Clement Afagwu, Saad F. K. Al-Afnan, Mohamed Mahmoud, S. Patil
Shale is a type of unconventional reservoir with a significant potential for storing natural gas attributed to its ability to host hydrocarbons as both free and sorbed phases. However, modeling this multi-physics storage capacity requires redefining some macroscopic parameters such as the porosity to capture the adsorption behavior and pore compressibility, which changes over the entire production life of the asset. Besides, a distinct confining stress phenomenon occurs in a reservoir with a different faulting system and degree of stress heterogeneity. Such mechanisms at nanoscale are complex and difficult to isolate through conventional experimental approaches. Alternatively, computational frameworks like molecular simulation can provide a proxy to accurately describe such intervening mechanisms. The study starts with recreating realistic organic matter structures from a given macromolecule kerogen unit using a molecular dynamics protocol. The created structures were subject to adsorption analysis and mechanical properties assessment while tracking the changes in porosity and pore size distribution. The analyses were used to redefine the porosity considering the adsorption behavior, mechanical properties, pore, and confining pressures. Furthermore, a correlation between stress-induced porosity and Langmuir quantities was developed to predict the Langmuir parameters. The logarithmic function-based model showed that a 33.3% change in stress-dependent kerogen porosity could result in a Langmuir amount, pressure and maximum adsorbed gas density variation of around 100%, 100%, and 50% respectively. Consequently, nanoporosity influence on Langmuir parameters should be critically understood as it plays a significant role in adsorbed gas storage and molecular transport processes in organic-rich shale.
{"title":"Langmuir Parameters Prediction: New Insights into the Porosity of the Nanoporous Media of Organic Media of Organic-Rich Shale","authors":"Clement Afagwu, Saad F. K. Al-Afnan, Mohamed Mahmoud, S. Patil","doi":"10.2523/iptc-22670-ms","DOIUrl":"https://doi.org/10.2523/iptc-22670-ms","url":null,"abstract":"\u0000 Shale is a type of unconventional reservoir with a significant potential for storing natural gas attributed to its ability to host hydrocarbons as both free and sorbed phases. However, modeling this multi-physics storage capacity requires redefining some macroscopic parameters such as the porosity to capture the adsorption behavior and pore compressibility, which changes over the entire production life of the asset. Besides, a distinct confining stress phenomenon occurs in a reservoir with a different faulting system and degree of stress heterogeneity. Such mechanisms at nanoscale are complex and difficult to isolate through conventional experimental approaches. Alternatively, computational frameworks like molecular simulation can provide a proxy to accurately describe such intervening mechanisms. The study starts with recreating realistic organic matter structures from a given macromolecule kerogen unit using a molecular dynamics protocol. The created structures were subject to adsorption analysis and mechanical properties assessment while tracking the changes in porosity and pore size distribution. The analyses were used to redefine the porosity considering the adsorption behavior, mechanical properties, pore, and confining pressures. Furthermore, a correlation between stress-induced porosity and Langmuir quantities was developed to predict the Langmuir parameters. The logarithmic function-based model showed that a 33.3% change in stress-dependent kerogen porosity could result in a Langmuir amount, pressure and maximum adsorbed gas density variation of around 100%, 100%, and 50% respectively. Consequently, nanoporosity influence on Langmuir parameters should be critically understood as it plays a significant role in adsorbed gas storage and molecular transport processes in organic-rich shale.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74920239","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}
Oil reservoirs comprise layers of sandstone with oil and gas held in the spaces between the grains that make up the rock. Allowing an oil reservoir to produce oil through declining natural pressure results in relatively low recoveries (10 to 30%), therefore most fields inject water (waterflooding sweeps oil towards the producing wells) into the oil-bearing rocks which typically increase the oil recovery by 5 to 10%. This means only 30 to 40 % of the oil in place is extracted and to further increase recovery various enhanced oil recovery (EOR) techniques are required including: gas-lift, polymer flood, steam injection depending on the reservoir and oil characteristics. In some reservoirs membranes are already used for low sulphate seawater injection to minimizes potential scaling or souring issues due to interactions with the formation rocks or water, however, this is for production maintenance rather than EOR. Waterflooding was first practiced for the purposes of pressure maintenance after primary depletion and displacing oil by taking advantage of viscous forces and has become the most widely adopted improved oil recovery (IOR) technique. Its high availability and simple injection, as well as lower cost and capital investment, are the other key operational and economical features of water flooding. Historically, little attention has been given to the role of injected water chemistry on the displacement efficiency or its recovery. However, over the past decade, many studies have shown that injecting brine with a salinity in the range of 1000–2000 ppm can affect crude oil/brine/rock (COBR) interactions in a favorable manner to reduce the remaining oil saturation.
