In this paper we present a methodology for synchronized integration of a dynamic simulation model of the wells and production facilities with the real-time online data obtained from the production field. Through dynamic simulation, the production system can be characterized as a transient, multiphase operation capable of modeling time-dependent phenomena. The implementation incorporates development of an accurate dynamic model of the wells and the production network, as well as an online, real-time application which transfers data in a time synchronized manner between historian database and the simulation model at predetermined time steps.
This system has been implemented by Pioneer Resources on the Oooguruk oil field which is the basis of this case study. One important outcome of this system is that it acts as "virtual instrumentation?? for key unmeasured variables such as well flow rates. The system can also monitor the performance of specific equipment and support decisions to switch to production modes such as artificial lift. The system can be run offline as a look-ahead tool to predict future behavior given initial conditions or to run what-if scenarios. It has been shown that real-time models that match the field data improve understanding of the overall system, and provide the tools to translate vast amount of data into decision support for daily operational strategies.
Within the Exploration and Production (E&P) industry much focus has been on the application of "Smart?? technologies. Deployment of these technologies has frequently focused on new field developments, where costs of installation and training of users are included in the overall field development cost.
However within the Royal Dutch Shell group of Companies ("Shell??) a significant volume of hydrocarbon production comes from mature assets, where the business case for such large investment is not always clear. The level of installed instrumentation and it's condition on these platforms, whilst not impacting on the integrity of the asset, is not always optimal for the implementation of "Smart?? technologies.
Globally within Shell two programs, Well and Reservoir Management (WRM) and Smart Fields Foundation Mark I ("Mark I??), are being deployed to a number of assets. These programs focus on "fixing the basics?? and deploying a minimum "foundation?? level of smartness to support field management best practices.
The successful implementation of Mark I requires new ways of working for all members of the asset; from offshore operators through to onshore petroleum engineering staff. Using a set of integrated applications and processes, it is only when these changes are fully embedded that the production and other benefits expected by the project are realised.
The authors describe both the technical installation and subsequent implementation of Mark I on the Nelson platform in the central UK sector of the North Sea. The topics covered include; challenges in the installation project, changes to the way operations are executed in the asset, organisational changes and the development of a support structure to ensure the Mark I applications remain sustainable. The paper documents the benefits realised from an implementation that is focused on changes in peoples working practices with minimal capital investment.
Goh, Keat-Choon (Shell) | Narayasamy, Devarajan (Brunei Shell Petr. Sdn Bhd) | Briers, Jan (IPCOS) | de Boer, Frank (IPCOS BV) | Ibrahim, Kolin (Brunei Shell Petr. Sdn. Bhd.) | Jaberi, Mohd Yussof (Brunei Shell Petr. Sdn. Bhd.)
This paper describes how Brunei Shell Petroleum Co Sdn Bhd (BSP) uses cross validated and reconciled real time production data across large offshore and onshore production networks to support more proactive day-to-day oil and gas production surveillance and management. Examples are presented of the gathering network surveillance systems for the extensive BSP East and Darat Production Assets.
In modern oil fields, there is an abundance of instrumentation distributed over often large geographical areas. The production network ranges from the individual wellheads, to production manifolds, test and bulk separators, past surge vessels and export pumps, to crude dehydration tanks at a central crude terminal or to the gas compressors and gas export points. At least the initial parts of the production gathering network at the wells will have multiphase flow with uncertain and variable oil, water and gas proportions. Normally the most downstream flow meters are well calibrated with good calibration records, but the actual accuracy of the majority of the flow meters upstream will be uncertain, and they will not be nominally designed to handle multiphase fluids or mixtures of fluids with varying densities. Conventionally, it is regarded to be problematic to track production variations in real time across the network back to the source wells. This is due to issues with metering multiphase flows and assumed uncertain transport delays.
