned and unplanned hard driving and corresponding methods on drill and drive.
{"title":"Mitigating Early Pile Refusal to Meet Foundation Capacity Requirement for Offshore Platform","authors":"A. R. Abdul Rahman, Raja Sharifuddin Ahmad Raja Badrol, Mohd Hafis Muhammad Daud, Noorizal Nasri Huang","doi":"10.4043/31356-ms","DOIUrl":"https://doi.org/10.4043/31356-ms","url":null,"abstract":"\u0000 The scope of this paper is to present the issues faced during pile installation for offshore platforms specifically due to early refusal and its implication to the required platform foundation capacities. The scope of the paper will include a discussion on pre-development activities, soil reports, drivability analysis, pile and conductor installation using jack-up rig (JUR) and advantages of drill and drive to mitigate early refusal.\u0000 Soil parameters obtained from soil boring during pre-development activity are used by the design consultant as upon relied information in developing the foundation design. Pile termination depth is formulated based on required pile capacity than translate into number of piles and size for both operating and storm condition of the platform. Early refusal means that the pile has not reached the termination depth but has met the refusal criteria. This is normally stated in blowcounts per depth at a given measured depth. Meeting the pile refusal criteria does not mean the pile has met the required foundation capacity as per platform design but it only indicates the pile cannot be driven further using the same hammer size. A larger hammer size maybe required provided that the stresses induced during driving is lesser than the allowable stress. During engineering stage, pile driving pattern can be predicted by performing pile drivability analysis and any sign of pile refusal prior to target penetration depth is reported. The outcome can be different for upper bound and lower bound cases that takes into consideration both continuous and set-up case during driving due to equipment breakdown. Mitigation to avoid pile refusal should be deployed to meet pile target penetration depth in ensuring long-term integrity of the platform.\u0000 If unavoidable due to limited piles and hammers selection, early refusal can be mitigated with planned drill and drive. Refusal can also occur if actual site condition differs from expected drivability analysis report. Internal skin friction contributed by the soil in the pile annulus is removed to reduce the resistance during pile driving. It is also critical to understand how JUR operates in terms of pile installation, handling of hammer and clean out activities to fully appreciate the complexities of drill and drive.\u0000 Based on two recent JUR-installed light weight structure (LWS) projects which is similar in design at two different locations, this paper will outline the notable difference in soil boring data, drivability analysis, planned and unplanned hard driving and corresponding methods on drill and drive.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87336882","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}
Recently, many hydraulic fracturing has been executed in Sirikit oil field (S1), an onshore oil field in Thailand, to unlock the production from tight sands. However, production performances of each stimulated well were varied despite a similar fracturing technique. The variation may be due to different fracture geometry, fracture properties, and reservoir properties. Although these parameters are critical in optimizing fracturing design, they are unfortunately difficult to be quantified by analytical method, especially the diagnostic of hydraulic fracture after having actual production data. To answer this question, we leveraged the automatic history match (AHM) scheme based on Neural Network-Markov Chain Monte Carlo (NN-MCMC). We utilized the production data to characterize fractures and reservoir properties and stochastically quantify their uncertainty.The framework is based on a practical and efficient iterative workflow that integrates four main stages: (1) Embedded Discrete Fracture Model (EDFM) preprocessing for the best fracture characterization over Local Grid Refinement (LGR), (2) multiphase fluid reservoir simulation, (3) neural network application for generating proxy models, and (4) proxy-based Markov Chain Monte Carlo (MCMC) algorithm for screening the best stochastic solutions. Three wells from the same wellsite and hydraulic fracturing campaign were selected for a study. Uncertain parameters including hydraulic fractures geometry and properties, reservoir permeability, water saturation and relative permeability curves were included for automatic history matching. Rapid uncertainty quantification was completed by screening through 1 million realizations and proposed only 325 realizations to be validated with reservoir simulation. The automatic history matching was executed and required running time less than a day for each well. The posterior distributions of uncertain parameters emphasizing most likely values and their uncertainty were obtained. The difference in fractures and reservoir properties were obtained. Also, the production forecast for each well can be performed probabilistically based on multiple history matching solutions. The automatic history matching workflow could extract the valuable information of fractures and reservoir geometry from production data, which does not require any additional cost. This characterization of fracture geometry and properties, integrating with other methods, can help optimizing fracturing and improving completion design in hydraulically fractured wells in Sirikit oil field in the future.
