J. Mandl, C. Mills, Eissa Al Obaidli, M. Basioni, K. A. Ali, Ahmed Yahya Al Blooshi, N. Belova, E. Arroyo
The offshore Field-A Gas Development Project is an integral part of the Abu Dhabi Deep Gas Project targeting untapped hydrocarbon reserves with priority given to gas reservoirs to satisfy an increasing gas demand and sustain economic growth of Abu Dhabi Emirate. Well test data from Field-A Khuff Formation cannot be modeled solely using a matrix based porosity system and requires the presence of fracture network to give a "mixed" porosity system to explain the observed flow test results. To assess this a subsurface study was initiated to incorporate fractures within the matrix porosity based 3D reservoir model and to examine different methods of populating fracture distributions across the geologic model. The ultimate aim of this work was to more accurately predict gas rates to better understand and mitigate rate uncertainties across a range of development scenarios.
{"title":"Impact of Natural Fractures in Reservoir Modelling and Characterization. Case Study in UAE","authors":"J. Mandl, C. Mills, Eissa Al Obaidli, M. Basioni, K. A. Ali, Ahmed Yahya Al Blooshi, N. Belova, E. Arroyo","doi":"10.2118/193316-MS","DOIUrl":"https://doi.org/10.2118/193316-MS","url":null,"abstract":"\u0000 The offshore Field-A Gas Development Project is an integral part of the Abu Dhabi Deep Gas Project targeting untapped hydrocarbon reserves with priority given to gas reservoirs to satisfy an increasing gas demand and sustain economic growth of Abu Dhabi Emirate.\u0000 Well test data from Field-A Khuff Formation cannot be modeled solely using a matrix based porosity system and requires the presence of fracture network to give a \"mixed\" porosity system to explain the observed flow test results. To assess this a subsurface study was initiated to incorporate fractures within the matrix porosity based 3D reservoir model and to examine different methods of populating fracture distributions across the geologic model. The ultimate aim of this work was to more accurately predict gas rates to better understand and mitigate rate uncertainties across a range of development scenarios.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73442198","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. Soufi, B. Prahawinarto, Fouad Abdussalam, Asif M. Khan, S. Ashour, P. Baudot, A. ElBarbary, Sheirf Salama
Gas Injector Well is part of the project to improve the pressure communication between peripheral gas injectors and nearby producers in the Northern Part of Unit G WAG Patterns. This well was injecting gas only to upper part of Unit G reservoir based on the PLT and TGT results. Based on the study using tracer chemical injection, this upper Unit G reservoir was found to be in connecting with another nearby different reservoir. The initial plan was to re-horizontalize the well and place injector in the proper reservoir, later this was changed and revised to use this innovation technology by installing blank liner with isolating packer to isolate the upper part of Unit G reservoir and let the lower part of open-hole remained open and connected to the required layer of reservoir. After extensive discussion with vendors and performing simulation runs, finally agreed to run this kind of swell packer. Vendor custom designed this kind of innovative packer at their USA facility and transported to ADNOC Onshore yard just before the execution phase. First run the swell packer on blank pipe and placed it at desired depth in the open hole, later run upper completions and sting into the top packer of lower completion. This way, we were able to inject gas into the lower part of reservoir Unit-G only, whereas the upper part was remained isolated completely. Using this technique saved company additional 2 million and extra time for re-horizontalization.
{"title":"Innovative Approach to Enhance Reservoir Sweeping Efficiency Using Open Hole Swellable Packers in Gas Injector to Isolate Undesired Reservoir Section in Carbonate Reservoir Field of Abu Dhabi, UAE","authors":"A. Soufi, B. Prahawinarto, Fouad Abdussalam, Asif M. Khan, S. Ashour, P. Baudot, A. ElBarbary, Sheirf Salama","doi":"10.2118/193045-MS","DOIUrl":"https://doi.org/10.2118/193045-MS","url":null,"abstract":"Gas Injector Well is part of the project to improve the pressure communication between peripheral gas injectors and nearby producers in the Northern Part of Unit G WAG Patterns. This well was injecting gas only to upper part of Unit G reservoir based on the PLT and TGT results. Based on the study using tracer chemical injection, this upper Unit G reservoir was found to be in connecting with another nearby different reservoir.\u0000 The initial plan was to re-horizontalize the well and place injector in the proper reservoir, later this was changed and revised to use this innovation technology by installing blank liner with isolating packer to isolate the upper part of Unit G reservoir and let the lower part of open-hole remained open and connected to the required layer of reservoir.\u0000 After extensive discussion with vendors and performing simulation runs, finally agreed to run this kind of swell packer. Vendor custom designed this kind of innovative packer at their USA facility and transported to ADNOC Onshore yard just before the execution phase. First run the swell packer on blank pipe and placed it at desired depth in the open hole, later run upper completions and sting into the top packer of lower completion.\u0000 This way, we were able to inject gas into the lower part of reservoir Unit-G only, whereas the upper part was remained isolated completely. Using this technique saved company additional 2 million and extra time for re-horizontalization.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"24 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78113034","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}
After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations. Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1,500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time. The results show increasing the regain permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regain permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The regain permeability was then increased with longer soaking time, as a result of reducing the chocking effect at the core inlet. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regain permeability on shale cores was 0.14 of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores. This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.
