bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prediction of Rock Mechanical Properties from Wireline Data and their Use in Drilling Simulation
Authors: Cooper George A. , Hatherly Peter 
Published: December 2007

Abstract
We have used wireline log data to derive rock strength and abrasivity as a function of depth for a well. This information was fed to a computer-based drilling simulator that was then used to drill the well in simulation using the same operating parameters as had been used in the field.
Comparison of the field and simulated rates of penetration and states of wear of the bit for different bit runs showed close agreement. This demonstrated not only that our technique for deriving the rock-mechanical strength and abrasivity values from the geophysical data was correct, but also that the drilling mechanics algorithm in the simulator was able to match the drilling performance in the field.
We believe that when the simulator is tuned in this way to reproduce field drilling behavior, it may be used to investigate different drilling scenarios with the objective of finding the most desirable conditions for drilling a future well in a similar geological environment.
Physics-based Reconstruction of Sedimentary Rocks
Authors: Jin Guodong , Patzek Tad W. , Silin Dmitry B. 
Published: December 2007

Abstract
We develop a depositional model that reconstructs numerically the geometrical structure and mechanical properties of natural sedimentary rocks in two and three dimensions. Our emphasis is on unconsolidated sands and sandstones. Our model has the following distinctive features: (1) it accounts for the dynamic geologic processes of grain sedimentation and compaction, and the diagenetic rock transformations; and (2) it reproduces the mechanical rock properties. The main input parameters are the grain size distribution, the final rock porosity, the type and amount of cement and clay minerals, the coefficient of friction, the bond strength parameters, and the grain stiffness moduli. The initial grain shapes are circular in 2D and spherical in 3D. Our depositional model can also be used to study the initiation, growth, and coalescence of micro-cracks in the rock. The proposed approach makes it possible to model the accumulation of rock damage and fracture propagation. The development of micro-cracks in, for example, a 2D marble rock model is studied under increasing vertical stress. Both the box fractal dimension of the micro-crack distribution and its variation with the applied stress are estimated.
Developing and Using Slimhole Rotary Steerable Systems in the North Sea Changing the Economics of Mature Asset Drilling
Authors: Kuyken Chris , van der Plas Klaas , Frederiks Kees , Williams Mike , Cockburn Colin 
Published: December 2007

Abstract
Slimhole drilling has long been regarded as means to reduce drilling costs and environmental effects through economies of scale and reduction of produced drill cuttings. However, its potential benefits have often been lost because of poor drilling performance and lack of well-placement capability in smaller holes. This is particularly true of brownfield environments, such as the North Sea, where tortuous multiple-target well paths require accurate and predictable directional capability in often-depleted reservoir sections. The development and effective deployment of a slim-hole rotary steerable system, (RSS), has changed this dramatically. Since initial field-testing in mid-2002, more than 30,000 ft of 6-in. hole has been drilled in the UK Continental Shelf alone. Performance has been exceptional, with average timesavings of over 60% compared with conventional drilling systems. Typical of this are wells on Shell U.K. Exploration and Production, (Shell Expros'), Brent and Cormorant Alpha fields, where up to 4850 ft has been drilled with near perfect well placement in a single run. Continued reduction of mature asset well costs through successful applications like these makes slimhole mature asset drilling economic and has the potential to extend drilling activity, field life and hence increase the ultimate recovery of the field.
Smørbukk Field: Fluid Modelling and Upscaling Issues to Simulate the Gas Cycling Process in Lower Tilje Formation
Authors: Pedersen Cecilie , Thibeau Sylvain 
Published: December 2007

Abstract
Smørbukk is an oil and gas condensate field, part of the Åsgard development in the Norwegian Sea in Norway.
The field consists in a vertical succession of various reservoirs of Jurassic age. Most of these reservoirs are layer cake, with sand bodies with several kilometers of horizontal extension versus only a few meters thickness. Lower Tilje formation consists of a volatile oil with a liquid rich gas cap.
The development scheme consists in two phases: A gas cycling period, currently taking place, with injected gas coming both from field produced gas and imported gas;A blow down phase, including gas back-production from the initial injectors.
In a previous paper, it was demonstrated that: –Without specific upscaling techniques, the two production phases request a different definition of the net to gross, leading to difficulties to simulate the entire production period;–The gas-oil ratio developments at the producers are highly sensitive to how the reservoir layering is derived from the heterogeneity captured at the wells.
The relevance of that work was limited, due to a simplified fluid description (live oil / wet gas fluid model) that could not accurately simulate the various processes taking place during a gas cycling scheme.
This paper presents new results, obtained with a compositional description of the fluids using an equation of state.
The key results are: –A comparison of various techniques to derive live oil / wet gas fluid models from the compositional one, and the implications in term of reservoir simulation results;–The set up, validation and implementation of an upscaling technique based on a comprehensive review of the physical phenomenon taking place in the reservoirs;–The fact that, using this technique, both production phases can be modeled consistently.
Otter - A Challenging Marginal Oil Field Development
Authors: Boyne Kevin , Horn Mark , Bertrane Didier , Fournie Francois , Cooper Terry , Quinn Patrick , Coudeville Fred , Buchan David , Allan Ken , Arnott Stuart 
Published: December 2007