{"title":"Rapid Characterisation of Fractures and Reservoir Properties using Automatic History Matching: An Investigation of Different Production Performance in Hydraulically Fractured Wells in Sirikit Oil Field","authors":"Sutthaporn Tripoppoom, Voramet Pattarasinpaiboon, Marut Wantawin, Kritsada Charoenniwesnukul, Krit Ngamkamollert","doi":"10.4043/31459-ms","DOIUrl":"https://doi.org/10.4043/31459-ms","url":null,"abstract":"\u0000 Recently, many hydraulic fracturing has been executed in Sirikit oil field (S1), an onshore oil field in Thailand, to unlock the production from tight sands. However, production performances of each stimulated well were varied despite a similar fracturing technique. The variation may be due to different fracture geometry, fracture properties, and reservoir properties. Although these parameters are critical in optimizing fracturing design, they are unfortunately difficult to be quantified by analytical method, especially the diagnostic of hydraulic fracture after having actual production data.\u0000 To answer this question, we leveraged the automatic history match (AHM) scheme based on Neural Network-Markov Chain Monte Carlo (NN-MCMC). We utilized the production data to characterize fractures and reservoir properties and stochastically quantify their uncertainty.The framework is based on a practical and efficient iterative workflow that integrates four main stages: (1) Embedded Discrete Fracture Model (EDFM) preprocessing for the best fracture characterization over Local Grid Refinement (LGR), (2) multiphase fluid reservoir simulation, (3) neural network application for generating proxy models, and (4) proxy-based Markov Chain Monte Carlo (MCMC) algorithm for screening the best stochastic solutions.\u0000 Three wells from the same wellsite and hydraulic fracturing campaign were selected for a study. Uncertain parameters including hydraulic fractures geometry and properties, reservoir permeability, water saturation and relative permeability curves were included for automatic history matching. Rapid uncertainty quantification was completed by screening through 1 million realizations and proposed only 325 realizations to be validated with reservoir simulation.\u0000 The automatic history matching was executed and required running time less than a day for each well. The posterior distributions of uncertain parameters emphasizing most likely values and their uncertainty were obtained. The difference in fractures and reservoir properties were obtained. Also, the production forecast for each well can be performed probabilistically based on multiple history matching solutions.\u0000 The automatic history matching workflow could extract the valuable information of fractures and reservoir geometry from production data, which does not require any additional cost. This characterization of fracture geometry and properties, integrating with other methods, can help optimizing fracturing and improving completion design in hydraulically fractured wells in Sirikit oil field in the future.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90313241","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}
When monoethylene glycol (MEG) is used to provide hydrate protection for gas condensate production, MEG pre-treatment, reconcentration and reclamation systems are generally employed to recover and reuse the MEG. Prior to reconcentration, low solubility salts of divalent cations such as calcium, iron, strontium and magnesium, that may be present in the Rich MEG, are removed in a MEG pre-treatment process. This process involves the addition of a base, such as NaOH or KOH, to the Rich MEG at elevated temperatures to convert dissolved carbon dioxide to carbonate ions and so precipitate the cations, as their respective insoluble carbonate or hydroxide salts. When enough residence time is available within the process these precipitated salts are removed from the Rich MEG stream through physical separation. For onshore based MEG systems, this is usually accomplished via settling tanks. However, in offshore systems the residence time for crystallization and settling becomes limited due to vessel sizes imposed by facility space limitations so precipitated salts are actively removed using mechanical equipment such as centrifuges. Centrifuges are only effective when crystals reach threshold particle sizes. Contaminants in MEG such as dissolved hydrocarbons and magnesium ions can inhibit crystal growth of calcium and iron carbonate. This study details the development of testing methodologies to screen chemistries to assist in particle agglomeration and led to the identification of a promising class of chemistries that could be applied in MEG Pre-treatment for the flocculation of cation salts.
