bluuebunny/crossref_metadata_2025 huggingface dataset:
Machinery Predictive Analytics
Authors: Rawi Zaid
Published: July 2010

BP has deployed early warning systems that monitor heavy machinery, markedly increasing the reliability, operational integrity, and performance of equipment in BP's operations. Early warning allows BP to more effectively schedule maintenance (with costs of planned maintenance typically being a fraction of the costs of emergency repairs) and plan to minimize any production loss during the work through reconfiguration and feed rerouting. The company's initial trial generated value of $2 million during the trial alone, at a cost of only $50,000. Additional trials provided further savings of almost $3 million through detections such as pump seal problems, failing instrumentation, control problems, and turbine fouling. These striking benefits led BP to plan a significant deployment across the company.

In just over a year, BP has made significant implementations at more than half of its facilities in one business segment and online pilots in all other business areas. Millions of dollars have already been saved; BP's goal of significantly reducing unplanned maintenance is well on its way to being realized. Far fewer experts are required to spot developing problems than with traditional data monitoring methods, this can now be done by a skilled technician; so more problems are caught. Quick- win maintenance savings more than paid for the technologies in the first year, and the safety benefits in a potentially hazardous environment are priceless.

BP's aggressive adoption of wired and novel wireless technology to capture more measurements has significantly increased the volume of data available. This wealth of data put BP in an even better position to leverage predictive analytics technology. The technologies’ data-driven approach has many advantages over the traditional trending or first principles models used in the past. It's generally faster to implement, easier to maintain, does not require sophisticated engineering knowledge, and makes use of a wealth of existing but unused data, representing a breakthrough in the area of equipment health.
Remote Optimization Improves Drilling Performance in US Land
Authors: Estep Nathan , Parsons Barry , Middleton Rod , Alvi Ahsan
Published: July 2010

An Operation Support Center (OSC) was established in Colorado, USA to support clients drilling in the Pinedale Anticline in Wyoming as well as other operators throughout the onshore drilling market of the continental US. In the Pinedale Anticline region, operators plan to drill several hundred wells per year. The time to drill and complete a typical well stood at thirty-five days through 2007, and a target was set to reduce this to fifteen days. Achieving this target would result in a savings of approximately 2190 combined rig days a year thus saving the operator over $100mm.

A strategy with 2 main elements was developed: a powered rotary steerable service for vertical drilling and remote optimization via the OSC. This approach allowed for no rotary steerable operations personnel to be based at the wellsite during drilling. The new OSC centric processes and procedures developed increased efficiency and allowed fast deployment across a fleet of rigs. The process included a rig-up crew that moved from rig to rig for BHA pick up or lay down.

The remote operations team then monitored operations and began analysis to optimize performance. Using offset data and mean- specific-energy (MSE) techniques, drilling performance targets were set for each depth interval. OSC based drilling engineers alerted the rig when penetration rates were compromised by adverse drilling dynamics, or when input energy needed to be reduced to preserve bit life and minimize trips. The remote team also generated a daily report for each well that continuously compared penetration rates with expected performance targets and captured best practices. This process was used to communicate across the entire drilling organization.

This method of challenging the target was complimented by the operator's ongoing optimization initiatives and resulted in an increased average ROP of 36% through February 2009. Average time to drill and complete these wells was substantially reduced from the original benchmark; with average drilling and completion time standing at seventeen days. This reduction in days has the potential of saving the operator an average of $900k per well.
Laboratory Evaluation of a Chemical Additive to Increase Production in Steam Assisted Gravity Drainage (SAGD)
Authors: Srivastava P. , Debord J. , Sadetsky V. , Stefan B. , Orr B.
Published: July 2010

This paper describes a laboratory method used to evaluate an additive to enhance bitumen production in a steam assisted gravity drainage (SAGD) operation. This steam additive enhances bitumen production by accelerating the release of bitumen encapsulating the sand grains. The condensed water is then able to carry a higher loading of this released bitumen. A lab-based gravity-driven displacement process was used to simulate the thermal recovery process by passing pressurized steam at 200°C and 2000 kPa over an unconsolidated oilsands core sample. In these experiments, a dosage rate of the additive at 1,000 parts per million (PPM) resulted in a 13.5% increase in bitumen recovery from oilsands compared to the baseline (no additive, pure steam). These lab-based test results establish the effectiveness of this steam additive to enhance bitumen production at a dosage rate as low as 1,000 PPM and thereby precluding any need for recovering the chemical driven by economics.
Integrating Data Mining and Expert Knowledge for an Artificial Lift Advisory System
Authors: Vega E. De , Sandoval G. , Garcia M. , Nunez G. , Al-Kinani A. , Holy R. W. , Escalona H. , Mota M.
Published: July 2010

This paper describes a new workflow to accelerate and improve decisions regarding where and when to apply an artificial lift system in fields with a considerable number of active wells. The workflow deploys a hybrid combination of a user-driven expert system and a data-driven knowledge-capturing system calibrated with historic data. Both systems interact to determine the right point in time to support a particular well with an artificial lift system.