Abstract
The Total E&P UK operated Otter Field is located in 184 m water depth in block 210/15a in the Northern North Sea area (partners Dana, Exxon Mobil and Shell Expro). It came onstream on schedule in October 2002, with a plateau production rate of over 30 000 bopd being achieved in May 2003. The economic development of this field has only been possible by using a combination of innovative drilling techniques, production technology and process systems to overcome the technical challenges posed, combined with the maximum use of existing infrastructures, to minimise Capex investment.
The three production wells are fitted with dual Electrical Submersible Pump (ESP) systems (a subsea first) and the total tieback distance is 21.5 km (a world record for ESP assisted tiebacks). These dual pump systems will allow significant production acceleration and improved recovery, while retaining lift redundancy and operational flexibility.
The Otter oil is exported in multiphase flow via Eider to North Cormorant. Both platforms are fitted with state of the art, minimum facility slug control systems. Eider will continue to operate in "lighthouse" mode (6- 8 personnel on board), a mode of operation developed by the Eider operator to extend field life by minimising field Opex. Prior to the sanction of the Otter project, it was planned to decommission Eider in 2005. Using Eider as a host for Otter has extended field life by around 5 years, increasing reserves recovery and deferring decommissioning expenditures.
The Otter development is therefore a successful example of a technically innovative and collaborative approach between the subsea tieback and host platform /infrastructure operators, partners and workforce. It provides a model for the future extension of North Sea Production, by using existing infrastructure, sharing expertise, and minimising costs.
The paper describes the Otter Development project and will focus on the technological innovations that have been deployed as part of this project, namely the subsea tie-back with downhole dual ESPs in the wells, the related flow assurance issues and mitigating measures (slug control systems, use of Kinetic Hydrate Inhibition facilities), their installation and other modifications required to accept Otter on the space constrained host Shell platforms. It also discusses the technical, commercial, contractual and risk management methodology employed by Total E&P UK during the project definition and sanction stages to facilitate the successful launch of this pioneering development.
Enhanced Oil Recovery by Retrofitting Subsea Processing
Authors: Rasmussen Andreas W. 
Published: December 2007

Abstract
A short presentation of subsea processing with focus on the most important drivers that would give high NPV on a prospect.
Operational experience from the world's first subsea processing station on Troll.
Status from the ongoing Demo2000 project - Subsea Sand Management
Learnings and experience from a JIP in subsea processing with recommendations to how to cooperate between oil companies and supplier industry (AkerKværner, ABB, BP ChevronTexaco).
Promoting Real-Time Optimization of Hydrocarbon Producing Systems
Authors: Saputelli L. A. , Mochizuki S. , Hutchins L. , Cramer R. , Anderson M. B. , Mueller J. B. , Escorcia A. , Harms A. L. , Sisk C. D. , Pennebaker S. , Han J. T. , Brown A. , Kabir C. S. , Reese R. D. , Núñez G. J. , Landgren K. M. , McKie C. J. , Airlie C. 
Published: December 2007

Abstract
The term "Real-Time Optimization" (RTO) has rapidly found its way into common usage in the oil and gas industry, as it already has in many others. However, RTO in the oil and gas industry is usually used more as a slogan rather than describing a system or process that truly optimizes anything at all, let alone does so in real-time.
In this paper, we describe what RTO means in the exploitation of hydrocarbons and what technologies are available now and are likely to be available in the future. We discuss how it is misunderstood and what real financial benefits await those who adopt it. Furthermore, we are working toward developing a method of classification to allow us to establish where a field operation lies on the RTO ladder, and to help plan a strategy to generate the benefits that moving up the RTO ladder can offer on specific fields and assets.
The paper also describes a new SPE Technical Interest Group (TIG), explaining why it has been formed, and outlining its objectives and some planned deliverables.
Leadership And Performance Management: The Key To Exploiting Hidden Returns
Authors: MacLeod Andrew 
Published: December 2007

Abstract
The structure of the North Sea oil industry, with its extended supply chains and high reliance on contracted out services, has provided an ideal environment for sub-optimal performance to develop, become accepted, and form part of our culture. Partially due to a lack of clarity and agreement on performance goals, and partially due to under-developed management and leadership skills, this inefficiency now provides "hidden returns" for operators, waiting to be exploited like untapped reserves.
Whether introducing new technology, or seeking to maximise the value of existing strategies, organisations are now recognising that it is the practices and behaviours of their personnel that determine whether their full potential is realised.
This paper describes some of the factors that inhibit performance within the oil industry and offers a methodology for continuously improving efficiency and financial returns. Two case studies are presented, demonstrating the effectiveness of the process in practical situations.
The Northwest European HSE Case
Authors: Windhorst Gert-Jan , Richardson Jay , McLean Ian , Krahn Dennis 
Published: December 2007

Abstract
Moving rigs across North Sea borders is costly and inefficient. Thus, area regulators requested IADC's N.Sea Chapter cooperate on a Northwest European HSE1 Case.
The framework illustrates substantial drill crew input to identify hazards, assess risks, and maintain controls based on a decade of experience in stringent HSE regimes.
Life of Field Energy Performance
Authors: Svalheim Stig , King Dave C. 
Published: December 2007

Abstract
BP has, in collaboration with the Norwegian Petroleum Directorate (NPD), conducted an energy performance study based on life of field data's from the Norwegian Continental Shelf (NCS).
This paper shares lessons learned from this work, in terms of methodologies, energy performance, and measures to improve energy efficiency.
Key observations from the study: the energy performance level on the NCS is excellent, BP has developed a new tool that improves the understanding of energy performance and identifies where energy could be saved and commercial values created, energy consumption on oil producing platforms is fairly constant whereas the % energy consumed increases significantly as a field matures.
Health Risk Assessment And Health Monitoring
Authors: Sætersdal Lars , Skeggs John 
Published: December 2007

Abstract

A theoretical and practical model that combines the two and its implementation on three mobile drilling installations offshore
Monitoring the health of employees in order to detect possible long-term effects of adverse working environment conditions has been a task for several years and is also a regulatory requirement related to a systematic follow-up of the working environment in the petroleum industry.
To design a model that effectively combines the results of working environment exposure data and possible adverse health effects, and at the same time being the practical tool we have been looking for as an occupational health service team, has been a major challenge for us for a long time.
The theoretic approach we chose has been similar to the safety risk analysis models, but the terms probability of events and the event severity (consequence) are replaced with exposure level and potential health effect severity. We also introduce the term "health-risk score" which is the product of the two above mentioned elements.
This health risk score triggers off different actions. These include the possible need for follow-up exposure measurements in the working environment, an evaluation of the use of personal protective equipment, the need for further education/training among the employers/employees and, of course, -what kind of specific measures are to be chosen and included in the health monitoring programme and at which intervals.
To support our work we have developed a software programme which is of major importance in combining all the results of the actual working environment exposure data and keeping record of the health monitoring programme for the different departments and employee categories in a company.
We strongly believe that this approach benefits both the company in its aim for a systematic follow-up of the working environment, and it gives us, as their partner in the QHSE field, the practical tool we have been looking for.
In 2001 we started the process of implementing this model in a company we have been collaborating with as an occupational health service for several years. This company is an oil drilling company managing three mobile installations in the North Sea.
We will present how the practical implementation took place and the experience so far.
Improving Fundamental Safety of Xmas Trees and Wellheads for Platforms
Authors: McKenzie J. , Webb P. , Copland M. 
Published: December 2007

Abstract
This paper outlines the principles and actual learning from the whole process of designing the inherently safer production Xmas Trees and wellheads and highlights the benefits of early consultation with the regulator during the design phase of a project. The paper demonstrates how to reduce the risks to individuals by the rigorous application of good engineering practice.
Strategic Value of a Systematic Energy and Greenhouse Gas Management System
Authors: Nordrum Susann , Duff Alexandra , Lee Arthur 
Published: December 2007

Abstract

Description
ChevronTexaco believes that global climate change is an important issue and is taking action to address it in a comprehensive way. We recently made publicly available our corporate-wide system for estimating greenhouse gas emissions and energy utilization. This paper specifically focuses on the advantages of using a systematic, auditable energy and greenhouse gas (GHG) management system in a mature oilfield. Material in this paper is based on our experience in using Chevron Texaco's SANGEATM Emissions Estimating System at upstream locations in the North Sea and worldwide.

