bluuebunny/crossref_metadata_2025_split huggingface dataset:
OTEC Commercialization Challenges
Authors: Cooper Dennis , Meyer Laurie , Varley Robert 
Published: July 2009

Abstract
An industry and university team is developing ocean thermal energy power plant designs to provide baseload, renewable electricity to commercial power grids and to Department of Defense base grids. This paper provides some general thoughts on OTEC commercialization challenges. A brief description of OTEC and a view of the market are provided. Based on two years of design efforts and market assessments, challenges in technology, economics, and risk are discussed. No technology barriers are evident at this time. OTEC can be affordable though much work remains to be done. Because OTEC has not been commercialized nor has been demonstrated by anything approaching megawatt scales, a megawatt scale pilot plant is necessary to validate performance and cost for subsequent availability of financing for commercial applications.
Intelligent Well Completions in Agbami: A Review of the Value Added and Execution Performance
Authors: Adeyemo Kunle Mojeed , Aigbe Chris , Chukwumaeze Ikenna Chibuzo , Meinert David , Shyrock Steve 
Published: July 2009

Abstract
Application of Intelligent Well Completion (IWC) technology has continued to grow within the industry even in the face of perceived risks associated with installation and longevity of the system. In Agbami, where 80% of the development wells are planned with IWC installations, understanding these risks played a key role in justifying intelligent completions. This paper will present the methodology used to quantify the realizable value from zonal control and data acquisition, and review the execution performance for the initial IWC wells.
The Agbami field is Chevron's first operated deepwater asset in offshore Nigeria. It is located 70 miles offshore of the Niger Delta in ~5000 feet of water. The subsurface is characterized by a double-plunging anticline structure with a thrust fault along the main axis and multiple flank normal faults dividing the three major reservoirs into five or six main producing areas. Each major reservoir is vertically subdivided into 3 or more sub-reservoirs. The field is being developed with 38 wells, consisting of 20 producers, 12 water injectors and 6 gas injectors spread over 3 development drilling stages. Pressure maintenance will be via peripheral Water Injection and produced Gas Re-injection.
The production facilities include full Subsea infrastructures (trees, manifolds & flowlines) producing to a Floating Production, Storage, and Offloading vessel (FPSO).
The Agbami wells are typically completed in multiple zones of the same reservoir. The completed zones are geologically in pressure equilibrium, but vertical and lateral/cross-fault connectivity under dynamic conditions is still very uncertain. Given this uncertainty, the water and gas flood-fronts are likely to advance at different rates through the reservoir. To optimize field performance and recovery, Intelligent Completions with downhole control valves are being installed in Agbami wells. The system will provide zonal information and control of production and injection into the completed sub-reservoir zones.
SS: Panel: Structuring Projects to Benefit Multiple Stakeholders - How IOCs, NOCs and service Companies Can Collaborate to Create Stakeholder Value and Promote Local Development
Authors: Ross Chris 
Published: July 2009

Preface
This manuscript is intended to set the stage for a panel discussion, " Structuring Projects to Benefit Multiple Stakeholders—How IOCs, NOCs and Service Companies Can Collaborate to Create Stakeholder Value and Promote Local Development??, scheduled for Tuesday, May 5th, 2009. The panel participants include:Emmanuel Engelmann, Vice President of Technology, TotalWolfgang Puennel, Group Vice President, Global MarketingDean Slocum, President, Acorn International
And the moderator, who gratefully acknowledges the materials provided by the panelists and their predecessors Jean-Marie Guillermou of Total and Keith Morley of Weatherford in preparing this paper:Chris Ross, Vice President, CRA International

Theme
The large international oil companies (IOCs) are finding it difficult to gain access to resources under traditional terms. The citizens and national governments of several resource rich countries have become frustrated by their failure to translate oil revenues into lasting economic benefits for their nations. Increasingly, contracts awarding access to resources include provisions requiring a growing level of local content in capital and operating expenditures as well as programs to build local capabilities. Some awards go further and include an obligation to invest downstream of the resource development project. Some internationalizing national oil companies (INOCs) have been assisted by government to government agreements to invest in infrastructure development in the host country.
This panel will outline the expectations of government and society in resource rich countries, describe the issues as seen from the IOC perspective, explore the tension between global expertise and local content in the provision of products and services, and describe a model for building capacity in local suppliers.