It is shown here that it is now practical to track in real time production rates across large production networks, working back from the most downstream, well metered, points to the individual bulk separator units or production platforms or the wells themselves. Indeed, it is possible to obtain a consistent, real-time reconciled view of the current production rates across these larger production networks. This allows more accurate surveillance of production from the wells, early detection of measurement issues and quicker responses to system upsets. Various common blockers to real time network wide production flow surveillance are addressed, including noisy meters, storage tanks, on-off pumps and hard-to-measure multiphase flows from the wells. The work reported may be seen as a "top-down" approach that complements the existing metering systems, integrating the data to "make the best of" all available metering and instrumentation. An example shows how better metering and instrumentation, virtual metering and real time data analysis are combined to detect and correct significant discrepancies.
With ever increasing amounts of data available to surveillance engineers Shell Exploration and Production in the Western hemisphere has used Lean concepts to eliminate waste in a surveillance engineers day, allowing them to concentrate on the highest value tasks and removing unnecessary analysis. This paper illustrates the design and use of the Exception Based Surveillance tool as well as the integration of the tool in a collaborative work environment. This overall process improvement to reservoir and facility surveillance has had a significant financial impact and has lead to efficiencies in procedures, engineering performance and production for the offshore and onshore assets in the Americas.
The need to increase production, lower operating costs, provide longer field lifetimes, and improve exploitation of the oil and gas resources is met by a change in work processes labelled by actors on the Norwegian continental shelf as ‘Integrated Operations', also known as e-fields, smart fields, and intelligent energy. These organizational changes are meant to improve decision-making by utilising real time information to collaborate across social, professional, organisational and geographical boundaries. Integrated Planning transfers these principles to the planning domain, supporting integration of information and utilizing experience, allowing for knowledge-intensive decision-making. Disciplinary or domain-specific activity plans are integrated into one holistic view in order to optimize the use of common resources like logistic support and maintenance expertise. In addition, a holistic view of the operations allow for more efficient deviation and change management, as changes in one asset domain might prove to be an opportunity for another domain. The organization's ability to take advantage of the extensive information accessible and flexibly handle deviations is reinforced by organisational and human qualities or capabilities. Organizational capabilities are development paths for acquiring certain skills or competences. The paper presents a theoretical framework of how to understand and analyse integrated planning, and proposes four organizational capabilities for successfully implementing Integrated Planning, namely organizational learning, communicative capabilities, agility & resilience, and mindfulness.
The major challenges for future oil and gas installations are to create and increase business value in addition to improve HSE (Health, Safety and the Environment). The oil and gas industry has recognised the potential of operations and maintenance in ‘normally unmanned areas' where access to the entire process is based on utilisation of new robotics-based technologies from remote onshore locations.
This paper concerns remote integrated operations by deploying teleoperation and telepresence of oil and gas installations. The challenges involve more than the technology of transferring data and performing operations. A teleoperator or a telerobot is a ‘machine' which extends a human operator's sensing and manipulation capability to a remote environment. An essential issue of telepresence is to keep the human operators in the control loop to enable them to use their high levels of skill to complement the power of remote manipulators.
Teleoperation within oil and gas differs from other known applications as offshore installations represent large, complex and dynamic processes located hundreds of miles away, often in very harsh environments where failures may result in major consequences for the environment and process equipment.
The challenges of offshore teleoperation are to enhance the operator's perception of the current situation so that the operator has a complete understanding of the state of the process and operates the process as if he was offshore without hundreds of miles and complex technology in between.
This paper outlines the challenges and opportunities of deploying robotics in integrated remote operations with a description of laboratory and early field tests as part of a joint project between ABB and Statoil.
Without any doubt, safe and efficient remote operation is critical for operating profitable new fields which may be completely unmanned in the future.
The Intelligent Energy vision is particularly relevant to mid-career professionals with strong management potential. As aspiring asset or service managers, this group has a strong need to improve their analytic and integrative skills, and adopt the holistic view of the industry which characterises the Intelligent Energy approach.
This paper describes results of five years experience with an Executive Master program for mid-career professionals. The program was initiated at the time that Intelligent Energy concepts were being formulated, and embodies many of those principles. It is designed to achieve, within twelve months, a quantum leap in the multi-discipline integration and multi-level abstraction skills of participants, enabling them to solve efficiently complex managerial problems much earlier than traditional training programs. They learn to formulate an integrated vision of the E&P value chain and how this creates a framework for computing added value of individual projects. Mastering this skill is normally achieved after years of experience. The course could be labeled "the MBA for E&P professionals??, however with both feet firmly on technical ground.
