Mohmed Helmy, R. Farajzadeh, Adnan Al Maqbali, Mohamed Sabahi
The paper presents an integrated reservoir modeling (IRM) of a giant complex fractured carbonate reservoir to get insights about the reservoir's displacement process. Historically the field has undergone many recovery mechanisms, nowadays two still remains: Gas-Oil Gravity Drainage (GOGD) and waterflood. A major change in understanding the vertical connectivity of the different reservoir units henders the future development options. A decision-based approach was followed to select an economically feasible field development option. Selection of economically feasible development option need; field performance review, full frame structure and geological model is built, ideal conceptual sector models sliced from the full frame structural model and numerical dynamic simulation is carried out with different development options (water injection (WI), gas oil gravity drainage (GOGD) and mixture of WI and GOGD). Understanding the fluid flow behavior in fractured carbonate reservoirs is complex and challenging. The complexity directly linked to the understanding of the fracture hierarchy and connectivity. The field development plan at the time of analyzing the field data was water injection with very good recovery factor that cannot be explained by the injected water pore volume. Applying the integrated reservoir modeling (IRM) procedures, full filed performance review is carried out, update of subsurface models with different fracture model realizations and run numerical dynamic simulations over idealized conceptual models with different development options. Full filed history match is carried out on the selected development option. Front Loading and data analysis is key for successful modeling strategy, the main uncertainty is the fracture distribution, better understanding of the reservoir units cross flow, understand the effect of different development options on recovery factor in significantly short time and create reasonable scenarios of subsurface. Well performance showed some effects of water injection. Gas oil gravity is the dominant recovery process. Gas recirculation of shallow wells have negative effects on the GOGD process. Adding water injectors with continuous gas injection has negative effects on the recovery factor. The fracture hierarchy is key to understand the subsurface. All the studied reservoir units are in communication via fracture corridors. The main recovery mechanism is gas oil gravity drainage (GOGD). WI may have local effects but as development concept it will not add value. Well location relative to fracture corridors is critical to achieve better history match. Water injection has negative effect on field recovery and operationally (WRFM). Filed operation optimization (optimize gas injection) can result in maintain the same rate with lower CPEX and OPEX (Capital spending efficiency). This paper presents significant importance understanding the integration and clear vision of the modeling strategy that saves effort an
{"title":"Sultanate of Oman Giant Fractured Carbonate Field, Fracture Model Impact on Understanding Field Connectivity from Seismic to Flow","authors":"Mohmed Helmy, R. Farajzadeh, Adnan Al Maqbali, Mohamed Sabahi","doi":"10.2118/200154-ms","DOIUrl":"https://doi.org/10.2118/200154-ms","url":null,"abstract":"\u0000 The paper presents an integrated reservoir modeling (IRM) of a giant complex fractured carbonate reservoir to get insights about the reservoir's displacement process. Historically the field has undergone many recovery mechanisms, nowadays two still remains: Gas-Oil Gravity Drainage (GOGD) and waterflood. A major change in understanding the vertical connectivity of the different reservoir units henders the future development options. A decision-based approach was followed to select an economically feasible field development option. Selection of economically feasible development option need; field performance review, full frame structure and geological model is built, ideal conceptual sector models sliced from the full frame structural model and numerical dynamic simulation is carried out with different development options (water injection (WI), gas oil gravity drainage (GOGD) and mixture of WI and GOGD).\u0000 Understanding the fluid flow behavior in fractured carbonate reservoirs is complex and challenging. The complexity directly linked to the understanding of the fracture hierarchy and connectivity. The field development plan at the time of analyzing the field data was water injection with very good recovery factor that cannot be explained by the injected water pore volume. Applying the integrated reservoir modeling (IRM) procedures, full filed performance review is carried out, update of subsurface models with different fracture model realizations and run numerical dynamic simulations over idealized conceptual models with different development options. Full filed history match is carried out on the selected development option.\u0000 Front Loading and data analysis is key for successful modeling strategy, the main uncertainty is the fracture distribution, better understanding of the reservoir units cross flow, understand the effect of different development options on recovery factor in significantly short time and create reasonable scenarios of subsurface.\u0000 Well performance showed some effects of water injection. Gas oil gravity is the dominant recovery process. Gas recirculation of shallow wells have negative effects on the GOGD process. Adding water injectors with continuous gas injection has negative effects on the recovery factor.\u0000 The fracture hierarchy is key to understand the subsurface. All the studied reservoir units are in communication via fracture corridors. The main recovery mechanism is gas oil gravity drainage (GOGD). WI may have local effects but as development concept it will not add value. Well location relative to fracture corridors is critical to achieve better history match. Water injection has negative effect on field recovery and operationally (WRFM). Filed operation optimization (optimize gas injection) can result in maintain the same rate with lower CPEX and OPEX (Capital spending efficiency).\u0000 This paper presents significant importance understanding the integration and clear vision of the modeling strategy that saves effort an","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82148849","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}