Resource Rich Country Needs
The needs of resource rich countries vary widely according to their stage of development. Norway, for example, is fully developed and has successfully leveraged its resources into national economic development. According to Helge Lund, CEO of StatoilHydro: " I think most people regard the Norwegian model as maybe one of the most successful ways of organizing oil and gas activities to benefit not only the general public and government finances but also to build a strong oil and gas company and a strong service industry.?? Brazil voluntarily opened its upstream oil sector to attract competition, and privatized Petrobras, which has become a globally respected for its deep water competencies. Brazil also is developing a capable service sector. The needs of Brazil and Norway are to continue to attract competition with new ideas on resource discovery and development who will also be good citizens and customers for their service sectors.
SS - Sakhalin I: Managing a PSA Environment in Russia - A Success Story
Authors: Flood Jim , Harding Stephen J. 
Published: July 2009

Abstract
The Sakhalin-1 Project is a world-class development located in a remote, harsh environment off the east coast of Sakhalin Island, Russia. The first phase of the development was the Chayvo field, which has been successfully executed with full production achieved in late 2006. The Project presented multiple challenges, including the harsh sub-arctic climate, a remote location with minimal existing infrastructure, limited availability of skilled labor, and a complex and extensive regulatory regime. This paper provides an overview of the Project with an emphasis on the Phase-1 development of Chayvo field and describes the challenges, presents some of the key project management steps implemented to successfully address these challenges, and summarizes some of the benefits to Russia and the local community. This paper also serves as an introduction to the following Sakhalin-1 papers that address specific topics in greater detail.

Sakhalin-1 Background
The Sakhalin-1 Project is a world-class development opportunity, one of the largest single foreign direct investments in Russia, and an excellent example of how advanced technological solutions and front-end execution planning can be applied to meet the challenges of growing worldwide energy demands. The development consists of multiple offshore fields off the east coast of Sakhalin Island, Russia. Development of these fields is challenged by the presence of seasonal thick ice, gail-force winds, and the year-round potential for severe waves and seismic activity. The successful completion of the Project required the use of innovative technologies, disciplined management processes, and high levels of environmental and safety protection.
SS: Sakhalin-1: Project Execution Risks and Management
Authors: Roxburgh Sam , Kostiuk E.A. 
Published: July 2009

Abstract
Phase-1 of the Sakhalin-1 development serves as an example of how to successfully address the multiple challenges associated with working in a frontier environment with limited infrastructure. This paper highlights how the project managed the technical, execution and environmental challenges it faced as it developed the resources at Chayvo field.
A detailed front end execution planning effort identified execution risks and was used to develop plans to mitigate those risks. Major outcomes of this effort included an execution schedule that would allow use of the weather windows provided by the arctic region; winterization plans to continue construction progress during the winter months; the use of large modules built in a fabrication yard versus stick building on site and implementation of a " plug and play?? concept to maximize commissioning at the fabrication yard and minimize start-up in the field.
The project also managed the challenges associated with a complex regulatory regime, limited existing infrastructure, limited skilled labor and difficult logistics. All the challenges faced by the Sakhalin Phase-1development were successfully managed by the integrated project team. This fostered the development of execution strategies that lead to the ultimate success of the project. Lessons learned from this project can be applied at other projects in challenging frontier regions, particularly those in arctic environments with limited existing infrastructure.

Introduction
The Sakhalin-1 concession area, located along the east coast of Sakhalin Island, Russia, consists of the Chayvo, Odoptu and Arkutun Dagi fields with recoverable resources in excess of 2.3 billion barrels of oil and 17 trillion cubic feet of gas. The Sakhalin-1 Consortium consists of ExxonMobil affiliate Exxon Neftegas Limited (ENL) (30%, operator), SODECO (30%); ONGC Videsh Limited (20%); and two affiliates of the Russian national oil company, Rosneft (20%).1 The Consortium successfully completed the Phase-1 development of the Chayvo field with first production in late 2006, approximately 10 years after the signing of the Production Sharing Agreement.
SS: Canadian: Atlantic Development: The Sydney Basin of Eastern Canada An Overlooked Carboniferous Basin with Demonstrated Petroleum Potential Thoughts, Facts and Musings
Authors: MacDonald D. Jack 
Published: July 2009

