The unconventional fracture model (UFM) has been routinely used to model complex fracture systems. The UFM generates both geometry and conductivity of simulated hydraulic fracture networks, which can be used to create unstructured grids for production simulation. The production simulation model generated from the UFM must be calibrated with actual production data so that it can be used for production predictions and different sensitivity analyses such as well spacing, landing point evaluation and completion optimization. The calibration of the production simulation model is done by specifying oil production rate and history matching the bottomhole pressure (BHP), gas-oil ratio (GOR), and water cut (WCT) measured from oil production wells. The history-matching process mainly involves modifications of the geometry (height and length) and conductivity (permeability) of the hydraulic fracture system, as well as the stimulated reservoir volume (microfractures) surrounding the hydraulic fractures. Modification of the hydraulic fracture geometry usually requires rerunning of the UFM modeling process, which is time consuming. The modification of the hydraulic fracture conductivity usually requires the use of different permeability multipliers in different fracture regions that are defined arbitrarily. To make these modifications, a consistent and systematic process, a permeability multiplier function, has been developed and successfully used in different projects. The function and its application will be introduced and discussed in this paper. The decline permeability multiplier (DPM) function is defined with three parameters: the permeability multiplier at the initiation point (wellbore) of the fracture, the permeability multiplier at the endpoint (tip) of the fracture, and the curvature of the decline between the two points. By adjusting these three parameters, pressure and production data (BHP, GOR, and WCT) can be reasonably history matched. In practice, the function can be applied to hydraulic fractures and microfractures separately with different parameter values. The function can be used not only to define conductivity distribution inside hydraulic fractures, but also to help initialize water saturation distributions in hydraulic fractures in either structured grids or unstructured grids. An example of water saturation distributed with this decline function to better match the water cut is also presented in the paper.
{"title":"Unconventional Oil - Decline Permeability Multipliers for Model Calibration","authors":"James Li, L. Fan, Xu Zhang","doi":"10.2118/197256-ms","DOIUrl":"https://doi.org/10.2118/197256-ms","url":null,"abstract":"\u0000 The unconventional fracture model (UFM) has been routinely used to model complex fracture systems. The UFM generates both geometry and conductivity of simulated hydraulic fracture networks, which can be used to create unstructured grids for production simulation. The production simulation model generated from the UFM must be calibrated with actual production data so that it can be used for production predictions and different sensitivity analyses such as well spacing, landing point evaluation and completion optimization.\u0000 The calibration of the production simulation model is done by specifying oil production rate and history matching the bottomhole pressure (BHP), gas-oil ratio (GOR), and water cut (WCT) measured from oil production wells. The history-matching process mainly involves modifications of the geometry (height and length) and conductivity (permeability) of the hydraulic fracture system, as well as the stimulated reservoir volume (microfractures) surrounding the hydraulic fractures. Modification of the hydraulic fracture geometry usually requires rerunning of the UFM modeling process, which is time consuming. The modification of the hydraulic fracture conductivity usually requires the use of different permeability multipliers in different fracture regions that are defined arbitrarily. To make these modifications, a consistent and systematic process, a permeability multiplier function, has been developed and successfully used in different projects. The function and its application will be introduced and discussed in this paper.\u0000 The decline permeability multiplier (DPM) function is defined with three parameters: the permeability multiplier at the initiation point (wellbore) of the fracture, the permeability multiplier at the endpoint (tip) of the fracture, and the curvature of the decline between the two points. By adjusting these three parameters, pressure and production data (BHP, GOR, and WCT) can be reasonably history matched. In practice, the function can be applied to hydraulic fractures and microfractures separately with different parameter values. The function can be used not only to define conductivity distribution inside hydraulic fractures, but also to help initialize water saturation distributions in hydraulic fractures in either structured grids or unstructured grids. An example of water saturation distributed with this decline function to better match the water cut is also presented in the paper.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79429279","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}
With the advent of next cycle of stabilization and steady increment of oil and gas prices, the deepwater blocks which were marginalized due to high development cost, are beginning to appear as a lucrative proposition again. Globally new oil and gas production is focused in remote locations which are also challenging to operate. Deepwater, ultra-deepwater, tight oil and shale gas are great examples of this. In last two decades, exploration & production players have made rapid progress in pushing the depth of subsea production. The on-going development of new hydrocarbon discoveries in different deepwater regions creates significant opportunities for the pipeline industry. Also, the need of the ‘oil & gas markets’ to get well connected with the ‘oil & gas producers’ is leading its way to the announcements of long distance deepwater pipelines in a record water depth of up to 3500 m in the recent past. Gearing up for this challenge, this paper broadly elucidates the deepwater pipeline installation risks and challenges, such as selection of the line pipe to sustain high external over-pressure and tensile stresses generated due to installation forces, selection of external coating system, capability requirement of installation vessels with high tensioner capacity to hold the long catenary of thick-walled pipe, pipeline configuration control and prevention against accidental flooding while laying, challenges in touch-down point monitoring and buckle detection, seabed intervention requirement & methodologies and new evolving testing & commissioning philosophies required for ensuring the integrity of the deepwater pipelines after installation. This paper also covers the findings of installation analysis, for S-lay configuration, performed for deepwater pipelines with varying water depths. This paper intends to bring awareness among the "oil and gas fraternity" regarding challenges involved in ultra-deepwater pipelines and discusses the technical advancements made in this segment and the need of further works for bringing the installation of pipelines in ultra-deepwater one step closer.