Lichi Deng, A. Salehi, Wassim Benhallam, H. Darabi, D. Castineira
Horizontal wells provide a highly efficient way to maximize contact with the reservoir target and to increase overall recovery by allowing a larger drainage pattern. Traditionally, the identification of optimal horizontal well locations involves domain expertise across multiple disciplines and takes a long time to complete. In this work, a fully streamlined artificial intelligence (AI)-based workflow is introduced to facilitate horizontal opportunity identification by combining geological and engineering attributes in all types of reservoirs. This workflow relies on automated geologic and engineering workflows to map the remaining oil in place and identify areas with high probability of success (POS) and high productivity potential. Advanced computational algorithms are implemented under a variety of physical constraints to identify best segments for placing the wellbores. Statistical and machine learning techniques are combined to assess neighborhood performance and geologic risks, along with forecasting the future production performance of the proposed targets. Finally, a comprehensive vetting and sorting framework is presented to ensure the final set of identified opportunities are feasible for the field development plan. The workflow incorporates multiple configuration and trajectory constraints for the horizontal wells’ placement, such as length/azimuth/inclination range, zone-crossing, fault-avoidance, etc. The optimization engine is initialized with an ensemble of initial guesses generated with Latin-Hypercube Sampling (LHS) to ensure all regions of good POS distribution in the model are evenly considered. The intelligent mapping between discrete grid indexing and continuous spatial coordinates greatly reduced the timing and computational resources required for the optimization, thus enabling a fast determination of target segments for multi- million-cell models. The optimization algorithm identifies potential target locations with 3D pay tracking globally, and the segments are further optimized using an interference analysis that selects the best set of non-interfering targets to maximize production. This framework has been successfully applied to multiple giant mature assets in the Middle East, North and South America, with massive dataset and complexity, and in situations where static and dynamic reservoir models are unavailable, partially available, or are out of date. In the specific case study presented here, the workflow is applied to a giant field in the Middle East where tens of deviated or horizontal opportunities are initially identified and vetted. The methodology presented turns the traditional labor-intensive task of horizontal target identification into an intelligently automated workflow with high accuracy. The implemented optimization engine, along with other features highlighted within, has enabled a lightning-fast, highly customizable workflow to identify initial opportunity inventory under high geological complexity
{"title":"Artificial-Intelligence Based Horizontal Well Placement Optimization Leveraging Geological and Engineering Attributes, and Expert-Based Workflows","authors":"Lichi Deng, A. Salehi, Wassim Benhallam, H. Darabi, D. Castineira","doi":"10.2118/200069-ms","DOIUrl":"https://doi.org/10.2118/200069-ms","url":null,"abstract":"\u0000 Horizontal wells provide a highly efficient way to maximize contact with the reservoir target and to increase overall recovery by allowing a larger drainage pattern. Traditionally, the identification of optimal horizontal well locations involves domain expertise across multiple disciplines and takes a long time to complete. In this work, a fully streamlined artificial intelligence (AI)-based workflow is introduced to facilitate horizontal opportunity identification by combining geological and engineering attributes in all types of reservoirs.\u0000 This workflow relies on automated geologic and engineering workflows to map the remaining oil in place and identify areas with high probability of success (POS) and high productivity potential. Advanced computational algorithms are implemented under a variety of physical constraints to identify best segments for placing the wellbores. Statistical and machine learning techniques are combined to assess neighborhood performance and geologic risks, along with forecasting the future production performance of the proposed targets. Finally, a comprehensive vetting and sorting framework is presented to ensure the final set of identified opportunities are feasible for the field development plan. The workflow incorporates multiple configuration and trajectory constraints for the horizontal wells’ placement, such as length/azimuth/inclination range, zone-crossing, fault-avoidance, etc. The optimization engine is initialized with an ensemble of initial guesses generated with Latin-Hypercube Sampling (LHS) to ensure all regions of good POS distribution in the model are evenly considered. The intelligent mapping between discrete grid indexing and continuous spatial coordinates greatly reduced the timing and computational resources required for the optimization, thus enabling a fast determination of target segments for multi- million-cell models. The optimization algorithm identifies potential target locations with 3D pay tracking globally, and the segments are further optimized using an interference analysis that selects the best set of non-interfering targets to maximize production. This framework has been successfully applied to multiple giant mature assets in the Middle East, North and South America, with massive dataset and complexity, and in situations where static and dynamic reservoir models are unavailable, partially available, or are out of date. In the specific case study presented here, the workflow is applied to a giant field in the Middle East where tens of deviated or horizontal opportunities are initially identified and vetted.