bluuebunny/crossref_metadata_2025_split huggingface dataset:
Clopidogrel‐Associated Bleeding and Related Complications in Patients Undergoing Coronary Artery Bypass Grafting
Authors: Pickard A. Simon , Becker Richard C. , Schumock Glen T. , Frye Carla B. 
Published: February 2008

Objective. To determine if clopidogrel use before coronary artery bypass grafting (CABG) is associated with an increase in major bleeding, hemorrhage‐related complications, or transfusion requirements.Methods. A structured literature search of English‐language articles was conducted by using MEDLINE, EMBASE, and the Cochrane Collaboration Database for the period of January 1, 1990‐April 30, 2007. Studies were included if they met the following criteria: randomized controlled trials, prospective observational trials, or retrospective trials; characteristics and outcomes of patients who were exposed to clopidogrel within 7 days before CABG were analyzed; at least 20 patients were enrolled; and reported outcomes were related to transfusion requirements, resource utilization, clinical events, or hemorrhage‐related reoperation rates. Patients were considered exposed to clopidogrel if they discontinued the drug within a specified time frame that was designated in each study. The rates of the outcomes were compared between those patients exposed and those not exposed to clopidogrel.Results. Twenty‐three studies, with data on 3505 patients exposed to clopidogrel before CABG, met the selection criteria. Results suggested that clopidogrel exposure within 7 days before CABG increased the risk of major bleeding and related complications, such as reoperation and blood product transfusions. For other outcomes such as mortality, myocardial infarction, or stroke, the studies' designs lacked statistical power to detect significant differences. In five of the 23 studies, antifibrinolytic therapy with aprotinin was evaluated; in the other studies, aprotinin may have been administered, but it was not discussed in detail. In these studies, the clopidogrel‐exposed patients typically had significantly higher chest tube output volumes, reoperation rates due to bleeding, and greater transfusion requirements. Although aprotinin appeared to mitigate hemorrhagic risk, the drug has been temporarily suspended from the market due to safety concerns.Conclusion. Clopidogrel exposure within 7 days before CABG is associated with an increase in major bleeding, hemorrhage‐related complications, and transfusion requirements, and leads to potentially greater consumption of health care resources. The overall risks and benefits for each patient should be considered before using the drug.
Intelligent Continual Right-Time Analysis of Field Data as a Service
Authors: Knabe S. , Shaw D. C. , Webb S. J. 
Published: February 2008

Abstract
This paper describes one application of Right-Time analysis of continual field measurements as used in a high-rate HPHT field in the North Sea. Many sensors and devices in the field are available for constant monitoring at the reservoir manager's desk, yet, we are still faced with the challenge of transforming all this raw streaming data into useful information. Data is regularly used to identify anomalies in the classical Field Automation sense. At medium-long term, however, it ought to be used to identify well and reservoir signatures that help in Formation Evaluation, and for reservoir management and planning. This rarely happens because the analysis involved – which includes highly technical disciplines – simply cannot be automated by computer. This makes it vital to be able to streamline these activities and to deliver the associated analysis as a turnkey service to the Field Operator.
Integrated Production Surveillance and Reservoir Management IPSRM — How Petroleum Management Unit PMU combines Data Management and Petroleum Engineering Desktop solution to achieve Production Operations and Surveillance POS business objectives
Authors: Abd Aziz Mariam , Kasim Mohamad , Som Mohamad , Gunarto Ronny , Lee Hin Wong , Ngu Chai King 
Published: February 2008

Abstract
The role of managing PSC's (Production Sharing Contractor) performance as the main function of PETRONAS's Petroleum Management Unit (PMU) poses challenges for Production Operations and Surveillance (POS) engineers to efficiently perform technical review and monitor performance of the fields across all Malaysian PSCs.
In order to address these challenges, PMU has embarked on an Integrated Production Surveillance and Reservoir Management project to implement a system that integrate cross-domain data into end users engineering software with a pre-defined surveillance workflow, processes, procedures and techniques. The objectives is to provide POS engineers with the required data and workflow templates at their fingertips to enable them to make quick analysis, hence, accurate decisions.
IPSRM implementation consists of two components. The first component involves the Data Management team to build the Data Hub to consolidate cross-domain data from PSC Operators. The second component consists of setting up the workflow and techniques templates in engineering software with online interface to the Data Hub. A unique hybrid Petroleum Engineering tools that combines parametric, user-driven and data driven analysis capabilities are introduced to allow full surveillance capability.
IPSRM implementation has been in operation and provides an effective way for PMU engineers to perform day-to-day surveillance analysis across Malaysia fields. Some benefits and achievements from IPSRM implementation are as follows: Reduced analysis cycle time of engineers by eliminating engineers' time in data preparation and processingPMU engineers are provided with a full spectrum of analysis capabilities to perform study and analysis, covering from user-driven, parametric to data-driven applicationsSome studies have successfully identified potential for recovery improvementNeural Network applications have successfully identified potential for injection/production optimization
ConocoPhillips Onshore Drilling Centre in Norway—A Virtual Tour of the Centre Including a Link Up With Offshore
Authors: Herbert Mike , John Aurlien , James Reagan 
Published: February 2008

