bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Opportunities for Emergency Handling in the Intelligent Energy Organization
Authors: Tveiten Camilla K. , Albrechtsen Eirik , Wærø Irene , Wahl Aud Marit 
Published: July 2010

Abstract
The objective of this paper is to present, discuss and provide recommendations for emergency handling and show how new work processes, technology and integrated information could influence or change future emergency handling in the oil and gas industry in Norway. The way normal operations of petroleum production are handled have changed because of introduction of new technology and involvement of new actors in the work processes. The organization or the work processes within emergency handling has up to now not changed. Our finding indicates that there are possibilities for more efficient and earlier handling of possible hazardous deviations from normal work. The measures that need to be taken are related to involving new actors in the emergency handling as well as by developing the way actors are involved. In emergency preparedness analysis and plans it is required to identify the roles, functions and interactions of all involed actors in the handling of different emergencies. The emergency handling needs to include the transition period from normal operation to emergency handling by use of support centers. The work processes must be supported by adapted information and communication technology that improve the quality of the information and communication processes. Training, in terms of the right training scenarios, involvement of the right actors and use of all ready present and adapted technology is crucial for implementation of improved emergency handling on the Norwegian continental shelf. The findings are based on observation studies in two emergency training sessions and a workshop with industrial experts from different contractors, consultancy's and oil companies that operate on the Norwegian continental shelf.
Downhole Flow Control for High Rate Water Injection Applications
Authors: Williams Brock , Barrilleaux Mark 
Published: July 2010

Abstract
DownHole Flow Control (DHFC) is a technology that was originally developed to remotely control the production from multiple reservoirs in the same well. BP recognized the value of using this capability in injection wells to manage the injection of water into separate reservoirs. BP's Field of the Future program worked with service providers to develop the capability of "choking downhole flow-control for water injectors" that allows one well to serve the role of two injection wells thereby reducing the number of injection wells required for field development.
At Intelligent Energy 2008, BP reported on development and qualification of DHFC technology for high rate water injection (SPE Paper No. 112143). Since then, BP has implemented the newly developed DHFC technology in two fields with over a dozen installations. BP has achieved its goals in one field and not achieved its goals in another field. This paper reviews the key learnings associated with both the successes and the failures.
A summary of key learnings: The DHFC technology is very reliable, although difficulties have been experienced with some of the associated multizone completion technologies.Remotely operating the valves to vary the injection rate has proven to be a straightforward operation.Higher than expected injection pressure in excess of the maximum differential pressure rating of the open hole isolation packer in one field is preventing the DHFC system from achieving its objective.
In summary, DHFC application for high rate water injectors is considered a success. Development engineering continues on open hole isolation packers to allow deployment of DHFC in fields with high injection pressure requirements.
Recent Developments in Control and Monitoring of Remote Subsea Fields
Authors: Bringedal Bjørn , Storkaas Espen , Dalsmo Morten , Aarset Marius , Marius Hans 
Published: July 2010

Abstract
Two trends in development and operations of offshore oil and gas installations give increased demand for real-time monitoring and control; number & reach of subsea tie-ins and emerging implementation of integrated operations solutions. Within integrated operations, remote operation and collaboration between onshore and offshore are key elements. Sophisticated monitoring and control applications for wells and pipelines have been available from several vendors for some time. However, these applications have generally been stand-alone expert applications connected to a single subsystem, for example, a slug control solution for pipelines located in the plant control system or a virtual flow metering system for wells located in the subsea (control) system. The usage and benefit of these systems have therefore been limited. This paper outlines how monitoring and control applications for gathering networks should be structured in an integrated operations framework, and which benefits this will give for operators.
Structuring of the different applications ensures that data from monitoring applications are easily available for a large group of users while ensuring that closed-loop control applications retains the robustness and security that is required. Furthermore, recent developments of the applications itself, partially made possible by the modern integrated operations system topology with increased data availability, provides additional functionality not only for expert users, but for generalists as well. Finally, synergies between different monitoring and control applications can give additional value to the users.
Control and monitoring for remote subsea field in an integrated operations framework offers benefits such as faster decision making processes, increased production, improved deduction testing, condition monitoring of sensors using a combination of virtual metering and process data.
The paper outlines the status and future development trends for control and monitoring applications for subsea fields, illustrates the value of the technology and gives recommendations for implementation.
Continuous Improvement Through Real-Time Data Integration into Reservoir Management Workflows
Authors: Kragas Tor K. , Gokdemir Oktay M. 
Published: July 2010

