P. A. Patil, Asyraf M Hamimi, M. A. Abu Bakar, D. Das, P. Tiwari, P. Chidambaram, M. A. B. A. Jalil
Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project. Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells. This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score <10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security. Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.
{"title":"Scrutinizing Wells Integrity for Determining Long-Term Fate of a CO2 Sequestration Project: An Improved and Rigorous Risk Assessment Strategy","authors":"P. A. Patil, Asyraf M Hamimi, M. A. Abu Bakar, D. Das, P. Tiwari, P. Chidambaram, M. A. B. A. Jalil","doi":"10.2523/iptc-22348-ms","DOIUrl":"https://doi.org/10.2523/iptc-22348-ms","url":null,"abstract":"\u0000 Depleted hydrocarbon reservoirs are considered inherently safe for carbon sequestration, but high well density penetrating the CO2 storage reservoir could compromise the containment performance in a carbon, capture & sequestration (CCS) project. Based on the available well data, it is crucial to understand the age of the well, materials used for wellbore construction, cement quality, barriers performance, and well integrity. A risk management methodology can be incorporated to evaluate primary and secondary barriers in existing plugged and abandoned (P&A) and development wells to ensure long-term fate of CO2 sequestration project.\u0000 Existing P&A wells and development wells in a depleted field were drilled 3–5 decades ago. The wellbore construction utilized non-corrosive resistant materials. Health of all wells that ever penetrated the CO2 storage reservoir need to be analyzed from long term perspective of storing CO2. Throughout the lifespan of wells, subsurface barriers should maintain hydraulic isolation to prevent leakage happening from subsurface to environment of reservoir fluids and injected CO2. Deterioration of strength of wellbore construction material due to corrosion, induced by downhole pressure and temperature conditions, should be considered. This study investigated 3 exploration and 21 development wells. Risk register was developed for each well describing causes and CO2 leakage risks, impacts and consequences. Metrics were defined for parameters such as well age, well head materials, wellhead functional test and leak test, sustained casing pressures for risk determination. Wells were risk rated individually based on the assessment. Wells with low risk can be utilized for well conversion. While for high-risk wells, an opportunity risk matrix was developed to mitigate risks in all the wells.\u0000 This study evaluates the well integrity and CO2 leakage risk along the wells that penetrated the CO2 storage reservoir. The improved rigorous risk assessment exercise evaluates well barrier failure causes and impacts along with estimating the risk number per well. The well risk assessment score calculated was between 9.24 and 13.35 for 21 development wells. Out of these 21 wells, 4 wells with risk score <10 can be utilized for wells conversion. Specific barrier restoration process by additional scope of work such as lower completion removal including packer milling, intermediate casing removal, or installation of downhole permanent barriers with remedial cement is discussed for designing the well abandonment process to minimize leak potential of high-risk wells for ensuring long-term containment security. Improved rigorous well integrity risk assessment for CO2 storage field is decisive for any CCS project economics that utilizes barrier identification process and remedial actions.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87452412","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}
For many CO2-emitting industrial sectors, such as the cement and chemical industry, Carbon, Capture and Storage (CCS) will be necessary to reach any set climate target. CCS on its own is a very cost-intensive technology. Instead of considering CO2 as a waste to be disposed of, we propose to consider CO2 as a resource. The utilisation of CO2 in so-called CO2 Plume Geothermal (CPG) systems generates revenue by extracting geothermal energy, while permanently storing CO2 in the geological subsurface. To the best of our knowledge, this pioneer investigation is the first CCUS simulation feasibility study in Switzerland. Among others, we investigated the concept of injecting and circulating CO2 for geothermal power generation purposes from potential CO2 storage formations (saline reservoirs) in the Western part of the Swiss Molasse Basin ("Muschelkalk" and "Buntsandstein" formation). Old 2D-seismic data indicates a potential anticline structure in proximity of the Eclépens heat anomaly. Essentially, this conceptual study helps assessing it's potential CO2 storage capacity range and will be beneficial for future economical assessments. The interpretation of the intersected 2D seismic profiles reveals an apparent anticline structure that was integrated on a geological model with a footprint of 4.35 × 4.05 km2. For studying the dynamic reservoir behaviour during the CO2 circulation, we considered: (1) the petrophysical rock properties uncertainty range, (2) the injection and physics of a two-phase (CO2 and brine) fluid system, including the relative permeability characterisation, fluid model composition, the residual and solubility CO2 trapping, and (3) the thermophysical properties of resident-formation brine and the injected CO2 gas. Our study represents a first-order estimation of the expected CO2 storage capacity range at a possible anticline structure in two potential Triassic reservoir formations in the Western part of the Swiss Molasse Basin. Additionally, we assessed the effect of different well locations on CO2 injection operations. Our currently still-ongoing study will investigate production rates and resulting well flow regimes in a conceptual CO2 production well for geothermal energy production in the future. Nonetheless, our preliminary results indicate that, under ideal conditions, both reservoirs combined can store more than 8 Mt of CO2 over multiple decades of CCUS operation. From our results, we can clearly identify limiting factors on the overall storage capacity, such as for example the reservoir fluid pressure distribution and well operation constraints.