{"title":"Selection of a Flocculant to Assist in Divalent Cation Removal in a MEG Pre-Treatment Process","authors":"N. Fisher, M. Lehmann, S. Brunt, Mark Gloyn","doi":"10.4043/31690-ms","DOIUrl":"https://doi.org/10.4043/31690-ms","url":null,"abstract":"\u0000 When monoethylene glycol (MEG) is used to provide hydrate protection for gas condensate production, MEG pre-treatment, reconcentration and reclamation systems are generally employed to recover and reuse the MEG. Prior to reconcentration, low solubility salts of divalent cations such as calcium, iron, strontium and magnesium, that may be present in the Rich MEG, are removed in a MEG pre-treatment process. This process involves the addition of a base, such as NaOH or KOH, to the Rich MEG at elevated temperatures to convert dissolved carbon dioxide to carbonate ions and so precipitate the cations, as their respective insoluble carbonate or hydroxide salts. When enough residence time is available within the process these precipitated salts are removed from the Rich MEG stream through physical separation. For onshore based MEG systems, this is usually accomplished via settling tanks. However, in offshore systems the residence time for crystallization and settling becomes limited due to vessel sizes imposed by facility space limitations so precipitated salts are actively removed using mechanical equipment such as centrifuges. Centrifuges are only effective when crystals reach threshold particle sizes. Contaminants in MEG such as dissolved hydrocarbons and magnesium ions can inhibit crystal growth of calcium and iron carbonate. This study details the development of testing methodologies to screen chemistries to assist in particle agglomeration and led to the identification of a promising class of chemistries that could be applied in MEG Pre-treatment for the flocculation of cation salts.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"186 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89332060","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}
Tam Chanh Nguyen, Devesh Bhaisora, Nga Thi Ninh, Tai Trong Nguyen
With recent discoveries, offshore Vietnam continues to provide promising prospects for hydrocarbon production, especially with rapid exploration and deployment in the offshore HPHT fields in the last decade. However, Vietnam has some of the most complex and hottest wells in the region. An operator was planning to break the barrier of the hottest well in offshore Vietnam. Bottom hole pressure and temperatures for this well were predicted to be around 12,000 psi and 200 deg C, respectively. Designing and delivering a dependable zonal isolation barrier was paramount to the success of the well. The well architecture included the primary cementing job for six casing strings - 30-in. conductor casing, 20-in. surface casing, 16-in. casing, 13 5/8-in. casing, 9 7/8-in. casing, and 7-in. production liner. The well was for exploration purposes and was to be abandoned by seven (7) cement plugs in cased hole across various depths. A total of 4,200 bbls of cement slurry with a wide density range from 12.0 lbm/gal for the surface casing to 18.0 lbm/gal for the production liner, were tailored and pumped in the well. Rigorous slurry testing was conducted up to 198 deg C and 13,000 psi downhole pressure for the production section slurries. To provide for proper hole cleaning a tailored spacer was designed and tested for stability under the same downhole pressure and temperatures. A total of ~1,000 bbl of spacer were pumped in the well, having a density range from 10 lbm/gal to 17.2 lbm/gal. To maintain the robustness of the slurry design in order to handle any changes in well parameters various sensitivity tests were performed at different temperatures, retarder concentrations and with mud contamination levels (predicted by computational fluid dynamic modelling). For the production section, an aggressive slurry with less than a 15 min transition time was designed to avoid any gas migration in the setting cement. This case study, techniques and lessons learned can be applied to similar wells around the globe especially in the challenging environments of extreme HPHT.
{"title":"Delivering a Dependable Zonal Isolation Barrier for an Extreme HPHT Well in Offshore Vietnam - Lessons Learned from Cementing High Pressure High Temperature Well","authors":"Tam Chanh Nguyen, Devesh Bhaisora, Nga Thi Ninh, Tai Trong Nguyen","doi":"10.4043/31383-ms","DOIUrl":"https://doi.org/10.4043/31383-ms","url":null,"abstract":"\u0000 With recent discoveries, offshore Vietnam continues to provide promising prospects for hydrocarbon production, especially with rapid exploration and deployment in the offshore HPHT fields in the last decade. However, Vietnam has some of the most complex and hottest wells in the region. An operator was planning to break the barrier of the hottest well in offshore Vietnam. Bottom hole pressure and temperatures for this well were predicted to be around 12,000 psi and 200 deg C, respectively. Designing and delivering a dependable zonal isolation barrier was paramount to the success of the well.\u0000 The well architecture included the primary cementing job for six casing strings - 30-in. conductor casing, 20-in. surface casing, 16-in. casing, 13 5/8-in. casing, 9 7/8-in. casing, and 7-in. production liner. The well was for exploration purposes and was to be abandoned by seven (7) cement plugs in cased hole across various depths. A total of 4,200 bbls of cement slurry with a wide density range from 12.0 lbm/gal for the surface casing to 18.0 lbm/gal for the production liner, were tailored and pumped in the well. Rigorous slurry testing was conducted up to 198 deg C and 13,000 psi downhole pressure for the production section slurries. To provide for proper hole cleaning a tailored spacer was designed and tested for stability under the same downhole pressure and temperatures. A total of ~1,000 bbl of spacer were pumped in the well, having a density range from 10 lbm/gal to 17.2 lbm/gal. To maintain the robustness of the slurry design in order to handle any changes in well parameters various sensitivity tests were performed at different temperatures, retarder concentrations and with mud contamination levels (predicted by computational fluid dynamic modelling). For the production section, an aggressive slurry with less than a 15 min transition time was designed to avoid any gas migration in the setting cement.\u0000 This case study, techniques and lessons learned can be applied to similar wells around the globe especially in the challenging environments of extreme HPHT.","PeriodicalId":11081,"journal":{"name":"Day 2 Wed, March 23, 2022","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81192912","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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