{"title":"Deepwater Pipelines Installation Risks and Challenges","authors":"N. Sinha, Nawin Singh","doi":"10.2118/197306-ms","DOIUrl":"https://doi.org/10.2118/197306-ms","url":null,"abstract":"\u0000 With the advent of next cycle of stabilization and steady increment of oil and gas prices, the deepwater blocks which were marginalized due to high development cost, are beginning to appear as a lucrative proposition again. Globally new oil and gas production is focused in remote locations which are also challenging to operate. Deepwater, ultra-deepwater, tight oil and shale gas are great examples of this. In last two decades, exploration & production players have made rapid progress in pushing the depth of subsea production. The on-going development of new hydrocarbon discoveries in different deepwater regions creates significant opportunities for the pipeline industry. Also, the need of the ‘oil & gas markets’ to get well connected with the ‘oil & gas producers’ is leading its way to the announcements of long distance deepwater pipelines in a record water depth of up to 3500 m in the recent past.\u0000 Gearing up for this challenge, this paper broadly elucidates the deepwater pipeline installation risks and challenges, such as selection of the line pipe to sustain high external over-pressure and tensile stresses generated due to installation forces, selection of external coating system, capability requirement of installation vessels with high tensioner capacity to hold the long catenary of thick-walled pipe, pipeline configuration control and prevention against accidental flooding while laying, challenges in touch-down point monitoring and buckle detection, seabed intervention requirement & methodologies and new evolving testing & commissioning philosophies required for ensuring the integrity of the deepwater pipelines after installation. This paper also covers the findings of installation analysis, for S-lay configuration, performed for deepwater pipelines with varying water depths.\u0000 This paper intends to bring awareness among the \"oil and gas fraternity\" regarding challenges involved in ultra-deepwater pipelines and discusses the technical advancements made in this segment and the need of further works for bringing the installation of pipelines in ultra-deepwater one step closer.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"131 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80255761","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}
M. Soliman, Mohammed Abdo Alwani, Abdullah Younis Aiderous
The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature. In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.
{"title":"Troubleshooting Glycol Loss in Gas Dehydration Systems Using Data Analysis at Upstream Operation","authors":"M. Soliman, Mohammed Abdo Alwani, Abdullah Younis Aiderous","doi":"10.2118/197768-ms","DOIUrl":"https://doi.org/10.2118/197768-ms","url":null,"abstract":"\u0000 The objective of this paper is to showcase the successful and innovative troubleshooting data analysis techniques to reduce glycol loss and to meet the product specifications in one of the gas dehydration systems in an upstream gas oil separation plant (GOSP). The gas dehydration system using Triethylene Glycol (TEG) is the most widely used and reliable gas dehydration system in upstream operation. These proven data analysis techniques were used to tackle major and chronic issues associated with gas dehydration system operation that lead to excessive glycol losses, glycol degradation, and off-specification products. Glycol loss is the most important operating problem in the gas dehydration system and it represents a concern to the operation personnel. Most dehydration units are designed for a loss of less than 1 pound of glycol per million standard cubic feet of natural gas treated, depending on the TEG contactor operating temperature.\u0000 In this paper, comprehensive data analysis of the potential root causes that aggravate undesired glycol losses degradation and off-specification products will be discussed along with solutions to minimize the expected impact. For example, operating the absorption vessel (contactor) or still column at high temperature will increase the glycol loss by vaporization. Also, the glycol losses occurring in the glycol regenerator section are usually caused by excessive reboiler temperature, which causes vaporization or thermal decomposition of glycol (TEG). In addition, excessive top temperature in the still column allows vaporized glycol to escape from the still column with the water vapor. Excessive contactor operating temperature could be the result of malfunction glycol cooler or high TEG flow rate. This paper will focus on a detailed case study in one of the running TEG systems at a gas-oil separation plant.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80839810","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. Al-Taq, Basil M. Alfakher, Abdulla A. Alrustum, Sajjad Aldarweesh