{"title":"Experimental Investigation for the Effect of the Soaking Process on the Regain Permeability After Hydraulic Fracturing in Tight Sandstone and Shale Formations","authors":"A. Ibrahim, H. Nasr-El-Din","doi":"10.2118/193123-MS","DOIUrl":"https://doi.org/10.2118/193123-MS","url":null,"abstract":"\u0000 After hydraulically fracturing of shale gas wells, theoretical and experimental studies showed that over 75% of the injected water-based fracture fluids left unrecovered. The trapped water causes permeability damage and productivity impairment. The flowback water also tends to be highly saline, often with TDS contents of as much as 200,000 ppm. This study aims to investigate the effect of well shut-in before flowback stage (the soaking process) on the production of shale and tight sandstone formations.\u0000 Shale and sandstone samples were analyzed by X-ray diffraction (XRD). Marcellus shale and Kentucky sandstone cores were used. A modified core flood setup was used to allow porosity measurements by gas expansion method, then pulse decay permeability measurements, and fluid injection during the leak-off process. Nitrogen was used for gas expansion and permeability measurements, while 5 wt% KCl brine was used as representative of leak-off fracturing fluid. The fracturing fluid was injected under a constant pressure gradient (300 in the case of sandstone cores and 1,500 psi in the case of shale cores. After removing the pressure gradient, gas permeability was measured at different soaking times. Computed tomography (CT) was used to scan the cores during the experiment to observe the propagation of fracturing fluid in the core with time.\u0000 The results show increasing the regain permeability for sandstone formation was 60% of its initial value directly after the leak-off stage. Then, the regain permeability decreased with increasing the soaking time 38% of its initial value after the core completely invaded with leak-off fluid. The regain permeability was then increased with longer soaking time, as a result of reducing the chocking effect at the core inlet. The propagation rate of water saturation front from CT-scan data decreased with time until reaching the core outlet. The regain permeability on shale cores was 0.14 of its initial value and decreased with soaking time, due to depressed relative permeability curve on this tight pore-space cores.\u0000 This study addresses the mechanism of production enhancement or reduction as a result of the soaking process for shale and tight sandstone formations.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"115 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79005308","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 is in continuation to SPE-187306- MS "Enhanced Oil Recovery - Polymer Flooding: Surface Transfer Facility Design, Graphical Approach for Hydraulics and Tackle Induced Vibrations," with core focus on induced vibrations in surface facilities and corresponding mitigating steps. Cairn Oil & Gas, vertical of Vedanta Limited, has implemented one of the largest Enhanced Oil Recovery Process (Polymer flood) for its Mangala field (in Rajasthan block). The current facility set up follows centralized polymer handling facility concept. This concept was found to be the most economic and it ensured an optimal utilization of the existing water flood network. Large volume of polymer injection requirement for Mangala polymer project drove the requirement of higher concentrated mother solution to reduce the Central Polymer Facility (CPF) plant size. The CPF is among one of the largest centralized polymer solution preparation facilities in the world, producing 80,000 barrels of polymer mother solution at 15,000 ppm concentration. The concentrated polymer solution (mother solution) is transferred from the CPF to the various existing well-pads (15 nos.) via a pipeline distribution. The mother solution transfer pipeline network is of over 15 km. Once at the well pads the concentrated polymer solution (mother solution) is diluted with the injection water at a specific dilution ratio. The diluted solution is then injected into the individual wells through the existing injection water lines after boosting the pressure. However, post Mangala EOR commissioning some piping system failures have been experienced in polymer solution facility. These failures are largely attributed to vibration induced fatigue and arose both, at the suction and discharge lines of the Positive Displacement polymer Injection Pumps. The vibration is attributed mainly to the visco-elastic nature of the polymer fluid. The paper covers the issue through following steps: Evaluating the vibration effect on surface facilities and equipment due to polymer fluid rheology Identifying, in detail, the sections of surface facility susceptible to equipment failure and performance loss. Presenting lessons learnt based on field experience Qualifying effective design solutions to address the issues of flow induced vibration Establishing the efficacy of the recommendations through performance evaluation post on-site design modification