{"title":"Modelling Potential Geological CO2 Storage Combined with CO2-Plume Geothermal CPG Energy Extraction in Switzerland","authors":"Kevin P. Hau, F. Games, R. Lathion, M. Saar","doi":"10.2523/iptc-22254-ms","DOIUrl":"https://doi.org/10.2523/iptc-22254-ms","url":null,"abstract":"\u0000 For many CO2-emitting industrial sectors, such as the cement and chemical industry, Carbon, Capture and Storage (CCS) will be necessary to reach any set climate target. CCS on its own is a very cost-intensive technology. Instead of considering CO2 as a waste to be disposed of, we propose to consider CO2 as a resource. The utilisation of CO2 in so-called CO2 Plume Geothermal (CPG) systems generates revenue by extracting geothermal energy, while permanently storing CO2 in the geological subsurface.\u0000 To the best of our knowledge, this pioneer investigation is the first CCUS simulation feasibility study in Switzerland. Among others, we investigated the concept of injecting and circulating CO2 for geothermal power generation purposes from potential CO2 storage formations (saline reservoirs) in the Western part of the Swiss Molasse Basin (\"Muschelkalk\" and \"Buntsandstein\" formation).\u0000 Old 2D-seismic data indicates a potential anticline structure in proximity of the Eclépens heat anomaly. Essentially, this conceptual study helps assessing it's potential CO2 storage capacity range and will be beneficial for future economical assessments. The interpretation of the intersected 2D seismic profiles reveals an apparent anticline structure that was integrated on a geological model with a footprint of 4.35 × 4.05 km2.\u0000 For studying the dynamic reservoir behaviour during the CO2 circulation, we considered: (1) the petrophysical rock properties uncertainty range, (2) the injection and physics of a two-phase (CO2 and brine) fluid system, including the relative permeability characterisation, fluid model composition, the residual and solubility CO2 trapping, and (3) the thermophysical properties of resident-formation brine and the injected CO2 gas.\u0000 Our study represents a first-order estimation of the expected CO2 storage capacity range at a possible anticline structure in two potential Triassic reservoir formations in the Western part of the Swiss Molasse Basin. Additionally, we assessed the effect of different well locations on CO2 injection operations.\u0000 Our currently still-ongoing study will investigate production rates and resulting well flow regimes in a conceptual CO2 production well for geothermal energy production in the future. Nonetheless, our preliminary results indicate that, under ideal conditions, both reservoirs combined can store more than 8 Mt of CO2 over multiple decades of CCUS operation. From our results, we can clearly identify limiting factors on the overall storage capacity, such as for example the reservoir fluid pressure distribution and well operation constraints.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86179751","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}
S. Maity, Muhammad Abrar Manzar, H. Al-Shabibi, Jana Jindan, Mohamed Larbi Zeghlache
Knowledge of fluid density along with phase measurement are extremely important for reducing the variance in estimating the flow profile from the production logging tool (PLT). When both oil and water are produced simultaneously, induced reflectance measurement derived from the optical refractive index is not effective. This is mainly due to phase persistence behaviour of the optical sensor caused by the coating of the previous phases. The most effective way to characterize such flow is to measure the fluid's fluorescence along with refractive index and density. In this paper, a novel solution is presented using a piezo helm resonator sensor with simultaneous and congruent measurements of fluid mass density, viscosity and sound speed.