{"title":"Combinational Membrane Technique to Support Low Salinity Water Flooding Lswf","authors":"M. Sakthivel","doi":"10.2523/iptc-22612-ea","DOIUrl":"https://doi.org/10.2523/iptc-22612-ea","url":null,"abstract":"\u0000 Oil reservoirs comprise layers of sandstone with oil and gas held in the spaces between the grains that make up the rock. Allowing an oil reservoir to produce oil through declining natural pressure results in relatively low recoveries (10 to 30%), therefore most fields inject water (waterflooding sweeps oil towards the producing wells) into the oil-bearing rocks which typically increase the oil recovery by 5 to 10%. This means only 30 to 40 % of the oil in place is extracted and to further increase recovery various enhanced oil recovery (EOR) techniques are required including: gas-lift, polymer flood, steam injection depending on the reservoir and oil characteristics. In some reservoirs membranes are already used for low sulphate seawater injection to minimizes potential scaling or souring issues due to interactions with the formation rocks or water, however, this is for production maintenance rather than EOR.\u0000 Waterflooding was first practiced for the purposes of pressure maintenance after primary depletion and displacing oil by taking advantage of viscous forces and has become the most widely adopted improved oil recovery (IOR) technique. Its high availability and simple injection, as well as lower cost and capital investment, are the other key operational and economical features of water flooding.\u0000 Historically, little attention has been given to the role of injected water chemistry on the displacement efficiency or its recovery. However, over the past decade, many studies have shown that injecting brine with a salinity in the range of 1000–2000 ppm can affect crude oil/brine/rock (COBR) interactions in a favorable manner to reduce the remaining oil saturation.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74554438","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}
Mikhail Tcibulskii, Ivan Trofimenko, Marat Yagudin, A. Lodin, Vladimir Khohryakov
Lost circulation (LC) is commonly encountered in drilling and cementing operations and can significantly contribute to non-productive time (NPT). An operator in the Kyumbinskoe Field faced this challenge in a fractured production section of the formation, and conventional LC solutions had been ineffective at achieving strict regulatory top of cement (TOC) requirements and satisfactory cement bonding. This paper describes the experience of utilizing foam cementing technology as a primary solution to solve a lost circulation issue on the project. For this project a foam cementing solution was designed to meet operational parameters for cementing a production casing in one stage (multi-stage tool was eliminated). Use of foam cementing technology helped to minimize losses experienced in all cementing operations previously on this project. CBL results were also improved. All Customer requirements were met: Planned Top Of Cement (TOC)Minimum losses during cementing operationsRig time savingImproving CBL results.
{"title":"First Ever Deployment of Production System Optimization Tool in Giant Carbonate Offshore Field in UAE - Laying the Foundation for Digital Oil Field","authors":"Mikhail Tcibulskii, Ivan Trofimenko, Marat Yagudin, A. Lodin, Vladimir Khohryakov","doi":"10.2523/iptc-22040-ms","DOIUrl":"https://doi.org/10.2523/iptc-22040-ms","url":null,"abstract":"\u0000 Lost circulation (LC) is commonly encountered in drilling and cementing operations and can significantly contribute to non-productive time (NPT). An operator in the Kyumbinskoe Field faced this challenge in a fractured production section of the formation, and conventional LC solutions had been ineffective at achieving strict regulatory top of cement (TOC) requirements and satisfactory cement bonding. This paper describes the experience of utilizing foam cementing technology as a primary solution to solve a lost circulation issue on the project. For this project a foam cementing solution was designed to meet operational parameters for cementing a production casing in one stage (multi-stage tool was eliminated).\u0000 Use of foam cementing technology helped to minimize losses experienced in all cementing operations previously on this project. CBL results were also improved. All Customer requirements were met: Planned Top Of Cement (TOC)Minimum losses during cementing operationsRig time savingImproving CBL results.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83548646","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}
I. Seddik, Maniesh Singh, Salem Saleh Al Wahedi, Noor Nasriq Bin Ujal, Ayesha Al Memari, S. AlSaadi, S. Al Arfi, Mariam N. M. Al Baloushi, Mohamed Anwar, A. Hamouda, Douglas Boyd, Nader Gerges, A. Mumtaz, S. Potshangbam, K. Saravanakumar, Yuriy Antonov, Mohahmed Yehia