In the case presented, the mature gas field has a large number of operating wells, with predominantly manual operating data entry and a long processing time for newly acquired data. Due to the rapid decline rate in many wells, however, quick decisions are needed to improve productivity and hence the economics of each individual well. During the first two phases of the project, the asset team focused on data collection and workflow automation to speed up well production surveillance operations (e.g., gas rate calculation, estimation of critical velocity, etc.) (Mota, 2007). This paper documents the third phase, which addresses the knowledge-capturing and advisory components of the solution.

Mature fields typically have significant field and asset expertise and a huge amount of historic data. Both information sources—the expert documentation and historic data—can be integrated to investigate past decisions and identify an optimum approach to field interventions. This paper describes the setup and implementation of a hybrid model that combines expert knowledge from asset engineers with the new knowledge discovered through the latest data-mining technology. The resulting system is then implemented in a fully automated workflow that identifies which wells require artificial lift.

The results from a case study in a North Mexico gas field are presented. The reservoir is highly compartmentalized and requires fracturing as a way to increment well productivity. The data-mining approach used in this study is a special visualization technique, the self-organizing map (SOM), and a clustering algorithm (Zangl, 2003). The model was trained with historic production data, well test data, and information about historic well intervention decisions. In addition, expert knowledge from the asset engineers was introduced. The combination of data and expert knowledge enabled fast and reliable identification of the optimal time to install an artificial lift system to increase production while also effectively managing costs.

This system reduces the typical decision time from several days to a matter of hours. The automated workflow runs immediately after the data is acquired and provides a continuous, up-to-date, and ranked list of proposed wells for artificial lift analysis. When new decisions are taken, the model can be updated for future use. The rapid analysis and decision cycle reduces lost production and improves overall field and asset value.
New Opportunities for Emergency Handling in the Intelligent Energy Organization
Authors: Tveiten Camilla K. , Albrechtsen Eirik , Wærø Irene , Wahl Aud Marit
Published: July 2010

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

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

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

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

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

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

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

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

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

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

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

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.
Multi-Company-Design-Efforts in the European Aerospace Industry
Authors: Wenzel Holger
Published: July 2010

In the European Union Framework 6 programme, the large scale integrated project "Value Improvement through a Virtual Aeronautical Collaborative Enterprise" (VIVACE) (Anoymous, 2007) was initiated, with participation from large European Aerospace companies, as Airbus and Rolls Royce, medium and small sized companies, research centers, universities and software vendors.

The overall aim of VIVACE was to enable the virtual product concept in a collaborative environment (the Virtual Enterprise) through design, simulation and integration, starting from the early phases of aircraft conception. The high level objectives that the project was expected to achieve were: Halve the time to market for new products with the help of advanced design, manufacturing and maintenance tools, methods and processes.Increase the integration of the supply chain into a networkMaintain a steady and continuous reduction in travel charges through substantial cuts in operating costs.

This paper presents parts of the work done within this project based on the example of the design of the high pressure turbine of a jet engine (Wenzel et.al, 2010).

Such a large design effort is typically shared between various partners. There exists not one partner that can impose the tool suite to be used by the virtual enterprise. Each partner uses its own design framework, which usually combines Commercial Off The Shelf (COTS) and proprietary in-house developed tools. The ensuing design framework contains the expertise of the partners involved; hence there is a balance between the need to share the capability during a collaborative design and protecting the intellectual property rights of each partner's core assets. Traditionally such multi-partner collaboration is accomplished by exchanging limited design information between partners via paper or e-mail.
Closing the Loop - Integrating Predictive Surveillance With Remote Control Operations
Authors: Lima C. B. , Diniz L. L. , Sobreira G. , Rossi D. , Kumar A.
Published: July 2010

The oil and gas industry has had a long-time vision to close the feedback decision loops in the Integrated Digital Oilfield. Petrobras has made initial steps toward this goal by integrating Production Surveillance (for wells, equipment, and facilities) with Remote Control Operations on five platforms that comprise 15% of production operations in the Campos Basin. This represents a step change from the way Petrobras has historically operated, and has required systematic and inter-dependent changes to various sections in the organization.