{"title":"Advanced Multi-Physics Sensor Utilizing Molecular Fingerprinting for Production Logging Tool","authors":"S. Maity, Muhammad Abrar Manzar, H. Al-Shabibi, Jana Jindan, Mohamed Larbi Zeghlache","doi":"10.2523/iptc-22350-ms","DOIUrl":"https://doi.org/10.2523/iptc-22350-ms","url":null,"abstract":"\u0000 Knowledge of fluid density along with phase measurement are extremely important for reducing the variance in estimating the flow profile from the production logging tool (PLT). When both oil and water are produced simultaneously, induced reflectance measurement derived from the optical refractive index is not effective. This is mainly due to phase persistence behaviour of the optical sensor caused by the coating of the previous phases. The most effective way to characterize such flow is to measure the fluid's fluorescence along with refractive index and density. In this paper, a novel solution is presented using a piezo helm resonator sensor with simultaneous and congruent measurements of fluid mass density, viscosity and sound speed.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80372685","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
T.A. Murtazin, S. Usmanov, M. Validov, V. Sudakov, Aidar Takhauv, N. Aslyamov, Vitaliy Gataullin, M. Amerkhanov
A significant part of the hydrocarbon reserves in the Republic of Tatarstan belongs to heavy ultra-viscous oil. At the moment, due to the oil price rise, the development of these deposits is an actual task. In the recent decades, development planning has traditionally included the creation of three-dimensional reservoir models. The approaches that are also used are traditional and include data quality control, well log interpretation (determination of stratigraphy and calculation of reservoir properties), construction of a three-dimensional grid and filling it with properties. Meanwhile, the active development of information technology and artificial intelligence makes it possible to automate some of the routine processes. The purpose of this work is to create a chain of software algorithms combined under a digital platform for automating the process of constructing a geological model of ultra-viscous oil (hereinafter, UVO) deposits and calculating reserves on the example of the Republic of Tatarstan. The paper presents the general approaches that made it possible to solve part of the routine tasks of a geologist when constructing UVO deposit models. The tasks to be solved included the automation of stratigraphic boundaries definition, core-log matching, calculation of reservoir properties for wells, as well as determination of OWC position and placement of additional wells taking into account surface constraints. The approaches presented in this work are developed on the example of the UVO deposits of the Republic of Tatarstan, however, the principles used can be transferred to similar objects with the modification of the features used.
{"title":"The Development of Automatic System for Geological Modeling of Extra-Viscous Oil Deposits on the Example of Tatarstan Republic","authors":"T.A. Murtazin, S. Usmanov, M. Validov, V. Sudakov, Aidar Takhauv, N. Aslyamov, Vitaliy Gataullin, M. Amerkhanov","doi":"10.2523/iptc-22175-ms","DOIUrl":"https://doi.org/10.2523/iptc-22175-ms","url":null,"abstract":"\u0000 A significant part of the hydrocarbon reserves in the Republic of Tatarstan belongs to heavy ultra-viscous oil. At the moment, due to the oil price rise, the development of these deposits is an actual task.\u0000 In the recent decades, development planning has traditionally included the creation of three-dimensional reservoir models. The approaches that are also used are traditional and include data quality control, well log interpretation (determination of stratigraphy and calculation of reservoir properties), construction of a three-dimensional grid and filling it with properties.\u0000 Meanwhile, the active development of information technology and artificial intelligence makes it possible to automate some of the routine processes. The purpose of this work is to create a chain of software algorithms combined under a digital platform for automating the process of constructing a geological model of ultra-viscous oil (hereinafter, UVO) deposits and calculating reserves on the example of the Republic of Tatarstan.\u0000 The paper presents the general approaches that made it possible to solve part of the routine tasks of a geologist when constructing UVO deposit models. The tasks to be solved included the automation of stratigraphic boundaries definition, core-log matching, calculation of reservoir properties for wells, as well as determination of OWC position and placement of additional wells taking into account surface constraints. The approaches presented in this work are developed on the example of the UVO deposits of the Republic of Tatarstan, however, the principles used can be transferred to similar objects with the modification of the features used.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90998525","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}
The offshore eastern Mediterranean region has received increased international interest in the last decade for its hydrocarbon potential in the pre-salt traps. The presence of a heterogeneous Messinian-age salt layer and complex pre-Messinian structures pose very difficult challenges in seismic imaging. In this paper, we provide a detailed workflow for seismic data preconditioning and imaging which resolves the subsurface challenges of the Mediterranean. Broadband acquisition was used to collect seismic data, which combines the responses of dual-sensor receivers to remove the effect of the receiver ghost. Adaptive source de-ghosting was then applied to address the source-side ghost. Data was processed using robust multiple attenuation and converted wave attenuation (CWA). A high-resolution velocity model building and imaging workflow was designed as follows: Diving waves full-waveform inversion (FWI) to capture detailed velocity for the complex overburden, followed by post-salt reflection tomography. Born modeling-based reflection FWI to update the velocity heterogeneities inside the salt body followed by reflection tomography for the deep section. Reverse time migration (RTM) to handle the waveform multi-pathing. De-ghosting corrected the wavelet phase and expanded the usable frequency bandwidth, resulting in a broadband dataset for imaging. Robust multiple attenuation and converted wave attenuation (CWA) techniques aided in revealing the true geological dips beneath the salt and facilitated picking accurate residual move-outs during the velocity model building. RTM in conjunction with the high-resolution velocity model significantly improved imaging of complex salt structures and pre-salt reservoirs. At well locations, our workflow resulted in a very good match between the available well data and surface seismic in terms of markers depths and velocity trends. This paper presents a novel approach for modelling the velocity heterogeneities inside the complex Messinian-age salt formation using the Born modeling-based reflection FWI. In addition, salt-related strong converted waves were successfully attenuated, whereas previously the presence of this energy misled interpreters and caused anomalous velocity updates in similar geological settings in the Mediterranean.
{"title":"Improving the Imaging of Pre-Messinian Reservoirs in the East Mediterranean Sea, Offshore Egypt, Using Converted Wave Attenuation, Full-Waveform Inversion and Reflection Tomography","authors":"Mahmoud Abdelqader, Sameh Hamama, Usama Abdelqader, A. Kanrar, Refaat Zaki, Mahmoud Eloribi","doi":"10.2523/iptc-21874-ea","DOIUrl":"https://doi.org/10.2523/iptc-21874-ea","url":null,"abstract":"\u0000 The offshore eastern Mediterranean region has received increased international interest in the last decade for its hydrocarbon potential in the pre-salt traps. The presence of a heterogeneous Messinian-age salt layer and complex pre-Messinian structures pose very difficult challenges in seismic imaging. In this paper, we provide a detailed workflow for seismic data preconditioning and imaging which resolves the subsurface challenges of the Mediterranean.\u0000 Broadband acquisition was used to collect seismic data, which combines the responses of dual-sensor receivers to remove the effect of the receiver ghost. Adaptive source de-ghosting was then applied to address the source-side ghost. Data was processed using robust multiple attenuation and converted wave attenuation (CWA).\u0000 A high-resolution velocity model building and imaging workflow was designed as follows:\u0000 Diving waves full-waveform inversion (FWI) to capture detailed velocity for the complex overburden, followed by post-salt reflection tomography. Born modeling-based reflection FWI to update the velocity heterogeneities inside the salt body followed by reflection tomography for the deep section. Reverse time migration (RTM) to handle the waveform multi-pathing.\u0000 De-ghosting corrected the wavelet phase and expanded the usable frequency bandwidth, resulting in a broadband dataset for imaging. Robust multiple attenuation and converted wave attenuation (CWA) techniques aided in revealing the true geological dips beneath the salt and facilitated picking accurate residual move-outs during the velocity model building. RTM in conjunction with the high-resolution velocity model significantly improved imaging of complex salt structures and pre-salt reservoirs. At well locations, our workflow resulted in a very good match between the available well data and surface seismic in terms of markers depths and velocity trends.\u0000 This paper presents a novel approach for modelling the velocity heterogeneities inside the complex Messinian-age salt formation using the Born modeling-based reflection FWI. In addition, salt-related strong converted waves were successfully attenuated, whereas previously the presence of this energy misled interpreters and caused anomalous velocity updates in similar geological settings in the Mediterranean.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84210251","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. Pituganova, Taofik H. Nassan, M. Amro, I. Minkhanov, M. Varfolomeev, A. Bolotov
Crude oil production from conventional oil reservoirs is declining owing to heavy exploitation to meet the global energy market demand which is growing on a yearly basis. Unconventional oil resources, e.g. extra-heavy oil and bitumen, can compensate for this decline if appropriate enhanced oil recovery (EOR) methods are developed to enable economic flow from these resources. The main objective of this study is to set the best practice for the extra-heavy oil production of the Oykino-Altuninsky uplift of the Romashkinskoye oilfield (Tatarstan Republic, Russia). A series of experimental tests are applied on a real unextracted unconsolidated core sample from Romashkinskoye oilfield where the viscosity of the crude oil is above 600,000 cP at reservoir conditions. Different recovery schemes are tested experimentally and sequentially, namely: water flooding, hot water flooding, steam flooding, and finally in-situ combustion (ISC). Furthermore, the complete experimental run is simulated by a standard nonisothermal simulator and the results are compared to the experiments. On contrary to what was expected hot water at 100°C didn’t achieve any recovery from the sample and steam injection recovered only 11,5% of OOIP. ISC-is also known as fire flooding-attained the best recovery which reached 45% after steam flooding. Complete SARA analysis of the original oil and produced oil by steam and ISC is implemented to understand the mechanisms of each process. Numerical modeling is applied to the corresponding laboratory experiments and the results for water, hot water, and steam flooding were in good agreement with the experimental results while the in-situ combustion simulation showed a better recovery factor than experiments. The laboratory and numerical experiments will improve our understanding of the recovery options of Oykino-Altuninsky uplift of the Romashkinskoye oilfield and help the developers to choose the best production sequence for this oilfield particularly. Moreover, the experiments will provide inputs for the field-size numerical model after running more experiments on unconsolidated and consolidated cores.