\u0000 The methodology presented turns the traditional labor-intensive task of horizontal target identification into an intelligently automated workflow with high accuracy. The implemented optimization engine, along with other features highlighted within, has enabled a lightning-fast, highly customizable workflow to identify initial opportunity inventory under high geological complexity","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"18 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76576319","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}
Li‐Qin Jin, Wenyong Li, Yan Lu, Jiabo Liang, Jian’an Dong, Shouxin Wang, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, Tammeem Muktadh, Fang Yongjun, Jon Tuck
CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies. To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir’s main production unit. Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable. Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields. When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation. Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water. The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated. Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy. This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.
{"title":"Diverse Asphaltene Challenges in a Mature Field: A Fluid Study from Iraq","authors":"Li‐Qin Jin, Wenyong Li, Yan Lu, Jiabo Liang, Jian’an Dong, Shouxin Wang, Hussein Kadhim Laaby, Ali Jabbar Ammar, Ali Ouda Tayih, R. Muteer, Tammeem Muktadh, Fang Yongjun, Jon Tuck","doi":"10.2118/200202-ms","DOIUrl":"https://doi.org/10.2118/200202-ms","url":null,"abstract":"\u0000 CNOOC Iraq Limited (CILB) operates the Missan oilfield in Iraq, which consists of three oilfields: Buzurgan oilfield, Abu Gharib oilfield and Fauqi oilfield. To maximize production from the field it has been necessary to overcome different challenges related to asphaltenes (tubing deposition, formation damage, emulsions) – firstly by properly understanding the fluid behaviour, and then by developing and implementing mitigation strategies.\u0000 To understand the asphaltene stability of the reservoir fluids, an isothermal depressurization study was performed on a monophasic bottomhole sample from the reservoir’s main production unit.\u0000 Asphaltene Onset Pressures (AOPs) were identified and used for tuning an equation-of-state model to generate an asphaltene precipitation envelope (APE). Modelling software was used to calculate pressure-temperature profile of fluids both in the near wellbore region and production wells and determine if they entered the APE. This was reviewed against historical field data to assess if asphaltene issues were predictable.\u0000 Common fluid property screening tests (e.g. De Boer plots, Colloidal Instability Index) under-predicted the occurrence of asphaltene precipitation in the oilfields.\u0000 When fluid pressures and temperatures in the reservoir and well environment were compared against the modelled APE, they showed the reservoir fluids passing through the asphaltene instability region for most wells, indicating a risk of deposition in the tubing and in the formation.\u0000 Comparing predictions with field data highlighted that precipitation of asphaltenes does not always result in tubing deposition and additional factors such as watercut and oil viscosity need to be considered. Other fluid-related issues, such as stable emulsions and formation damage, have been observed in the field and require managing. Results from this study show that these can be explained in terms of asphaltene stability issues arising from fluid P/T behavior and interactions with water.\u0000 The importance of drawdown management, already practiced by the field operator, is shown to be a key tool for managing and controlling asphaltene issues. The value of optimizing solvent-based stimulations and retaining the ability to stimulate ESP-lifted wells is also demonstrated.\u0000 Measuring asphaltene stability using virgin reservoir samples, and applying fluid screening tests, are common activities during new field appraisals. The results inform high value decisions, ranging from completion design to reservoir management strategy.\u0000 This study, conducted on a mature field with known production history, shows how results from fluid characterisation studies relate to actual experience of asphaltenes during production. The use of fluid studies in diagnosis and treatment of operational challenges is also demonstrated.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76303012","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}
Matthew J. Monette, Alolika Das, R. Nasralla, R. Farajzadeh, Abdulaziz Shaqsi, Q. Nguyen
Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity. LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type. High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali. The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.