The first step in this direction entailed bringing remote control technical capabilities onshore, to be in closer proximity to the decision center. This ensures stronger person-to-person inter-relationships between production engineers and control operators. The decision center has been operational for over 18 months and has undergone a transformation from reactive to proactive surveillance and analysis approach on the processes supporting production operations. Now that proactive processes have been established, Petrobras has instituted combined surveillance-control processes, with each onshore team focusing on a single platform. As the project has matured, the role has changed so that now each onshore team manages multiple platforms with similar levels of operational complexity. This has led to a strengthening of the quality of remote control operations, has allowed technical expertise to be leveraged across operations, and has reduced overall HSE exposure.

This paper describes the initial steps taken by Petrobras to achieve integration between predictive surveillance and remote control production operations. It also describes the benefits that have been realized, such as reducing costs and the number of people on board platforms. Based on the early success of this work, Petrobras plans to expand the program to cover all of its operations in the Campos Basin. After proving success in the Campos Basin, it is expected that this approach will guide Petrobras as it prepares for the many challenges in Pre-Salt operations: complex logistics, personnel shortages, and environmental challenges.
Digital Technology: An IOC's Perspective to Maximize People and Process for Efficient Hydrocarbon Recovery
Authors: Spahr Russ D.
Published: July 2010

Many oil and gas operators are developing and implementing their vision for "digital oilfields" in order to more efficiently recover hydrocarbons in an increasingly complex and challenging environment. ExxonMobil* has a long history in the application of digital technology to maximize asset performance. Continued applications of new advances in digital technology are implemented to further optimize people's time and expertise towards maximizing hydrocarbon opportunity identification and recovery. ExxonMobil's global functional organization provides a framework to deploy globally standard asset management processes and technology tools to improve the efficiency and effectiveness of its professionals across technical disciplines and operations. ExxonMobil's vision is to create breakthrough performance and competitive advantage through systematic application of digital technologies integrated with global standard processes.

This paper shares ExxonMobil's approach to leveraging digital technology in management of assets. Key success factors in this approach are cross-discipline collaboration across the asset's lifecycle, standardized processes, and a long-term commitment to technology. Included in this paper are examples of digital technology implementations and how they enable people and processes for higher asset performance.
State-of-Art Digital Oilfield Implementation in Petrobras Campos Basin
Authors: Lima C. B. , Sobreira G. , Rossi D. , Kumar A. , Sauvé B.
Published: July 2010

After its success with the implementation of Digital Oilfield program in Carapeba field, Petrobras decided to expand the concept to other fields and assets of the Campos Basin. These new fields had dissimilarities ranging from field instrumentation to varying production concepts and technical processes – posing a new set of challenges enforcing the need to review solution deployment strategy.

The solution methodology required analysis of the various functional processes from these fields and assets. Therefore, a functional committee represented by the assets was established to help define the standard business process along with rationalization of the appropriate tools and technology coupled with scalable IT architecture. This clearly led to help achieve consistency and transparency in managing production operations across the organization – resulting in better integration of information and significant increase in efficiency of the functional groups. The key to success was certainly driven by strong management sponsorship and willingness of the asset teams to adapt to the new approach.

The solution focused on key business processes which had a direct impact on the production of the assets e.g. Well Surveillance, Analysis & Diagnostics; Losses Control; Sub-Sea Integrity and Surveillance; Well Test Validation & Control; Turbomachines Surveillance – with clearly outlined objective to deliver immediate value to the assets and the business unit. This approach has helped establish Campos Basin as a potential role model for the other assets and business units within Petrobras.

This paper intends to describe the challenges faced during the expansion of the program beyond the pilot implementation and the strategies used to overcome them. It also highlights the key aspects of the implemented solution with specific examples - delivering value creation through standardization of infrastructure and production processes of the assets.
Unconventional Hydrocarbons: Intelligent Integration and Operation
Authors: Tye Ben
Published: July 2010

The integrated energy company of the 21st century will possess an increasingly diverse portfolio mix of conventional and unconventional hydrocarbon resources including heavy oil, oil-sands, coal bed methane, coal-to and gas-to-liquids.

In contrast with conventional hydrocarbon deposits which are hard to find and limited in volume, unconventional reserves are relatively easy to locate and often plentiful. In addition, the word unconventional in this context is derived from the unusual production processes required to develop and produce commercial viable oil and gas. These processes are very diverse and will vary according to hydrocarbon type and geographical location.

Over the last two years, the industry has witnessed an increase of merger and acquisition activity in unconventional hydrocarbons. This paper will explore the rationale behind unconventional resource acquisitions and how the principles of intelligent energy can mitigate integration risks and enable integrated operations.
Steam Development Areal Surveillance Programme in Petroleum Development Oman
Authors: Rocco G. , Adawi R. , Kindy F. , Busaidi S. , Farsi S. , Maamari A. , Jorgensen P. , Kiyaschenko D. , Mehta K. , Lopez J. , Zwaan M.
Published: July 2010

After 26 years of cold production in a South of Oman heavy oil field, enhanced oil recovery through steam-flooding is currently planned. The first steam-injection pattern started in 2009 and the challenge is to monitor the rate of growth and shape of the steam chest at 1,000 m below surface. The Well and Reservoir Management (WRM) plan for this field includes a comprehensive set of areal surveillance activities including seismic and non-seismic methods that have been put together by a joint effort between Petroleum Development Oman (PDO) and Shell International EP (SIEP).