Aromatic-based solvents, including benzene, toluene, xylene (BTX) and their derivatives have been successfully applied for asphaltene removal from downhole and surface facilities. These solvents are considered non-environmentally friendly due to their associated health and safety concerns including high toxicity, low biodegradability and low flash point. Currently, more attention has been given in the oil industry to develop environmentally friendly asphaltene solvents. This paper examines several environmentally friendly solvents derived from natural precursors to dissolve asphaltene, wax and combined asphaltene/paraffin organic deposit. A group of plant-derived and terpene-based asphaltene solvents with flash points ranging from 50.5 to 136 °C was examined in this study. Extracted asphaltene from a crude oil and wax obtained from distillation were used to assess solvency power of these solvents. Solubility of organic deposits containing more 42 wt% asphaltene with associated paraffin was evaluated in these solvents. The performance of these solvents was examined as a function of soaking time and temperature. These environmentally friendly solvents showed comparable solvency power to toluene. The lowest flash point solvent exhibited the highest solvency power for asphaltene while the opposite relation was observed for the wax sample. The lowest flash point (50.5 °C) solvent was able to dissolve 91 wt% of the asphaltene sample after soaking for 2 hours at ambient temperature compared with the highest flash point solvent (136 °C), which dissolved only 7.4 wt% at the same conditions. For wax, the solvent with the second highest flash point (132 °C) was able to dissolve 97 wt% of the wax while the solvent with a flash point of 50.5 °C was able to dissolve 85.5 wt% at ambient temperature and after 2 hours. Some of the examined environmentally friendly solvents showed very high dissolution power to organic deposits composed of asphaltene and paraffin where a solubility of 96 wt% was obtained at 80 °C and after a soaking time of 6 hours. The paper will discuss these results in detail.
{"title":"Alternative Environmentally Friendly Solvents for Asphaltenes/Paraffins Removal from Oil Producing Wells","authors":"A. Al-Taq, Basil M. Alfakher, Abdulla A. Alrustum, Sajjad Aldarweesh","doi":"10.2118/197697-ms","DOIUrl":"https://doi.org/10.2118/197697-ms","url":null,"abstract":"\u0000 Aromatic-based solvents, including benzene, toluene, xylene (BTX) and their derivatives have been successfully applied for asphaltene removal from downhole and surface facilities. These solvents are considered non-environmentally friendly due to their associated health and safety concerns including high toxicity, low biodegradability and low flash point. Currently, more attention has been given in the oil industry to develop environmentally friendly asphaltene solvents.\u0000 This paper examines several environmentally friendly solvents derived from natural precursors to dissolve asphaltene, wax and combined asphaltene/paraffin organic deposit. A group of plant-derived and terpene-based asphaltene solvents with flash points ranging from 50.5 to 136 °C was examined in this study. Extracted asphaltene from a crude oil and wax obtained from distillation were used to assess solvency power of these solvents. Solubility of organic deposits containing more 42 wt% asphaltene with associated paraffin was evaluated in these solvents. The performance of these solvents was examined as a function of soaking time and temperature. These environmentally friendly solvents showed comparable solvency power to toluene. The lowest flash point solvent exhibited the highest solvency power for asphaltene while the opposite relation was observed for the wax sample. The lowest flash point (50.5 °C) solvent was able to dissolve 91 wt% of the asphaltene sample after soaking for 2 hours at ambient temperature compared with the highest flash point solvent (136 °C), which dissolved only 7.4 wt% at the same conditions. For wax, the solvent with the second highest flash point (132 °C) was able to dissolve 97 wt% of the wax while the solvent with a flash point of 50.5 °C was able to dissolve 85.5 wt% at ambient temperature and after 2 hours. Some of the examined environmentally friendly solvents showed very high dissolution power to organic deposits composed of asphaltene and paraffin where a solubility of 96 wt% was obtained at 80 °C and after a soaking time of 6 hours. The paper will discuss these results in detail.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75680659","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. J. D. Barros, Ahmed Rashed Alaleeli, Ahmedagha Hamidzada, A. Hassan, A. Melo, Mohd Waheed Orfali, T. Phyoe, J. Salazar, S. Kapoor, K. Kondo
Lost circulation (LC) is an expensive and time-consuming problem. It's desirable to minimize losses before cement job to ensure good cement coverage and maximize well integrity. But quite commonly, wells experience induced losses just before cementing, during casing running and circulation. In such a scenario, the options to control losses have been few, with limited results. The paper demonstrates a viable solution that can be successfully applied to reduce or eliminate such induced losses during the cement job. To effectively solve lost circulation with the correct technique, it is necessary to know the severity of the losses and the type of lost circulation zone. In UAE fields, the loss rates range from 150 bbl/h to more than 700 bbl/h in the 17½- and 12¼-in open hole sections. During cementing operations, lost circulation causes reduced top of cement, poor zonal isolation, and risks to drill ahead. To solve this problem, a composite fiber-based spacer system based on a novel four-step methodology was designed using advanced software. Before a field trial, rigorous lab-scale and yard-scale testing was conducted to optimize the application. Initially, no losses were witnessed while drilling the 12¼-in section. But during casing running and circulation, severe losses of 150 bbl/hr were induced. To counter these losses, the