Introductory Comments
The Sydney Basin represents the most easterly extent of the upper Paleozoic fill of the much larger Maritimes Basin of Atlantic Canada (Figure 1). Thick sequences (12 km+) of mid-Devonian to Upper Carboniferous / Permian sediments include thick non-marine, multi-storied sandstones, extensive limestones and thick salt overlain by multistoried fluvial sands and coal measures. It is worth noting that a significant portion of Canada's light oil and gas output comes from Paleozoic reservoirs, and over 20% of world oil reserves originate in Paleozoic reservoirs. (Enachescu, M.E, 2006)
The Carboniferous sediments of the Maritimes Basin have been productive since the very early 1900's with both oil and gas being produced over an 80+ year period from the Early Carboniferous rocks in the neighbouring province of New Brunswick. Corridor Resources of Halifax has been producing natural gas from the McCully field in New Brunswick from these same sediments since 2003. That field is now connected to the Maritimes & Northeast Pipeline which provides some 400+ mmcf/d to markets locally and to the northeastern U.S. Corridor has also made a significant discovery of oil in sandstone lying beneath as well. Oil shales are found in New Brunswick, Nova Scotia and Newfoundland. Stealth Ventures Ltd. has committed to eastern Canada's first coalbed methane production agreement in the Cumberland Basin of western Nova Scotia. One nearshore well drilled just in the same rock units on the western side of Cape Breton Island, Nova Scotia yielded gas rates of 5.5MMcf/d. Shale gas has been evaluated in Nova Scotia with independent estimates suggesting that some 63 trillion cubic feet (in place) may exist in only one of several basins where the shales are known to occur. On June 24, 2008 Elmworth Energy Corporation submitted a development plan as part of their application in accordance with requirements for a shale gas production agreement. In each case sited, the mentioned resource has both its source and reservoir unit within the Carboniferous interval. Some fifteen companies are currently exploring for, or are developing, Carboniferous reservoirs in the Maritimes Basin of Atlantic Canada.
SS: Unlocking the Unconventional Oil and Gas Reservoirs: Utilization of Real Time Microseismic Monitoring and Hydraulic Fracture Diversion Technology in the Completion of Barnett Shale Horizontal Wells
Authors: Waters George A. , Ramakrishnan Harihan , Daniels John , Bentley Doug , Belhadi Jamel , Sparkman Deane 
Published: July 2009

Abstract
It is now well documented that hydraulically fractured horizontal wells are effective at stimulating shale reservoirs. Most commercial shale wells utilize cement or open hole packers to achieve some form of annular isolation. With annular isolation now commonly accepted, the general evolution of these completions has been to stimulate ever shorter sections of the lateral with multiple perforation clusters placed closely together. The objective being to create closely spaced fractures, thereby increasing the reservoir contact area that more effectively imposes a pressure drawdown within the ultra-low permeability reservoir, resulting in a higher recovery factor.
The heterogeneous nature of unconventional shale reservoirs makes achieving a complex, closely spaced fracture network problematic. Frequently, geologic structure impacts the created fracture network to such a degree that fluid entry points into the reservoir are of secondary importance. Horizontal well evaluation can be utilized to optimize perforation placement and fracture staging for near-wellbore fracture geometry generation. This has proven to improve well performance. An additional productivity step can be achieved if the far field fracture geometry can be influenced by techniques other than perforation and fracture staging, especially if this technique can be applied in real time during the stimulation treatment.
One method that has been successful at altering the created hydraulic fracture geometry is real time microseismic fracture mapping coupled with fracture diversion packages incorporated into the fracturing treatment. Evaluating microseismic events in real time allows one to determine the need to change the fracture geometry being generated. The introduction of diversion packages to achieve this fracture geometry alteration can immediately be evaluated for effectiveness via the microseismic activity. This feedback allows the completions engineer to appropriately use these diversion packages so that effective stimulation along the whole lateral can be achieved.
Examples of the use of real time microseismic fracture mapping and fracture diversion packages are shown from the Ft. Worth Basin Barnett Shale formation. Both initial well completions and recompletions are shown. The importance of integrating well, geologic, log, and seismic information, is emphasized so that decisions can be made effectively in real time using the microseismic activity from the treatments. These examples demonstrate that hydraulic fracture geometries can be influenced by the introduction of these diversion packages. Resulting well productivity and fracture pressure responses validate the effectiveness of this real time diversion and evaluation process.
SS: Unlocking the Unconventional Oil and Gas Reservoirs: The Effect of Laminated Heterogeneity in Wellbore Stability and Completion of Tight Gas Shale Reservoirs
Authors: Suarez-Rivera Roberto , Deenadayalu Chaitanya , Yang Yi-Kun 
Published: July 2009