Abstract
Integrated Operations can be defined as using information technology opportunities to change work processes to achieve better decisions, to remotely control equipment and related processes, and to move functions and operations personnel onshore as stated in the Norwegian White Paper, number 38, 2002 (St.meld. nr. 38, 2001-2002, Ministry of Oil and Energy)
Integrated Operations are often characterized by operational concepts where new information and communication technologies are used in real time to optimize offshore oil and gas exploration and production resources. This enables large volumes of data to be measured, sent to users via high bandwidth computer links that are shared amongst a broader user audience, and data that can be used to form better decisions.
Integrated Operations cover all aspects of business activities from Exploration to Drilling to Production though this discussion will focus on the Drilling aspects. For ConocoPhillips Norway (COPNo.) to employ this technology there has been a need to re-organize operations, to investigate new work processes and a need to establish a willingness to share information.
According to a study by the Cambridge Energy Research Associates in 20031, the increased use of new and emerging digital technologies could potentially boost world oil reserves by 125 billion barrels over the next 5 years. Petoro A.S. of Norway has estimated the added value of applying eField and Integrated Operations (IO) on the Norwegian Continental Shelf to be NOK 150 billion2. A more recent report by the OLF (Norwegian Oil Industry Association) indicates that the value of IO to Norway could be NOK 250 billion3. In summary, industry studies indicate that the potential benefits of IO are significant.
Five key digital technologies will substantially improve the oil industry's ability to see reserves more clearly, plan optimal drilling and production strategies and manage operations more efficiently. They are: Remote sensingVisualizationIntelligent drilling and completionsAutomation, andData integration.
This paper outlines the industry-leading experiences of the COPNo. drilling and well service group over the last 5 years from field-wide Integrated Operations.
Workover Rig Scheduling Using Reservoir Simulation
Authors: Lasrado Vineet Kevin 
Published: February 2008

Abstract
In this paper we will discuss the results of a prototype software application to view the rig schedule generated by a reservoir simulator. Visualization of simulation rig schedules and comparing with planned rig schedule would help in identifying opportunities to improve operations. With the help of the schedule chart and rig movement data, we better the schedule generated by trying to reduce the net distance traveled by the rig and reduce the number of rigs utilized. We ensure that the overall field oil production is not affected for all the cases.
Using reservoir simulation as a tool to assist in the rig planning and scheduling process has the potential to foster team collaboration between reservoir engineering, planning and operations team and facilitate better Integrated field management. The teams would appreciate the challenges associated with planning and scheduling activities for the field.
Walking the Line: Finding Balance Between Commodity and Custom Intelligent Completion Systems
Authors: Jackson Nielsen V. B. , Tips T. R. 
Published: February 2008

Abstract
For most of the ten years since market introduction, the majority of intelligent completion systems have been custom-designed and manufactured to meet the specific requirements of the customer. Customization was a natural step in the evolution of the technology, as operators tested usability and reliability in individual wells that reflected unique environments and challenges. Each situation was different, and the technology developed more or less in answer to those distinct demands (Figure 1); consequently, the experience base grew and the capabilities expanded.
Collaborative Working—People Issues in Perspective
Authors: Williams Paul 
Published: February 2008

Abstract
The accelerating growth in the construction and usage of collaborative environments designed to ensure that the oil and gas industry can have immediate access to scarce support and expertise has meant people in remote geographical locations have had to forge new relationships, acquire new intervention skills, and accept new ways of working.
This has raised many people issues, ranging from how to engage people in the necessary management of change programmes, the development of necessary behavioral protocols, through to acquiring appropriate leadership skills and installing appropriate recognition schemes, as well as the fundamental issue of how this new connectivity capability impinges upon existing communication processes.
Nowhere is this more acute, relevant and critical than in connecting the offshore operations community with their onshore support colleagues.
Drawing on real life examples the author surfaces, tackles and deals with these issues, showing how collaborative environments can be used to produce a high performance one-team culture.
Modeling Flow Profile Using Distributed Temperature Sensor DTS System
Authors: Wang X. , Lee J. , Thigpen B. , Vachon G. , Poland S. , Norton D. 
Published: February 2008