specially designed fiber-based lost circulation spacer system was pumped ahead of the cement slurry using standard surface equipment. At the beginning of the displacement—while cement and spacer were still in the casing string—the loss rate increased to 700 bbl/hr (total losses). This high loss rate in the crucial intermediate section would normally have resulted in costly remedial operations, loss of mud and cement, and expensive rig time. It was observed that the loss rate remained at 700 bbl/hr until the lost circulation spacer arrived at the loss zone. Subsequently, the loss rate kept on declining finally resulting in full returns during remaining displacement. The designed excess of cement was received as returns, thereby ensuring the desired top of cement at surface. This proved that the fiber-based spacer was effective in curing the losses. An advanced cement bond log showed complete cement coverage over the entire section. This further proved the spacer's effectiveness in achieving all well integrity objectives. The successful application of the engineered fiber-based lost circulation control spacer during primary cementing demonstrates a reliable solution to the challenge posed by losses induced immediately before a cement job. The system is easy to deliver and design and can plug the fracture network in the formation during the cement job. Globally, this engineered composite fiber-blend spacer has proved to improve performance during cementing operations by healing losses to maximize well integrity.
{"title":"Healing Total Losses and Establishing Well Integrity with Engineered Fiber-Based Lost Circulation Control Spacer During Primary Cementing in UAE Offshore","authors":"A. J. D. Barros, Ahmed Rashed Alaleeli, Ahmedagha Hamidzada, A. Hassan, A. Melo, Mohd Waheed Orfali, T. Phyoe, J. Salazar, S. Kapoor, K. Kondo","doi":"10.2118/197432-ms","DOIUrl":"https://doi.org/10.2118/197432-ms","url":null,"abstract":"\u0000 Lost circulation (LC) is an expensive and time-consuming problem. It's desirable to minimize losses before cement job to ensure good cement coverage and maximize well integrity. But quite commonly, wells experience induced losses just before cementing, during casing running and circulation. In such a scenario, the options to control losses have been few, with limited results. The paper demonstrates a viable solution that can be successfully applied to reduce or eliminate such induced losses during the cement job.\u0000 To effectively solve lost circulation with the correct technique, it is necessary to know the severity of the losses and the type of lost circulation zone. In UAE fields, the loss rates range from 150 bbl/h to more than 700 bbl/h in the 17½- and 12¼-in open hole sections. During cementing operations, lost circulation causes reduced top of cement, poor zonal isolation, and risks to drill ahead. To solve this problem, a composite fiber-based spacer system based on a novel four-step methodology was designed using advanced software. Before a field trial, rigorous lab-scale and yard-scale testing was conducted to optimize the application.\u0000 Initially, no losses were witnessed while drilling the 12¼-in section. But during casing running and circulation, severe losses of 150 bbl/hr were induced. To counter these losses, the specially designed fiber-based lost circulation spacer system was pumped ahead of the cement slurry using standard surface equipment. At the beginning of the displacement—while cement and spacer were still in the casing string—the loss rate increased to 700 bbl/hr (total losses). This high loss rate in the crucial intermediate section would normally have resulted in costly remedial operations, loss of mud and cement, and expensive rig time. It was observed that the loss rate remained at 700 bbl/hr until the lost circulation spacer arrived at the loss zone. Subsequently, the loss rate kept on declining finally resulting in full returns during remaining displacement. The designed excess of cement was received as returns, thereby ensuring the desired top of cement at surface. This proved that the fiber-based spacer was effective in curing the losses. An advanced cement bond log showed complete cement coverage over the entire section. This further proved the spacer's effectiveness in achieving all well integrity objectives.\u0000 The successful application of the engineered fiber-based lost circulation control spacer during primary cementing demonstrates a reliable solution to the challenge posed by losses induced immediately before a cement job. The system is easy to deliver and design and can plug the fracture network in the formation during the cement job. Globally, this engineered composite fiber-blend spacer has proved to improve performance during cementing operations by healing losses to maximize well integrity.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73166742","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}
