bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Method For Coiled Tubing Installation
Authors: Simpson Pete , Hatton Stephen 
Published: October 2008

Abstract
Installation of flexible pipe for offshore developments is costly due to both the physical cost of the flexible pipe, and the expensive day rates and availability of suitable installation vessels. Considering the scarcity of flexible pipe in today's increasingly demanding and busy market, operators are seeking a cost effective solution for installing piping in a range of water depths using vessels which are readily on hand.
This paper describes a novel approach to installing reeled coiled tubing, from 1inch to 5inch diameter, from the back of a small vessel in water depths from 40m up to around 1000m. The novelty of the system is the fact that the equipment design allows it to be installed on even relatively small vessels of opportunity, such as anchor handling or installation vessels, from smaller, and cheaper quayside locations. Such an approach is the ideal solution to the problem faced by operators, in that it allows the installation of cheaper, readily available coiled tubing, from cheaper and more readily available vessels.

Introduction
Flexible pipe technology has developed rapidly in order to meet the increasingly demanding requirements of the offshore industry. As offshore developments have progressed into deeper and more demanding environments, flexible pipe manufacturers have been pressing to provide new flexible pipe technologies suitable to the task.
The natural advantages of flexible pipe over rigid pipelines make it the preferred solution for many shallow water developments, however, its convenience means that there is enormous demand for the product. Such is the market's demand for flexible pipe that flexible pipe factories are working at maximum production and long lead times and high prices are commonplace. Once produced, the pipe still needs to be installed and the available installation vessels are not only expensive, they are usually operating on long term contracts and must be booked months or years in advance.
However, there is an alternative to using flexible pipe for some offshore situations. Coiled tubing is a proven technology which has largely been forgotten by the industry after the advent of flexible pipe technology. This paper shows how it is still a viable and attractive alternative to flexible pipe, and can be installed cheaply and easily from the back of small vessels of opportunity.

Introduction to Coiled Tubing
As long ago as 1944 engineers were faced with deploying subsea pipelines using a reliable and easily deployable design. The project in question was how to supply the allied army with fuel oil after the D-day invasion. The pipes needed to be installed in as short amount of time possible after D-day, using whatever vessels and crew were available. The solution devised by British engineers was to lay twenty three 3?? pipelines across the English channel, varying from 30 to 70miles long (48km to 113km). The pipe was made in 4000ft (1219m) sections, butt welded together, stored in spools and deployed across the English channel.
LNG Imports Into North America and Implications
Authors: Juden Mike , Inglesby Tommy , Bodden Stuart 
Published: October 2008

Abstract
The need for LNG to fill the natural gas supply gap in North America may increase dramatically to 2015 and beyond as natural gas demand increases at rates higher than most observers expect. Developing CO2 legislation, increasingly advantaged gas-fired generation, oil sands demand, and biofuels demand could drive a greater than expected demand for natural gas domestically, with LNG imports expected to fill the gap.
However, LNG liquefaction is expected to continue to be short to 2015 and beyond. These shortages are driven by increasing liquefaction costs, contractor/crew shortages, reserve access issues, project delays, and the often overlooked increasing domestic demand in the LNG exporting counties. Increasingly, LNG contracts will include flexible diversion clauses allowing movement of LNG supplies to markets other than originally contracted markets. Although there is some baseloaded North American LNG, significant LNG is attracted to North American regas based on price/producer-net-backs when other regions have adequate supplies to meet needs. The trend toward greater LNG flexibility could strengthen the linkage in North American natural gas pricing to alternate fuels through competition with Europe for LNG volumes priced at residual fuel oil and eventually with Asian crude-linked LNG.
North America will compete with Europe and Asia for marginal LNG supplies unless European end users have over-contracted for LNG, which may well be the case. European and Asian end users, with based-loaded LNG, will retain LNG supplies, when needed, to fill supply needs irrespective of price. Over-contracted European LNG, if it were to flow to North America, would represent approximately 10 percent or more of U.S. and Canadian demand in 2010 and would go a long way in meeting a potential supply short-fall. With LNG at the margin, mechanisms impacting the level of North American LNG imports influence natural gas pricing, which in turn impacts gas producer and power generator profitability and company valuations.