{"title":"Polymer Flooding: Surface Facility Design for Mitigating Induced Vibrations and On-field Performance Validation","authors":"Shagun Jain, K. Vasavada","doi":"10.2118/192609-MS","DOIUrl":"https://doi.org/10.2118/192609-MS","url":null,"abstract":"\u0000 This paper is in continuation to SPE-187306- MS \"Enhanced Oil Recovery - Polymer Flooding: Surface Transfer Facility Design, Graphical Approach for Hydraulics and Tackle Induced Vibrations,\" with core focus on induced vibrations in surface facilities and corresponding mitigating steps.\u0000 Cairn Oil & Gas, vertical of Vedanta Limited, has implemented one of the largest Enhanced Oil Recovery Process (Polymer flood) for its Mangala field (in Rajasthan block). The current facility set up follows centralized polymer handling facility concept. This concept was found to be the most economic and it ensured an optimal utilization of the existing water flood network. Large volume of polymer injection requirement for Mangala polymer project drove the requirement of higher concentrated mother solution to reduce the Central Polymer Facility (CPF) plant size. The CPF is among one of the largest centralized polymer solution preparation facilities in the world, producing 80,000 barrels of polymer mother solution at 15,000 ppm concentration.\u0000 The concentrated polymer solution (mother solution) is transferred from the CPF to the various existing well-pads (15 nos.) via a pipeline distribution. The mother solution transfer pipeline network is of over 15 km. Once at the well pads the concentrated polymer solution (mother solution) is diluted with the injection water at a specific dilution ratio. The diluted solution is then injected into the individual wells through the existing injection water lines after boosting the pressure.\u0000 However, post Mangala EOR commissioning some piping system failures have been experienced in polymer solution facility. These failures are largely attributed to vibration induced fatigue and arose both, at the suction and discharge lines of the Positive Displacement polymer Injection Pumps. The vibration is attributed mainly to the visco-elastic nature of the polymer fluid.\u0000 The paper covers the issue through following steps:\u0000 Evaluating the vibration effect on surface facilities and equipment due to polymer fluid rheology Identifying, in detail, the sections of surface facility susceptible to equipment failure and performance loss. Presenting lessons learnt based on field experience Qualifying effective design solutions to address the issues of flow induced vibration Establishing the efficacy of the recommendations through performance evaluation post on-site design modification","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"78 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77200216","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}
Plant safety remains a number 1 Priority for all operating companies especially in the Oil & Gas segments, with many companies publishing goals of zero incidents or accidents. In very simple terms, it’s all about managing risk. If you do it well, it leads to profit. If you don’t, then it can lead to losses. Defining & Implementing performance monitoring & management systems to achieve the above-mentioned goals has been the primary focus of our industry and our efforts can broadly be divided in two distinct buckets. Occupational safety: Primarily can be summarised to include Protection of the Personal present near the hazard and therefore includes procedures for protecting personnel from trips, falls or handling hazardous materials, and working at heights.Functional safety: This arena arose from the need to avoid large-scale industrial disasters and involves the safeguards required to manage and mitigate hazards, assess possible consequences and risks, and determine a required level of protection. Today international standards such as IEC 61511, IEC 61508, ISA S84, and others are widely adopted and considered best practice in the industry. They provide a performance-based framework for the design, implementation, and operation/maintenance of automated safeguards, including safety instrumented systems (SIS) such as emergency shutdown systems (ESD), alarm functionality of the distributed control system (DCS), burner management systems, and other automation and control technology geared toward safe operations. But regardless of how well-designed these safeguarding systems are, they can only ever be fully effective if operated and maintained according to their design criteria over the entire operational life of the plant. Growing awareness of this fact has given rise to a newer discipline of process safety management (PSM). Why pursue improvements in safety in addition to the fact that human life and health should be safeguarded at all times? Evidence is beginning to emerge that companies with good process safety realize significant direct cost benefits.