{"title":"Experimental and Numerical Analysis of Thermal EOR Recovery Schemes for Extra-Heavy Oil of the Oykino-Altuninsky Uplift of the Romashkinskoye Oilfield","authors":"A. Pituganova, Taofik H. Nassan, M. Amro, I. Minkhanov, M. Varfolomeev, A. Bolotov","doi":"10.2523/iptc-22425-ms","DOIUrl":"https://doi.org/10.2523/iptc-22425-ms","url":null,"abstract":"\u0000 Crude oil production from conventional oil reservoirs is declining owing to heavy exploitation to meet the global energy market demand which is growing on a yearly basis. Unconventional oil resources, e.g. extra-heavy oil and bitumen, can compensate for this decline if appropriate enhanced oil recovery (EOR) methods are developed to enable economic flow from these resources. The main objective of this study is to set the best practice for the extra-heavy oil production of the Oykino-Altuninsky uplift of the Romashkinskoye oilfield (Tatarstan Republic, Russia). A series of experimental tests are applied on a real unextracted unconsolidated core sample from Romashkinskoye oilfield where the viscosity of the crude oil is above 600,000 cP at reservoir conditions. Different recovery schemes are tested experimentally and sequentially, namely: water flooding, hot water flooding, steam flooding, and finally in-situ combustion (ISC). Furthermore, the complete experimental run is simulated by a standard nonisothermal simulator and the results are compared to the experiments. On contrary to what was expected hot water at 100°C didn’t achieve any recovery from the sample and steam injection recovered only 11,5% of OOIP. ISC-is also known as fire flooding-attained the best recovery which reached 45% after steam flooding. Complete SARA analysis of the original oil and produced oil by steam and ISC is implemented to understand the mechanisms of each process. Numerical modeling is applied to the corresponding laboratory experiments and the results for water, hot water, and steam flooding were in good agreement with the experimental results while the in-situ combustion simulation showed a better recovery factor than experiments. The laboratory and numerical experiments will improve our understanding of the recovery options of Oykino-Altuninsky uplift of the Romashkinskoye oilfield and help the developers to choose the best production sequence for this oilfield particularly. Moreover, the experiments will provide inputs for the field-size numerical model after running more experiments on unconsolidated and consolidated cores.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"38 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81497374","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}
Sajid Hussain, Fahad Harthi, A. Shaikh, Francois Missiaen
Drilling into the fields with the presence of communities, will limit closer surface well placement and eliminate the option of conventional well design. With the continuous advancement of Extended Reach Drilling (ERD) technologies, it is possible to drill in such areas; although this approach does present numerous challenges in particular while casing deployment. The project began by preparing a surface location which required a long stretch of the planned well to penetrate the reservoir target(s), thereby, placing it in the ultra-extended reach well category. Due to the shallow TVD and long well departure, the frictional forces developed in the horizontal sections were of significant magnitude. As a result of this, torque and drag were major challenges to overcome during casing running operations. This paper will examine the planning, design, simulation and practices implemented during the (1) drilling of a 12.25 in. horizontal hole section with a stepout of over 16,000 ft., and (2) the deployment of a long 9.5/8 in. casing string with partial flotation and low friction centralizers technologies. Effectively deploying such a long 9.5/8 in. casing string to the bottom of this uniquely challenging wellbore, requires significant engineering and close operational scrutiny. This involves managing frictional and drag losses through effective hole cleaning practices and fluids performance. This study documents using both partial flotation technology and low friction polymer centralization where drag and torque limits, along with potential casing lock up were considered to allow for successful casing running operations. The casing flotation is allowed by employing a buoyant chamber length over 8,800 ft., thus effectively reducing drag in the lateral section as well as the required force to deploy the casing into the extended horizontal section. This results in complete buckling elimination and significant torque reductions. Tailoring the buoyant chamber length/capacity proves to be a critical factor to allow for extended formation exposure and/or reach for casing deployment. A detailed pre-job planning methodology and modeling technique are provided to demonstrate the technical limits and improvement achieved with such technologies to effectively run the 9.5/8 in casing. Expected vs. actual friction factors will be defined and evaluated in order to enhance the assessments and predictions of the computational tools. A tailored methodology to tackle ERD challenges is also presented herein based on the combination of real time data vs. designed simulations.