A multi-disciplinary integrated approach to well construction and navigation is demonstrated in an extended reach well drilled in a mature waterflooded limestone oil reservoir with water override and slumping issues. Integration is vital to optimizing drilling operations, increasing efficiency and enhancing reservoir navigation to maximize production and recovery from a well. The wells primary objective was to maximize reservoir exposure with an extended reach profile while mapping injection water override / slumping intervals and geological structure while avoiding any potential nonproductive zones. Data acquisition pertaining to reservoir characterization, fracture and fault identification were planned to enhance reservoir understanding and to optimize completion design. While drilling a long horizontal section can increase sustainability and recovery potential, the risk of high cost and reduced well life can become a reality if not planned and executed properly. Based on the existing field knowledge and petrophysical data from offset wells, a reservoir navigation strategy was developed respecting the structural and geological setting of the area. A feasibility modeling study incorporating injection water override / water slumping scenarios predicted the Extra Deep Azimuthal Resistivity (EDAR) LWD tool capable of mapping water slump intervals with high confidence at a remote distance from the wellbore which would be key to optimal reservoir navigation. A BHA consisting of RSS, Near Bit Gamma, Density & Porosity, High Resolution Resistivity Image along with Extra Deep Directional Resistivity service was deployed for the first half of the Extended Reach lateral section. The second half of the lateral section was drilled by replacing the Density & Porosity tool containing radioactive sources with a NMR porosity tool to decrease the risk of a lost in hole source. The 8500 ft lateral section was successfully navigated validating proof of concept to include such extended reach wells in future well development plans. Extra Deep Directional Resistivity inversion mapped the reservoir architecture reducing saturation, structural and geological uncertainties and water slumping. Reducing the uncertainties, supported informed geosteering decisions to achieve 100% reservoir exposure while maintaining minimum wellbore tortuosity. This smooth well profile facilitated in running the longest limited entry liner completion in the field. Integrating the inversion result with fracture evaluation from High Resolution Electrical Image, NMR porosity and permeability distribution enabled optimization of the completion design. Updated surfaces from the inversion result were integrated into the customer 3D model for future field development. This integrated approach enhanced Reservoir Navigation enabling a better understanding of the petrophysical and geological settings of the reservoir in real-time which can maximize the production potential and ultimately, re
{"title":"Integration of Extra Deep Azimuthal Resisitivity Application with Formation Evaluation Technologies Reduces Uncertainties and Enchances Reservoir Navigation in the First Extended Reach Well in a Carbonate Reservoir of a Mature Field – A Case History from Abu Dhabi Onshore","authors":"I. Seddik, Maniesh Singh, Salem Saleh Al Wahedi, Noor Nasriq Bin Ujal, Ayesha Al Memari, S. AlSaadi, S. Al Arfi, Mariam N. M. Al Baloushi, Mohamed Anwar, A. Hamouda, Douglas Boyd, Nader Gerges, A. Mumtaz, S. Potshangbam, K. Saravanakumar, Yuriy Antonov, Mohahmed Yehia","doi":"10.2523/iptc-22637-ms","DOIUrl":"https://doi.org/10.2523/iptc-22637-ms","url":null,"abstract":"\u0000 A multi-disciplinary integrated approach to well construction and navigation is demonstrated in an extended reach well drilled in a mature waterflooded limestone oil reservoir with water override and slumping issues. Integration is vital to optimizing drilling operations, increasing efficiency and enhancing reservoir navigation to maximize production and recovery from a well.\u0000 The wells primary objective was to maximize reservoir exposure with an extended reach profile while mapping injection water override / slumping intervals and geological structure while avoiding any potential nonproductive zones. Data acquisition pertaining to reservoir characterization, fracture and fault identification were planned to enhance reservoir understanding and to optimize completion design.\u0000 While drilling a long horizontal section can increase sustainability and recovery potential, the risk of high cost and reduced well life can become a reality if not planned and executed properly.\u0000 Based on the existing field knowledge and petrophysical data from offset wells, a reservoir navigation strategy was developed respecting the structural and geological setting of the area. A feasibility modeling study incorporating injection water override / water slumping scenarios predicted the Extra Deep Azimuthal Resistivity (EDAR) LWD tool capable of mapping water slump intervals with high confidence at a remote distance from the wellbore which would be key to optimal reservoir navigation.\u0000 A BHA consisting of RSS, Near Bit Gamma, Density & Porosity, High Resolution Resistivity Image along with Extra Deep Directional Resistivity service was deployed for the first half of the Extended Reach lateral section. The second half of the lateral section was drilled by replacing the Density & Porosity tool containing radioactive sources with a NMR porosity tool to decrease the risk of a lost in hole source.\u0000 The 8500 ft lateral section was successfully navigated validating proof of concept to include such extended reach wells in future well development plans. Extra Deep Directional Resistivity inversion mapped the reservoir architecture reducing saturation, structural and geological uncertainties and water slumping. Reducing the uncertainties, supported informed geosteering decisions to achieve 100% reservoir exposure while maintaining minimum wellbore tortuosity. This smooth well profile facilitated in running the longest limited entry liner completion in the field.\u0000 Integrating the inversion result with fracture evaluation from High Resolution Electrical Image, NMR porosity and permeability distribution enabled optimization of the completion design. Updated surfaces from the inversion result were integrated into the customer 3D model for future field development.\u0000 This integrated approach enhanced Reservoir Navigation enabling a better understanding of the petrophysical and geological settings of the reservoir in real-time which can maximize the production potential and ultimately, re","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78250164","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}
