bluuebunny/crossref_metadata_2025_split huggingface dataset:
Expatriate Health and Welfare: The Hidden Costs of Getting It Wrong
Authors: Cox R. , Jeremijenko A. , Doig K. M. 
Published: December 2007

Abstract
The increasing globalisation of the Oil and Gas industry has resulted in the relocation of large numbers of expatriate workers, often accompanied by dependant families, to geographically, environmentally and culturally unfamiliar locations. In many cases, expatriate assignments are seen by the employee as an affirmation of their value to the company, and/or expatriate choice by the employer is based on recognition of previous high performance. While medical issues are usually well handled, the cultural, social, and family adjustment dynamics of the assignment and impact on the employee and dependants are often considered secondary to the work objectives and deliverables, if they are considered at all.
This paper considers several factors critical to the success of an assignment from a health perspective, and the effect these will have on the family and working life. It argues that assignment selection should be an integrated process which examines the suitability of the entire relocating family for the proposed assignment and suggests processes and methodologies to increase the likelihood of completing a successful overseas posting. It lists factors to be considered by the corporate health professional both in terms of the transferee, and in terms of the host country infrastructure.
Health Management—A Contractor's Point of View
Authors: Mika F. , De Sanctis S. , Consentino M. , Nicosia V. 
Published: December 2007

Abstract
Differently from many other activities in O&G industry, particularly those referred to QHSE, Health management has not been standardised yet across the sector. Only lately major initiatives are being undertaken at industry associations’ levels (i.e. Oil and Gas Producers Association, IPIECA, Intnternational Marine Contractors Association) to line up the companies, Oil companies and contractors involved in the business, on this issue.
Saipem, as on of the biggest upstream contractors, is working world wide often facing situations where different Clients operating in the same country or area have similar but yet different health related requirements, or that the same Client operating in different countries in is having different approach towards health issues management. In this condition and circumstances it becomes extremely difficult, complicated, time and money consuming for the contractor to satisfy the Client and to manage the subcontractors.
That is why, approximately a decade ago, Saipem took the decision to establish its’ own health management standards that will represent the minimum bellow which, regardless contractual requirements, the company will not go and will make it recognisable among both Clients and competitors. The results of this ongoing and never-ending process are as follows.
Optimizing Field Development Concepts for Complex Offshore Production Systems
Authors: Cullick A. S. , Cude Ron , Tarman Mehmet 
Published: December 2007

Abstract
An analysis framework is presented that unifies the subsurface and surface disciplines involved with developing offshore projects. The method treats the complex interactions between surface and subsurface aspects of a production problem as a single system. The framework optimizes and assesses the risks and uncertainties associated with facility concept selection and sizing, with consideration of relevant subsurface and surface uncertainties and risks.
There is considerable uncertainty in the subsurface; this manifests itself in terms of a range of reservoir deliverability and reserves. In many projects, this subsurface uncertainty is not properly conveyed to the surface teams who are charged with selecting the best facilities design for the project. Often, the result of this disconnect yield suboptimal facilities followed by expensive retrofitting. The framework presented automates optimization of the concept design with rigorous reservoir and facilities modeling.
Two case studies are presented, both with multiple reservoirs connected through a common pipeline network. The first case is a typical deepwater U.S. Gulf of Mexico project. The second case is more typical of a medium water depth development in northern Europe. Full scenario analyses of multiple production platform alternatives and number of wells optimization is evaluated within a context of reservoir volumetric and drive mechanism uncertainties.
This framework accomplishes the following: it links physics-based reservoir deliverability and expert-system based facilities screening tools with the economics analysis in a unified workflow, and it applies advanced non-linear optimization to deliver better decisions regarding facilities selection and sizing.
WindStore—Large-Scale Energy Storage Offshore
Authors: Boehme Thomas , Cammaert Gus , McCurry John , Judt Michael , Deckers Marie 
Published: December 2007

Abstract
WindStore is a research project focussed on Compressed Air Energy Storage (CAES) in the UK and Ireland, both onshore and offshore. CAES uses low-cost electricity at off-peak times or from renewable projects to compress air into a subsurface void or reservoir for storage. At peak times or when required, the compressed air and additional fuel drive a turbine to generate electricity.
The two existing CAES projects in Germany and the USA are located onshore and use solution-mined salt cavities as storage reservoirs. Offshore the storage options include voids such as steel vessels and salt structures, and porous media such as saline aquifers and depleted gas reservoirs. There are two major applications for CAES offshore. (1) Small projects of some 10 MW capacity could be operated on platforms to store the variable output from nearby wind, wave or tidal current generators and make offshore installations more energy-independent. The fuel usage of CAES is significantly reduced compared to single cycle gas turbines. (2) Large offshore wind farms are planned, for instance, in the southern North Sea where depleted gas reservoirs exist. A large-scale CAES plant of several hundred megawatt capacity could be built on a disused platform using the depleted reservoir for air storage.
This paper describes the applications and likely economics of small and large CAES plants located offshore with focus on the North Sea. It is outlined how CAES can allow a more economic use of high-voltage DC transmission links in future offshore networks.
Estimation of Fracture Spacing in Naturally Fractured Carbonate Reservoirs
Authors: Pérez-Rosales C. , Serrano E. , Moctezuma A. , Luna E. 
Published: December 2007

