In oil & gas operations, optimisation opportunities of the field production efficiency and performance can be developed and guaranteed by combining monitoring and control elements in so-called "value loops??. Such an approach is possible when reliable and consistent data and information from the complete production system are provided to the right users at the right time.
This paper presents existing field applications of advanced data validation and reconciliation (DVR) techniques which use all available information and measurements in order to provide reliable and consistent data from reservoir to oil and gas delivery.
Implementation and application of advanced DVR to offshore production installations located in Middle East and West Africa are described in detail with specific focus on well production determination and gas balancing and measurements.
Specific highlights are given to advanced DVR models development, field implementations and on results obtained in continuous well flow rate calculations, in equipment monitoring and topside measurements.
By combining sensors, flow measurements and modelling, advanced DVR has permitted to question and validate measurements but also multiphase metering information, equipment operation and flow models parameters.
Operational field experience gained by TOTAL demonstrates that online use of advanced DVR techniques allows to:
This gives the user the possibility to improve well production figures and environmental reporting and also the opportunity to optimize equipment operation and instrumentation maintenance.
The promise of an "Intelligent Energy?? initiative is premised both on the availability of real-time data, and on improving real-time communications between the field and the office. However, acquiring, organizing, and making sense of real-time data for field production management poses a number of challenges for any individual surveillance engineer. For an asset team working collaboratively, the challenge of efficient and effective data monitoring and the performance of optimization workflows can be even more demanding. Many production workflows require an engineer to coordinate data flows between numerous, diverse, and frequently siloed systems and applications. Studies have shown that approximately 50-70% of an engineer's time is spent finding, gathering, and managing data for use in these different applications1. This non-productive time can be drastically reduced by defining standard production workflows, by implementing an automated system to execute these prescribed workflows, and by ensuring that the data sources are well defined and accessible.
A well-designed, thoughtfully implemented, and automated workflow ensures that all the relevant data is available "at the fingertips?? of each member of the asset team, reduces the likehood of input errors, and removes the burden of data management from engineering personnel. These automated workflows allow knowledge workers to focus on value-added engineering tasks. In addition, the design and implementation of automated and configurable workflows creates a transparency and consistency in work processes that can be customized to the unique needs of each asset.
This paper presents an asset-based collaborative project that includes:
The core enabling technology that allows these automated workflows is a vendor-neutral integration platform that dynamically links diverse data sources and software applications currently in use for production monitoring and optimization.
Rwechungura, Richard Wilfred (Norwegian U. of Science & Tech) | Suwartadi, Eka (Norwegian U. of Science & Tech) | Dadashpour, Mohsen (NTNU) | Kleppe, Jon (Norwegian U. of Science & Tech) | Foss, Bjarne A. (Norwegian U. of Science & Tech)
As the first of its kind, the Norne field case proposes to use real field data for a comparative case study. The Center for Integrated Operations in the Petroleum Industry (IO Center) at NTNU include four comprehensive research programs. The "Reservoir management and production optimization" program work on the development of methods, technology and work processes for real-time reservoir management and real-time production optimization. One of the program's objectives is to develop a benchmark data base for research and trial activities. The IO Center states: "The data base should use a real field and in particular promote comparative studies of alternative methods for history matching and ultimately closed loop reservoir management??. Statoil's Norne Field in the Norwegian Sea has been in production for approximately 12 years. The field has high quality 4D seismic data, production data and well logs in addition to a reservoir model (geo model) and seismic model. This data has kindly been made available to the IO Center by the Norne license in general and Statoil in particular. The IO Center will make the data available in packages for IO Center partners and the research community as a whole. At the moment there exist no benchmark cases consisting of real data. The most realistic case present today is probably the Brugge Field (synthetic) presented early in 2008.
The first Norne release considers the Segment E of the Norne field. The reservoir model for this segment consists of 8733 active grids and it has 7 wells (2 injectors and 3 producers with 2 side tracks). This limited starting point was chosen to ensure simplicity and softness at the beginning. Later cases will include the whole field.