Prabhu Elumalai, G. Sams, Umanath Subramani, Pinkesh Sanghani
Historically, the engineering and operations teams in refineries have been constantly challenged to deploy efficient solutions for their crude desalting processes as part of the crude distillation unit (CDU). Inefficient crude oil desalting employing AC technology leads to higher utility consumption and corrosion-related issues with downstream equipment that create multiple bottlenecks while processing opportunity crudes. In addition, these challenges lead to a significant increase in operating expenses due to processing upsets and subsequent downtime. A major independent crude oil refinery in Asia is processing crude oil in two CDUs utilizing an AC technology desalting system. The total design capacity for the CDU is 206,000 BPD. The first CDU desalting equipment is designed for 150,000 BPD, and the second CDU is designed for 56,000 BPD. Both CDUs were operated in a range of 10 to 30 PTB inlet salinity. However, due to inefficient desalting, less than 60% desalting efficiency was achieved for each train with subsequent low dehydration efficiency. This led to a considerable bottleneck with the processing capacity and much higher chemical consumption, accompanied by frequent upsets and operational issues on downstream equipment. After a review of the entire desalting operations, the CDU 1 desalter vessel was upgraded to dual frequency technology, and a new dual frequency desalter was installed at the second stage of CDU 2. This change provided a paradigm shift in handling opportunity crude blends in the range of crude density 21 to 28° API with the flexibility of 20 to 100 PTB inlet salinity. After the upgrade, the CDUs achieved a desalting efficiency of more than 90% on each stage and more than 99% on two stages. This paper examines the project from early engagement through conceptual technology selection phase, engineering design, and project execution leading to a successful startup backed by operational history. Furthermore, the adoption of dual frequency technology over legacy AC technology demonstrates the twin goals of positive economic and environmental stewardship, thereby lowering the total cost of ownership to the customer. The CDU 1 dual frequency technology retrofit has been in continuous operation since 2019 and performing well within the PTB outlet specifications. The system is running with 40 to 50 % lower utility consumption, both chemical and power savings with reduced downstream corrosion and an increase in uptime reliability.
{"title":"No More Inefficient Crude Desalting - Breaking Bottleneck with Dual Frequency Technology Lowering Total Cost of Ownership","authors":"Prabhu Elumalai, G. Sams, Umanath Subramani, Pinkesh Sanghani","doi":"10.2523/iptc-22365-ms","DOIUrl":"https://doi.org/10.2523/iptc-22365-ms","url":null,"abstract":"\u0000 Historically, the engineering and operations teams in refineries have been constantly challenged to deploy efficient solutions for their crude desalting processes as part of the crude distillation unit (CDU). Inefficient crude oil desalting employing AC technology leads to higher utility consumption and corrosion-related issues with downstream equipment that create multiple bottlenecks while processing opportunity crudes. In addition, these challenges lead to a significant increase in operating expenses due to processing upsets and subsequent downtime.\u0000 A major independent crude oil refinery in Asia is processing crude oil in two CDUs utilizing an AC technology desalting system. The total design capacity for the CDU is 206,000 BPD. The first CDU desalting equipment is designed for 150,000 BPD, and the second CDU is designed for 56,000 BPD. Both CDUs were operated in a range of 10 to 30 PTB inlet salinity. However, due to inefficient desalting, less than 60% desalting efficiency was achieved for each train with subsequent low dehydration efficiency. This led to a considerable bottleneck with the processing capacity and much higher chemical consumption, accompanied by frequent upsets and operational issues on downstream equipment.\u0000 After a review of the entire desalting operations, the CDU 1 desalter vessel was upgraded to dual frequency technology, and a new dual frequency desalter was installed at the second stage of CDU 2. This change provided a paradigm shift in handling opportunity crude blends in the range of crude density 21 to 28° API with the flexibility of 20 to 100 PTB inlet salinity. After the upgrade, the CDUs achieved a desalting efficiency of more than 90% on each stage and more than 99% on two stages.\u0000 This paper examines the project from early engagement through conceptual technology selection phase, engineering design, and project execution leading to a successful startup backed by operational history. Furthermore, the adoption of dual frequency technology over legacy AC technology demonstrates the twin goals of positive economic and environmental stewardship, thereby lowering the total cost of ownership to the customer.\u0000 The CDU 1 dual frequency technology retrofit has been in continuous operation since 2019 and performing well within the PTB outlet specifications. The system is running with 40 to 50 % lower utility consumption, both chemical and power savings with reduced downstream corrosion and an increase in uptime reliability.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78852377","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}