Abstract
Distributed Temperature Sensing (DTS) technology uses fiber-optic cable to measure continuous temperature profile along the wellbore. Measurement interpretation can provide valuable information, and one of them is real time flow profiling that helps to monitor the fluid flow in wells. This valuable information can assist real time production decision with no well intervention. However, the complexity of the data analysis limits the use of DTS as a flow allocation technique.
This paper presents a new flow-profiling model using DTS technology. The model is based on steady-state energy balance equation and it handles multiple production zones with its own zonal fluid properties. The model is applicable for gas and oil wells in onshore and offshore environment. The model is integrated into easy-to-use software and it can be run in two modes: forward simulation and flow profiling. The forward simulation calculates temperature distribution along the wellbore for any given production profile, and this mode is critical for the model calibration. It is also very useful for emulating what-if scenarios, like water breakthrough. The flow profiling estimates production profile based on measured temperatures, which is the base for the real time well monitoring.
Our studies with the model show that geothermal profile, fluid properties, formation properties, well completion, and deviation as well as Joule-Thomson effect all play key roles for the model accuracy. Joule Thomson gas cooling effect only occurs at lower pressure while reversal appears at higher pressure region.
The model is tested against synthetic, literature and field examples and good agreements have been obtained. Test results have been presented.
Optimize Well Performance with Electrical Wireline Interventions
Authors: Kruger C. , Schwanitz B. 
Published: February 2008

Abstract
In recent years, re-invention and development of electrical wireline mechanical applications, initially for high-angle well-access in conjunction with wireline tractors, has proven able to unlock value potentials by allowing interventions, previously thought impossible or cost prohibitive, even in low angle wells. Common denominators are remote-control, rig-less operations and documented large value-creations.
The most recent advancement in this service category includes milling and drilling on wireline; a breakthrough within intelligent production optimization. With the ability to engage a wide variety of challenges downhole, this technology provides hitherto unseen possibilities to increase production quickly, efficiently and safely. Also representing new capabilities is the technology of transforming constant mechanical force independently of the wireline and depth/deviation of the well. The advantage here is that operations can be performed from a crane or mast unit with electric line and apply a pulling/pushing force capable of manipulating down hole production control devices in a controlled and repeatable manner.
This paper will present innovative areas of recovering production through various case histories.
Improved Efficiency & Knowledge Based Support of Oil Well Drilling through Cased Based Reasoning (CBR) Approach
Authors: Islam Aminul M. , Skalle Pål 
Published: February 2008

Abstract
As of today, no well is drilled without problem. Oil and gas companies spend about $ 25 billion annually on drilling. Unfortunately, not all of that money is well spent. A significant portion, about 20% is attributed to losses. These include loss of materials & drilling process continuity. In particular, wellbore stability related problem remedy cost is substanting and such problem are repeatedly occurring but still so complex that they are not easily solved. The necessary experience obtained by individuals or by the organization is difficult to transfer efficiently to those that need it. The objectives of this paper is to a problem analysis method called Case Base Reasoning(CBR) and its application in terms of a new level of active computerized support for information handling, decision support for wellbore instability cases and prediction of potential unwanted events in the drilling engineering domain.
CBR is well suited for dealing with the complexity of wellbore stability problems, and the large number of parameters involved, experience is stored in cases which are linked to a model of general domain knowledge. The general domain knowledge is containing information with explanatory support to case knowledge. A knowledge Tool named "Creek" (research version) has been used here to create the ontology framework.
This paper mostly addresses how to make a case from real case data, create symbolic entities including case retrieval methodology and finally diagnosis similar problem cases.The cases resented are all related to improving the drilling plan, in such a way that the problem can be planned away throughts the next drilling plan. The resulting outcome from pased cases acts as input for making better drilling plan to avoid similar problems in the future.
Meeting the Challenges of Real Time Production Optimization— A Parametric Model-based Approach
Authors: Awasthi Ankur , Sankaran Sathish , Nikolaou Michael , Saputelli Luigi , Mijares Gerardo 
Published: February 2008