Results, Observations and Conclusions
A credible, systematic approach, such as the SANGEATM Emissions Estimating System, provides strategic value to mature fields that are facing increasing constraints on greenhouse gas emissions and increasing energy costs. By having a rigorous and verifiable inventory of greenhouse gas emissions, operators can demonstrate to government and nongovernmental organizations how greenhouse gas emissions change over time as a field ages. In addition, energy utilization and greenhouse gas emission information can be used to guide investments, in order to achieve the maximum energy efficiency and greenhouse gas emissions minimization per barrel produced.

Applications
ChevronTexaco's new system, the SANGEATM Emissions Estimating System, is an automated, electronic data management information system that is designed to gather monthly energy and greenhouse gas emissions data from worldwide exploration and production, refining and marketing, petrochemicals, transportation and coal activities. ChevronTexaco Corporation and its Chevron, Texaco and Caltex facilities enter data to calculate greenhouse gas emissions and energy utilization on a monthly basis. Energy and greenhouse gas emission estimates are reported to ChevronTexaco Corporation each quarter.

Technical Contributions
The SANGEATM Emissions Estimating System is now publicly available. ChevronTexaco is making the system available free of charge in order to promote standardization of methodologies, and to improve comparability of greenhouse gas inventory information across the petroleum industry worldwide. We believe that widespread use of the SANGEA(tm) software will help provide a standard methodology for our industry. The American Petroleum Institute and several petroleum companies around the world have requested review copies of the software system.
Using TAML-3 Multilateral Technology to Deliver a Technologically Challenging, Fast-Track, One-Well Development in the Southern North Sea
Authors: Hay Bill , Horne Ken 
Published: December 2007

Abstract
As part of its exploration and development strategy of selectively developing resources in existing basins, BP has chosen to develop its Hoton field in the southern North Sea using a "normally unattended" satellite platform tied back to the West Sole pipeline system. To optimize volumes and drive efficiencies, BP has applied novel technologies, including multilateral completions, to the Hoton development.
This paper describes how the Baker Oil Tools HOOK Hanger multilateral completion system evolved during the recompletion of Hoton well 48/7 b-12 to provide a fit-for-purpose solution for the application. The paper also describes some of the many "firsts" achieved during the re-completion of well 48/7b-12 and describes how the well was successfully completed in a timely and efficient manner.
The Hoton field, operated by BP, lies 8 miles northeast of the West Sole field in North Sea blocks 48/6 and 48/7b. The field is composed of a tilted fault block structure with 918.6 ft relief on top of the Rotliegend formation, and bound on its southern, western and eastern flanks by faults. The southern bounding fault separates the Hoton Main area from a separate structure called Hoton SE.
Hoton well 48/7b-12 was drilled in 1996 as an appraisal / development well for the field, but lower than expected gas production rates resulted in the development being put on hold until technology had matured to a level that would better exploit the prospect. In 2000, careful appraisal of the Hoton prospect concluded that re-entering well 48/7b-12 and delivering a tri-lateral well would provide an economically feasible completion option. This conclusion assumed a one-well development tied to a monopod, minimal facility Normally Unmanned Installation (NUI): in summary, a technologically challenging, fast track-development.
In 2001, the Hoton 48/7b-12 well was developed as a Technical Advancement of Multilaterals (TAML) Level 3 well using the Baker Oil Tools HOOK Hanger system.
Applicability of Vapor Extraction Process to Problematic Viscous Oil Reservoirs
Authors: Karmaker Kulada , Maini Brij B. 
Published: December 2007

Summary
Production of heavy oil and bitumen from subterranean deposits is difficult, even under best of circumstances, due to very high oil viscosity. The recovery by currently used thermal based methods is more problematic and uneconomical for some of the reservoir scenarios, such as the reservoirs with an overlying gas cap, bottom water table, high water saturation, low porosity, low thermal conductivity, thin pay zone, vertical fractures and/or fissures, etc. Currently there is no proven recovery technique that can be economically applicable to such viscous oil reservoirs. However, there is a huge amount of hydrocarbon resource present in such reservoirs that can only be exploited with new concepts.
The Vapex (vapor extraction) process has recently emerged as a superior technology for the recovery of heavy oil and bitumen reservoirs. Recent research has shown that the process is highly energy efficient, environmentally friendly, causes in-situ upgrading, and requires low capital investment compared to its competitor SAGD process. The objective of this work was to evaluate the effectiveness of this newly postulated Vapex process to some of these problematic reservoir scenarios. An extensive experimental study has been carried out in a partially scaled physical model. Some experimental results, theoretical analysis, and the applicability of this process to such problematic viscous oil reservoirs are presented and discussed.