The approach to monitoring the steam conformance and sweep efficiency as the steam is injected in the reservoir focuses on simultaneously deploying a wide range of proven technologies early on. The objective is to select the most appropriate tool for the later full field deployment. The first active pattern is currently being used to investigate the effectiveness of existing seismic techniques such as cross-well and 3D vertical seismic profiling (VSP) to detect early signs of steam front movement. Pre-steam baseline data has been acquired and forward modeling helped determine the best time for repeat surveys. The more traditional, though challenging in South Oman, surface seismic data is also being adapted to the crowded conditions of the field. Alternative plans also include state-of-the-art high resolution virtual source seismic as well as surface deformation and time-lapse geochemistry. Improved lateral and vertical resolution at depth are key factors for success in this and future similar developments. Details of the areal surveillance programme and initial results are summarized here.
Evaluation of EOR Techniques for Medium-Heavy Oil Reservoirs with a Strong Bottom Aquifer In South Oman
Authors: Brooks A. D. , de Zwart A. H. , Bychkov A. , Al-Azri N. , Hern C. Y. , Al-Ajmi W. , Mukmin M.
Published: July 2010

This paper describes the search for viable EOR techniques for a medium-heavy oil reservoir with high permeability and a strong bottom aquifer in south Oman. Horizontal production wells drilled at the top of the oil column yield high (commercial) initial oil rates however, they suffer fast water breakthrough and subsequent oil production is at high water cut. Given the poor primary oil recovery, these reservoirs are candidates for EOR as a means by which to improve the ultimate recovery. However, determination of the most appropriate process is non-trivial as field characteristics pose a significant challenge to most EOR schemes. These challenging characteristics include an oil column of around 40m, a large and strong bottom aquifer, sustained high reservoir pressure (100bar) and medium-high oil viscosity (250 to 500cP).

Three EOR techniques were identified as potentially feasible, both in terms of increasing ultimate recovery and their practical implementation; in-situ combustion (ISC), high-pressure steam injection (HPSI) and polymer flooding. None of the three processes are conventionally prescribed for reservoirs such as these and modifications to the basic processes were imperative. ISC is generally applied to thin, confined and dipping sands in the absence of bottom water. Steam injection is normally applied at low reservoir pressure and polymer is normally applied to oils with viscosity less than 150cP.

The paper describes a fully integrated evaluation of these EOR processes. Comparison is made in terms of simulated incremental recovery, economics, energy requirements and CO2 footprint, target volume and the practicality of implementation in a brown field. Against these metrics, polymer flooding is shown to be the best option.
Conformance Control in Horizontal Wells for Steam and Polymer Flooding Projects in the Sultanate of Oman
Authors: Lanier G. H. , Kok A. , Young-Mclaren A. , Al-Riyami M. , Ambusaidi M. , van Wunnik J.
Published: July 2010

In the South of Oman, several billion barrel heavy oil fields are located in a clastic reservoir setting. Many of the fields typically contain 200 - 2000 cP viscosity oil in good quality reservoirs at depths of about 1000 meters from the surface. These fields have usually been densely developed, often with horizontal wells, and produced cold for many years. Nevertheless, most of the oil-in-place will not be produced conventionally unless a suitable EOR technique is applied. Steam and polymer flooding are two potential EOR techniques, but each option faces technical and economic challenges. This paper focuses, for one of the fields in the Haima group, on the common challenge of well count reduction and utilizing the existing horizontal well stock by a combination of creative thinking and novel technology.

New vertical well patterns lead to high well counts and vertical injectors generally exhibit poor conformance in relation to existing horizontals. Even when the existing wells are closed in, the horizontal sections, in particular from dual-laterals, can often not be abandoned and will keep acting as conduits in a vertical pattern layout. New horizontal wells with conformance control equipment can provide a cost effective solution that compliments the existing horizontal well stock and provides better conformance and injectivity than vertical wells. Conformance control equipment that can withstand steam temperatures has recently been developed. For both the steam and polymer flooding options, the production technology and reservoir engineering aspects of horizontal well conformance control will be discussed in detail and compared to vertical wells. Simulation modelling results will demonstrate that even in relatively homogeneous reservoirs, conformance issues can significantly reduce recovery if not properly mitigated. In particular, injector versus producer conformance control, the number of discrete completion intervals and novel technology solutions will be discussed.