{"title":"Laboratory Investigation on Impact of Gas Type on the Performance of Low-Tension-Gas Flooding in High Salinity, Low Permeability Carbonate Reservoirs","authors":"Matthew J. Monette, Alolika Das, R. Nasralla, R. Farajzadeh, Abdulaziz Shaqsi, Q. Nguyen","doi":"10.2118/200192-ms","DOIUrl":"https://doi.org/10.2118/200192-ms","url":null,"abstract":"\u0000 Past laboratory experiments have shown Low Tension Gas (LTG) floods to be a promising tertiary oil recovery technology in low permeability and high salinity carbonate reservoirs. Gas availability and cost are the major challenges in applying this technology under field conditions. The cost of importing gas from an outside source or on-site generation of nitrogen can be eliminated if the produced gas from the oilfield can be re-injected for generating in-situ foam. Also, the cost of both purchasing freshwater and processing the produced water can be decreased dramatically by injecting both the ultra-low IFT inducing surfactant slug and the drive at the same (constant) salinity.\u0000 LTG corefloods were conducted for a carbonate reservoir with low permeability (<100 mD), moderate temperature (69 °C) and high formation brine salinity (180,000 ppm). Microemulsion phase behavior experiments were conducted at reservoir conditions with different gases. Dynamic foam propagation experiments with methane and a mix of methane-ethane (80 mol. % methane) were performed. The effect of microemulsion (generated using the constant salinity approach) on foam stability was also studied. Optimal conditions for both foam propagations and IFT reduction based on these experiments were identified and used to further develop injection strategies for enhancing oil recovery in coreflood on the same rock type.\u0000 High pressure microemulsion phase behavior experiments showed that produced gas increased the optimum solubilization ratio compared to methane or nitrogen. The solubilization ratio at fixed salinity was a strong function of the surfactant formulation, pressure and the composition of the produced gas. Foam strength experiments showed that produced gas could generate an in-situ foam strength similar to the nitrogen gas. Lower foam quality showed higher apparent viscosity at lower injected surfactant concentration. Preliminary results from core flood experiments indicated that using constant salinity for both slug and drive could result in a remarkable increase in the oil recovery, even though ultra-low IFT inducing surfactants were only injected for a small slug. It also helped improve surfactant transport, which is important for the application of LTG process in high salinity carbonate reservoirs without the use of alkali.\u0000 The results have advanced our understanding of how field gas can be combined with a high performance surfactant formulation to (i) provide necessary conformance control for surfactant flooding, (ii) improve surfactant transport in a very high salinity environment without the need for alkali, and thus soft water, (iii) reduce the complexity of salinity reduction from slug to drive that is typically required in ASP flooding, and (iv) further improve surfactant efficiency due to the increase of oil solubilization and oil viscosity reduction with the injection gas enrichment.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"92 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80477962","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 discusses how re-designing the well is driving the performance and maximizing the well life considering all risks and challenges associated with drilling in Oman thermal Q fields that required further engineering solutions and in-depth simulation and analysis. Managing the risk and delivering wells safely in the most competitive and economical approach are most critical value drivers of these wells. Main risks in Q field are shallow gas, high level of H2s, highly fractured formation, drilling in total losses scenario with ERD wells profile, managing high reactive shale, cement bond quality and critical zonal isolation requirement. It also reflects the unique well control approach in managing gas cap risk with total losses scenario. Collecting the data and list all risks and challenges associated with drilling operation to identify the functionality and other enablers was the most critical step in evaluating what givens and opportunities are. Then, utilizing well plan landmark and other simulation tools to simulate torque and drag, shock and vibration, hydraulics and hole cleaning to optimize the design of the well profile and BHA configurations. Consequently, re-designing the well and proposed the most suitable and fit for purpose design along with different loads and stress checks utilizing wellcat tool. Real-time data utilized during the execution phase to maximize drilling efficiency and design effectiveness. Finally, the well delivered assessed against its critical function requirements like minimum zonal isolation between different reservoirs and well integrity. By proposing engineering solutions and design optimization, utilizing both frontend simulation and past filed best practices, all Q field wells delivered safely with required quality within its budget and time frame. All challenges and risks have been overcome and managed to deliver the project efficiently like torque and drag, hole cleaning, shock and vibration, and back-reaming. Also landing criteria and drilling parameters have been developed to avoid losses while landing the well in a highly depleted reservoir and manage the threat of getting well control scenario. Furthermore, in the execution phase, real-time data monitored to enhance the efficiency and drilling parameters were optimized to keep them within the planned operating envelope. As the design focused on long-term well integrity and longevity, further evaluation post well delivery curried out to check the zonal isolation with positive results that reflect healthy well integrity and fulfillment all functional requirement. This paper reflects the complexity and unique approach in managing well control risk with dynamic kill procedure (Natih procedure) while drilling gas cap in highly fractured formation associated with concertation of H2S gas. Also, it is echoing the importance of advance engineering analysis and solutions in delivering the high ERD ratio wells with their challenges and risk profile. As w