Introduction
North American natural gas demand, domestic supply, natural gas price setting mechanisms, Atlantic Basin pricing dynamics, and contracting regulations and practices for electric and natural gas utilities all impact the level of LNG imported into North America. The resulting flows of LNG, especially into the U.S., have very significant implications for the global LNG trade, as well as substantial and far-reaching implications for producers, LNG developers, end users, and policy-makers.
Predicting When and Where Hydrate Plugs Form in Oil-Dominated Flowlines
Authors: Boxall John , Davies Simon , Koh Carolyn Ann , Sloan E. Dendy 
Published: October 2008

Abstract
This work provides a means to predict when and where hydrate plugs will form in oil-dominated flowlines. The method was funded by DeepStar and is based on a hydrate kinetic model, CSMHyK, developed over the last six years, which is currently an addition to the transient multiphase program OLGA by SPT (Scandpower) Inc. The predictions show good agreement to data for hydrate formation in three flowloops with five oils.
Recent CSMHyK-OLGA workshops have been held in Houston and Oslo, and major companies are beginning to use the program in flow assurance to predict where and when hydrate plugs will form in flowlines.

Introduction
Gas and oil sub sea production and transportation are moving to deeper developments where the temperature and pressure conditions are well within the hydrate stability region. The subsequent increased risk of hydrate formation requires new strategies in flow assurance. Traditional methods of thermodynamic avoidance are impractical or uneconomic due to the large amounts of thermodynamic inhibitor (e.g. methanol or monoethylene glycol) required to prevent hydrates from forming under these conditions [1, 2]. Transient operations are particularly problematic due to the temporarily extreme subcoolings under these conditions. The prediction of hydrate formation rates in these conditions is a major challenge requiring knowledge of the kinetics of hydrate formation, rather than only hydrate thermodynamics. The ability to predict the rate of hydrate formation in sub sea flowlines under restart and shutdown conditions is extremely valuable in establishing new operating procedures during transient operations and in flowline design.
CSMHyK is a subroutine module for the OLGA (SPT Group) multiphase flow simulator. Researchers at CSM in cooperation with the SPT Group have been developing the module since 2003. The model predicts the rate of hydrate formation using a first-order rate equation based on the thermal driving force. The rate equation was originally proposed by Vysniauskas and Bishnoi [3] in the absence of mass and heat transfer limitations. In order to accurately simulate hydrate formation in flowloops, it was necessary to reduce the intrinsic kinetic constant by a factor of 500 [4]. The adjusted parameter accounts for mass and heat transfer limitations in the flowloops. The current model assumes that the hydrate particles convert directly from emulsified water droplets. Nucleation is assumed to occur instantaneously at a subcooling of 6.5°F, a parameter proposed by Matthews [5]. Once formed, the model assumes that these particles remain in the oil phase. The change in relative viscosity of this phase is then found from the Camargo and Palermo [6] correlation for steady state slurry flow. An overview of the current CSMHyK module and its integration into OLGA is shown in Figure 1.
Installation-Driven Field Developments for Deepwater Subsea Projects
Authors: Dixon Mark A.J. , David Easter 
Published: October 2008

Abstract
At the concept select stage and certainly at the FEED stage of deepwater subsea projects the focus is often exclusively on optimisation of functionality during operation. For deepwater and particularly in the current market climate, however, the ‘best’ field development may need to satisfy other drivers. The ‘best’ solution does require knowledge and definition of what is considered of most value to the project whilst managing CAPEX and lowering risk.
Given that, for a Greenfield subsea development, approximately one third of the CAPEX is associated with the SURF (subsea umbilicals, risers and flowlines) package, and around one half of this cost is attributable to the offshore installation phase. Along with all the risk, there are strong commercial reasons alone for focusing on installability during all phases of the development cycle. Layering on top of this the shortage of capable vessels and their tight availability, the development scenario that provides a greater number of suitable vessels for offshore construction offers a more competitive bid phase, additional schedule benefits and lower risk as the subsea systems are that much more installable by design.
This paper illustrates how an installation-driven (or installation-focused) development process provides the necessary operational functionality for deepwater subsea projects by leveraging recent experience on a variety of projects from around the world.

