bluuebunny/crossref_metadata_2025_split huggingface dataset:
SS: Agbami Field Development: Agbami Project: People and Partnerships Delivering a World Scale Field Development
Authors: Bloomer Craig 
Published: July 2009

Abstract
The Agbami Project successfully commenced production in July 2008, ten years after the discovery of this world-class reservoir. Agbami represents one of Chevron Corporation's largest capital investments of the decade and the project achieved many outstanding results, overcoming various challenges along the way. This paper provides an overview of the project and discusses the key project objectives, strategies employed and some of the lessons learned, such as:establishing a world-wide incident and injury free culturebuilding the largest FPSO in the world and an extensive subsea production systemapplication of intelligent well completions for reservoir managementsetting new standards in Nigerian Contentachieving schedule objectives and production reliability in a challenging cost environment
Agbami is a unitized deepwater oil field offshore Nigeria. Star Deep Water Petroleum Limited, an affiliate of Chevron Corporation, is the operator of the Agbami Unit. It took partnership with the concessionaires, Nigerian National Petroleum Corporation, Famfa Oil Limited, and the other funding participants: Statoil Nigeria Limited, Petroleo Brasileiro Nigeria Limited, and Texaco Nigeria Outer Shelf Inc. (an affiliate of Chevron Corporation), as well as countless contractors and suppliers across the globe to achieve this remarkable outcome. Earning their support required a strong commitment to finding solutions, focus on interface management, and responsiveness to each stakeholder's interests.

Introduction
The Agbami field started production on 29 July 2008, a result of the efforts of a worldwide team of tens of thousands of people. In the ten years since the field's discovery, the project overcame a wide range of challenges to safely set new standards in Nigerian Content and expand technology boundaries. This paper, and related papers of the OTC conference, provides an overview of the project and highlights some of its accomplishments.

Discovery and Early Partnerships
The Agbami discovery in 1998 hailed as the largest oil field discovery of the year with estimated recoverable reserves exceeding 900 MM BBLs. The largest deepwater field in Nigeria extends across two blocks, OML 126 and 127, with Famfa Oil Limited and Nigerian National Petroleum Corporation as concessionaires. Star Deep Water Petroleum Limited (an affiliate of Chevron Corporation) is the Unit Operator, and Statoil Nigeria Limited, Petroleo Brasileiro Nigeria Limited and Texaco Nigeria Outer Shelf Inc. (an affiliate of Chevron Corporation) are funding partners. As an early signpost to the level of partnership needed to develop Agbami, after six years of appraisal and project planning, the parties established the first deepwater Unit Agreement in Nigeria in 2004. From that point onward, the Agbami project was on its way to production.
Low-Frequency Drill Bit Seismic While Drilling
Authors: Radtke Robert Paul , Fontenot John , Glowka David , Stokes Robert 
Published: July 2009

Abstract
A breakthrough has been discovered for controlling seismic sources to generate selectable low frequencies applicable to many seismic applications. All possible borehole pulsed sources, including hydraulically driven devices, explosives, and etc., by their very nature produce high frequencies. This is counter to the need for long transmission through rock. Specifically, we are reporting the application of an otherwise high frequency sparker source on the drill string for Drill Bit Seismic While Drilling (SWD). The low frequency source provides real-time imaging in deep (15,000 feet+) high-temperature (150°C) high-pressure (HTHP) wells ahead of the bit for accurate pore pressure determinations and geosteering, reservoir model verification, and near wellbore diagnostics. Furthermore, to have additional energy available at the drill bit can result in increased rates of penetration.

Introduction
It has been said, " The time is coming when we will not drill without looking ahead of the bit anymore than we would drive at night without headlights - occasionally shining a lamp to see what we hit.?? An alternative seismic source for the roller bit as it was being replaced by the PDC bit is something oil and service companies have sought since the early 1990's.
A breakthrough has been discovered for controlling seismic sources to generate selectable low frequencies (&lt; 40 Hz) applicable to many seismic applications. All possible borehole pulsed sources, including hydraulically driven devices, sparkers, explosives, etc., by their very nature produce high frequencies. This is counter to the need for long distance transmission through rock. Specifically, we have demonstrated the application of an otherwise high frequency sparker source which can be encorporated into a drill bit for Drill Bit Seismic While Drilling (SWD). The low frequency source, capable of creating selectable mid-band frequencies of 1 to 20 Hz, provides a source to perform real-time imaging in deep (15,000 feet+), high-temperature (150 degrees C), high-pressure (HTHP) wells for (a) geosteering, (b) accurate seismic hole depth, (c) accurate pore pressure determinations ahead of the bit, (d) near wellbore diagnostics with a downhole receiver and wired drill pipe, and (e) reservoir model verification. Furthermore, to have additional energy available at the drill bit for rock desintergation can result in increased rates of penetration.
SS: Agbami Field Development: Subsea Installation Contract, Overcoming the Challenges
Authors: Sanders David , Chauvin Frederic 
Published: July 2009