{"title":"Digitalization of Safety Lifecycle Compliance for Operational Excellence.","authors":"Y. Kapadia, S. Elliott","doi":"10.2118/193107-MS","DOIUrl":"https://doi.org/10.2118/193107-MS","url":null,"abstract":"\u0000 Plant safety remains a number 1 Priority for all operating companies especially in the Oil & Gas segments, with many companies publishing goals of zero incidents or accidents. In very simple terms, it’s all about managing risk.\u0000 If you do it well, it leads to profit. If you don’t, then it can lead to losses.\u0000 Defining & Implementing performance monitoring & management systems to achieve the above-mentioned goals has been the primary focus of our industry and our efforts can broadly be divided in two distinct buckets. Occupational safety: Primarily can be summarised to include Protection of the Personal present near the hazard and therefore includes procedures for protecting personnel from trips, falls or handling hazardous materials, and working at heights.Functional safety: This arena arose from the need to avoid large-scale industrial disasters and involves the safeguards required to manage and mitigate hazards, assess possible consequences and risks, and determine a required level of protection. Today international standards such as IEC 61511, IEC 61508, ISA S84, and others are widely adopted and considered best practice in the industry. They provide a performance-based framework for the design, implementation, and operation/maintenance of automated safeguards, including safety instrumented systems (SIS) such as emergency shutdown systems (ESD), alarm functionality of the distributed control system (DCS), burner management systems, and other automation and control technology geared toward safe operations.\u0000 But regardless of how well-designed these safeguarding systems are, they can only ever be fully effective if operated and maintained according to their design criteria over the entire operational life of the plant. Growing awareness of this fact has given rise to a newer discipline of process safety management (PSM). Why pursue improvements in safety in addition to the fact that human life and health should be safeguarded at all times? Evidence is beginning to emerge that companies with good process safety realize significant direct cost benefits.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"2022 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82507096","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 considerable number of fixed offshore platforms around the world have either already surpassed their design life or are approaching it. In the Middle East, more than 70% of the platforms are operating for more than 25 years; some of the assets are even operating for more than 40 years. High oil price and advancement in technology planned to increase the productivity of reservoirs have led to significant investment in terms of cost and resource to manage these assets. There is still a lot of recoverable oil and gas in the reservoirs hence, there is an increased need to extend the life of these facilities while managing the associated risk. This technical paper details a methodology for assessment of remaining life and details some of the degradation/ life extension issues for fixed offshore assets. As it is extremely difficult to cite all the degradation issues, some of the critical degradation issues based on experience and knowledge has been covered in this paper.
{"title":"Integrity and Life Extension Assessment of Fixed Offshore Platforms","authors":"V. Shanker","doi":"10.2118/193137-MS","DOIUrl":"https://doi.org/10.2118/193137-MS","url":null,"abstract":"\u0000 A considerable number of fixed offshore platforms around the world have either already surpassed their design life or are approaching it. In the Middle East, more than 70% of the platforms are operating for more than 25 years; some of the assets are even operating for more than 40 years. High oil price and advancement in technology planned to increase the productivity of reservoirs have led to significant investment in terms of cost and resource to manage these assets. There is still a lot of recoverable oil and gas in the reservoirs hence, there is an increased need to extend the life of these facilities while managing the associated risk. This technical paper details a methodology for assessment of remaining life and details some of the degradation/ life extension issues for fixed offshore assets. As it is extremely difficult to cite all the degradation issues, some of the critical degradation issues based on experience and knowledge has been covered in this paper.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"59 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83996267","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}
Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified. It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed. The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity. This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.
