bluuebunny/crossref_metadata_2025_split huggingface dataset:
Multi-Company-Design-Efforts in the European Aerospace Industry
Authors: Wenzel Holger 
Published: July 2010

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.
Steam Assisted GOGD in Light Oil Reservoir - Pre-EOR Cold Daseline Importance and How We Achieved It
Authors: Saluja Jasmeet Singh , Hamm Ron , al Ghafri Salah , al Gharbi Mohammed , Diri Muhammad 
Published: July 2010

Abstract
Steam Assisted Gas-Oil Gravity Drainage (SAGOGD) trial is planned for a limited area of a giant producing light oil field in Oman. Oil production from this oil-wet fractured carbonate reservoir commenced in 1967, and recovery factor currently stands at approximately 20%. The SAGOGD process in a light oil fractured reservoir is complex and is comprised of numerous recovery mechanisms, with a number of these being uncertain and poorly understood. Very little world analogue data is available [1], and that, combined with large recovery process uncertainties make this ‘large pilot scale’ Phase 1 essential to mitigate the downside risk in a full-field development.
During Phase-1 it is planned to inject 2000t/d of steam by means of 4 vertical steam injectors. Oil, gas and condensed steam will be produced by 7 horizontal producers and 5 vertical back-up producers.
The magnitude of the SAGOGD production response is highly uncertain. Having the capability to accurately measure the incremental oil production response over this wide uncertainty range was considered to be a key success factor for the Phase 1 project. To accurately measure the incremental response required that a ‘no steam’ production response could be confidently projected into the future for a minimum of two, and up to five years. This task was made considerably more complex by the fact that historical GOGD well production profiles were often relatively unstable.
This paper describes the work carried out within PDO to ensure that one of the key Phase 1 success criteria – that being to measure the incremental oil due to SAGOGD – can be achieved over a primary evaluation period of two to five years. The discussion will include a description of efforts linked to optimization of cold GOGD performance (optimum oil rim management), well production stabilization (via installation of new production control hardware) and accurate measurement of total and individual well production levels (dedicated bulk and well-test facilities), and how this all came together to yield a stable cold production baseline which could be confidently projected into the future.
Impact of Shale Baffles During Pattern Steam Drive and Steam Assisted Gas Oil Gravity Drainage (SA-GOGD)
Authors: Al-Hinai Suleiman M. , Van Wunnik John 
Published: July 2010

Abstract
It is common practice to model shales in dynamic simulation models implicitly by assigning a global reduction factor to the sand's vertical permeability. Such an approach is required due to the complexity and computational limitations of modelling shales explicitly in large simulation models. The validity of this approach in the case of discontinuous shale baffles in a steam flood is the subject of this paper. The study concentrates on understanding the physics of flow in the presence of these discontinuous shales by conducting generic fine scale simulations for a water flood, a gas-oil gravity drainage system and a steam flood. The results show that in general implicit modelling of shales by an effective vertical permeability that is derived from single phase flow simulations cannot capture the flow mechanism and predicts a different oil recovery to models where shales are accounted for explicitly. For steam flooding implicit shale models take longer to heat the reservoir than explicit shale models; the main reason being that steam can percolate around shale baffles and so quickly achieve an elaborate network of continuous flow paths to the top of the reservoir. A parameter evaluation technique is worked-out that captures explicit shales correctly in an effective vertical permeability although this needs also tuning of (pseudo-) relative permeability parameters. Encouragingly, when a good history match is obtained for a bottom-up water flood by modeling the shales implicitly in the described way, these tuned implicit models also give good steam forecasts. The actual appearance of the floods can, however, be very different from the explicit appearance.
Fractured Carbonates: A Methodology to Evaluate Surfactant Performances
Authors: Chabert M. , Morvan M. , Tabary R. 
Published: July 2010

Abstract
Wettability alteration is a key method for recovering oil from naturally-fractured, oil-wet carbonate reservoirs. Many surfactants have been proposed for this purpose, including sulfonates, alkyl ammonium bromides or ethoxylated alcohols. Nevertheless, the very intrinsic link between oil recovery from an initially oil-wet rock and surfactant characteristics has been poorly studied. In particular, the interplay between rock wettability alteration and oil/water interfacial tension (IFT) reduction due to chemicals is not fully described.
We present a high throughput screening test to specifically address the problematic of surfactant effects on wettability. Automated contact angle measurements allow for the selection of successful candidates. From this screening, we propose a complete workflow using model minerals treated with crude oil and Amott/USBM measurements on outcrop carbonate cores. We demonstrate that taking into account surfactant effect both on IFT and on wettability gives superior results compared to focusing on aqueous solution spreading only. A qualitative correlation between results from high-throughput screening tests and Amott-Harvey wettability indexes variations is extracted. These results provide a consistent set of parameters to be included in future numerical simulations.
New Insights into Polymer Rheology in Porous Media
Authors: Seright R. S. , Fan Tianguang , Wavrik Kathryn , Balaban Rosangela de 
Published: July 2010

Abstract
This paper clarifies the rheology of xanthan and HPAM solutions in porous media, especially at low velocities. Previous literature reported resistance factors (effective viscosities in porous media) and an apparent shear thinning at low fluxes that were noticeably greater than expected from viscosity measurements. The polymer component that causes the latter behavior is shown to propagate quite slowly and generally will not penetrate deep in a formation. Particularly for HPAM solutions, this behavior can be reduced or eliminated for solutions that experience mechanical degradation and/or flow through a few feet of porous rock. Under practical conditions where HPAM is used for enhanced oil recovery, the degree of shear thinning is slight or non-existent, especially compared to the level of shear thickening that occurs at high fluxes.
Numerical Simulation of an Enhanced Oil Recovery Process of Toe to Heel Air Injection (THAI)
Authors: Rojas Jose , Ruiz Jorge , Vargas Jaime 
Published: July 2010

Abstract
This paper offers an innovative method to test various scenarios for toe-to-heel air injection wells, to meet the demands for new technology and methods using in-situ combustion coupled with steam injection. It presents research conducted over the last few years on the numerical simulation of the toe-to-heel air injection enhanced heavy oil recovery process.
Reservoir simulations were used to evaluate multiple variables and scenarios, leveraging the integrated workflow capabilities of software while maximizing the effective time for performance analysis.
Included are discussions of the workflow process, a description of base model details, well array testing results (i.e., four patterns combining horizontal and vertical wells), a comparison of injection air rate in the toe-to-heel air injection process versus a conventional in-situ combustion method, and sensitivities in oxygen concentration and injection rate, which led to increased recovery through the application of toe-to-heel air injection technology.
The effects of heterogeneities on the development of the toe-to-heel air injection process are also examined, along with multisegmented well model benefits demonstrated in the reservoir simulation software tool (ECLIPSE). Additionally, coke deposition during combustion was simulated, showing that toe-to-heel air injection does not affect the fluid flow dynamics process.
Based on our research study, this analysis of the best scenario for toe-to-heel air injection well placement efficiently produces nonconventional hydrocarbon accumulations by delivering increased process control on the combustion front.