Stratigraphically discordant massive dolomite bodies of the Upper Jurassic have long been documented because they strongly affect reservoir quality. Dolomitization is affected by varies factors such as original depositional texture, dolomitizing fluid, dolomitization timing and types, and previous diagenetic stages, which can make dolomite bodies either flow conduits or barriers. Therefore, understanding the complex diagenetic system and the distribution of the massive dolomite are extremely important. In this study, we integrated forward diagenetic and geological modeling following 4-step approach: (1) detailed 3D geologic modeling to delineate the spatial distribution of the massive dolomite; (2) calculation of the effects of dolomitization on reservoir quality; (3) property modeling to predict the spatial distribution of reservoir quality; (4) integrate geological and diagenetic forward modeling to improve the understanding of the dolomitization system and its impact on reservoir quality. Modeling results indicate that: (1) In general, dolomitization can be divided into two phases, replacement and pore-filling. During the replacement phase, porosity preservation is the dominant process, while during the pore-filling phase porosity decreases sharply with the increase of dolomite volume fraction. Overall, the replacement phase improves reservoir quality, while the pore-filling destroys it; (2) The massive dolomite is heterogeneously distributed with an overall regional trend of decreasing dolomite content southwards; (3) two episodes of dolomitization are likely to occur, supported by multiple types of data, the first is driven by the tectonic compression and developed adjacent to salt basins, whereas the second is related to late hydrothermal dolomitization overprinting the early dolomite. This integrated forward diagenetic and geological modeling approach helps to better understand the dolomitization mechanisms and regional diagenetic system, by improving the mapping of the massive dolomite and the prediction of reservoir quality.
{"title":"Improved Massive Dolomite Mapping by Integrated Forward Diagenetic and Geological Modeling","authors":"Yin Xu, Peng Lu","doi":"10.2118/197450-ms","DOIUrl":"https://doi.org/10.2118/197450-ms","url":null,"abstract":"\u0000 Stratigraphically discordant massive dolomite bodies of the Upper Jurassic have long been documented because they strongly affect reservoir quality. Dolomitization is affected by varies factors such as original depositional texture, dolomitizing fluid, dolomitization timing and types, and previous diagenetic stages, which can make dolomite bodies either flow conduits or barriers. Therefore, understanding the complex diagenetic system and the distribution of the massive dolomite are extremely important.\u0000 In this study, we integrated forward diagenetic and geological modeling following 4-step approach: (1) detailed 3D geologic modeling to delineate the spatial distribution of the massive dolomite; (2) calculation of the effects of dolomitization on reservoir quality; (3) property modeling to predict the spatial distribution of reservoir quality; (4) integrate geological and diagenetic forward modeling to improve the understanding of the dolomitization system and its impact on reservoir quality.\u0000 Modeling results indicate that: (1) In general, dolomitization can be divided into two phases, replacement and pore-filling. During the replacement phase, porosity preservation is the dominant process, while during the pore-filling phase porosity decreases sharply with the increase of dolomite volume fraction. Overall, the replacement phase improves reservoir quality, while the pore-filling destroys it; (2) The massive dolomite is heterogeneously distributed with an overall regional trend of decreasing dolomite content southwards; (3) two episodes of dolomitization are likely to occur, supported by multiple types of data, the first is driven by the tectonic compression and developed adjacent to salt basins, whereas the second is related to late hydrothermal dolomitization overprinting the early dolomite.\u0000 This integrated forward diagenetic and geological modeling approach helps to better understand the dolomitization mechanisms and regional diagenetic system, by improving the mapping of the massive dolomite and the prediction of reservoir quality.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"20 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73745753","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}
Jianbo Zhang, Zhiyuan Wang, Wenguang Duan, W. Fu, Shikun Tong, Baojiang Sun
Hydrate formation and deposition usually exist during deep-water gas well testing, which easily cause plugging accident in the testing tubing if it was not found and handled in time. A method to estimate and manage hydrate plugging risk in real-time during deep-water gas well testing is developed in this work. This method mainly includes the following steps: predicting hydrate stability region, calculating hydrate behaviors, analyzing the effect of hydrate behaviors on the variation of wellhead pressure, monitoring the variation of wellhead pressure and estimating hydrate plugging risk in real-time, and managing hydrate plugging risk in real-time. As hydrates continue to form and deposit, the effective inner diameter of the tubing decreases, and the wellhead pressure also decreases accordingly. The risk of hydrate plugging can be estimated by monitoring the variation of wellhead pressure. When the wellhead pressure decreases to the critical value for safety at a given gas production rate, it is indicated that hydrate plugging is likely to occur. Under this condition, hydrate inhibitor is needed to inject into the tubing to reduce the severity of hydrate plugging, and real-time monitoring of wellhead pressure variation is also needed to guarantee the risk of hydrate plugging in the testing tube is within safe range. By using this method, the real-time estimation and management of hydrate plugging during the testing process can be achieved, which can provide basis for the safe and efficient testing of deep-water gas wells.