{"title":"Merging Buoyancy Technology and Low Friction Centralizers in Deploying a Long 9-5/8\" Casing String: Case History of an Ultra Extended Reach Well","authors":"Sajid Hussain, Fahad Harthi, A. Shaikh, Francois Missiaen","doi":"10.2523/iptc-22689-ea","DOIUrl":"https://doi.org/10.2523/iptc-22689-ea","url":null,"abstract":"\u0000 Drilling into the fields with the presence of communities, will limit closer surface well placement and eliminate the option of conventional well design. With the continuous advancement of Extended Reach Drilling (ERD) technologies, it is possible to drill in such areas; although this approach does present numerous challenges in particular while casing deployment.\u0000 The project began by preparing a surface location which required a long stretch of the planned well to penetrate the reservoir target(s), thereby, placing it in the ultra-extended reach well category. Due to the shallow TVD and long well departure, the frictional forces developed in the horizontal sections were of significant magnitude. As a result of this, torque and drag were major challenges to overcome during casing running operations.\u0000 This paper will examine the planning, design, simulation and practices implemented during the (1) drilling of a 12.25 in. horizontal hole section with a stepout of over 16,000 ft., and (2) the deployment of a long 9.5/8 in. casing string with partial flotation and low friction centralizers technologies. Effectively deploying such a long 9.5/8 in. casing string to the bottom of this uniquely challenging wellbore, requires significant engineering and close operational scrutiny. This involves managing frictional and drag losses through effective hole cleaning practices and fluids performance. This study documents using both partial flotation technology and low friction polymer centralization where drag and torque limits, along with potential casing lock up were considered to allow for successful casing running operations. The casing flotation is allowed by employing a buoyant chamber length over 8,800 ft., thus effectively reducing drag in the lateral section as well as the required force to deploy the casing into the extended horizontal section. This results in complete buckling elimination and significant torque reductions. Tailoring the buoyant chamber length/capacity proves to be a critical factor to allow for extended formation exposure and/or reach for casing deployment.\u0000 A detailed pre-job planning methodology and modeling technique are provided to demonstrate the technical limits and improvement achieved with such technologies to effectively run the 9.5/8 in casing. Expected vs. actual friction factors will be defined and evaluated in order to enhance the assessments and predictions of the computational tools. A tailored methodology to tackle ERD challenges is also presented herein based on the combination of real time data vs. designed simulations.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"69 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83796880","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}
Kseniia Zhukova, Miroslav Antonic, M. Soleša, Dragan Camber
The paper presents a practical tool for hydraulic fracturing efficiency evaluation. The tool is based on a data-driven approach that helps in interpreting real-time data. Based on the hydraulic fracturing (HF) job monitoring, statistic metrics and key performance indicators (KPIs) are generated to be valuable input for further designs and identification of potential savings in operation. Machine learning (ML) algorithms are proposed to reduce the tedious work of completion engineers by automatically classifying each treatment schedule's timestamp and assigning the stage label. For operation stages classification Support vector machines and neural networks algorithms are used. These models are trained and evaluated on real-time treatment datasets. After automatic stage recognition, relevant statistic parameters are calculated, enabling advanced data analytics. Detailed analysis of historical data allows to identify the areas for improvements and set new best practices. The first research objective was to gather data from various companies and structure them under the same template to conserve the most critical information gained during the hydraulic fracturing job. Afterwards, the data are preprocessed and labelled by using signal processing routines that significantly decrease the labelling time. The labels or classes are used to define different stages that can be distinguished during the treatment. Finally, the goal is to decrease the necessary time for data labelling. Therefore, two multiclass classification models (Support Vector Machines (SVM) and Neural Network (NN)) are built and evaluated. Based on evaluation metrics, both models resulted in high accuracy and reliable results. However, the SVM model resulted in slightly higher accuracy and an F1 score. The key value of these models is that they provide a computational method to extract a pumping schedule from hydraulic fracturing time-series data automatically. Also, these models allow conducting post-job analysis and choosing the proper pump schedule for a future HF treatment based on previous experience. This past-job analysis could contribute to the effectiveness of future operations by utilizing the materials and fluids more efficiently.