F. H. Kasim, Nurul Nadhira Idris, S. Majidaie, B. Kantaatmadja, Numair Ahmed Siddiqui, A. Sidek, Nur Aqilah Nabila Yahaya
The numbers of machine learning technologies used in subsurface characterization work is increasing with more company rely on data driven to assist in performing any evaluation. In this study, a supervised random forest machine learning approach was utilized in two stages; first stage was to predict static reservoir using well logs and core as inputs. The output is then used as the basis in the second stage to predict initial oil rate (Qi) and subsequently to determine estimated ultimate recovery (EUR) at targeted interval as proposed in the first stage. Static reservoir machine learning prediction outputs were benchmark with available routine core analysis with the result showed R2 of 88% respectively. For initial oil rate (Qi) prediction, a total of 9000 observation points from 20 wells were extracted for training and blind testing process by using variables such as permeability, net thickness, well choke size, well flowing pressure, average pressure, water cut, irreducible water saturation (Swi), and historical production rate. The estimated ultimate recovery (EUR) is then predicted utilizing the thickness of that unit and the decline rate that is obtained from the neighboring wells that has produced from the said reservoir as the analogue. The Qi and EUR results from machine learning is compared with the estimated Qi and EUR using conventional methods for verification purpose. The results from machine learning dynamic properties prediction showed 97% R2 for training while the testing score mean is 87% against the historical data. High R2 from static and dynamic machine learning prediction indicated that the method was reliable and able to assist petroleum engineer in reservoir potential evaluation process.
{"title":"The Utilization of Machine Learning Method to Predict Hydrocarbon Flow Rate for a Better Reservoir Potential Evaluation","authors":"F. H. Kasim, Nurul Nadhira Idris, S. Majidaie, B. Kantaatmadja, Numair Ahmed Siddiqui, A. Sidek, Nur Aqilah Nabila Yahaya","doi":"10.2523/iptc-22025-ms","DOIUrl":"https://doi.org/10.2523/iptc-22025-ms","url":null,"abstract":"\u0000 The numbers of machine learning technologies used in subsurface characterization work is increasing with more company rely on data driven to assist in performing any evaluation. In this study, a supervised random forest machine learning approach was utilized in two stages; first stage was to predict static reservoir using well logs and core as inputs. The output is then used as the basis in the second stage to predict initial oil rate (Qi) and subsequently to determine estimated ultimate recovery (EUR) at targeted interval as proposed in the first stage.\u0000 Static reservoir machine learning prediction outputs were benchmark with available routine core analysis with the result showed R2 of 88% respectively. For initial oil rate (Qi) prediction, a total of 9000 observation points from 20 wells were extracted for training and blind testing process by using variables such as permeability, net thickness, well choke size, well flowing pressure, average pressure, water cut, irreducible water saturation (Swi), and historical production rate. The estimated ultimate recovery (EUR) is then predicted utilizing the thickness of that unit and the decline rate that is obtained from the neighboring wells that has produced from the said reservoir as the analogue. The Qi and EUR results from machine learning is compared with the estimated Qi and EUR using conventional methods for verification purpose.\u0000 The results from machine learning dynamic properties prediction showed 97% R2 for training while the testing score mean is 87% against the historical data.\u0000 High R2 from static and dynamic machine learning prediction indicated that the method was reliable and able to assist petroleum engineer in reservoir potential evaluation process.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85867684","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 geophysical study to understand and Identify Pliocene - Pleistocene channels system and improve better understand of the channel geometry, fill lithology and connectivity and Generate rock property volume, Enhance reservoir quality, Hydrocarbon distribution and sweet spot detection with min. risk in Miocene reservoir (Moki formation). The Taranaki Basin is the only New Zealand basin to produce commercial quantities of hydrocarbons and still being underexplored. The Parihaka field is on the north-western Taranaki Peninsula located along the west coast of New Zealand's North Island (Veritas, 2005) which there only dry hole drilled based on 2D lines (Arawa-1). Moki formation is our main reservoir its depositional environment is turbiditic fan complex. Hydrocarbons are yet to be commercially produced from the Moki Formation on onshore Taranaki, (Smale et al., 1999). There was AVO study called "Investigation of the Miocene Moki Formation Within the Parahaki 3D Survey; Taranaki Basin, Offshore New Zealand Using Some Geophysical Tools" in Moki reservoir to Investigate and assess the AVO response of the Moki sand formation. By using the results of The AVO study, the inversion can apply in the area to enhance the result, generate rock property volume, Enhance reservoir quality, Hydrocarbon distribution and sweet spot detection with min. risk. By running three volumes of post stack inversion (vp, vs, density) and use λ, μ and vp/vs to identify the hydrocarbon contact distribution. Then by using AVO Inversion (Another different fast technic in the relative domain) to prove the results and using Extend Elastic Impedance Method. The result of this study is there are three prospects in Moki formation, the maps show that Arawa -1 at very low probability of hydrocarbon content which provide our result as it is a dry hole. By using multi-Attribute analysis, we can find new channels system in Pliocene age. Depending on the complexity of the channel system, different attribute analyses had varying success with each system. By using 3D curvature, variance and RMS Amplitude we can improve understanding of the Pliocene channel elements in terms of structure, channel evolution, and lithology. Based on the previous results for these channel systems, RMS amplitude and sweetness attributes can use to detect lithological changes that highlight both shale and sand dominant regions of the channel. These results suggest that the lithology of the small channel is refer to the delta lithology in this individuals channel area, and we can interpret the small channel is filled with a sand lithology, which allows the RMS and sweetness to detect in against the mud rich background lithology.
{"title":"Parihaka Reservoir Characterization by Integrating Well and Seismic Data through Seismic Inversion and Multiattribute Analysis","authors":"Eman Ahmed Ibrahiem El Gandy","doi":"10.2523/iptc-21945-ms","DOIUrl":"https://doi.org/10.2523/iptc-21945-ms","url":null,"abstract":"\u0000 A geophysical study to understand and Identify Pliocene - Pleistocene channels system and improve better understand of the channel geometry, fill lithology and connectivity and Generate rock property volume, Enhance reservoir quality, Hydrocarbon distribution and sweet spot detection with min. risk in Miocene reservoir (Moki formation). The Taranaki Basin is the only New Zealand basin to produce commercial quantities of hydrocarbons and still being underexplored. The Parihaka field is on the north-western Taranaki Peninsula located along the west coast of New Zealand's North Island (Veritas, 2005) which there only dry hole drilled based on 2D lines (Arawa-1).\u0000 Moki formation is our main reservoir its depositional environment is turbiditic fan complex. Hydrocarbons are yet to be commercially produced from the Moki Formation on onshore Taranaki, (Smale et al., 1999).\u0000 There was AVO study called \"Investigation of the Miocene Moki Formation Within the Parahaki 3D Survey; Taranaki Basin, Offshore New Zealand Using Some Geophysical Tools\" in Moki reservoir to Investigate and assess the AVO response of the Moki sand formation.\u0000 By using the results of The AVO study, the inversion can apply in the area to enhance the result, generate rock property volume, Enhance reservoir quality, Hydrocarbon distribution and sweet spot detection with min. risk.\u0000 By running three volumes of post stack inversion (vp, vs, density) and use λ, μ and vp/vs to identify the hydrocarbon contact distribution. Then by using AVO Inversion (Another different fast technic in the relative domain) to prove the results and using Extend Elastic Impedance Method.\u0000 The result of this study is there are three prospects in Moki formation, the maps show that Arawa -1 at very low probability of hydrocarbon content which provide our result as it is a dry hole.\u0000 By using multi-Attribute analysis, we can find new channels system in Pliocene age. Depending on the complexity of the channel system, different attribute analyses had varying success with each system. By using 3D curvature, variance and RMS Amplitude we can improve understanding of the Pliocene channel elements in terms of structure, channel evolution, and lithology.\u0000 Based on the previous results for these channel systems, RMS amplitude and sweetness attributes can use to detect lithological changes that highlight both shale and sand dominant regions of the channel. These results suggest that the lithology of the small channel is refer to the delta lithology in this individuals channel area, and we can interpret the small channel is filled with a sand lithology, which allows the RMS and sweetness to detect in against the mud rich background lithology.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88753843","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}
Andrés Núñez, Mauricio Corona, B. Goodkey, G. Hernandez, Shamlan Gabriel, Mahmoud Elghoneimy, E. Brahmanto, F. Moretti, Arnott Evert Dorantes Garcia, Ahmad Kojo, Kamal Atriby, E. Barrera
As the oil and gas business progresses and rapidly moves to an Automation and Digital "ERA", a wide array of initiatives have been launched in pursuit of increased performance. In a demanding Deep Gas Carbonate well project in the Middle East, seven years of continuous improvement has led to a variety of technology implementations which have dramatically affected operational efficiency and drilling performance. The opportune selection and implementation of new technology and optimized practices has contributed to a significant increase in the project team's ability to exceed one of the Operator's main key performance indicators: well delivery. In this paper, a summary will be provided of the digital and automation solutions implemented to standardize drilling procedures, drill pipe connections, optimize the rate of penetration, reduce downhole shocks and vibrations, all while minimizing drill string failures. New technologies were implemented to optimize the operation without compromising well operations. Part of the success in reducing failures and non-desirable events, has resulted from the enhancement of the Real Time Monitoring resources available, through the implementation of different digital technologies, including hole cleaning monitoring, drilling fluid property controls, cementing operations monitoring, and algorithms utilized to infer the displacement plug position over the well.