{"title":"Well Design Advancement – Engineering Solutions to Overcome Risks and Challenges in Drilling Risky Thermal Filed in North of Oman","authors":"Qasim Rawahi, H. Rashdi","doi":"10.2118/200268-ms","DOIUrl":"https://doi.org/10.2118/200268-ms","url":null,"abstract":"\u0000 This paper discusses how re-designing the well is driving the performance and maximizing the well life considering all risks and challenges associated with drilling in Oman thermal Q fields that required further engineering solutions and in-depth simulation and analysis. Managing the risk and delivering wells safely in the most competitive and economical approach are most critical value drivers of these wells. Main risks in Q field are shallow gas, high level of H2s, highly fractured formation, drilling in total losses scenario with ERD wells profile, managing high reactive shale, cement bond quality and critical zonal isolation requirement. It also reflects the unique well control approach in managing gas cap risk with total losses scenario.\u0000 Collecting the data and list all risks and challenges associated with drilling operation to identify the functionality and other enablers was the most critical step in evaluating what givens and opportunities are. Then, utilizing well plan landmark and other simulation tools to simulate torque and drag, shock and vibration, hydraulics and hole cleaning to optimize the design of the well profile and BHA configurations. Consequently, re-designing the well and proposed the most suitable and fit for purpose design along with different loads and stress checks utilizing wellcat tool. Real-time data utilized during the execution phase to maximize drilling efficiency and design effectiveness. Finally, the well delivered assessed against its critical function requirements like minimum zonal isolation between different reservoirs and well integrity.\u0000 By proposing engineering solutions and design optimization, utilizing both frontend simulation and past filed best practices, all Q field wells delivered safely with required quality within its budget and time frame. All challenges and risks have been overcome and managed to deliver the project efficiently like torque and drag, hole cleaning, shock and vibration, and back-reaming. Also landing criteria and drilling parameters have been developed to avoid losses while landing the well in a highly depleted reservoir and manage the threat of getting well control scenario. Furthermore, in the execution phase, real-time data monitored to enhance the efficiency and drilling parameters were optimized to keep them within the planned operating envelope. As the design focused on long-term well integrity and longevity, further evaluation post well delivery curried out to check the zonal isolation with positive results that reflect healthy well integrity and fulfillment all functional requirement.\u0000 This paper reflects the complexity and unique approach in managing well control risk with dynamic kill procedure (Natih procedure) while drilling gas cap in highly fractured formation associated with concertation of H2S gas. Also, it is echoing the importance of advance engineering analysis and solutions in delivering the high ERD ratio wells with their challenges and risk profile. As w","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"328 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77599585","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. Masalmeh, S. A. Farzaneh, M. Sohrabi, M. Ataei, Muataz Alshuaibi
Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoirs that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, CO2- EOR has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs. In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artefacts, long cores were used in the experiments and to observe the effect of gravity both 2-inch diameter and 4-inch diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, CO2 was used as a miscible agent and a mixture of 50% C1 and 50% CO2 was used as near miscible injectant. All gas injection experiments were performed using vertically oriented cores and the gas was injected from the top unless it is stated otherwise. The main parameters investigated in this study are: 1- The effect of miscibility on oil recovery for both continuous gas injection and WAG, 2- The effect of gravity on gas sweep efficiency compared to water flooding, 3- the effect of gas-oil IFT on oil recovery when using the same oil, 4- the effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions, 5- the effect of immiscible gas injection on subsequent miscible gas injection performance and 6- Impact of CO2 cycle length on ultimate oil recovery. In addition, this work investigated the impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection. The main conclusions of this study are: 1- As expected miscibility has a significant impact on displacement efficiency and oil recovery, however a significant variation in oil recovery is observed, i.e., about 10 saturation units difference, depending on the oil properties even when both experiments are performed at miscible conditions using the same injected gas. 2- The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. 3- Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. 4- During WAG experiments, s