Abstract
Fracture spacing is an important concept for characterizing flow properties of naturally fractured reservoirs, since the main function of fractures that separate matrix blocks is transporting fluids through long distances; however, the estimation of fracture spacing presents some difficulties mainly due to the fact that fractures occur at different scales, going from microfractures in thin sections and minifractures in cores, up to macrofractures in geological outcrops. The scale of interest in this work is that used in reservoir simulation, which is of the order of feet or meters.
This article is based on the ideas developed in a previous paper, where a procedure to locate fractures is presented. That procedure, which makes use of resistivity data obtained through well logging, visualizes the fractures as highly conducting channels within a low conductivity medium (the rock matrix). By using a special way of data processing, it is possible to filter out data that are not associated with fractures, keeping only those data related to fractures. In this way, fracture spacing can easily be estimated. However, that procedure exhibits some uncertainties which must be overcome to make it a more reliable one.
In this work, a study is made to search for an improved procedure to estimate fracture spacing. For this purpose, fractures are considered at two scales: local scale which includes micro- and minifractures present in matrix blocks, and at reservoir scale which refers to fractures separating matrix blocks. These latter fractures, called principal fractures, constitute the main fracture network, and are the subject matter of this work.
Conductivity studies reveal that local scale fractures have a frequency distribution quite different from that of principal fractures. As it will be seen below, this fact facilitates establishing a procedure for estimating fracture spacing without uncertainties.
To make the ideas clear, an application to a carbonate reservoir is presented. The results obtained show that the improved procedure is a simple, reliable, and practical tool for establishing the distribution of fractures along a well, from which fracture spacing can be inferred.
A Cost-Effective and Safe Method for Transportation and Installation of Subsea Structures—The Pencil Buoy Method
Authors: Mork Henrik , Lunde Johannes 
Published: December 2007

Abstract
The patented Pencil Buoy Method has been developed for transportation and installation of subsea structures. Based on standard equipment onboard ordinary construction vessels in combination with tailor-made special equipment, a cost-effective method is developed.
The special equipment consists of a slender pencil shaped buoy, a passive heave compensator and associated rigging. The system allows for installation of various subsea structures such as Templates, Suction anchors and Manifolds, as well as for removal of subsea items.
The submerged cargo capacity of the system during installation ranges from about 60 tonnes to 370 tonnes including a recent enhancement including a new passive heave compensator. The capacity during subsea transportation ranges from about 150 tonnes to 370 tonnes. During transportation the system is designed to sustain a typical unrestricted summer storm, while during installation the criteria is equal or better than for typical heavy lift vessels.
This paper will present the main principles of the Pencil Buoy Method. The paper will mainly focus on the design aspects related to landing of structures on seabed including installing a structure into another, and will present data from a recent such operation.
Indigenous Peoples and Oil Companies: Respect the Differences
Authors: Bergman Michaela S. , Guldin Gregory Eliyu , Dennis Aaron K. 
Published: December 2007

Abstract
The search for oil is bringing petroleum engineers increasingly face to face with the world’s Indigenous Peoples. Simultaneously, Indigenous Peoples, conscious of the international value of resources such as oil, are becoming increasingly better organized, rights-savvy, and globally connected.
Acting in a socially responsible manner is important for the petroleum industry both from the perspective of ethics as well as from the perspective of reputation. This paper describes how Indigenous Peoples can be engaged on an equitable basis, giving them full respect, identifying how best to mitigate any potential adverse impacts and identify in a participatory manner how they can be enabled to benefit from any Project.
Work experience among Indigenous Peoples in Russia and throughout Asia leads the authors to identify the importance of ‘respect’ for Indigenous Peoples’ values and cultures. This can avoid multi-million dollar delays and maintain a company’s reputation.
Focusing on the Sakhalin II oil and LNG project in Russia’s Far East, the paper advises companies to create a special indigenous space within their corporate hierarchy; with Human Resources, Finance and External Affairs having to adapt their normal procedures and styles. By seemingly "giving away the store," but actually "giving face" to often marginalized economic and social actors, those in charge of the Indigenous Peoples strategy at Sakhalin Energy countermanded corporate logic while embracing a philosophy of cultural and ethnic partnership.
The paper describes what is considered to be best practice (in terms of international and national laws and policies). It then discusses how various contemporary projects in Far Eastern Russia and Indonesia, inter alia, attain these standards. Finally we shall propose a set of standards and best practices that should be adopted by professionals working in the Petroleum industry that take into account the concerns and priorities of Indigenous Peoples.
Multiphase Measurements and Sampling—Operating Experience
Authors: Joshi N. B. , Joshi B. H. 
Published: December 2007