Abstract
A significant challenge facing companies implementing digital oilfield technologies is integration. Instrumentation delivers vast quantities of high frequency downhole and surface real-time data over the life of a well. Integrating this data into engineering applications and workflows to capture its value is often a manual, time-intensive process. This is particularly true when data needs to cross functional boundaries or disciplines, such as integrating production data gathered by real-time systems into reservoir simulation and history matching processes. Currently, field-specific or even engineer-specific processes lead to inefficient use of real-time data.
We describe the development and implementation within BP's Field of the Future Program of a software application for automatically transforming real-time production data into a simulation-ready format for reservoir management. The web-based application allows access to multiple, different databases and data files that store measured or derived dynamic subsurface data. It provides a sustainable, standardized process by streamlining the most common activities of updating simulation models, including data access, retrieval, merging, transformations, quality control, and formatting. The application is built on principles of service-oriented architecture and component-based, plug-in technologies, providing well-defined boundaries and interfaces between application components and extensibility for adding new simulation data sources, formats, and workflows.
The application has been implemented for nine BP assets in 2009. It has been used by reservoir engineers to increase the update frequency of simulation models with production data, and has reduced the time required for updates to minutes compared to days in previous manual processes. Expansions to functionality and automation, and further at-scale deployments are ongoing.
By automating data access, retrieval, quality control, and formatting, the time required to update simulation models with historical data is greatly reduced, giving reservoir engineers more time to focus on critical engineering tasks. The shortened time for data preparation enables more frequent model updates, mitigating risks associated with decisions based on outdated reservoir model predictions. In addition, the application provides a consistent, sustainable process for model updating and data quality assurance. Typical benefits of a standardized tool are also realized, including reduced training requirements and access to a defined workflow.
Planning for a Sustainable Production Optimisation Solution
Authors: Davidson S. S. , Mos S. M. , Coppock S. 
Published: July 2010

Abstract
As organisations transition from concept and design to the deployment and operational phases of a Production Optimisation solution, they anticipate new levels of performance and possibilities. They plan for increased production from the ‘right’ wells, with production engineers and operators able to easily access information, share near-real-time views of the same issues, and make informed production decisions on a daily basis.
The organisation may have accurately estimated the cost of the project design, build, deployment and implementation. But they may have assumed ongoing maintenance costs will primarily be the IT support needed for defect fixing and software release management. That narrow definition of support can lead to problems and ultimately, decreased confidence in the solution and jeopardise its sustainability and evolution.
With a new solution, new roles must be defined to reinforce the relationship between day-to-day activities and their impact on performance metrics and business targets. Continuous improvement and solution enhancements should be sponsored by appropriate decision-makers, and management must recognise and champion the contributions of these new roles.
Data quality issues may require diagnosis and follow-up, with different skill-sets mobilised to address them. Engineers must own the integrity of certain information - alarm levels, valid ranges, thresholds, and calculations. End users and support team must adopt a diagnostic process for identifying the type of follow-up needed to address issues. Simple and focused support metrics need to be devised and reviewed to insure that the support model returns the anticipated benefits.
Benefits Quantification and Change Management in Petrobras Corporate Program for Digital Integrated Field Management GeDIg
Authors: Russo E. E. , Amoroso J. C. , Rolim T. A. 
Published: July 2010

Abstract
The development of the GeDIg program was performed through the implementation of six pilots which have been selected considering the diversity of their operations (automation level, location, type of crude oil, level of exploitation, and assisted recovery method) and with two different approaches, in-house development and partnership with integrated companies (Moises et al., 2008).
This methodology allowed Petrobras to evaluate the strategies and drivers to be adopted when extending to other assets this new way of work, where skills, workflows, and technological resources are integrated in a systemic perspective, with the objective of generating a significant change in operating and producing oil and gas fields.
The diversity of scenarios, in which the pilots were implemented, and the different experiences acquired in each one constitute a valuable source of information and learning, especially for planning change management.
The quantification of the benefits obtained through this new way of operating is another important aspect that deserves special attention, since they are, ultimately, the ones that demonstrate the success of the program.
The present work has the objective of describing the different aspects of the change management process in Petrobras pilots, the impact observed through an adequate planning and sponsorship, as well as the approach adopted to quantify the benefits, not only the ones that directly impact the results, but also the ones that allow measuring the asset performance in terms of safety, environment, and information quality.
A Dynamic Business Needs Dynamic Solutions; How Field of the Future Has Turned BP into a Smooth Operator
Authors: Calvert P. , Davis J. 
Published: July 2010

