Introduction:The Craig Hospital Inventory of Environmental Factors instrument (CHIEF) is one of the few tools to assess the environmental barriers. The purpose of this study was to translate long and short CHIEF into Hindi language, and to determine its validity and reliability.Design and Setting:The study design was observational case series with repeated measures. It was carried out at Indian Spinal Injuries Centre New Delhi, a specialized center for rehabilitation for spinal cord injury.Methods:The CHIEF instrument was translated from English to Hindi based on the Beaton guidelines for the cross-cultural adaptation of health status measures. The Hindi version of the CHIEF instrument was then administered on a convenience sample of 30 spinal cord injured subjects. Its content validity, internal consistency, test-rest reliability (intraclass correlation coefficient [ICC] 2,1), standard error of measurement (SEM), and minimum detectable change (MDC) were determined for both the longer and shorter version.Results:The mean ± SD of total of Hindi-CHIEF instrument, longer version was 1.44 ± 0.82 and total score of the shorter version was 1.07 ± 0.66. The content validity determined by the content validity ratio was found to be 1 for all the items except item number 5, 11, and 12. The content validity index was 0.97 for the longer version and for the shorter version it was 0.98. Internal consistency, Cronbach's α value was found to be 0.92 and test-retest value (ICC 2,1) was 0.80 (P < 0.001). The MDC was found to be 0.99 and SEM was 0.36 for the longer version. The Cronbach's α was 0.731, ICC 2,1 was 0.63 (P < 0.001), SEM was 0.24, and MDC was 0.66 for the shorter version.Conclusion:The Hindi translated version of the CHIEF scale has acceptable content validity and reliability. It can be used to assess environmental barriers perceived by spinal cord injury patients.
This paper discusses business intelligence algorithms and data analytics capabilities of an integrated digital production platform implemented in a giant gas condensate field. The advanced workflow focuses on helping the user navigate through the bulk of data to identify patterns and make predictions utilizing exception-based intelligence alarming. This helps derive insightful findings and provides recommendations for users to make efficient business decisions for achieving field potential optimization objectives. An Integrated digital production platform within a giant gas condensate field is implemented with numerous production optimization workflows encompassing daily well and facility performance monitoring and surveillance. The data integration within the systems is enhanced by integration with powerful Business Intelligence (BI) tools, enabling users to create customized dashboards, KPI screens, and exception-based alarm screens. An additional integration to the production platform is carried out with data from real-time sources like PI Asset Framework and corporate databases, improving the integrated production system's daily well and facility surveillance capabilities. The advanced integration of BI tools provided users with various opportunities to identify bottlenecks, production improvement chances, and troubleshooting areas by capitalizing insights from various dashboards and business KPI screens. Further, integrating these dashboards with several corporate data sources and a real-time asset data framework enabled users to harness maximized information embedded in the bulk of data. This also enabled end-users to harness maximized system potential, with all information available under a single collaborative platform. The integration powered by various inbuilt complex algorithms extended scripting capabilities, and enhanced visualization assisted the asset in realizing business KPIs requirements. Business intelligence algorithms in user interface established a drill-down approach to utilize information associated with multiple variables on top of one another. This allowed for the quick identification of trends and patterns in data. The customization approach helped the user to draw maximum information out of data as per their engineering requirements and current practices. This advanced integration facilitated users to minimize their efforts in traditional data analysis such as gathering, mapping, filtering, and plotting. With the help of these powerful features embedded in an integrated platform, the user was able to drive more focus on optimization and minimize time and effort on system configuration. This unique integration was one of its kind. An online integrated digital production platform comprising of wells, networks, and various workflows was integrated with business intelligence tools, thereby providing end-users tremendous opportunities related to system optimization.