{"title":"A Systematic Experimental Study to Understand the Performance and Efficiency of Gas Injection in Carbonate Reservoirs","authors":"S. Masalmeh, S. A. Farzaneh, M. Sohrabi, M. Ataei, Muataz Alshuaibi","doi":"10.2118/200057-ms","DOIUrl":"https://doi.org/10.2118/200057-ms","url":null,"abstract":"\u0000 Gas injection is the most widely applied recovery method in light, condensate, and volatile oil carbonate reservoirs. Gas has high displacement efficiency and usually results in a low residual oil saturation in the part of the reservoirs that is contacted with gas. The displacement efficiency increases when the injected gas is near-miscible or miscible with the oil. In addition to nitrogen and hydrocarbon gas projects, CO2- EOR has been the dominant gas EOR process. Gas-based EOR has been implemented in both mature and waterflooded carbonate reservoirs.\u0000 In this paper, we present the results of a detailed experimental study aimed at understanding the performance and efficiency of gas injection in carbonate reservoirs. A series of immiscible and miscible gas injection coreflood experiments were performed using limestone reservoir cores under different injection strategies. To minimize laboratory artefacts, long cores were used in the experiments and to observe the effect of gravity both 2-inch diameter and 4-inch diameter (whole core) were used. The experiments were performed under reservoir conditions using live crude oil. The core wettability was restored by ageing the core in crude oil for several weeks under reservoir temperature. Hydrocarbon gas (methane) was used as the immiscible injectant, CO2 was used as a miscible agent and a mixture of 50% C1 and 50% CO2 was used as near miscible injectant. All gas injection experiments were performed using vertically oriented cores and the gas was injected from the top unless it is stated otherwise.\u0000 The main parameters investigated in this study are: 1- The effect of miscibility on oil recovery for both continuous gas injection and WAG, 2- The effect of gravity on gas sweep efficiency compared to water flooding, 3- the effect of gas-oil IFT on oil recovery when using the same oil, 4- the effect of oil type on oil recovery using the same injected gas at miscible and immiscible conditions, 5- the effect of immiscible gas injection on subsequent miscible gas injection performance and 6- Impact of CO2 cycle length on ultimate oil recovery. In addition, this work investigated the impact of the order of fluid injection where multiple WAG injection cycles were performed in separate experiments after water or gas injection.\u0000 The main conclusions of this study are: 1- As expected miscibility has a significant impact on displacement efficiency and oil recovery, however a significant variation in oil recovery is observed, i.e., about 10 saturation units difference, depending on the oil properties even when both experiments are performed at miscible conditions using the same injected gas. 2- The performance of tertiary CO2 flood was adversely affected by the slug of immiscible gas injected. Therefore, it is not recommended to have immiscible gas injection before miscible gas injection. 3- Regardless of injected gas type, gas injection with similar IFTs achieved similar oil recovery. 4- During WAG experiments, s","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86906662","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}
Injection of cold fluid is injected into hot reservoirs and rocks undergo contraction due to temperature difference. This contrast in temperatures causes the in-situ stress to reduce considerably. When the Minimum Horizontal Stress (σhmin) falls below the Bottomhole Pressure (BHP) due to temperature changes, fractures may initiate and/or propagate. Fractures resulted from thermal processes is referred as Thermally Induced Fractures (TIFs). TIFs can cause highly non-uniform distribution of the injected water flow in the wellbores, reduction in the sweep efficiency, and early water breakthrough in the nearby production wells. The objective of this paper is to evaluate the effectiveness of Inflow Control Device (ICD) to mitigate these fractures in water injection wells. A real field history matched sector model with evidence of TIF occurrence is utilized in this paper using a 3D reservoir thermal simulator coupled with a 2D TIF model and a geomechanical model. The impact of different completions in injection well with TIF modelling under different scenarios is investigated. The added value of ICD was quantified and proved to be effective in controlling TIF initiation and propagation as well as in improving the wellbore flow performance. The selected ICD size should be neither too big (no control) nor too small (over-restriction of injection rate). TIFs mitigation method proposed in this paper is practical, efficient, and strongly contribute to the research aimed at improving waterflood performance in oil fields. Recommendations and guidelines can be utilized in waterflooding operations during modelling, designing, and planning stages.