ABSTRACT
The multiphase meters are used both topside and subsea to measure the flowing conditions; pressure, temperature, volume flow rates of oil, gas and water. This real-time information is useful to several disciplines such as reservoir monitoring, production optimization, allocation and well testing. The new generation multiphase meters have been installed and operating for more than five years now. They are becoming more prevalent in the industry because of advances in their reliability and their utility to provide significant additional value. This paper describes the operational experience of multiphase meters using single and dual energy gamma-ray system. It discusses observed accuracies and maintenance processes. It will also discuss multiphase sampling; it's comparison with conventional sampling and also basic fluid property measurements. Illustrations of value addition with the use of multiphase meters in fluid measurement and allocation amongst stakeholders will be presented. It will show that with the use of multiphase meters, the allocation of produced fluids can be improved significantly and it's value addition can be easily higher than $5 MM per year. It will be presented that the capital cost as well as operational cost of the multiphase meter can easily be recovered by this value addition. In addition, the following topics and results will be presented (a) General operational and maintenance practices followed in the deepwater Gulf of Mexico (GoM), (b) Multiphase fluid sampling methodology and comparison with conventional sampling on fluid compositions.
This paper is intended to present hand-on experience of operating multiphase meters and discuss the related issues, challenges and advantages.
A Well Productivity Program in Pemex E&P Increases Oil Production in Short Time and at Low Cost
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T. 
Published: December 2007

Abstract
In the last 18 months, within the five Exploitation Integrated Assets in the South Region of PEMEX E&P, a well management program coupled with multidisciplinary teams has been implemented obtaining 24.5 MMSTB of oil and 40.1 Bscf of gas from workover of 372 wells that were shut in or had production problems. With the implementation and surveillance of this program in the field was possible for these assets to increase the production of oil to over 136 MSTB/D and gas to over 257 MMscf/D. These increases in production has made possible to maintain a production near to 500,000 STB/D of oil and 1,360 MMscf/D of gas in this region, offsetting natural production decline and loss of production due to a strong water invasion of wells. A profit-to-investment ratio of 16 has been obtained. Additional hydrocarbon production greater than 111 MSTB/D of oil and 196 MMscf/D of gas have been identified from 353 wells. The successful implementation of this program was based on the application of selected technologies that contributed to the increase of well productivity from the selected fields. This paper presents the applied methodology and the current results obtained from this well management program to optimize the recovery of hydrocarbons of the identified opportunities within these assets units with minimum investments. In addition to the value added of production increase through this well management approach, the following benefits were obtained: learning and applying the team work approach of well management, adaptation to a new cultural change of working as teams to solve difficult problems, training and transfer of diverse technologies, methodologies, and software technologies from the interdisciplinary teams to the technical personnel of PEMEX E&P, and specific well data information certified that can be used to evaluate reservoirs studies.
Temporary Program of Multiphase Flow Measurement to Provide Well Performance Data: Study Cases
Authors: Arévalo-Villagrán J. A. , Gutiérrez-Acosta T. , Serrano-Lozano J. R. , López-Ramírez S. , Ferreira H. 
Published: December 2007

Abstract
The South Region of Pemex Exploración & Producción (PEMEX E&P) is running a key development plan to improve the reservoir management, well productivity and ultimate recovery of all fields in the region. A fundamental part of this project is gathering reliable well production data on real time and on regular basics. The South Region of PEMEX E&P in cooperation with the technical team of PEMEX E&P performed a full study of available technologies in well testing to select a system that meet the needs of the region while simplifying the field logistic and minimizing environmental impact. PEMEX E&P selected the use of multiphase flow meters (MPFM). The program scope includes 8,064 measurements at well heads and collection manifolds during three years. The preparation and use of this MPFM program for multi-rate well tests was carried out with variable gas-liquid ratio flowstream and systems capable to measure all types of flow regimes in fields producing from heavy oil to gas condensates. This paper describes the lessons learned about the practical reliability, accuracy, and operability of the MPFM meters. The paper illustrates with field results the benefits of implementing the multiphase metering in the region. MPFM meters have proved to be a reliable system to measure well productivity.
Reservoir Characterization from Material Balance Results Analysis
Authors: El Ela M. Abu 
Published: December 2007