Abstract
The subsea installation contract (SIC) for Agbami was awarded by Star Deep Water Petroleum Ltd (an affiliate of Chevron Corporation) to Technip in May 2005. The scope of work included the design, fabrication and installation of nearly 100 km of flexible risers, flowlines and jumpers, and 45 km of static and dynamic umbilicals. It also included the installation of various Star Deep Water provided items including 12 piles and manifolds, 82 electrical flying leads and 51 hydraulic flying leads.
The project is in approximately 1,550m of water and represents one of the world's largest subsea installation contracts awarded.
The key logistical challenges for this very large project were to ensure the safe and timely delivery of the flexible and umbilical products, and the real time coordination of logistics associated with their transportation from Europe to Nigeria using a fleet of five heavy lift transport vessels and installation in the field. Installation had to be coordinated with the FPSO and other subsea contractors working in the field, as well as simultaneous field operations with drilling vessels throughout the installation phase. Additionally, working offshore Nigeria presented its own set of challenges including security and other operational constraints.
Of the technical challenges, the risers are the longest single section of flexibles to have been manufactured and installed to date. Production risers and flowlines may need to transport a mildly sour well fluid in the future, hence control of the permeation of hydrogen sulphide into the annulus was a significant issue that required an innovative design.
This paper will present an overview of the subsea systems employed for the Agbami field and outlines some of the particular challenges that the project team had to respond to, including:Flow assurance requirements and the consequent thermal performance required from the systemThe implications of potential sour produced fluid on the design of the flexibles.Scheduling of the installation activities around available windows including the early installation of piles, manifolds and static umbilicalsSuccessful offshore precommissioning of the production lines and associated control systems which were required for First Oil while continuing to progress the remainder of the installation programmeLogistics associated with transport of a very large quantity of products from Europe and delivery to Nigeria, along with the need for management of in-country logistical and safety support servicesThe constraints imposed by the available crane capacities and how they were resolved
SS: Canadian: Atlantic Development; Technological Advances to Assess, Manage and Reduce Ice Risk in Northern Developments
Authors: Randell Charles , Freeman Ralph , Power Desmond , Stuckey Paul 
Published: July 2009

Abstract
As the number of oil and gas players in Arctic and sub-Arctic regions increases, so do the suite of technology-based capabilities for cold region operations. Advances are being made in remote sensing, ice management, and ice engineering. R&D targeted to increase our understanding of the ice environment and ice mechanics is reducing uncertainties relating to ice loads. C-CORE and partners have been developing and providing technical solutions to most recent oil and gas initiatives facing the challenge of sustainable development in ice covered regions. Using this work as background, this presentation will highlight recent and imminent technological advances providing near-term improvement in the economics of cold ocean hydrocarbon production.

Background
Offshore oil and gas exploration began on the Grand Banks of Newfoundland in 1966 with the first major discovery, Hibernia, occurring in 1979. The discovery of Hibernia was the result of a joint exploration venture by Chevron and Mobil. Other major oil and gas discoveries on the Grand Banks followed with Hebron in 1981 and the White Rose and Terra Nova Fields in 1984. First oil was produced from Hibernia in 1997, Terra Nova in 2002, White Rose, 2005 with Hebron expected to be 2017-18. A number of R&D initiatives were undertaken in order to develop these resources safely and in the most cost effective manner possible. In the early 1980s comprehensive data collection programs were initiated by Mobil to develop a design basis for the Hibernia development (Dobrocky, 1984). Aerial surveys were conducted for above water iceberg characterization (size and mass) as well as iceberg profiling for below water geometry for mass. In 1996, Grappling Island iceberg impact experiments were carried out; the first ever iceberg impact experiments (Ralph et al, 2004). Research and development into ice mechanics and design load algorithms pioneered by Dr. Jordaan at the Ocean Engineering Research Center at Memorial University Canadian Offshore Design for Ice Environments (CODIE) project have made a tremendous impact in design for these harsh environments (CODIE I, 1997 and CODIE II, 2003). More recently, an improved understanding of ice mechanics and failure processes have led to an improved basis for global design loads based on a reduced iceberg pressure on large contact areas from 6.0 MPa used in the Hibernia design basis to a still conservative 1.5 MPa presently used for Hebron studies.
From 1999 to 2005, C-CORE led a comprehensive Ice Management R&D JIP addressing technology challenges relating to detection and towing. Research and development continues with improvements and optimized methods for ice management (detection, forecasting, threat analysis, decision-making and iceberg towing), the modeling of ice management effectiveness for design, and improved methods for iceberg collision and design load analyses.
SS: Canadian: Atlantic Development: The Value of Wellness
Authors: Wahl Mike Jonathan , Oneil Mike , Cooper T. 
Published: July 2009

Abstract

Description of the Proposed Paper:
The value of wellness paper is a comprehensive research review that proposes a conceptual model of the costs associated with high and low risk employees on an annual and career model. This model accurately addresses the variables specific to the oil and gas industry including the internal and external factors which must be addressed by the organization prior to engaging in wellness activities. This paper accurately portrays the specific costs by division as well as highlights the effect of wellness on safety as it relates to health as well as regulatory burden and license to operate.