Abstract
Technological advances in horizontal drilling, subsea processing and complex tie-backs have had a significant impact on pushing the boundaries of operability. As the continuous drive to stretch the envelope of operability has resulted in more and more sophisticated operations, it has become increasingly problematical to operate these facilities in an optimal way.
Dynamic flow instabilities account for a large proportion of the additional operational burden that needs to be overcome. Experiences within BP have shown that a good understanding of the flow dynamics experienced during start-up can have a significant impact on well up-time and overall production rates. Similarly, ensuring stable flow during normal operations can have a significant impact on the overall operational capacity of the process, raising the overall rate of production.
Multiphase flow instabilities are often complex in nature and difficult to interpret. Significant efforts in the field of multiphase modelling have led to an improved understanding of multiphase flow, yet the level of expertise needed to run dynamic models has restricted their widespread use for operational support. The key challenge is to blend the operational insight that multiphase modelling can provide with the people, process and technology elements that have become grouped under the umbrella of intelligent energy.
Within this paper, the value of deciphering flow instabilities will be established in light of the typical operational difficulties experienced at BP today, along with projections for future flow instability. A hybrid modelling and data analytical approach will be presented for the analysis of flow dynamics during start-up and for normal operation. Finally, the importance and value of applying effective control solutions to manage potentially unstable flow conditions will be discussed, with reference to the successful implementation of a ‘slug controller’ at one of BP's offshore assets.
Factors for Successful Deployments
Authors: Hickey Greg , Crossland Alan , Fox Alistair , Skile Mike 
Published: July 2010

Abstract
For the digital oilfield capabilities to be "Business as Usual" means that what is developed or selected must be deployed and used as the global standards in the daily operations of the chosen footprint of assets within our Exploration and Production operational environments. Continuous improvement of the deployment process underpins its efficiency and sustainability.
Within BP, this requires the support of a global organisation operating 150 assets which needs to have assurance that the capabilities are deployed in support of the organisation's stated aims and priorities. Within BP, successful deployment of the digital oilfield capability is embodied within our Operating Management System. Challenges in achieving this include portfolio selection, marketing, deployment, long term sustainability, and customer acceptance. These challenges all need to be addressed in the delivery of these products and capabilities as well as the business workflows they are intended to support. A problem with any one of the challenge areas can slow down or stop deployment progress towards the achievement of at scale delivery and sustainable long term use.
It is commonly stated and understood that the critical success factors underpinning capability are Organisation, People, Process, and Technology. For the type of digital oilfield "product" applications which are intended to deliver a capability to serve a well defined operational need on a large number of assets, the Organisation is often constrained by business needs and drivers while the People, Process and Technology elements can prove to be effective levers for change.
With reference to lessons learned, this paper describes how the Field of theFuture Data to Desktop (D2D) Program has evolved to use BP's organisational resources and critical success factors as levers to deliver digital real-time data enabled capabilities at scale.
Creating Value and Enhancing Operational Efficiency With the Subsea e-Field
Authors: Phillips Ray , Holley Stuart 
Published: July 2010

Abstract
The latest generation of Subsea Electronics Modules used for control & monitoring of subsea producing wells is able to offer great improvements in data bandwidth for "smart" subsea oil & gas applications, providing very high speed fibre optic links to surface facilities. These devices provide IP enabled data links, with transparent interfaces to subsea sensors and surveillance systems.
Even with such communications advances, the challenge is to interpret this data effectively to provide added value to the operators and prevent data overload. One area of added value is in Flow Assurance and the application of on-line flow assurance techniques to better understand the behavior of the produced fluid/gas and the effects that the various change agents have on production as well as the infrastructure. Also, with the growth of high-speed global communication networks, linked to Smart Operations centers, and the improvements in data security, the use of Remote Condition Monitoring & Diagnostics techniques to provide interactive support and proactive maintenance is a key concept for integrated operations based on expert system and historical data sharing. This approach is a fundamental driver in enhancing the efficiency of a facility through collaborative data and knowledge sharing.
This paper will describe the practical details and challenges for a service provider of setting up a Remote operations center, establishing connectivity and data security / integrity as well as setting to work the day to day operations and manning procedures. The paper will also describe a new generation technology and product for subsea projects, which provides a system micro-controller function as well as acting as the data communications router.
Creating a Digital Picture of our Integrated Operations within BP: Why a Picture Says a Thousand Barrels
Authors: Calvert P. , Heddle R. , Stenhouse B. , Woodman M. 
Published: July 2010