Integrated asset modeling, application of big data, and automation are among the top emerging trends in the oil and gas industry. The value associated with such implementation projects is very closely linked with the efficient use of the project management approach and a robust strategy to handle the technological challenges. This paper puts light on such initiatives implemented in a giant gas field. In this giant gas condensate field, a vast amount of data is generated and monitored on a daily basis. The frequent need to deliver the dynamic production target was driving this project implementation so that a value-driven system can be established while achieving the business KPIs. A phased approach was used to target multiple requirements into business deliverables where the early offline phases provided a robust base for full online integration. This project followed the agile approach focusing on getting insights from multiple stakeholders and domain experts and developing a lesson-learnt repository in all the project phases. The online integration solution is a critical differentiator in the workforce and process efficiency improvement. The multiple technical solution workflows helped in reducing manual efforts and streamlining the methodology in a standardized fashion. In addition, the standard project management practices, such as initializing the phases in a planned manner, followed by an interactive execution, monitoring, and controlling stages, ensured delivering project outcomes in an efficient way. This implementation also established a robust collaborative team effort to identify various different roles and responsibilities for stakeholders. This helped in the end phase when the project sustainability was essential. A strong team base maintained and updated the integrated system while delivering daily well and facility surveillance objectives and KPIs from users ranging from planning, engineering, operation, and management team. A special focus on IT team involvement throughout the project phase led to a successful data integration and diagnostic, as the core of the solution was a data-driven analytical framework integrated with multiple corporate and real-time data sources. In addition, this solution was equipped with various one-of-its-kind solution features such as business intelligence, advanced surveillance, dynamic-reservoir integration, manage-by-exception workflows, intelligence alerts, along with a strong digital framework and data architecture. The unique hybrid and agile project management approach focusing on delivering emerging trends and technologies to end-users in the most efficient way paved the way for achieving asset digitalization and standardization goals.
This paper demonstrates the use of an integrated production optimization platform to determine the well performance for gas condensate wells in a statistical approach to increase the data accuracy for reservoir studies, simulate the field limitations, and provide recommendations for production optimization in a multilayered large carbonate reservoir field. This case involves wells under recycle and natural decline with challenges in the evaluation of well performance where the bulk of the information is available in multiple data sources The first elemental block in establishing the well performance of a gas condensate well is to determine and simulate its fluid behavior. Based on the PVT reports and subsurface fluid studies, compositional PVT models are built and matched with experimental data analyzing representative phase envelop properties and relevant Equation of State (EOS). The next step incorporates the utilization of representative physics-based well models in an integrated system to determine the reservoir and well deliverability. Finally, by applying a detailed statistical approach to the production well test history, models are calibrated in order to predict the performance of the gas condensate wells. Tuning of compositional PVT models established the EOS to be incorporated in predicting the fluid behavior and integrating representative PVT models with well models to determine such behavior along the fluid path. Using the statistical approach, the poor well measurements were identified, facilitating the well-performance and deliverability calculation. In addition, the use of representative models helped in increasing the accuracy of identifying well performance. During this study, two different methodologies were identified based on the reservoir management guidelines. Firstly, for the recycle reservoir in which, the decline of reservoir pressure is arrested using gas Injection. Secondly, for the depletion reservoir, in which the reservoir pressure declines rapidly. For the recycle reservoir, it was statistically identified that the reservoir pressure was declining at less than 4%. Therefore, the acceptance criteria for the operating envelope for each well was defined using the reservoir decline of less than 4%. Similarly, for the depletion reservoir, the pressure was declining between 7% and 10%. Thus, the operating envelope's acceptance criteria were defined using the max reservoir decline tolerance of 10%. The above-identified criteria were incorporated into the integrated model framework to validate the well performance generated from the well tests. Implementing this specialized engineering approach in an integrated model framework considerably reduces the time required by engineers to validate the production well tests and provides higher levels of accuracy for production optimization, voidage replacement ratio calculation, daily rate estimation, and surveillance.
Digital oil fields have seen major advancements over the past ten years, with the goal of integrating and optimizing the loops of production operation, production optimization, well and reservoir surveillance based on real-time data and model-based workflow automation capabilities. This paper discusses how ADNOC onshore has successfully implemented model-based digital oil field workflows in all its producing fields and describes the process of migrating these workflows to a data-driven platform for improved decision making. In the existing workflows, data-driven diagnostic analytics are applied to validate well performance and accelerate the process of identifying underperforming wells and inefficiencies. These data-driven diagnostic analytics were implemented on a digital oilfield workflow platform where data is aggregated from disparate data sources consisting of non-real time well data, well events, well test history, MPFM, interpreted PTA, reservoir simulation, well integrity and wells tie-in data, along with continuous real-time sensor and model-generated data. The analytics are mapped with workflows and asset hierarchy. The linear regression method is used to forecast trends for water cut and GOR based on historical data. Diagnostic analytics have been successfully configured for a giant onshore field having more than a thousand wells and multiple reservoirs. The alarm diagnostic map is generated based on tolerance and difference with exceptions. The solution framework has a common data abstraction layer and integration. A built-in visualization engine allows customization based on user preferences, linking multiple screens and analytics. Well test validations are improved for non-instrumented wells by using diagnostic based on more than 10 years of well test history. Well level allocation analytics allow comparisons between real-time export meter and terminal figures at the same timestamp, based on well models. For model calibration, wellhead pressure estimation from the last valid model was introduced. Well surveillance and management diagnostic analyze wells which are operating on critical/sub-critical condition and increasing water cut based on models and measured data. The combination of reservoir simulation data, PTA, bottom-hole surveys and estimated data from well models provides insights to validate quality of simulation data and reduce uncertainty in well models. Compartment and reservoir-wise VRR diagnostic enable asset operators to take faster remedial actions for reservoir performance management. These analytics complemented traditional model-based automated workflows for identifying wells for optimization. A digital oilfield solution platform has been leveraged to implement diagnostic analytics in the first phase and to provide a road map to migrate it to next-generation data-driven platform that has more predictive capabilities. This paper discusses solutions and data integration frameworks, analytics visualization, integration with model-based workflows, value cases and the road map ahead.
This paper elaborates on the concept of successfully applying one combined platform that includes gas condensate dynamic simulation models, surface network, and individual well models interacting and running sequentially within a closed loop. The study also highlights the value created by integrating dynamic modelling, simulation data, history matching (covering gas condensate reservoirs consisting of gas producers and injectors under the recycle mode) with continuously calibrated well and network models, thereby allowing end-users to make the best use of an integrated system for their dynamic production forecasting. The dynamic reservoir integration methodology incorporates as a first step the data coming from the reservoir simulator model as the main source of reservoir parameters to build a comprehensive system for enhancing production forecasting profiles. In an automatic routine, the simulation data provides the Inflow Performance Relationship, which gets transferred to the well's models, so a well performance curve (WPC) can be generated automatically. Once the latter is generated, it gets transferred to a recycle production-injection network model where a user-configured surface network scenario optimizes in an IAOM (Integrated Asset Operation Model) environment to calculate the rates corresponding to each well taking into consideration distinct constraints. The rates generated are transferred back to the reservoir simulator as well control parameters to initialize the next step of the loop and begin the process under updated conditions. The number of steps, termed as the schedule of the run, are determined by the user based on the forecasting objectives. From the practical point of view, this dynamic reservoir integration mainly targets at getting the best possible assessment from the available data, assumptions, and constraints. The value generated by having a dynamic integration, including all main components of the field/reservoir production, initially relies on the accurate understanding of the dynamic behavior of the hydrocarbon reservoir in order to predict future performance under different development and production approaches. There are several reasons why an integrated approach proved to have strong value creation: Reliable evaluation of the entire production system from reservoir to processing facilities. Continuous assessment of well and network performance. Verifying consistency of data reducing uncertainties. Minimizing underlying assumptions and constraints. It is worth mentioning that during this implementation, the entire system employed compositional models where a high number of components and pseudo components were part of the system, and the thermodynamic behavior added further rigor to the overall calculations. This advanced methodology of carrying out dynamic integration of surface to sub-surface in a production platform framework enhances various key factors of numerical simulation, such as run time estimation, optimal incorporation of surface parameters, identifying gaps between the surface and sub-surface system and enabling the user to perform key business scenarios in an efficient and flexible workflow-based production platform system.
This paper describes an efficient, accurate, and timesaving approach for setting well allowable using advanced and automated workflows in a digital oil field with more than 300 producing and injecting strings from multi-layered reservoirs having varied reservoir characteristics. This paper provides an insight on the usage of ADNOC shareholders guidelines, well characteristics, surface facility constraints, and integrated asset models to compute the well allowable rate. An integrated asset operations model (IAOM) within a digital framework provides an automation of engineering approach where shareholder/reservoir management guidelines, in conjunction with a calibrated well and network models, are used to improve efficiency and accuracy of setting wells allowable. This process incorporates the interaction among various components, including wellbore dynamics (Inflow and outflow performance), surface network backpressure effect, and complex system constraints. "System Efficiency and Well Availability" factors as well as predicted well parameters such as GOR and watercut. This advance workflow computes the rate that can be delivered from each well corresponding to each guideline and constraint, thereby providing key inputs to various business objective scenarios for production efficiency improvement. This automated "Setting Well Allowable" workflow, using an IAOM solution in a digital framework, has enabled the asset to identify true potential of wells and overcoming potential challenges of computational time saving while identifying opportunities. This automated validation workflows ensured usage of updated and validated well models, allowing effective use of the well test information and real time data for further analysis and sensitivities. The use of the automated workflow has reduced the time to compute the well allowable rates and well technical rates by more than 50%. This workflow prevented engineers from performing tedious manual calculations on a well-by-well basis, therefore engineers focus on engineering and analytical problems rather than collecting data. Additionally, this robust engineering approach provides users with key information associated with a well's performance under various guideline index such as potential rates, well technical rate, minimum backpressure rate, rate to maintain drawdown/ minimum bottom hole pressure limit to ensure a homogenous reservoir withdraw to avoid pressure sink areas. This work process also highlights the wells with increased watercut (WC) and gas oil ratio (GOR), thus providing crucial information for deteriorating well performance. A short-term forecasting with diagnostic curve fitting and trend analysis enabled users to validate deliverability of allowable rates in a calibrated network model scenario, thereby incorporating potential surface constraints and facility bottlenecks. The robustness of advanced and automated setting of well allowable workflow enables the operator to establish well performance with a solid engineering analysis base, and thereby unlocks key opportunities for saving cost, computational time and assuring short-term production mandate deliverables. This approach supports standardization of the work process across the whole organization.
This paper demonstrates the successful implementation of an advanced integration of production system for well and facility surveillance, which incorporates the utilization of automated workflows, intelligent exception-based dashboards and KPI (Key Performance Indicator) screens for a giant gas condensate field for a major E&P operator. The incorporated case studies highlight how analytical tools, automation, and data integration enable proactive evaluation of the facility surveillance and reservoir management strategy, thereby supporting efficient and faster decision-making to achieve the desired target while extending the life of the wells. In the current scenario, strong and effective reservoir management demands continuous, rigorous, and proactive reservoir surveillance tools. An intelligent integrated production optimization framework is being utilized as a single platform to combine information, processes, and multidisciplinary knowledge in a systematic and efficient manner. This allows management and end-users to proactively maintain engineering focus on problematic wells diagnostic and opportunity generation that support the execution of the business plan in a more coherent and reliable fashion. Using the real-time measurements in conjunction with an IAOM (Integrated Asset Operation Model) framework and collaborative feedback from the engineers, intelligent dashboards, and screens were designed to highlight the well and facility-related problems and highlighting decremental well behavior or facility bottlenecks. Most of the intensive computational technical calculation and data aggregation from different sources, such as well testing and real-time production and injection measurements, are integrated with automatic workflows and displayed in visualization dashboards; thus, users can carry out purposeful analysis utilizing information in processed data to realize potential value. These dashboards measure the true well and facility performance towards operational objectives and production targets. Intelligent KPIs also helps in identifying well health-status, potential risks, and mitigate them for continuous improvement of short- and long-term recovery factors to obtain an optimum reservoir energy balance daily. In case of unexpected well performance behaviors, the dashboards provide crucial data insights, highlighting the root cause of bottlenecks. Additionally, the integrated models help in providing the recommendation for troubleshooting and support engineers in devising mitigation plan. In order to have control over the large fields containing hundreds of wells, having integrated well and facility surveillance is the need of the hour. The advanced workflow and intelligent dashboards implemented in the asset tremendously helped in reducing the operational cost and increasing the average uptime per well per field, thereby providing opportunities to management and end-users to leverage the utmost value from a digital framework implementation for the purpose of daily well and facility surveillance.
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