The data is accessible via a dedicated web-page where the task at hand is described. It includes a reservoir simulation model in Eclipse format , a geological report describing the stratigraphy of the field consisting 17 zones, and petrophysics reports from three wells which provides data related to permeability, water saturation, net-to-gross, thickness, porosity, capillary pressure, porosity-permeability relationship in all formations.
This paper reports on the preparatory work that included introduction of flux boundary conditions for Norne E - segment separation with a perfect match between the separated E - segment and the E - segment attached to the rest of the field.
Sandoval, G. (PEMEX-AIB) | Martinez, F. (PEMEX-AIB) | Cadena, A. (PEMEX-AIB) | Bernal, H. (PEMEX-AIB) | De la Vega, E. (PEMEX-AIB) | Navarro, M. (PEMEX-AIB) | Garcia, M. (PEMEX-AIB) | Leal, I. (PEMEX-AIB) | Figon, L. (PEMEX-AIB) | Zambrano, A. (PEMEX-AIB) | Duran, J. (PEMEX-AIB) | Rangel, M. del (PEMEX-AIB) | Garza, E. (PEMEX-AIB) | Corbellini, F. (Schlumberger) | Mota, M. (Schlumberger) | Escalona, H. (Schlumberger) | Aguilar, Y. (Schlumberger) | Corona, A. (Schlumberger) | Montes de Oca, A. (Schlumberger) | Tortolero, M. (Schlumberger) | Diaz, T. (Schlumberger) | Alvarez, N. (Schlumberger) | Montes, E. (Schlumberger) | Romero, E. (Schlumberger) | Suarez, A. (Schlumberger) | Romay, J. (Schlumberger) | Fuehrer, F. (Schlumberger) | Al Kinani, A. (Schlumberger) | Holy, R. (Schlumberger) | Nunez, G. (Schlumberger) | Vernus, J. (Schlumberger)
This paper presents the advances in Production System Optimization for the largest gas field in Mexico. The Burgos Asset is a large gas brown field with reservoir characteristics like gas-loading backpressure, reduced permeability and tight gas formations where production declines rapidly. Due to the large number of wells (more than 3500 active wells) and the fact that 95% of the measured parameters are obtained by field operators, it is difficult to continuously monitor and to plan the usage of operational resources.
To help solve this situation, PEMEX and the service company (Schlumberger) implemented a production surveillance system that gathers all operational information providing storage, quality control, and developed engineering processes to estimate gas rates and liquid loading, monitors KPI and detects anomalies in operational events.
Implementation of this operational surveillance environment started in 2007, with a functionality that has been focused on monitoring KPI calculation and event analysis at well level. Due to the large number of wells and activities carried out by the Asset, the need arose to generate additional workflows that contribute to the production optimization process, candidate selection workflow for workover and artificial lift installation, allowing upscaling of the current solution to a level that supports the technical and economical decisions of the Asset.
As part of this requirement the team took the initiative to incorporate workflows of candidate recognition for workover, de-bottlenecking and optimization of a particular set of facilities, allowing the Asset to take corrective action in these areas and to plan the recommendations accordingly. Additionally, as proof of concept, an intelligent candidate selection system was implemented for artificial lift installation opportunities, using artificial intelligence tools such as data mining, improving decisions and results.
The initiatives mentioned above help to increase, validate and rank the Asset's diverse candidate basket and to integrate the economic constraints into the decision making process. The positive results that have been obtained in these focalized areas show a significant opportunity to be upscaled for the whole Asset.
As an industry we often say that we should learn from the lessons of others. This is an example of such a case. The United States Department of Defense is developing the next generation Battlefield of the Future concept, and as a part of that effort they are using gaming technology to create a situational awareness tool for the operating theater. Chevron Corporation and Science Applications International Corporation (SAIC) have teamed to develop a proof of concept using this approach to evaluate its usefulness for operations and simulation/modeling in the oilfield environment, in addition to the proven applicability for training personnel.