Abstract
Unconventional shale-gas reservoirs are complex systems with predominant layered heterogeneity. This results in high variability in material properties and in considerable contrast in mechanical and elastic properties along orientations parallel and perpendicular to bedding. Understanding the effect of this variability in strength and elastic properties with bed orientation, to hydraulic fracturing breakdown pressures, height containment, and long-term stability of wellbores and perforations, are of highest interest to unconventional, shale gas, reservoir applications. Successful hydraulic fracturing is fundamental for economic production from nano-darcy permeability gas shales. By incorporating anisotropic elastic deformation, to better represent the behavior of unconventional tight gas reservoirs, we facilitate the understanding of nearwellbore stress concentrations and their effect on fracture initiation. Results show that strong elastic anisotropy results in lower breakdown pressures and lower tortuosity at the wellbore face. As a consequence, selecting perforating intervals along sections with highest elastic anisotropy minimize fracture initiation problems, and results in lower treating pressures. In addition, elastic anisotropic behavior influences the magnitude of the minimum horizontal stress and the potential for fracture containment. Traditional isotropic-rock models do not capture this behavior. When applied in anisotropic formations these models misrepresent the potential of fracture containment. This leads to erroneous selections of perforation intervals (vertical completion) or landing depths of horizontal wellbores. A third consequence of strength and elastic anisotropy is the high risk of wellbore stability during drilling. In rocks with changing elastic moduli and strength with bed orientation, the highest risk of wellbore failure often occurs during building angle from the vertical to the horizontal directions. Along this path, there is a critical angle, defined by the strength anisotropy of the rock that will maximize the risk of failure. Minimizing this risk, e.g., by controlling the mud weight or well inclination, is of principal importance to the economic success of the play. In this paper we conduct numerical simulations on unconventional gas shales, exhibiting moderate to strong elastic and strength anisotropy, to evaluate the effect of their anisotropic behavior on well construction and completion. We also show that traditional isotropic models may lead to erroneous completion decisions, and underestimating the risk of wellbore failure. We conclude by suggesting that modeling and predicting near-wellbore effects of horizontal completions and wellbore stability in anisotropic shales is straightforward, provided that appropriate measurements of anisotropic strength and elastic properties are obtained on each of the various lithofacies present in the system.
SS: Offshore Floating LNG - LNG FPSO Development - bringing two industries together
Authors: Meek Harke Jan , Cariou Herve , Schier Marc 
Published: July 2009

Abstract
Floating liquefaction solutions are receiving growing interest lately as they are seen as potential enablers to un-lock and monetize offshore gas reserves that are currently considered stranded.
Although Onshore LNG liquefaction facilities and Offshore Oil&Gas FPSOs are each successfully proven in operation, combining the two technologies into a LNG FPSO poses new technical, organizational, execution and economical challenges to the industry that have to be properly addressed to be able to successfully implement a first of a kind concept.
Having to integrate two distinctly different industries during design, execution and operation, and the LNG FPSO concept not being operational to date yet, being technically quite complex and capital intensive, it is essential to have a well-balanced, reputable, strong and experienced team to develop and execute such a project. It is hence critical that organisations involved in the execution concentrate their efforts and leverage complementary skills, capabilities and track records to make the LNG FPSO project a success.
Important aspects of a LNG FPSO are the space constraints and the location of operation. Contrary to an onshore LNG plant, space is very limited on the LNG FPSO and utmost care and creativity is required to arrive at a safe, constructible, operable and maintainable topside configuration. Any LNG FPSO concept shall find a good balance between efficiency and simplicity to safeguard the reliability of the facility.
SBM and Linde have approached the development challenge by operating as one fully integrated team during the complete project development, which allows us to manage critical interfaces and leverage each other's complementary expertise in the best possible way. The so-called Generic LNG FPSO design uses only proven components and can handle a wide range of gas compositions. The flexibility of the concept is achieved by designing the layout and weight requirements for the most conservative scenario in the design envelope. The generic design can subsequently quickly be tailored for a specific field application.
Having finalized the FEED phase of the generic LNG FPSO concept and the associated detailed CAPEX estimate by the end of September 2008, SBM/Linde believe that a mid-scale LNG FPSO is a technically and economically feasible concept that can unlock value of gas reserves that are currently considered stranded.