1.0 INTRODUCTION
In a world of ever-increasing demand for hydrocarbons, the race is to tap the deepwater resources and get the production started as early as possible. For a deepwater subsea field development this leads to a fast-track approach and due attention is not given to all project drivers. At the concept select stage and certainly at the FEED stage of deepwater subsea projects the focus is often exclusively on optimisation of functionality during operation. For deepwater and particularly in the current market climate, however, the ‘best’ field development may need to satisfy other drivers. The ‘best’ solution does require knowledge and definition of what is considered of most value to the project whilst managing CAPEX and lowering risk.
Mitigating Flow Assurance Challenges Using Subsea Meters on Independence Hub
Authors: Joshi Nikhil B. , Buck Robert John 
Published: October 2008

Abstract
The Independence Hub development is a fifteen-well subsea tieback to the host capable of producing up to 1 bscf/d of gas production and associated fluids. The subsea architecture is designed to deliver the required amount of hydrate inhibitor (mono-ethylene glycol) to each well. This is done using a combination of subsea wet gas meters (SWGMs) installed in the well jumpers and subsea orifice valves installed with the subsea trees, in addition to topside MEG injection pumps and meters. The SWGMs measure the total gas, condensate and water production from the wells and these measurements are used to optimize the MEG injection requirements. In addition to the SWGMs and subsea orifice valves, subsea acoustic sand detectors are used to monitor sand production. A combination of these devices provides a robust methodology to mitigate any flow assurance challenges for this development.
The subsea architecture is such that a common MEG injection umbilical can deliver the required volume of MEG and chemicals to each well by using the information from the SWGMs and by controlling the subsea orifice valves. In addition to the CAPEX savings from avoiding a MEG injection line for each well, the use of SWGMs also provides accurate production measurements to conduct produced gas and liquid allocations. The wells producing to the host are of varied royalty regimes and ownership. The use of one SWGM per well provides the required measurements for allocation of production with minimal uncertainty.
The experiences from the Independence Hub operation are shared in this paper, especially related to the measurement of production from each well and optimization of chemicals using subsea orifice valves. Also, some of the operational challenges and lessons learned during startup and routine operations are addressed.

Introduction
The Independence Hub development started as a joint project between Independent producers to tap the reserves around the Mississippi Canyon 920 block. During the exploration and development phase, the hydrocarbons discovered were primarily dry biogenic gas with a condensate-gas ratio of less than 1 bbl/mmscf. Several independent E&P companies had discoveries in the vicinty (a summary is provided in Table 1 below). The E&P companies made a decision to jointly develop these fields to not only optimize CAPEX and OPEX, but to also use the best expertise in various areas of development to make the project feasible and successful. The Independence Hub semi-submersible platform receives production from these wells with a capacity to process up to 1 Bscf/d of hydrocarbon gas. It is located 123 miles southeast of Biloxi, Mississippi. The platform is operated by Anadarko and owned by Enterprise (80%) and Helix (20%). The Independence trail, owned 100% by Enterprise, is used to transport the gas and associated fluids from the platform to the shallow-water hub (West Delta 68). The wells and subsea systems are owned by the operating companies.
Analyses and Measurements of Conductor Response for Jack-up Drilled Wells in 110 m Water Depth in Harsh Environments.
Authors: Baerheim Morten , North Andrew , Steinkjer Oddrun 
Published: October 2008

Abstract
The analysis of conductor systems for wells drilled by jack-ups is often limited to analysis of the conductor alone as a free standing unit. This paper discuss the various aspects of the analysis of the whole conductor system and shows that the limitations in strength may be in the conductor itself, but in other parts of the system

Introduction
This paper deals with top tensioned drilling conductors that are drilled from jack-up platforms. The conductor system consists of an outer drilling conductor cemented to the sea bed and kept in tension by a tension system on the jack-up. The conductor is guided horizontally at the Texas deck. The conductor system also includes equipment connected to the conductor such as BOP, wellhead, packer and overshot system. The paper describes a conductor system typical for the jack-up rig used for the deep water drilling. Other jack-ups may have different systems, but the main message of this paper on total system analysis is still valid.

Conclusion
It is important to model all elements of the conductor system for deep water jack-up drilled wells. There are strength limitations in various parts of the system, and changing the strength or stiffness of one part may have negative effects on other parts of the system.

Analyses of the drilling conductor
The analysis of the drilling conductor need to include all components in the system. Typical components included in the analysis are:Seabed fixation (soil-pipe interaction modelled with springs)Conductor pipe with internal pipes (pipe to pipe contact modelled)Texas deck supportTension systemAdjustable landing ringWellheadBOPMandrelPacker / overshotDiverter
In addition, the jack-up movements must be input to the analyses.
Onshore Versus Offshore LNG Import Facilities - Commercial Advantages and Limitations
Authors: Danielsen Hans Kristian , Andreassen Goran 
Published: October 2008