A virtual model of a Chevron Corporation onshore brownfield asset was developed using a commercially available game development engine. Geospatial information, real-time operational data and organizational knowledge were integrated into the 3-dimensional (3-D) models to provide a virtual operating environment. Such an environment would enable operators to virtually ‘tour' the fields and prioritize activities before leaving their consoles, and provide engineers a richer understanding of the interaction between wells, facilities, and gathering systems. In addition, by integrating specialized tools (e.g., network optimizers); ‘what-if' scenarios can be visually interpreted within the virtual world for easier assimilation and learning. The resulting virtual model also facilitates collaboration functionality due to its inherent support for multiple users (avatars and instant messaging) and the rich 3-D visual capability, making it easy to facilitate field planning activities like well placements, as well as road and facility construction before construction actually starts.
Future functionality could include real-time personnel and asset tracking using live global positioning system (GPS) data fed into the 3-D virtual model. This platform can also lead to the development of ‘intelligent' workflows based on best practices, which can be refined and captured through the environment, and then guide users through routine troubleshooting and surveillance tasks based on those workflows (guided workflows). The next phase in the evolution of this paradigm is to be able to exercise supervisory control of field facilities through this environment by interfacing with the underlying supervisory control and data acquisition (SCADA) and distributed control system (DCS) systems.
A live demo of this proof of concept will be presented along with current findings.
"Knowledge makes you free from the chains of ignorance, and revives your heart, knowledge takes you out from the darkness of suspicions and superstitions, and gives a new light to your eyes.??
Hazrat Abu Ali Saqfi
Managing an operating asset in the oil and gas industry is a complex activity: the physical process needs to be controlled in such a way that its technical objectives are achieved, while the multitude of technical process parameters handled are being kept within their operational envelope, according to physical and chemical rules; the complex technical equipment supporting the physical process needs to deliver momentarily the technical process parameters as required by the technical process, while the sustainability of its reliability and integrity is being maximized; the asset's operating mode has to be changed with an acceptable frequency, according to economic, social and strategic requirements, and all operating modes, as well as the transitions from one operating mode to another, have to comply with the technical process feasibility and the equipment reliability and integrity criteria from above; regulatory constrains reduce the degrees of freedom for the technical and economic objectives, while adding new tags to the list of parameters to monitor and control; last but not least, the safety of the staff working on the asset and of the natural and social environment in which the asset is being implanted is a matter of concern which needs to be also monitored and controlled.
The conclusion is that the management of an operating asset is the joint effort of many disciplines and hierarchies which require coordination of people and their knowledge, procedures embedded in work and business processes, data, handling of ICT and technical means, interaction with the asset's equipment. This effort is only then successful, if it is guided by a clear strategy, the stakeholders are aligned and mobilized towards the strategic goals, the risks are known, risk mitigation and performance accomplishment instruments exist and continuous governance is applied and accepted.
This paper starts with an assumption which has been demonstrated and confirmed in practice: the coordination necessary for the effective management of an operated asset in the oil and gas industry is being made possible through the collaboration of all disciplines and hierarchies involved. Taking further in consideration that in today's world more operating modes are being added by market, political and social demand, the transitions from one operating mode to another occur more frequently and the regulations grow tougher, this paper asserts that the management of operated assets is confronted with an increase of disruptions and opportunities which need to be handled in very short time. The consequence is that the operated oil and gas assets need today to manage the disruptive events and the occurring opportunities by adapting opportunistically the plans for target achievements. The collaborative real-time event management and plan adaptation is defined in this paper as Managed Collaboration and Real-Time Decision Making.
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.
Passive ICDs (Inflow Control Devices) have been used in the past to enhance performance of producing horizontal wells in unfavorable environments such as non-uniform permeability and/or pressure variations along horizontal sections. This is the first ever attempt, to the best of our knowledge, at using ICDs combined with a fiber-optic DTS (Distributed Temperature Sensor) to manage the water injection profile across a horizontal reservoir horizon.
The cost of the permanent monitoring installation is comparable to a single coiled tubing deployed PLT intervention. This paper addresses how a passive ICD completion, utilizing DTS technology, was used to optimize and monitor well performance. In addition, the operational aspects of permanent vs. intervention monitoring are addressed while highlighting the opportunity for additional value creation using real-time monitoring combined with ICD technology.