Abstract
Recent technological advances in the oil and gas industry such as extended reach drilling, subsea processing and tiebacks from satellite fields have added to the complexity of daily operations. With a myriad of flow conditions, the dynamic interactions between different components of the gathering system can be significant. Deciphering these flow interactions can be difficult. Optimising them is a real challenge.
Whilst steady-state and dynamic modelling can provide a valuable insight into the occurring flow dynamics, the limitations of multiphase modelling and the level of reservoir uncertainty renders it difficult to determine an "optimal" operating point.
Within BP, an alternative paradigm for system optimisation has evolved from the desire to generate an operability map of the process. By combining data analytics with first principle-modelling and visualisation techniques, it is possible to generate operating maps for our oil and gas installations that are analogous to the "weather map". Process mapping provides a valuable insight into the operability of the process that can be accessed in a quick and easy manner. Operators can immediately relate to the encapsulated information by comparing their own observations with those plotted in front of them. Over time their knowledge of the process is enhanced and the process is manoeuvred towards the "optimal point".
Process mapping has led to significant increases in production within BP. Expressing the virtual insight of a model in a format that both the onshore and offshore teams can relate to has naturally led to an impressive level of asset engagement. In this paper, the people, process and technical implications of process mapping will be discussed alongside the value experienced to date.
Collaboration and Decision Support in Geosteering
Authors: Fjellheim Roar , Herbert Mike , Arild Øystein , Bisio Rossella , Holo Øystein 
Published: July 2010

Abstract
CODIO is an advanced decision support system for the drilling process with focus on geosteering. The CODIO system tackles both coordination and decision complexity of the drilling process. Coordination complexity is due to interactions between geographically and organizationally distributed experts in a real-time information environment, while decision complexity is inherent in the drilling domain itself, given unavoidable uncertainties about geology, equipment behavior, etc. In CODIO we approach each complexity dimension and propose solutions based on business process technology, mathematical decision models, and a service-oriented architecture. In the paper we outline and justify the approach taken, and summarize the lessons learned in developing a pilot version of CODIO for an Integrated Operations drilling center.
Increasing Drilling Efficiencies Through Improved Collaboration and Analysis of Real-Time and Historical Drilling Data
Authors: Staveley Catheryn , Thow Paul 
Published: July 2010

Abstract
Spears and Associates (2009) estimated spending on drilling and completions at over USD 250 billion in 2008. With rig costs estimated to consume 37% or USD 92.5 billion of that spending, every effort to reduce drilling time has a direct impact on our bottom line. Estimates of non-productive time (NPT) ran from 15–40% or USD 14–37 billion, depending on well type and operator. The causes were varied and included technical and non-technical challenges such as wellbore stability, stuck pipe, weather, logistics, etc. Obviously any effort made to reduce NPT will tremendously impact bottom line spending.
Given that causes of drilling inefficiencies are often known and predictable, why do we struggle to improve our results? The challenge is often one of fundamental knowledge management, which includes: difficulty in using historical data, lack of access to relevant data, and the inability to effectively correlate multiple wells in a single view.
Imagine how much more efficient the drilling process would be if you could plan future wells based on nearby offset wells populated with important drilling knowledge from a living drilling knowledge base. The knowledge base would contain all surface drilling parameter data, BHAs, bit records, MWD/LWD data, drilling events, lessons learned, best practices, etc., associated with each well. Data from new wells added to the knowledge base in real time make it more robust, allowing for tracking of position with respect to the shared earth model and updating of the model while drilling. All pertinent data could be displayed side-by-side, allowing correlation of multiple wells by formation, depth or time, in one, two, or three dimensions. Comparison of multiple wells in a single view facilitates better well planning through anticipation of problems and mitigation of risks. This comparative ability leads to an increase in drilling efficiency and a decrease in rig time, which can result in reduced spending.
This paper illustrates techniques for improving collaboration and analysis of real-time and historical drilling data, increasing the cost effectiveness of drilling efforts, and presents a case study highlighting the achievable benefits.