{"title":"Data-Driven Model for Measuring Hydraulic Fracturing Efficiency by Utilizing the Real-Time Treatment Data","authors":"Kseniia Zhukova, Miroslav Antonic, M. Soleša, Dragan Camber","doi":"10.2523/iptc-22384-ms","DOIUrl":"https://doi.org/10.2523/iptc-22384-ms","url":null,"abstract":"\u0000 The paper presents a practical tool for hydraulic fracturing efficiency evaluation. The tool is based on a data-driven approach that helps in interpreting real-time data. Based on the hydraulic fracturing (HF) job monitoring, statistic metrics and key performance indicators (KPIs) are generated to be valuable input for further designs and identification of potential savings in operation.\u0000 Machine learning (ML) algorithms are proposed to reduce the tedious work of completion engineers by automatically classifying each treatment schedule's timestamp and assigning the stage label. For operation stages classification Support vector machines and neural networks algorithms are used. These models are trained and evaluated on real-time treatment datasets. After automatic stage recognition, relevant statistic parameters are calculated, enabling advanced data analytics. Detailed analysis of historical data allows to identify the areas for improvements and set new best practices.\u0000 The first research objective was to gather data from various companies and structure them under the same template to conserve the most critical information gained during the hydraulic fracturing job. Afterwards, the data are preprocessed and labelled by using signal processing routines that significantly decrease the labelling time. The labels or classes are used to define different stages that can be distinguished during the treatment. Finally, the goal is to decrease the necessary time for data labelling. Therefore, two multiclass classification models (Support Vector Machines (SVM) and Neural Network (NN)) are built and evaluated. Based on evaluation metrics, both models resulted in high accuracy and reliable results. However, the SVM model resulted in slightly higher accuracy and an F1 score. The key value of these models is that they provide a computational method to extract a pumping schedule from hydraulic fracturing time-series data automatically. Also, these models allow conducting post-job analysis and choosing the proper pump schedule for a future HF treatment based on previous experience. This past-job analysis could contribute to the effectiveness of future operations by utilizing the materials and fluids more efficiently.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86717539","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}
Natural gas liquid (NGL) production facilities, typically, utilize turbo-expander-brake compressor (TE) to generate cold for C2+ separation from the natural gas by isentropic expansion of feed stream and use energy generated by expansion to compress residue gas. Experience shows that during operational phase TE can exposed to operation outside of design window that may lead to machine integrity loss and consequent impact on production. At the same time, there is a lack of performance indicators that help operator to monitor operating window of the machine and proactively identify performance deterioration. For instance, TE brake compressor side is always equipped with anti-surge protection system, including surge deviation alarms and trip. However, there is often gap in monitoring deviation from stonewall region. At the same time, in some of the designs (2x50% machines) likelihood of running brake compressor in stonewall is high during one machine trip or train start-up, turndown operating modes.