{"title":"Evaluation of Inflow Control Device Effectiveness to Mitigate Thermally Induced Fractures in Injection Wells","authors":"Misfer J. Almarri","doi":"10.2118/200185-ms","DOIUrl":"https://doi.org/10.2118/200185-ms","url":null,"abstract":"\u0000 Injection of cold fluid is injected into hot reservoirs and rocks undergo contraction due to temperature difference. This contrast in temperatures causes the in-situ stress to reduce considerably. When the Minimum Horizontal Stress (σhmin) falls below the Bottomhole Pressure (BHP) due to temperature changes, fractures may initiate and/or propagate. Fractures resulted from thermal processes is referred as Thermally Induced Fractures (TIFs). TIFs can cause highly non-uniform distribution of the injected water flow in the wellbores, reduction in the sweep efficiency, and early water breakthrough in the nearby production wells. The objective of this paper is to evaluate the effectiveness of Inflow Control Device (ICD) to mitigate these fractures in water injection wells.\u0000 A real field history matched sector model with evidence of TIF occurrence is utilized in this paper using a 3D reservoir thermal simulator coupled with a 2D TIF model and a geomechanical model. The impact of different completions in injection well with TIF modelling under different scenarios is investigated.\u0000 The added value of ICD was quantified and proved to be effective in controlling TIF initiation and propagation as well as in improving the wellbore flow performance. The selected ICD size should be neither too big (no control) nor too small (over-restriction of injection rate).\u0000 TIFs mitigation method proposed in this paper is practical, efficient, and strongly contribute to the research aimed at improving waterflood performance in oil fields. Recommendations and guidelines can be utilized in waterflooding operations during modelling, designing, and planning stages.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86578696","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}
Pierre-Edouard Schreiber, Andrea Osorio Ochoa, Jean-Claude Hild, C. Prinet, M. Bourgeois, Amit Kumar
This paper is based on a study performed on an offshore Middle East field. The field is a giant complex mostly carbonate oil field, which is characterized by a thin oil column, a low permeability associated with fractures, a large transition zone and a lateral variation in fluid properties. Even after an extensive and efficient water-flood development, there are substantial amounts of oil remaining in the reservoir due to the highly oil-wet nature of the rock. Various Enhanced Oil Recovery (EOR) techniques have been envisaged to enhance oil production. The most mature one is the immiscible hydrocarbon Water Alternating Gas (WAG) injection. This High Pressure (HP)-WAG project started in September 2012 after the encouraging results of the continuous Low Pressure (LP) gas injection trial performed in 2008. This paper presents the latest analysis of the performances of this HP-WAG project. The HP-WAG project performances is evaluated through (i) the oil gain (versus a water-flood baseline), (ii) the water injectivity evolution over the WAG cycles, (iii) the gas management and (iv) the well and surface integrity. The paper also aims to share the methodology for analyzing the contribution of the main mechanisms occurring over the WAG cycles: the oil-gas interaction mechanisms and the desaturation mechanisms. The oil-gas interactions that occur in immiscible gas injection cases lead to significant long-lasting WAG effects thanks to both the swelling effects that continue even once the oil is saturated and a permanent mobility ratio improvement. The contribution of both macroscopic and microscopic oil desaturation is also described and quantified in this paper. The work presented in this paper has evidenced the HP-WAG technique benefits and has improved the understanding of the impacts of the main mechanism occurring in the reservoir. This knowledge paved the way towards more extensive WAG deployment on the field. It also emphasized the need of laboratory experiments to calibrate the three-phase models and the absolute need of compositional models to capture the entire WAG benefits even in immiscible gas injection cases.