Application:
This conceptual model provides the audience with the accurate costs, factors and concerns associated with wellness initiatives in remote environments. Several factors such as senior managements role, medical costs, replacement workers and re-training are relayed to the audience encompassing the full scope of wellness risk as it exists in the offshore.

Results, Observations, and Conclusions:
The value of wellness paper quantifies that a high risk employee can cost a company $125,000 per year if encompassing all high risk factors and up to 2.65 million dollars over the course of a career. This paper concludes that by adopting a wellness culture and controlling for wellness risk the organization can avoid serious costs and gain intangible advantages in regulatory burden, license to operate and brand equity and company loyalty.

Significance of Subject Matter:
Wellness may be a substantial contributer to both HSE and value to an organization. Companies controlling for wellness risk with a comprehensive wellness program will control costs, operational issues such as safety and license to operate as well as retain and maintain employees in a competitive aging job market.

Introduction
Organizations frequently ask wellness professionals specific questions around the cost of wellness. How much does it cost to run a ‘best practice’ wellness program, how much should our cost be relative to our risk in an approach to employee's wellness and are our current wellness arrangements cost-effective? The reason for focusing on cost is that financial directors, board members and human resources directors have all identified cost minimisation as a critical element in ensuring an efficient and effective approach to an employee's wellness as part of a wider human resources and operational strategy. The following document demonstrates that examining the cost of wellness is just one part of the equation. Organizations also have to examine the value a wellness program provides.
SS: Unlocking the Unconventional Oil and Gas Reservoirs: Potential for Oil Shale Development in the United States
Authors: Biglarbigi Khosrow , Killen James Curtis , Mohan Hitesh , Carolus Marshall John 
Published: July 2009

Abstract
The development of domestic oil shale resources has regained significant attention in the past few years. Several factors have contributed to this, including high oil prices, emerging recovery technologies, increasing world demand for liquid hydrocarbons, and the continued decline in U.S. conventional oil production. In recent years, several initiatives have been taken by the Federal Government and the private sector to encourage the development of a domestic oil shale industry.
The United States has vast deposits of oil shale - Nearly 2.0 trillion barrels across the eastern and western states. The development of this massive resource, however, is constrained, however, by a number of key factors including, but to limited to;resource access,technology,economics,environmental and regulatory issues, andinfrastructure.
A comprehensive analysis has been completed to review emerging oil shale technologies from 23 companies and identify options to accelerate the development of this resource. The analysis is based on a representative sample (about 70 Billion Barrels) of Western Oil shale resource divided among multiple development " tracts??. The presentation will present a summary of the technologies; including but not limited to emerging in-situ processes as well as traditional mining with surface retorting technology. Each development " tract?? was screened for the potential application of representative recovery technologies. A detailed economic evaluation was conducted for each " tract?? and the selected technology with consideration for development under alternative economics, environmental, technology, and socio-economic options. The analysis indicated that with a concerted effort from industry, local, state, and Federal governments, the oil shale production potential could reach 2.5 million barrels per day (MMBbl/d) with substantial benefits to the local and national economy.

Introduction
Oil shale is carbonate rock, generally marlstone that is very rich in organic sedimentary material called " kerogen.?? Oil shales are " younger?? in geologic age than crude oil-bearing formations; natural forces of pressure and temperature have not yet converted the sediments to crude oil. Kerogen can be converted to superior quality jet fuel, #2 diesel, naphtha, and other high value by-products. The kerogen content of " oil shale?? ore can range from 10 to 60 or more gallons of oil per ton2.
Worldwide, there are nearly 10 trillion barrels of shale oil resource. These resources are located in North America, South American, Europe, Middle East, North Africa (MENA), Asia, and Australia (Figure 1). Table 1 shows the resource for the top ten countries. Nearly 60% of the total resource is located in the United States with significant deposits in the western and eastern states.
Flow Assurance Challenge for Offshore Deep Water in Republic of Congo
Authors: Monahan Peter 
Published: July 2009