{"title":"Real-Time Estimation and Management of Hydrate Plugging Risk During Deep-Water Gas Well Testing","authors":"Jianbo Zhang, Zhiyuan Wang, Wenguang Duan, W. Fu, Shikun Tong, Baojiang Sun","doi":"10.2118/197151-ms","DOIUrl":"https://doi.org/10.2118/197151-ms","url":null,"abstract":"Hydrate formation and deposition usually exist during deep-water gas well testing, which easily cause plugging accident in the testing tubing if it was not found and handled in time. A method to estimate and manage hydrate plugging risk in real-time during deep-water gas well testing is developed in this work. This method mainly includes the following steps: predicting hydrate stability region, calculating hydrate behaviors, analyzing the effect of hydrate behaviors on the variation of wellhead pressure, monitoring the variation of wellhead pressure and estimating hydrate plugging risk in real-time, and managing hydrate plugging risk in real-time. As hydrates continue to form and deposit, the effective inner diameter of the tubing decreases, and the wellhead pressure also decreases accordingly. The risk of hydrate plugging can be estimated by monitoring the variation of wellhead pressure. When the wellhead pressure decreases to the critical value for safety at a given gas production rate, it is indicated that hydrate plugging is likely to occur. Under this condition, hydrate inhibitor is needed to inject into the tubing to reduce the severity of hydrate plugging, and real-time monitoring of wellhead pressure variation is also needed to guarantee the risk of hydrate plugging in the testing tube is within safe range. By using this method, the real-time estimation and management of hydrate plugging during the testing process can be achieved, which can provide basis for the safe and efficient testing of deep-water gas wells.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"87 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76821806","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 characterization of the clastic Zubair reservoir is challenging because of the high lamination and the oil properties change making the conventional saturation technique uncertain. A new workflow has been recently established in the newly appraised wells which has involved advanced petrophysical measurements along with the fluid sampling. The new technique has led to identify new HC layers that were overlooked by the previous techniques, thus adding more reserves to the KOC asset. Because of the high lamination of clastic Zubair formation and the change of the oil properties, the dielectric dispersion measurement was integrated along with the diffusion-based NMR to identify new oil zones that has been initially masked by the resistivity-based approach. The new approach has also provided details on the oil movability and the characterization of its property. As the newly identified layers were identified for the 1st time across the field, the fluid sampling was conducted to confirm the new findings. The advent of a new logging technology from a multi-frequency dielectric technique deployed over the formation has independently pinned down the HC pays over the Zubair interval, including a new zone below the water column. The zone was initially identified as heavy Tar zone. The advanced diffusion-based NMR was thus conducted and integrated with Dielectrics which has demonstrated the movability of HC using the diffusion-based NMR approach over the newly identified zone. A fluid sampling was later performed which has confirmed the new finding. The new identified zone was initially overlooked by the previous interpretation and extensive modeling over the entire field. The seal mechanism was also explained by taking advantage of the high-resolution dielectric dispersion measurement (mainly the low frequency), which has been also supported by the Images interpretation. This new approach has added an incremental oil storage over the field.