The core of the program is the thesis project, which is designed to integrate all skills acquired during the program using real-world company data. It consists of two parts: an individual thesis topic relevant to the participant's work in their own company; and a team thesis in which the group creates a virtual company and makes a corporate analysis of the portfolio generated by the individual projects.
The paper gives a brief overview of the program, emphasising the shared vision with Intelligent Energy. We then discuss in detail the thesis project, and use examples of the individual theses to illustrate how the graduates and their theses act as catalysts for industry best-practices on their return to their home company.
The vision for Intelligent Strategies in the oil industry is stated by Rangow & Govia (2008) to be the optimal integration of business processes and advanced technologies, supported by organisational alignment, to deliver a new standard for decision making. For example, Saputelli et al (2003, 2007a, 2007b), Hocking & Shahly (2008), Moisés et al (2008), Vinturini et al (2008) and Sankaran et al (2009) report on the experience of implementing this vision for Digital Integrated Field Management, Rangow & Govia (2008) discuss the implementation for LNG Operations and Ursem et al (2003) for Drilling Operations.
As noted by Rangow & Govia (2008), the greatest challenge in the implementation of Intelligent Strategies is often not the development of advanced technologies but the effective delivery of the required change management. Intelligent Strategies can improve business performance by delivering value and creating opportunities (the theme of this 2010 Intelligent Energy Conference), but an essential element is the focus on people and managing change associated with the deployment of new technologies and business processes (the 2008 conference theme). In our view, the Intelligent Energy vision is particularly relevant to mid-career professionals with strong management potential. As aspiring asset or service managers, this group has a strong need to improve their innovative and integrative skills, and adopt the holistic view of the industry which characterises the Intelligent Energy approach.
Batocchio, Marcelo A. Pavanelli (Halliburton Servicos Ltda) | Triques, Adriana Lucia Cerri (PETROBRAS) | Pinto, Hardy Leonardo (PETROBRAS) | Lima, Luiz otavio (PETROBRAS) | Souza, Carlos Sales (PETROBRAS) | Izetti, Ronaldo Goncalves (PETROBRAS)
This paper describes a project initiated by Petrobras to map the steam-front progress in a heavy-oil, steam-assisted field. A new Distributed Temperature Sensing system (DTS) that was provided by a major service/engineering company to monitor the distributed temperature along the well has been deployed in a pilot program in a 4-well field that has three producers and one continuous steam-injection well. The project goals were to obtain:
The pilot forecasts selective injection in two zones using packers for isolation. Since there were no commercial packers available with feedthrough capabilities for deployment of hydraulic lines or optical fiber cables for steam injection, a new solution had to be devised to permit fiber installation at the injector.
Aspects considered for this project included the well selection for the pilot development, the performance capabilities of the system, and the solutions for fiber installation.
In 2007 Statoil had deployed new work processes as part of the Integrated Operations (IO) initiative. Many decision makers were already moved from offshore to onshore locations resulting in very high requirements for real-time drilling data onshore. Discussions with the major service companies indicated that meeting these new requirements was not an easy task.
The business model available gave the service companies little or no incentive to invest huge amounts of money upgrading their real time solutions according to these new requirements.
A project was established in order to implement a new business model between Statoil and the service companies securing deliverables according to the new requirements.
The idea was simple: change the end-point of the real-time data deliverables from offshore to onshore, and implement KPI's linked directly to the MWD/LWD and ML invoices each month.
For each milestone activity we will present our initial thoughts, what we learned from the implementation, and the final results:
We will present our observations and conclusions, the main conclusion being that the new business model helps to ensure high availability and quality on real-time data to onshore locations. This again enables a key feature of the new work processes: Quality decisions onshore founded on the best datasets available at any given time.
The conclusions and achievements are based on experiences from having used this new business model in operations since March 2009.
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.