Abstract
Until now, offshore oil and gas production in the Republic of Congo has been restricted to the area covered by shallow water technology, up to water depths of around 200m. The Moho Bilondo development is the first deepwater development in these offshore Congolese waters and this paper presents the flow assurance issues that have been addressed during the design, construction, installation and start-up of this field.
The development comprises of production from the two reserves of Mobim and Bilondo. To meet the challenging project schedule the flow assurance aspects of the process design had to play their part and had to be both functional and robust. This paper presents the flow assurance issues that have been addressed during the development of the project.
The challenges for flow assurance fall into three categories. Firstly, the hydrodynamic issues had to be addressed. Bilondo oil is relatively heavy and requires gas lift injected downhole to achieve the desired recovery of reserves. At the same time, the down-sloping nature of the sea bed terrain from the Bilondo manifold can present the typical problems of induced slug flow regime. Management of the gas lift strategy was therefore key to the operating philosophy.
The thermal insulation performance to provide the required cooldown time for preservation had to be achieved for the entire subsea production system, so as to avoid the formation of hydrates during prolonged shutdowns. Making matters worse is the downhole supply of cold lift gas via the Xmas tree, which has a cooling effect on the production fluid in the tubing. An additional risk identified here was that of wax formation on the inner tubing wall. Significant finite element studies were performed on the Xmas tree wet insulation to achieve the desired thermal performance.
Thirdly, the risk to production by the formation of naphthenate soap deposits was also assessed. Steps were taken in the design of the topsides process and of the chemical injection strategy, dosing rates and injection points both subsea and on the topsides, to manage these risks.
Moho Bilondo Compact Development: Layout and Planning Management
Authors: Carrier Pascal 
Published: July 2009

Abstract

Moho Bilondo - Compact development: layout and planning management
During the concept studies of Moho Bilondo, it was decided to develop two reservoirs: BILONDO and the new reservoir MOBIM, discovered in September 2004. This development is considered as a compact field, due to small distance between the two reservoirs: only 4.6Km.
A flexible pipeline concept for flow lines and risers was selected in order to develop this field, which was capable of accommodating the flow assurance, and insulation (cool down time) requirements of the fields. In addition, this concept reduced the development costs.
The field layout is comprises two developments areas MOHO and BILONDO with a FPU (Floating Production Unit) moored in the middle of these two reservoirs. Each field is linked to the FPU by:–2 flexible production 8'' (flow lines + risers) in loop–1 GLU (Gas lift Umbilical)–1 E/H Umbilical
Water injection on BILONDO field is provided via a rigid pipe 8'' coming from NKF2 platform on NKOSSA field, and the water injection for MOBIM is perform by a flexible network from FPU desulfatation unit (flexible riser and flowline 8'' from FPU to ITA, and flexible flowline 6'' from the ITA to remote WI well).
When Failure is not an Option: Managing Megaprojects in the Current Environment
Authors: Westney Richard E. , Fort Joel , Lucas James , Messier Luc , Vardeman R.  Don D. , Renfro Kevin 
Published: July 2009

Introduction
This manuscript is intended to set the stage for the OTC General Session Panel discussion entitled " When Failure is not an Option: Managing Megaprojects in the Current Environment??, scheduled for Thursday, May 7, 2009. Members of this panel session are as follows:Richard Westney, Chairman, Westney Consulting Group (Panel Moderator)Joel Fort, General Manager, Yemen LNGJames Lucas, President & CEO, Luman InternationalLuc J. Messier, Senior Vice President - Project Development and Procurement, ConocoPhillipsDon Vardeman, Vice President -Worldwide Projects, Anadarko Petroleum Corporation

Summary
Megaprojects can be defined as projects that are so large that the conventional body of project and risk management knowledge is insufficient to ensure success. Given that significant overruns and delays on megaprojects are almost the norm, it appears that no one really has all the answers to meeting the special challenges of these huge projects.
Failure is not an option for most megaprojects. The level of investment, the magnitude of the cashflows involved, and the organizational commitment required are such that the impact of bad outcomes can be devastating to the operator, partners and host countries involved.
Megaprojects create challenges that, although now fairly typical, have not typically been addressed in the past. Given the relatively small number of past megaprojects, and their long duration, many executives and practitioners have limited or no experience with them - and the experience of those that do is often not the sort that one would wish to repeat. New approaches are needed, many have been tried, and a new body of knowledge is emerging for these very large projects.
The panel is made up of people who are very experienced in megaprojects, representing the executive and project manager points of view, the owner and contractor points of view, as well as the independent perspective of consultants. Rather than focus on success stories, the panel will focus on the most difficult / challenging / intractable aspects of megaprojects and, with extensive audience participation, discuss what has worked, what has not, and what is needed going forward in the current energy and economic environment. Participants will take away an improved understanding that will assist in their planning and decision-making.