{"title":"Application of Enhancing Performance Initiatives in Conjunction with Automation & Digitalization Technlogies in Deep Gas Project in the Middle East, Outperforming and Breaking All Existent Records","authors":"Andrés Núñez, Mauricio Corona, B. Goodkey, G. Hernandez, Shamlan Gabriel, Mahmoud Elghoneimy, E. Brahmanto, F. Moretti, Arnott Evert Dorantes Garcia, Ahmad Kojo, Kamal Atriby, E. Barrera","doi":"10.2523/iptc-21983-ms","DOIUrl":"https://doi.org/10.2523/iptc-21983-ms","url":null,"abstract":"\u0000 As the oil and gas business progresses and rapidly moves to an Automation and Digital \"ERA\", a wide array of initiatives have been launched in pursuit of increased performance. In a demanding Deep Gas Carbonate well project in the Middle East, seven years of continuous improvement has led to a variety of technology implementations which have dramatically affected operational efficiency and drilling performance. The opportune selection and implementation of new technology and optimized practices has contributed to a significant increase in the project team's ability to exceed one of the Operator's main key performance indicators: well delivery. In this paper, a summary will be provided of the digital and automation solutions implemented to standardize drilling procedures, drill pipe connections, optimize the rate of penetration, reduce downhole shocks and vibrations, all while minimizing drill string failures.\u0000 New technologies were implemented to optimize the operation without compromising well operations. Part of the success in reducing failures and non-desirable events, has resulted from the enhancement of the Real Time Monitoring resources available, through the implementation of different digital technologies, including hole cleaning monitoring, drilling fluid property controls, cementing operations monitoring, and algorithms utilized to infer the displacement plug position over the well.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86339839","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}
Haodong Chen, Hexing Liu, M. Luo, Yan Jin, Xu Han, Jiwen Liang, Shiguo Wang, Yunhu Lu
How to drill through the huge mudstone formation safely and quickly in the Ying-Qiong basin, western South China Sea has always been a significant problem in deep-water drilling. Under the action of the hydrostatic pressure of high-density drilling fluid and confining pressure of deep strata, ultra-HTHP huge mudstone presents viscoelastic and severe plastic characteristics. It is difficult for the bit to penetration the strata and slow down the rate of penetration. Although the thickness of mudstone is less than 30% of the total footage, the pure drilling time accounts for more than 75% of the total drilling time, which is difficult to meet the demand for economic and efficient drilling. In order to solve the problem of low ROP, the deformation and failure characteristics of huge plastic mudstone are found through the experimental test. The critical confining pressure of brittle plastic transition of mudstone is analyzed. The evaluation method of brittle plastic transition of mudstone and its influence on drillability is proposed. The personalized design and selection template of drill bits for plastic mudstone is established, and the personalized bits and drilling acceleration tools are optimized. The design scheme of safe drilling fluid density is put forward, which considers both wellbore safety and elimination of chip hold down effect. Considering the engineering and geological characteristics, the integrated drilling speed-up technology with high-efficiency rock breaking and wellbore stability is formed. Compared with field drilling, the ROP is increased by 82.6%. This technology can improve the drilling efficiency and significantly reduce the drilling cost, which provides a reference for speeding up drilling in similar formations.