Abstract
Oil production in Egypt is based on the development of mature fields with highly complex geological and reservoir characteristics; therefore, a great amount of creativity is required to operate these oil fields. One of the main elements for development of mature fields is to estimate the reserves and determine the amount and location of the remaining oil.
Material balance equations have been used in petroleum engineering for many years to estimate the original hydrocarbon in place. This paper documents the ability of using the analysis of the material balance results in the reservoir characterization and determination of the remaining oil location. The applicability of this work is confirmed by actual field case study (Shukheir Bay Field) in Offshore Shukheir Oil Company (an international joint venture company in Egypt). Such study is an original contribution to the knowledge of the material balance results analysis.
Asset Team Work Methodology for Increasing Recovery Factor in Declined Reservoirs: A History Case in Southwestern Venezuela
Authors: Angel F. J. , Askoul Y. E. 
Published: December 2007

Abstract
Reservoirs declination in Apure State, Southwestern Venezuela, demands a huge technical effort in reservoir modeling when finding drilling opportunities to increase recovery factor and maintain oil production at attractive economical levels. One of these reservoirs, Escandalosa Inferior of La Victoria Oilfield was discovered by LVT-18 in 1991 with 38 MMSTB of STOOIP and in 1998, the last of its four producing wells was closed, reaching a recovery factor of 14%.
An Asset Team revised and integrated geophysical, geological, petrophysical and production data to update Esc-Inf static model in 2005. No robust sedimentological model could be built because of cores absence; however, a facies and later a property distribution was designed with the help of well logs, regional knowledge and geostatistics.
The resulting static model led to visualize the opportunity to drill a horizontal well in the highest attic of the structure to reactivate the reservoir. STOOIP calculation for this new model yielded a value of 13 MMSTB with 7.8 MMSTB of recoverable reserves and 2.5 MMSTB of remaining reserves, which could be extracted by the new well and finally obtain a recovery factor of about 60%. The dynamic model showed a reaccommodation of fluids due to its 5 years of closure, and certified the current presence of oil in the attic where the well was previously visualized. The prediction made by the simulator for a 5 years scenario, with a production of 650 STBD, highlighted the economical feasibility of drilling this well.
Nowadays, the successful well LVT-46H is still active with 2 MSTBD and has accumulated 0.245 MMSTB, since its completion in 2006. These results validate the methodology presented in this work where data integration, the use of geostatistics and reservoir simulation are the main key for reactivating declined reservoirs and maintaining oil production.
Optimizing Hydrocarbon Pay Estimates Using the Magnetic Resonance Imaging Logs in Development Wells of El Furrial Field, East Venezuela
Authors: Fam Maged , August Howard , Maestre Milagro , Guevara Edgar , Mendez Milton , Rondon Luis 
Published: December 2007

Abstract
Optimizing production in mature fields depends greatly on proper reservoir characterization. After a certain period of production, a reservoir may exhibit changes in its properties because of changes in formation water salinity arising from water injection, left-behind residual oil in the rock, and changes in pressure regime. These factors, combined with complexities in the original reservoirs properties, such as rapid variations in permeability and oil viscosity, strongly affect the degree of uncertainty in evaluating and predicting productive zones when using only conventional logging methods.
These variations affect the responses of most conventional logs. Consequently, traditional log analysis models may fail to provide realistic evaluation results and may not achieve appropriate production forecasts. Common examples of such failures have been recognized when producing high water content from a zone believed to be hydrocarbon or when perforating an interval that does not produce.
New logging technologies, such as magnetic resonance imaging (MRI), demonstrate promising formation evaluation results in mature fields. The MRI technology helps to properly distinguish candidate production zones and provide key in-situ reservoir properties, including hydrocarbon type, reservoir quality in terms of permeability and porosity, and barrier zones. The ability of MRI to determine oil viscosity influences the selection and elimination of zones to be produced based on its fluids mobilities. Thus, MRI serves well in the selection of hydrocarbon producing intervals.
This paper discusses the effectiveness of applying the MRI technology in characterizing the reservoir fluid properties in the El Furrial field, East Venezuela. It also highlights the value of this technology in minimizing the cost of mis-identified zones for production or testing by identifying best candidate intervals. Verification of the MRI results with actual production testing and/or formation pressure measurements will be demonstrated in the article.