Abstract
As LNG stakeholders assess whether and how to commit billions to re-gasification infrastructures, it is imperative that they address, early and meaningfully, the issues associated with commercial optimisation of their investments. Potential terminal developers face the option of moving offshore or stick with a traditional onshore development.
There have been large developments in offshore receiving terminal design, where many companies are hoping that new technologies can ameliorate the actual or perceived risks of a land-based location - that is, without introducing too many new dangers and challenges. Until Excelerate and Energy Bridge Floating Storage and Re-gasification Unit (FRSU) opened in the Gulf of Mexico, all LNG import terminals were land-based. FRSUs are now under construction to operate in Tuscany, Italy (using a refitted LNG carrier), Southern California (using a new, dedicated vessel), as well as Pecem and Guanabara Bay in Brazil.
This paper presents the learning from a number of site and concept selection studies. Through these early phases of project development there are commonly a limited number of parameters that are deceive for the concept that ultimately is chosen.
Typical concept differentiators such as; cost, lead time, technological maturity, asset risks and safety will be discussed.

Introduction
As LNG stakeholder assess whether and how to commit billions to re-gasification infrastructures, it is imperative that they address, early and meaningfully, the issues associated with commercial optimisation of their investments. Potential terminal developers face with the option of moving offshore or stick with a traditional onshore development.
There have been large developments in offshore receiving terminal design, where many companies are hoping that new technologies can ameliorate the actual or perceived risks of a land-based location - that is, without introducing too many new dangers and challenges. Until Excelerate and Energy Bridge Floating Storage and Re-gasification Unit (FRSU) opened in the Gulf of Mexico, all LNG import terminals were land-based. FRSUs are now under construction to operate in Tuscany, Italy (using a refitted LNG carrier), Southern California (using a new, dedicated vessel), as well as Pecem and Guanabara Bay in Brazil.
In addition to these sites which are in the construction phase, offshore import facilities have been considered as an alternative concept for a number of other sites. Experience from such studies is that a limited number of key parameters are decisive for concept selection in terms of offshore versus onshore.
Paraffin Cleanout in a Single Subsea Flowline Environment: Glycol to Blame?
Authors: Bailey J. Claire , Allenson Stephan John 
Published: October 2008

Abstract
Paraffin deposition was found in the RedHawk #2 subsea flowline and was successfully removed using a xylene slug swept by produced gas from the well. Testing indicated that the problem resulted from the interaction between glycol and produced condensate. Overtreatment with glycol and low produced water volumes contributed to the precipitation of paraffin and eventual plugging of the flowline.
The objective of this procedure was to clear the restriction by pumping a slug of xylene into the flowline and producing the well to carry the solids to surface. Glycol can react negatively with the condensate in some dry gas wells, resulting in paraffin precipitation. When there is sufficient water present to mix with the glycol the problem does not occur, however a lack of water causes the glycol to react with the condensate and form paraffin. Clearing the restriction would eliminate a pressure drop in the flowline, thus allowing the well to produce at optimal rate and prolonging the well's life. All work was performed from the host spar facility using temporary separation equipment and platform methanol pumps.
The RedHawk flowline restriction was successfully removed using two 25 bbl xylene slugs which were swept from the flowline with produced gas from the well. With the restriction removed, 982 psi of frictional loss was regained and the well was returned to optimal production. The deposition appears to be reoccurring, although at a much slower rate than before. However, any further reduction in glycol usage would not guarantee effective hydrate inhibition. Changing hydrate inhibitors is impractical due to platform equipment and annual cleanouts are a more cost effective option.
It is quickly becoming critical to develop means of cleaning single flowline systems with highly efficient and low cost methods. By understanding new problems that arise and putting new solutions into practice operators can extend the life of some wells and avoid significant downtime and workover costs.

Introduction
RedHawk is an Anadarko Petroleum Corporation operated cell spar located in 5300' of water in Garden Banks Block 876, about 177 miles southeast of Cameron, LA in the Gulf of Mexico. Devon Energy Corporation is a 50% working interest partner in the RedHawk field. The platform consists of two dry gas subsea tie-back wells, shown in figure 1, that are treated with recycled MEG via RedHawk's Glycol Reclamation Unit (GRU) for hydrate inhibition. As the GB 877 #2 well's chokes were opened to maintain the target rate of 75 MMCFD, it became apparent that the chokes were no longer controlling the flow from the well but rather some other restriction in the flowline (see figure 2). Modeling and testing showed that there was a restriction in the flowline causing a pressure loss and limiting the production rate of the well. The restriction was initially thought to be the result of fluids from the initial completion cleanup or from a preexisting blockage that occurred during installation of the flowline.