{"title":"Computerized Performance Monitoring System for Turboexpander Brake Compressor","authors":"Vadim Goryachikh, Fahad Alghamdi, Abdulrahman Takrouni","doi":"10.2523/iptc-22602-ms","DOIUrl":"https://doi.org/10.2523/iptc-22602-ms","url":null,"abstract":"\u0000 Natural gas liquid (NGL) production facilities, typically, utilize turbo-expander-brake compressor (TE) to generate cold for C2+ separation from the natural gas by isentropic expansion of feed stream and use energy generated by expansion to compress residue gas.\u0000 Experience shows that during operational phase TE can exposed to operation outside of design window that may lead to machine integrity loss and consequent impact on production. At the same time, there is a lack of performance indicators that help operator to monitor operating window of the machine and proactively identify performance deterioration.\u0000 For instance, TE brake compressor side is always equipped with anti-surge protection system, including surge deviation alarms and trip. However, there is often gap in monitoring deviation from stonewall region. At the same time, in some of the designs (2x50% machines) likelihood of running brake compressor in stonewall is high during one machine trip or train start-up, turndown operating modes.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88744997","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 shares the Project Management Team's experience of conducting a Remote Factory Acceptance Test (Remote-FAT) at the Hawiyah Unayzah Gas Reservoir Storage project instead of the conventional approach of a conventional Factory Acceptance Test (FAT). The paper also highlights the advantages gained from a Remote-FAT, along with the value engineering created. In addition, this paper will present some deficiencies and areas of improvement. This shared experience is from the point of view as a PMT client or customer. At Hawiyah Unayzah Gas Reservoir Storage (HUGRS), the Remote-FAT approach was used with many disciplines, such as mechanical, electrical, pipelines, etc. This paper focuses on the process control system experience only, from 2020 to 2021. Meanwhile the HUGRS project is in progress and is expected to be completed by 2024. Conducting a FAT is one of the main milestones in projects. The conventional method is usually to have individuals physically visit the manufacturer to check and approve shipping the purchased devices/equipment to the project site. Sometimes this practice "FAT" takes place in the same country where the project is being constructed. But in other cases, the manufacturer is not even on the same continent, requiring travel of hundreds or thousands of kilometers. During COVID-19, there were many active projects that needed to conduct FAT activities, but travel was suddenly restricted. Therefore, the only option was to proceed with Remote-FAT. One of these running projects is HUGRS. The Remote-FAT is a virtual inspection check conducted by the client and vendor via online video streaming at the manufacturer location. Multiple cameras are used and located in different views to visualize whatever needs to be seen. In some cases, the Remote-FAT can be conducted through sharing a screen only, such as system graphics and logic test. The client and the vendor verify and conduct the test, following the same steps that they would perform in the conventional FAT. This Remote-FAT had already existed for a couple of years, but many project managers considered it as a fancy tool that did not add value. This evaluation was proven wrong by COVID-19. Remote-FAT has become the most convenient approach recently and adopted around the world. For the past two years, the process control systems engineers at HUGRS conducted many Remote-FATs with different vendors for dissimilar systems. The advantages and disadvantages were recorded as lessons learned — part of PMT practice — and will be shared in the next sections of this paper.
{"title":"The Contribution of Remote Factory Acceptance Test Towards Project's Schedule, Cost & Quality at Hawiyah Unayzah Gas Reservoir Storage","authors":"Mansour Al-Saidi, Hamad Al-Fouzan","doi":"10.2523/iptc-22252-ea","DOIUrl":"https://doi.org/10.2523/iptc-22252-ea","url":null,"abstract":"\u0000 This paper shares the Project Management Team's experience of conducting a Remote Factory Acceptance Test (Remote-FAT) at the Hawiyah Unayzah Gas Reservoir Storage project instead of the conventional approach of a conventional Factory Acceptance Test (FAT). The paper also highlights the advantages gained from a Remote-FAT, along with the value engineering created. In addition, this paper will present some deficiencies and areas of improvement. This shared experience is from the point of view as a PMT client or customer. At Hawiyah Unayzah Gas Reservoir Storage (HUGRS), the Remote-FAT approach was used with many disciplines, such as mechanical, electrical, pipelines, etc. This paper focuses on the process control system experience only, from 2020 to 2021. Meanwhile the HUGRS project is in progress and is expected to be completed by 2024.\u0000 Conducting a FAT is one of the main milestones in projects. The conventional method is usually to have individuals physically visit the manufacturer to check and approve shipping the purchased devices/equipment to the project site. Sometimes this practice \"FAT\" takes place in the same country where the project is being constructed. But in other cases, the manufacturer is not even on the same continent, requiring travel of hundreds or thousands of kilometers. During COVID-19, there were many active projects that needed to conduct FAT activities, but travel was suddenly restricted. Therefore, the only option was to proceed with Remote-FAT. One of these running projects is HUGRS.\u0000 The Remote-FAT is a virtual inspection check conducted by the client and vendor via online video streaming at the manufacturer location. Multiple cameras are used and located in different views to visualize whatever needs to be seen. In some cases, the Remote-FAT can be conducted through sharing a screen only, such as system graphics and logic test. The client and the vendor verify and conduct the test, following the same steps that they would perform in the conventional FAT. This Remote-FAT had already existed for a couple of years, but many project managers considered it as a fancy tool that did not add value. This evaluation was proven wrong by COVID-19. Remote-FAT has become the most convenient approach recently and adopted around the world. For the past two years, the process control systems engineers at HUGRS conducted many Remote-FATs with different vendors for dissimilar systems. The advantages and disadvantages were recorded as lessons learned — part of PMT practice — and will be shared in the next sections of this paper.","PeriodicalId":11027,"journal":{"name":"Day 3 Wed, February 23, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-02-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85624352","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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