Abstract
The challenges to achieve real-time production optimization (RTPO) of oil and gas fields lie in the integration of asset-wide operations at multiple time scales, knowledge of reservoir phenomena, and efficient data management. Traditional approaches to production optimization workflows often make simplifying assumptions and work within artificial boundaries, to lower the complexity of an all-encompassing optimization problem. While this decomposition creates manageable workflows, it does not adequately support the integration of production optimization at multiple levels.
We propose a methodology to achieve hierarchical decomposition of the overall production optimization problem at different time scales, where real-time data are consistently used to identify reservoir performance and optimize production. The optimization tasks at each of these levels are organized through automated transactions of targets, constraints, and aggregate measurements. For example, strategic decisions such as long-term (e.g., yearly, monthly) injection targets, production plans etc. calculated using a full-physics reservoir model are resolved into tactical decisions for short-term (e.g., weekly, daily) production planning.
A moving-horizon based parametric model is proposed to provide fast predictions for production optimization in the short-term framework. Since the model structure is based on the decomposition of a full-physics reservoir model, it is reasonable to expect that the parametric model will be robust enough to be used for extrapolation outside the range of history data, a property needed for optimization purposes. In this paper, we present an analysis of the structure of the physics-compliant empirical model, the model's range of applicability, techniques that can be used for parameter identification, and use of the model for short-term production optimization. The paper presents a number of case studies to illustrate the benefits of the proposed methodology and its application in typical workflows for closed-loop reservoir management.
Progress in Integrated Operations Centers
Authors: Landgren Kenneth , Sood Sanjaya , Veeningen Daan , Berge Rolf 
Published: February 2008

Abstract
Oil and gas companies increasingly require environments that support real-time E&P business processes, where wellsite information, applications, and experts can be linked with operational managers and decision makers in one place so that daily operational parameters can be viewed and decisions executed. Most companies believe that making decisions in real time while leveraging global resources and infrastructure will help to improve their field productivity while reducing costs.
Project team members are often collocated to ensure open communication and planning. However, since E&P activities often take place in remote and hostile parts of the world where it may not be possible or economical to deliver all the required resources and personnel, global operations with dispersed personnel frequently require such operations support centers to be "virtualized." Reliable and secure information flow is central to ensuring success in the contemporary oil field.
In a previous paper, the authors outlined the significant challenges of process, networking, security, hardware, and software infrastructure encountered in creating and supporting these integrated operations centers. These challenges include the end-to-end IT infrastructure such as wellsite and field IT, the design of the work processes to be supported, and the business model for company implementation.
This paper discusses some of the progress that has been made in meeting these challenges over the past year, with particular focus on the actual applications that support oilfield operations.
Metrics for Economic Evaluation of Innovative Technologies in the Oil Industry
Authors: Marsala Alberto F. 
Published: February 2008

Abstract
Technological innovation is a key factor in an oil company's bottom line.
Not only is it a tool for operational process improvement (cost reduction, production, and reserves increase) but also a driver for the company's relational marketing. The intangible components of technological innovation, if properly evaluated and managed, are key drivers for know-how development, technological leadership, and reputation building.
These are crucial factors for staying in business in a world in which it is essential to demonstrate ability to control complex problems (e.g., exploitation in challenging areas, new energy scenarios, environmental, safety, and social constraints, etc.).
These are key issues vis-á-vis stakeholders, partner companies, producer countries, and the global community. Effective business management and performance improvement require quantitative analysis; in other words: never measured, never improved. This paper presents a methodology for the economic impact valuation of innovative technologies in the upstream oil industry. Both tangible and intangible components of an innovative technology contribute to generate value and thus each of them is to be considered as a very concrete point that requires comprehension, valuation, and management.
WITSML Changing the Face of Real-Time
Authors: Deeks N. R. , Halland T. 
Published: February 2008

Abstract
WITSML is a key enabler in an increasing number of real-time workflows. This is particularly true for integrated operations within the growing numbers of onshore operations centers. Two years ago WITSML was a technology known by few and actively used by even less. Now the SIG steering the standard has grown to 51 companies.
The starting point for most companies in using WITSML is to bring depth data into their asset databases. For many this has become the norm. Early adopters like Statoil are broadening their use into a wider range of wellsite operations. Within asset teams a standard data delivery mechanism allows integration of new tools and workflows, letting Geologists and Engineers make use of real-time data within their familiar desktop applications. It also enables centrally managed data delivery services letting them focus on their areas of expertise, not data gathering.
New technology and processes in these areas are helping operators make the next big step from real-time remote monitoring to real-time remote control.
For growing numbers it is now not enough to receive a visual representation of the data. They expect data to be delivered in real-time via a standard format.
WITSML also brings operators the opportunity to standardize data delivery workflows, to clarify contractual requirements to providers and to establish and measure realistic data delivery KPIs.
Within Schlumberger WITSML enabled workflows are well established, answer products for drilling optimization and interpretation utilize the standard via a unified WITSML client. This reduces software development cycle time and simplifies data gathering.
WITSML is becoming established, bringing proven advantages to real-time workflows. Continued uptake of the standard will enhance the competitive advantage of service companies and the operators utilizing it. WITSML is here to stay and should be supported more widely within the industry.