{"title":"A Novel Dynamic Assessment of Multi-Stage Hydraulic Fracture Propagation in Presence of Natural Fractures in Shale Gas Reservoirs","authors":"A. Suboyin, Motiur Rahman, M. Haroun, A. Shaik","doi":"10.2118/192811-MS","DOIUrl":"https://doi.org/10.2118/192811-MS","url":null,"abstract":"\u0000 Augmented by the recent activities in unconventional reservoirs, it can be easily said that hydraulic fracturing has become a pivotal component for the successful development of unconventional reservoirs. This novel study deals with the investigation of fracture propagation behavior in shale gas reservoirs under varying controllable and non-controllable parameters. In addition to the analysis of propagation behavior, their interaction in the presence of natural fractures are reviewed and quantified.\u0000 It is highly challenging to quantify and address the distinct contributions of an element due to the level of heterogeneity that is present in reservoirs. In-situ stress has been reported to be such a dominant contributor to the fracture propagation behavior as they are imperative to assess the extent and the direction of fractures. An enhanced dynamic simulation was conducted to investigate fracture propagation behavior in shale gas reservoirs under varying parameters which were categorized as controllable and non-controllable with respect to the fracture design, treatment and drilling process. After an extensive assessment, a set of natural fractures were introduced to the system and the system behavior was further analysed.\u0000 The constructed model is verified with traditional and published models to validate the generated results. It is illustrated that even modest variations of the associated principal stresses between the target zones and the bounding zones can severely limit hydraulic fractures. Further simulation runs under varying fluid conditions and its associated properties revealed similar observations. With the introduction of natural fractures, it is demonstrated that the distribution of the natural fracture network plays a critical role in the cumulative gas production along with its description. Additional investigation illustrates and verifies that fracture width assists in better performance as compared to fracture length for the defined conditions. Fracture placement along with its orientation and proppant properties are also considered to further examine the associated response on productivity.\u0000 This novel investigative approach will create a paradigm for future studies that will assist in a simplified prediction of fracture propagation behavior, its associated drilling parameters and anticipated response. In addition, an extensive investigation for the quantification of changes with respect to the variation in prime contributors is presented, which assists in the validation of modern best practices approach.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"17 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82736784","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}
Design of deepwater Subsea Control & Umbilical Systems is a challenging process subject. Challenges are emerging from subsea flow assurance ever demanding requirements as well as control and data transmission implications through long step-out. Zohr project Accelerated Start-up Phase FEED design adopted a Centre Control Platform (CCP) to accommodate the chemical injection, power & control Topsides facilities feeding and controlling subsea equipment at different drill centres through umbilical network. Subsea control is based on enabling multiplexed electrohydraulic Subsea Production Control System (SPCS) with Fiber Optic (FO) communication. Control of each drill centre is independent based on segregated power and data transmission scheme. The development adopted tight schedule due to the significance to country economics. Chemical Injection and control with related data transmission through very long step-out umbilical has demonstrated to be a complex job in terms of assuring reliable connection of the CCP with subsea equipment located about 160km far away from the CCP. This complexity is merited to tight coupling between SPCS, umbilical system and installation engineering. Also, the heavy impact of failure downtime attributed to production loss along with increasing cost of intervention has significant footprint on every design aspect. The current paper highlights a Fast-Track parallel design approach for very long step-out subsea development based on Zohr project achievements. With the tight schedule and massive amount of material involved in umbilical manufacturing (i.e. 2.2millions meter cables, 2million meter of tubes, and 2.7 million meter of fillers), any change after umbilical purchase order issuance will have significant impact on project execution and will probably put the project schedule into major risk. The traditional relay-based design scheme is replaced with an approach minimising the dependency of Umbilical Design on SPCS and Installation engineering. The criticalities include impact of power distribution/sparing scheme on electrical cables configuration and design of Umbilical Termination Assembly. Also, the work covers FO link budget design challenges, need for midway repeater and related impact on connection design between main umbilical sections. The proposed approach is supported with conservative deployment scheme to eliminate installation risks. Finally, the paper will conclude with a summary for key aspects to be taken into consideration during FEED in case of very-long step-out projects. Very-long step-out subsea field development projects being limited worldwide, the work will be valuable reference for similar future projects as being handling technicality from project management perspective.