{"title":"A Comprehensive Analysis of Water Alternating Gas Recovery Mechanisms in a Giant Middle East Field","authors":"Pierre-Edouard Schreiber, Andrea Osorio Ochoa, Jean-Claude Hild, C. Prinet, M. Bourgeois, Amit Kumar","doi":"10.2118/200067-ms","DOIUrl":"https://doi.org/10.2118/200067-ms","url":null,"abstract":"\u0000 This paper is based on a study performed on an offshore Middle East field. The field is a giant complex mostly carbonate oil field, which is characterized by a thin oil column, a low permeability associated with fractures, a large transition zone and a lateral variation in fluid properties. Even after an extensive and efficient water-flood development, there are substantial amounts of oil remaining in the reservoir due to the highly oil-wet nature of the rock. Various Enhanced Oil Recovery (EOR) techniques have been envisaged to enhance oil production. The most mature one is the immiscible hydrocarbon Water Alternating Gas (WAG) injection. This High Pressure (HP)-WAG project started in September 2012 after the encouraging results of the continuous Low Pressure (LP) gas injection trial performed in 2008.\u0000 This paper presents the latest analysis of the performances of this HP-WAG project. The HP-WAG project performances is evaluated through (i) the oil gain (versus a water-flood baseline), (ii) the water injectivity evolution over the WAG cycles, (iii) the gas management and (iv) the well and surface integrity. The paper also aims to share the methodology for analyzing the contribution of the main mechanisms occurring over the WAG cycles: the oil-gas interaction mechanisms and the desaturation mechanisms. The oil-gas interactions that occur in immiscible gas injection cases lead to significant long-lasting WAG effects thanks to both the swelling effects that continue even once the oil is saturated and a permanent mobility ratio improvement. The contribution of both macroscopic and microscopic oil desaturation is also described and quantified in this paper.\u0000 The work presented in this paper has evidenced the HP-WAG technique benefits and has improved the understanding of the impacts of the main mechanism occurring in the reservoir. This knowledge paved the way towards more extensive WAG deployment on the field. It also emphasized the need of laboratory experiments to calibrate the three-phase models and the absolute need of compositional models to capture the entire WAG benefits even in immiscible gas injection cases.","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"115 2 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83636250","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}
Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas. This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen. Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir. The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front. Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion. Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.
{"title":"The Role of Dispersion in Enhanced Gas Recovery and Gas Field Pressure Maintenance","authors":"Johan J. Van Dorp","doi":"10.2118/200261-ms","DOIUrl":"https://doi.org/10.2118/200261-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Enhanced Gas Recovery (EGR) is the process whereby an inert gas like nitrogen or flue gas is injected in a gas reservoir to improve hydrocarbon gas recovery. One of the objectives of EGR is recovery of remaining gas in place at the prevailing abandonment pressure by sweeping native hydrocarbon gas with an inert gas.\u0000 This paper treats the reservoir engineering aspects of dispersion in gas displacement by nitrogen.\u0000 \u0000 \u0000 \u0000 Relevant theory and knowledge from literature are applied to an example sandstone gas reservoir.\u0000 \u0000 \u0000 \u0000 The displacement is typically miscible, and the higher viscosity and density of the injected nitrogen over the native hydrocarbon gas improves the stability of the vertical displacement front. However, dispersion in the reservoir is another potential source of spreading of the front. This leads to early nitrogen breakthrough and a slowly growing nitrogen concentration in the production stream that needs to be dealt with prior to sales through N2 removal or dilution of the produced gas with other gas streams. Reservoirs with low formation dispersivity are therefore the most suitable targets for EGR. This leads to the selection of homogeneous reservoirs with short correlation distances of depositional features. Formation dispersivity is ideally measured upfront using a tracer push-pull test. As a result of the physics of the dispersion process a line drive with a large displacement well spacing provides an optimum selection as (horizontal or vertical) well configuration. Selection of high viscosity injection gas helps to increase the stability of the displacement front.\u0000 \u0000 \u0000 \u0000 Stabilization of the injection front by foam would significantly enlarge the targeted group of fields for EGR to include reservoirs with more adverse heterogeneity. R&D is required to establish a likely reduction in dispersion.\u0000 Accurate modelling of the mixing process is possible by tagging the injection fluid with a passive tracer while solving the advection equations explicitly using a higher order scheme to reduce numerical dispersion. Only physical dispersion at the sub-grid scale should be included. This modelling method could however lead to unstable displacement in the simulator because the density and viscosity contrasts are ignored.\u0000","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87957531","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}
Pub Date : 1986-12-31DOI: 10.1515/9783112494721-018
E. Kolley, W. Kolley
{"title":"Fokker-Planck Equation in the Spin-Glass Dynamics","authors":"E. Kolley, W. Kolley","doi":"10.1515/9783112494721-018","DOIUrl":"https://doi.org/10.1515/9783112494721-018","url":null,"abstract":"","PeriodicalId":11113,"journal":{"name":"Day 1 Mon, March 21, 2022","volume":"51 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"1986-12-31","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79991867","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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