{"title":"Integrated Approach of Evolving Petrophysical and Formation Testing Measurements Improves Hydrocarbon Reserves of Laminated Clastic Formations in Kuwait","authors":"Chao Chen, K. Sassi, H. Ayyad","doi":"10.2118/197381-ms","DOIUrl":"https://doi.org/10.2118/197381-ms","url":null,"abstract":"\u0000 The characterization of the clastic Zubair reservoir is challenging because of the high lamination and the oil properties change making the conventional saturation technique uncertain. A new workflow has been recently established in the newly appraised wells which has involved advanced petrophysical measurements along with the fluid sampling. The new technique has led to identify new HC layers that were overlooked by the previous techniques, thus adding more reserves to the KOC asset.\u0000 Because of the high lamination of clastic Zubair formation and the change of the oil properties, the dielectric dispersion measurement was integrated along with the diffusion-based NMR to identify new oil zones that has been initially masked by the resistivity-based approach. The new approach has also provided details on the oil movability and the characterization of its property. As the newly identified layers were identified for the 1st time across the field, the fluid sampling was conducted to confirm the new findings.\u0000 The advent of a new logging technology from a multi-frequency dielectric technique deployed over the formation has independently pinned down the HC pays over the Zubair interval, including a new zone below the water column. The zone was initially identified as heavy Tar zone. The advanced diffusion-based NMR was thus conducted and integrated with Dielectrics which has demonstrated the movability of HC using the diffusion-based NMR approach over the newly identified zone. A fluid sampling was later performed which has confirmed the new finding. The new identified zone was initially overlooked by the previous interpretation and extensive modeling over the entire field. The seal mechanism was also explained by taking advantage of the high-resolution dielectric dispersion measurement (mainly the low frequency), which has been also supported by the Images interpretation. This new approach has added an incremental oil storage over the field.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76883297","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 main objective of this paper is understanding the phenomenal anomalous diffusion flow mechanisms in unconventional fractured porous media. This understanding is crucial for estimating the impact of these flow mechanisms on pressure behavior, flow regimes, and transient and pseudo-steady state productivity index of the two cases of inner wellbore conditions: constant sandface flow rate and constant wellbore pressure. The targets are hydraulically fractured unconventional reservoirs characterized by porous media with complex structures. These media are consisted of a matrix and naturally induces fractures embedded in the matrix as well as hydraulic fractures. Several analytical models for pressure drop and decline rate as wells productivity index in ultralow permeability reservoirs are presented in this study for the two inner wellbore conditions. A numerical solution is also presented in this study for pressure behavior using a linearized implicit finite difference method. The analytical models are developed from trilinear flow models presented in the literature with a consideration given to the temporal and spatial fractional pressure derivative for the ano malous diffusion flow that could be the dominant flow mechanism in the stimulated reservoir volume between hydraulic fractures. Mittag-Leffler functions are used for solving fractional derivatives of pressure and flow rate considering that temporal and spatial fractional exponents are less than one. Two solutions are developed in this study for the two inner wellbore conditions. The first represents the transient state condition that controls fluid flow in unconventional reservoirs for very long produc tion time. The second is the solution of pseudo-steady state condition that might be observed after transient state flow. The second solution is used for estimating stabilized pseudo-steady state productivity index considering different reservoir conditions. In the numerical solution, the temporal and spatial domains are discretized into several time steps and block-centered grids respectively. The results of the analytical models are compared with numerical solutions. The outcomes of this study are: 1) Understanding the impact of temporal and spatial diffusion flow mechanisms on pressure behavior, flow rate declining pattern, and productivity index scheme during early and late production time. 2) Developing analytical and numerical models for fractional derivatives of pressure and flow rate considering diffusion flow mechanisms 3) Developing analytical models for different flow regimes that could be developed during the entire production life of reservoirs. 4) Studying the impact of reservoir configuration and wellbore type as well as different temporal and spatial diffusion flow conditions on stabilized pseudo-steady state productivity index. The study has pointed out: 1) Temporal and spatial diffusion flow have a significant impact on pressure drop, flow rate, and productivity index.