{"title":"Very Long Step-out Subsea Umbilical Fast-Track Design Approach based on Zohr Experience","authors":"S. Elsabbagh, Hesham Elkhafif","doi":"10.2118/192661-MS","DOIUrl":"https://doi.org/10.2118/192661-MS","url":null,"abstract":"\u0000 Design of deepwater Subsea Control & Umbilical Systems is a challenging process subject. Challenges are emerging from subsea flow assurance ever demanding requirements as well as control and data transmission implications through long step-out. Zohr project Accelerated Start-up Phase FEED design adopted a Centre Control Platform (CCP) to accommodate the chemical injection, power & control Topsides facilities feeding and controlling subsea equipment at different drill centres through umbilical network. Subsea control is based on enabling multiplexed electrohydraulic Subsea Production Control System (SPCS) with Fiber Optic (FO) communication. Control of each drill centre is independent based on segregated power and data transmission scheme. The development adopted tight schedule due to the significance to country economics.\u0000 Chemical Injection and control with related data transmission through very long step-out umbilical has demonstrated to be a complex job in terms of assuring reliable connection of the CCP with subsea equipment located about 160km far away from the CCP. This complexity is merited to tight coupling between SPCS, umbilical system and installation engineering. Also, the heavy impact of failure downtime attributed to production loss along with increasing cost of intervention has significant footprint on every design aspect.\u0000 The current paper highlights a Fast-Track parallel design approach for very long step-out subsea development based on Zohr project achievements. With the tight schedule and massive amount of material involved in umbilical manufacturing (i.e. 2.2millions meter cables, 2million meter of tubes, and 2.7 million meter of fillers), any change after umbilical purchase order issuance will have significant impact on project execution and will probably put the project schedule into major risk. The traditional relay-based design scheme is replaced with an approach minimising the dependency of Umbilical Design on SPCS and Installation engineering.\u0000 The criticalities include impact of power distribution/sparing scheme on electrical cables configuration and design of Umbilical Termination Assembly. Also, the work covers FO link budget design challenges, need for midway repeater and related impact on connection design between main umbilical sections. The proposed approach is supported with conservative deployment scheme to eliminate installation risks.\u0000 Finally, the paper will conclude with a summary for key aspects to be taken into consideration during FEED in case of very-long step-out projects. Very-long step-out subsea field development projects being limited worldwide, the work will be valuable reference for similar future projects as being handling technicality from project management perspective.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"69 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89562662","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}
Permeability is one of the most important parameters that is required in reservoir simulation, field development, and reservoir management. An innovative permeability derivation method and workflow has been developed using Stoneley wave attenuation mechanism (not Stoneley wave velocity as discussed in some previous studies). The workflow was applied to the sonic waveform data acquired from a vertical well in a giant carbonate field in Middle East. The workflow includes (a) extraction of Stoneley-wave attenuation rigorously from the waveform data, and (b) fast inversion from Stoneley-wave attenuation to permeability. Validation of the method and workflow were performed by comparing the results with core permeability and MDT mobility data. Results from this application indicate that low-frequency monopole waveforms provide good quality Stoneley wave data, and that Stoneley wave attenuation responds to permeability changes. The Stoneley-wave attenuation log extracted from the low-frequency monopole waveforms shows variability, and the permeability log obtained using the inversion workflow through different reservoir intervals has a good overall correlation with core permeability. The main reservoir interval is over 100 feet thick. Porosities are generally high throughout the interval, but permeabilities vary by several orders of magnitude due to pore type changes. The Stoneley wave attenuation permeability trend corresponds very well to vertical changes in the dominant pore system. Stoneley-derived permeabilities distinguish between microporosity in lower section with permeabilities in 1-20 millidarcy range, and mixed-pores in the upper section with permeabilities in the 10's to 100's of millidarcy range. The sonic permeability is also picking up tight streaks (stylolite zones with cementation) that have low porosity and permeability and can act as flow baffles within the reservoir. These results show that Stoneley wave attenuation is responding to changes in carbonate pore systems, and that Stoneley-derived permeabilities can provide useful permeability estimates in the absence of core data.