{"title":"Comprehensive Speed-Up Technology for Safe and Efficient Drilling Through Ultra-HTHP Huge Mudstone Formation in the South China Sea","authors":"Haodong Chen, Hexing Liu, M. Luo, Yan Jin, Xu Han, Jiwen Liang, Shiguo Wang, Yunhu Lu","doi":"10.2523/iptc-22693-ms","DOIUrl":"https://doi.org/10.2523/iptc-22693-ms","url":null,"abstract":"\u0000 How to drill through the huge mudstone formation safely and quickly in the Ying-Qiong basin, western South China Sea has always been a significant problem in deep-water drilling. Under the action of the hydrostatic pressure of high-density drilling fluid and confining pressure of deep strata, ultra-HTHP huge mudstone presents viscoelastic and severe plastic characteristics. It is difficult for the bit to penetration the strata and slow down the rate of penetration. Although the thickness of mudstone is less than 30% of the total footage, the pure drilling time accounts for more than 75% of the total drilling time, which is difficult to meet the demand for economic and efficient drilling. In order to solve the problem of low ROP, the deformation and failure characteristics of huge plastic mudstone are found through the experimental test. The critical confining pressure of brittle plastic transition of mudstone is analyzed. The evaluation method of brittle plastic transition of mudstone and its influence on drillability is proposed. The personalized design and selection template of drill bits for plastic mudstone is established, and the personalized bits and drilling acceleration tools are optimized. The design scheme of safe drilling fluid density is put forward, which considers both wellbore safety and elimination of chip hold down effect. Considering the engineering and geological characteristics, the integrated drilling speed-up technology with high-efficiency rock breaking and wellbore stability is formed. Compared with field drilling, the ROP is increased by 82.6%. This technology can improve the drilling efficiency and significantly reduce the drilling cost, which provides a reference for speeding up drilling in similar formations.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91470378","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}
Xupeng He, Weiwei Zhu, M. AlSinan, H. Kwak, H. Hoteit
Geological CO2 sequestration (GCS) has been a practical approach used to mitigate global climate change. Uncertainty and sensitivity analysis of CO2 storage capacity prediction are essential aspects for large-scale CO2 sequestration. This work presents a rigorous machine learning-assisted workflow for the uncertainty and global sensitivity analysis of CO2 storage capacity prediction in deep saline aquifers. The proposed workflow comprises three main steps: 1) dataset generation — we first identify the uncertainty parameters that impact CO2 storage in deep saline aquifers and then determine their corresponding ranges and distributions. We generate the required data samples by combining the Latin Hypercube Sampling (LHS) technique with high-resolution simulations. 2) surrogate development — a data-driven surrogate is developed to map the nonlinear relationship between the input parameters and corresponding output interests from the previous step. The implementation of Bayesian optimization accelerates the tunning process of hyper-parameters instead of traditional trial-error analysis. 3) uncertainty and global sensitivity analysis — Monte Carlo simulations based on the optimized surrogate are performed to explore the time-dependent uncertainty propagation of model outputs. Then the key contributors are identified by calculating the Sobol indices based on the global sensitivity analysis. The proposed workflow is accurate and efficient and could be readily implemented in field-scale CO2 sequestration in deep saline aquifers.
{"title":"CO2 Storage Capacity Prediction In Deep Saline Aquifers: Uncertainty and Global Sensitivity Analysis","authors":"Xupeng He, Weiwei Zhu, M. AlSinan, H. Kwak, H. Hoteit","doi":"10.2523/iptc-22463-ms","DOIUrl":"https://doi.org/10.2523/iptc-22463-ms","url":null,"abstract":"\u0000 Geological CO2 sequestration (GCS) has been a practical approach used to mitigate global climate change. Uncertainty and sensitivity analysis of CO2 storage capacity prediction are essential aspects for large-scale CO2 sequestration. This work presents a rigorous machine learning-assisted workflow for the uncertainty and global sensitivity analysis of CO2 storage capacity prediction in deep saline aquifers. The proposed workflow comprises three main steps: 1) dataset generation — we first identify the uncertainty parameters that impact CO2 storage in deep saline aquifers and then determine their corresponding ranges and distributions. We generate the required data samples by combining the Latin Hypercube Sampling (LHS) technique with high-resolution simulations. 2) surrogate development — a data-driven surrogate is developed to map the nonlinear relationship between the input parameters and corresponding output interests from the previous step. The implementation of Bayesian optimization accelerates the tunning process of hyper-parameters instead of traditional trial-error analysis. 3) uncertainty and global sensitivity analysis — Monte Carlo simulations based on the optimized surrogate are performed to explore the time-dependent uncertainty propagation of model outputs. Then the key contributors are identified by calculating the Sobol indices based on the global sensitivity analysis. The proposed workflow is accurate and efficient and could be readily implemented in field-scale CO2 sequestration in deep saline aquifers.","PeriodicalId":10974,"journal":{"name":"Day 2 Tue, February 22, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84759160","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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