{"title":"Temporal and Spatial Anomalous Diffusion Flow Mechanisms in Structurally Complex Porous Media: The Impact on Pressure behavior, Flow regimes, and Productivity Index","authors":"S. Al-Rbeawi","doi":"10.2118/197553-ms","DOIUrl":"https://doi.org/10.2118/197553-ms","url":null,"abstract":"\u0000 The main objective of this paper is understanding the phenomenal anomalous diffusion flow mechanisms in unconventional fractured porous media. This understanding is crucial for estimating the impact of these flow mechanisms on pressure behavior, flow regimes, and transient and pseudo-steady state productivity index of the two cases of inner wellbore conditions: constant sandface flow rate and constant wellbore pressure. The targets are hydraulically fractured unconventional reservoirs characterized by porous media with complex structures. These media are consisted of a matrix and naturally induces fractures embedded in the matrix as well as hydraulic fractures.\u0000 Several analytical models for pressure drop and decline rate as wells productivity index in ultralow permeability reservoirs are presented in this study for the two inner wellbore conditions. A numerical solution is also presented in this study for pressure behavior using a linearized implicit finite difference method. The analytical models are developed from trilinear flow models presented in the literature with a consideration given to the temporal and spatial fractional pressure derivative for the ano malous diffusion flow that could be the dominant flow mechanism in the stimulated reservoir volume between hydraulic fractures. Mittag-Leffler functions are used for solving fractional derivatives of pressure and flow rate considering that temporal and spatial fractional exponents are less than one. Two solutions are developed in this study for the two inner wellbore conditions. The first represents the transient state condition that controls fluid flow in unconventional reservoirs for very long produc tion time. The second is the solution of pseudo-steady state condition that might be observed after transient state flow. The second solution is used for estimating stabilized pseudo-steady state productivity index considering different reservoir conditions. In the numerical solution, the temporal and spatial domains are discretized into several time steps and block-centered grids respectively. The results of the analytical models are compared with numerical solutions.\u0000 The outcomes of this study are: 1) Understanding the impact of temporal and spatial diffusion flow mechanisms on pressure behavior, flow rate declining pattern, and productivity index scheme during early and late production time. 2) Developing analytical and numerical models for fractional derivatives of pressure and flow rate considering diffusion flow mechanisms 3) Developing analytical models for different flow regimes that could be developed during the entire production life of reservoirs. 4) Studying the impact of reservoir configuration and wellbore type as well as different temporal and spatial diffusion flow conditions on stabilized pseudo-steady state productivity index. The study has pointed out: 1) Temporal and spatial diffusion flow have a significant impact on pressure drop, flow rate, and productivity index. ","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91318353","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 seismic vertical resolution is too low to identify the vertical boundary and petrophysical properties of the thin shale layers inside the target precisely. This study focuses on structural and petrophysical modeling of shale reservoirs based on horizontal wells and seismic inversion. Combined seismic trend surface with the well tops on horizontal wells, we calculated the top and bottom surface of the target formation, and obtained the structural surface of each small layer according to the thickness percentage of each layer from few vertical wells. Ultimately, the structural model is made. The horizontal trend of the petrophysical properties can be controlled by the seismic inversion results. The vertical trend of the petrophysical properties can be controlled by well logs. Constricted by the linear combination weighting of the horizontal and vertical trend, the petrophysical model is established. The results show that the trajectory of the horizontal well in the target layer is accurate, and the layers are not intersected. The thickness of each layer is relatively even in plane, which is basically the same as that of the vertical well, indicating the characteristics of shale stable deposition. The discrepancy between the thickness of each layer in the model and those of the vertical wells is very small, especially in the main production layer 1, less than 0.1m. With the linear combination weighting, petrophysical properties show the bimodal distribution in vertical trend, which is in accordance with the regularities of petrophysical distributions from vertical wells, making up for the seismic low resolution in vertical direction. The research shows the fine structural and petrophysical modeling of the thin shale reservoirs, which provide the credible spatial distribution network and petrophysical properties for further modeling.
{"title":"Reservoir Modelling in the Shale Gas Reservoirs Based on Horizontal Wells and Seismic Inversion","authors":"S. Gai, Ai-lin Jia, Yunsheng Wei","doi":"10.2118/197330-ms","DOIUrl":"https://doi.org/10.2118/197330-ms","url":null,"abstract":"\u0000 The seismic vertical resolution is too low to identify the vertical boundary and petrophysical properties of the thin shale layers inside the target precisely. This study focuses on structural and petrophysical modeling of shale reservoirs based on horizontal wells and seismic inversion.\u0000 Combined seismic trend surface with the well tops on horizontal wells, we calculated the top and bottom surface of the target formation, and obtained the structural surface of each small layer according to the thickness percentage of each layer from few vertical wells. Ultimately, the structural model is made. The horizontal trend of the petrophysical properties can be controlled by the seismic inversion results. The vertical trend of the petrophysical properties can be controlled by well logs. Constricted by the linear combination weighting of the horizontal and vertical trend, the petrophysical model is established.\u0000 The results show that the trajectory of the horizontal well in the target layer is accurate, and the layers are not intersected. The thickness of each layer is relatively even in plane, which is basically the same as that of the vertical well, indicating the characteristics of shale stable deposition. The discrepancy between the thickness of each layer in the model and those of the vertical wells is very small, especially in the main production layer 1, less than 0.1m. With the linear combination weighting, petrophysical properties show the bimodal distribution in vertical trend, which is in accordance with the regularities of petrophysical distributions from vertical wells, making up for the seismic low resolution in vertical direction.\u0000 The research shows the fine structural and petrophysical modeling of the thin shale reservoirs, which provide the credible spatial distribution network and petrophysical properties for further modeling.","PeriodicalId":11328,"journal":{"name":"Day 4 Thu, November 14, 2019","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91144352","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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