{"title":"Permeability Derivation from Sonic Stoneley Wave Attenuation Measurements: Application in a Giant Carbonate Field from Middle East","authors":"H. Yin, Xianyun Wu, L. Yose","doi":"10.2118/193291-MS","DOIUrl":"https://doi.org/10.2118/193291-MS","url":null,"abstract":"\u0000 Permeability is one of the most important parameters that is required in reservoir simulation, field development, and reservoir management. An innovative permeability derivation method and workflow has been developed using Stoneley wave attenuation mechanism (not Stoneley wave velocity as discussed in some previous studies). The workflow was applied to the sonic waveform data acquired from a vertical well in a giant carbonate field in Middle East. The workflow includes (a) extraction of Stoneley-wave attenuation rigorously from the waveform data, and (b) fast inversion from Stoneley-wave attenuation to permeability.\u0000 Validation of the method and workflow were performed by comparing the results with core permeability and MDT mobility data. Results from this application indicate that low-frequency monopole waveforms provide good quality Stoneley wave data, and that Stoneley wave attenuation responds to permeability changes. The Stoneley-wave attenuation log extracted from the low-frequency monopole waveforms shows variability, and the permeability log obtained using the inversion workflow through different reservoir intervals has a good overall correlation with core permeability. The main reservoir interval is over 100 feet thick. Porosities are generally high throughout the interval, but permeabilities vary by several orders of magnitude due to pore type changes. The Stoneley wave attenuation permeability trend corresponds very well to vertical changes in the dominant pore system. Stoneley-derived permeabilities distinguish between microporosity in lower section with permeabilities in 1-20 millidarcy range, and mixed-pores in the upper section with permeabilities in the 10's to 100's of millidarcy range. The sonic permeability is also picking up tight streaks (stylolite zones with cementation) that have low porosity and permeability and can act as flow baffles within the reservoir. These results show that Stoneley wave attenuation is responding to changes in carbonate pore systems, and that Stoneley-derived permeabilities can provide useful permeability estimates in the absence of core data.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74980853","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. A. Siddiqui, Syed Saadat Hassan, Muhammad Mubasher, Saqib Latif, Usman Anjum Dar
The objective of writing this success story is to demonstrate how technology, in particular low cost solutions, are key to economically sustain and secure production from mature fields. Tubing Patch technology has been successfully utilized in Pakistan for the first time to restore the well integrity and saved huge CAPEX by avoiding expensive rig workover. Tubing-Annulus pressure suddenly increased in one of water disposal well (WDW). Annulus pressure varied directly with variations in Injection rates which were the clear evidence that tubing-annulus communication had been established and basic check ascertains that well had integrity issue. Being the only injector in area all production and processing of gas is majorly dependent on its injection reliability and integrity. After detailed in-house working it was decided to run diagnostic logging with spinner (quantitative) & temperature log (qualitative) to identify the leakage points precisely. All potential leakage paths (packer, tubing, tool joints) were considered while selecting the diagnostic techniques to have conclusive results. Based on diagnostic logging three leakage points were identified. Before proceeding for remedial measures to restore the well integrity, it was mandatory to check health of old carbon steel tubing string therefore it was planned to acquire corrosion log. Based on corrosion logging results, completion tubular was established in good condition which steered to install tubing patches best Techno-Economical solution across the leaks to restore well integrity instead of rig workover for re-completion. Consequently, three tubing patches, were successfully applied using wireline in water disposal well and integrity of well was restored. C-Annulus was pressure tested even after six months of installation and no pressure drop was observed during this interval.
{"title":"Successful Installation of Tubing Patches to Restore Well Integrity Leads to Remarkable CAPEX Saving at Water Disposal Well WDW","authors":"M. A. Siddiqui, Syed Saadat Hassan, Muhammad Mubasher, Saqib Latif, Usman Anjum Dar","doi":"10.2118/193062-MS","DOIUrl":"https://doi.org/10.2118/193062-MS","url":null,"abstract":"\u0000 The objective of writing this success story is to demonstrate how technology, in particular low cost solutions, are key to economically sustain and secure production from mature fields. Tubing Patch technology has been successfully utilized in Pakistan for the first time to restore the well integrity and saved huge CAPEX by avoiding expensive rig workover.\u0000 Tubing-Annulus pressure suddenly increased in one of water disposal well (WDW). Annulus pressure varied directly with variations in Injection rates which were the clear evidence that tubing-annulus communication had been established and basic check ascertains that well had integrity issue. Being the only injector in area all production and processing of gas is majorly dependent on its injection reliability and integrity. After detailed in-house working it was decided to run diagnostic logging with spinner (quantitative) & temperature log (qualitative) to identify the leakage points precisely. All potential leakage paths (packer, tubing, tool joints) were considered while selecting the diagnostic techniques to have conclusive results. Based on diagnostic logging three leakage points were identified. Before proceeding for remedial measures to restore the well integrity, it was mandatory to check health of old carbon steel tubing string therefore it was planned to acquire corrosion log. Based on corrosion logging results, completion tubular was established in good condition which steered to install tubing patches best Techno-Economical solution across the leaks to restore well integrity instead of rig workover for re-completion.\u0000 Consequently, three tubing patches, were successfully applied using wireline in water disposal well and integrity of well was restored. C-Annulus was pressure tested even after six months of installation and no pressure drop was observed during this interval.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74340306","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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