This field trial demonstrates the effectiveness of the ICD system when used in an injection well for injection profiling and fluid diversion during acid stimulation. In addition, the DTS proved to be an effective alternative to production logging in this horizontal water injection well.
The key factor in the success of this project was the use of the 3-1/2?? ICD completion along with a DTS system to monitor and passively control the injection sweep across the entire reservoir section. DTS data were also obtained during pre-injection and acid stimulation operations. This was the first occasion in which an operator was able to evaluate stimulation efficiency of an ICD completion using permanent real-time monitoring methods.
To understand the injection profile and well performance, a DTS system was deployed with ICDs and Swellable Packers as a field trial for the planned injection well. Although previous systems have been run above the production packer, in cased multilateral wells, and in open hole ICD production wells1, 2, this was the first attempt worldwide to deploy a DTS system in an injection well with open hole completion across a passive ICD system. The objective of the field trial was to provide real-time information on multi-rate testing, indicate real time compartmental injection profiling, and eliminate the need for horizontal flow meter logging and well intervention.
The field trial considered in this paper utilized a nozzle type ICD design. The ICD acts as a restriction between the wellbore and annulus. The pressure drop across the ICD increases as a square of the flow rate, effectively preventing any one zone/ICD from providing a dominant outflow along the wellbore (See ICD equations on pg.13).
Many benefits of Digital Oilfield (DOF) initiatives come from improved organisational integration. To date, much emphasis has been placed on integrating different functions within a company. However, experience from the defence sector suggests that significant gains can be realised by integrating across the supply chain. In this paper, we look at how these benefits were captured in defence and explore how this knowledge can be utilised in DOF improvement programmes. We also demonstrate that procurement models encouraging organisational integration proved essential to deliver Network Enabled Capability (NEC), the Defence sector equivalent of DOF.
Areas examined include: -
- What different procurement methods were adopted to deliver NEC initiatives? Why were these novel approaches required? How did they affect the capabilities that were delivered?
- What business models are being used in defence which are not seen in Upstream Oil & Gas? Are these models likely to succeed in our industry? Examples explored include "Contracting for Availability?? and "Through Life Capability Management??, where customers are guaranteed specific outcomes and benefits over many years for a fixed, known whole life cost.
- How do the roles and responsibilities of customer, Systems Integrator and supply chain vary in different business models? Who benefits in each scenario?
- How does the availability of real time data between customers and suppliers change the way we procure capabilities and services?
- What are the benefits of partnering with the supply chain?
- The criticality of building relationships of trust and mutual benefit between customer and supplier. When a customer becomes critically dependent on a service, how does this relationship evolve?
- Balancing long term benefits of coordinated procurement with short term delivery needs.
The paper concludes by exploring to what extent a similar story is unfolding with DOF and asking how can defence experience be leveraged?
The emerging trend in Oil and Gas industries for multi-disciplinary teams spread across diverse geographical locations is virtual team working. This concept is a key enabler in a digital oilfield environment where real time communication enables efficient decision making between field and office operations. The Shell Smart Fields Program, Shell's digital oilfield initiative, has deployed the use of Collaborative Work Environments (CWE) as an enabler to optimize operational value across its operating units globally.
The fundamental pillars supporting a CWE implementation are 1) People, 2) Work Process, 3) Tools and Applications and 4) Facility. During the design and implementation phases of building a CWE, emphasis is typically placed on work process, tools and applications, and facility while the people aspect is embedded within other improvement areas. The Smart Fields Program has observed that integration of the People aspect is critical to ensure a CWE's success. Without an effectively and efficiently trained workforce, the new CWE processes will not flow as intended. To address this, Shell has developed a tested methodology focused on driving the required behavioral change to achieve the necessary performance.
This paper will focus on the importance of the people aspect in a CWE implementation, based on a 2009 improvement effort centered on Human Factors Integration (HFI) and behavioral change coaching. In particular, this paper will address: