bluuebunny/crossref_metadata_2025_split huggingface dataset:
Perspectives on the New Energy Security: Consumers and Suppliers
Authors: Mobed Ron 
Published: October 2008

Abstract
Energy Security is at the forefront of geopolitics driven by the New Era of Supply Anxiety. Delivering energy for tomorrow has forced both consumer and supplier nations to heighten their roles in the energy arena. Consumer nations are re doubling their efforts to insure supply for their economies. New large fast growing consumer blocks have emerged in the last three years - India and China, along with the tradition ones. They seek diversity of supply, both in type and geography. Supplier nations are also feeling the pressure as things go global and new sources of supply emerge. As such, they are reasserting control of their assets both at home and abroad. Suppliers want to have long term market access and reasonable prices for their products. All this is leading to increased competition and a squeeze on fiscal terms and profit.
This paper discuss how some of the key consumer and supplier blocks work, and some of the issues they are facing.
The world's number one consuming nation, the US, is seeking diversification via supply and hydrocarbon type. Examples from Europe and Latin America provide insight into interdependence between consumer and supplier nations and highlight how hard it is to strike a balance. An example in Asia highlights how new partnerships are being formed between consumer and supplier nations which several years ago never would have been possible.
The result of the new dialogue on energy security has been identification of a set of benefits and challenges. Challenges include-a change in role of National Oil Companies; resource nationalism, surging capitol costs; while benefits are - regional and global delivery systems; renewed technology development; and addition of refining capacity and infrastructure.

Landscape and Definition
Currently we are in a period of "Energy Anxiety" brought on by the steep rise over the last 2 years in energy prices. The current price is attributable to an imbalance in supply and demand. Factors leading to constraints on supply are:Lackluster reserve replacement and discovery doldrums;Restricted access to remaining known resources and future exploration areas;Heightened political risk leading to "resource nationalism" and instability of contracts and fiscal terms;Delivery bottlenecks and aging infrastructure;Conflicts in the Middle East, Nigeria and Latin America;Rising costs and shortage of manpowerNatural disasters such as hurricanes and earthquakes
This paper focuses on the above ground risks to supply, which are dominantly driven by securing new supply, which is shifting from traditional regions. Access is thus a key issue and "resource nationalism" a prominent factor in determining access. Competition for access is being squeezed by "resource nationalism" leading to declining economic attractiveness of many regions. This in turn has lead to acceleration in portfolio rebalancing and large reshuffling of ownership. The return of "resource nationalism" is highlighting the greater need for cooperation among nations and market blocks.
Gas Production From Oceanic Class 2 Hydrate Accumulations
Authors: Moridis George J. , Reagan Matthew T. 
Published: October 2008

Abstract
Gas hydrates are solid crystalline compounds in which gas molecules are lodged within the lattices of ice crystals. The vast amounts of hydrocarbon gases that are trapped in hydrate deposits in the permafrost and in deep ocean sediments may constitute a promising energy source.
Class 2 hydrate deposits are characterized by a Hydrate-Bearing Layer (HBL) that is underlain by a saturated zone of mobile water. In this study we investigated three methods of gas production via vertical well designs. A long perforated interval (covering the hydrate layer and extending into the underlying water zone) yields the highest gas production rates (up to 20 MMSCFD), but is not recommended for long-term production because of severe flow blockage caused by secondary hydrate and ice. A short perforated interval entirely within the water zone allows long-term production, but only at rates of 4.5 - 7 MMSCFD. A new well design involving localized heating appears to be the most promising, alleviating possible blockage by secondary hydrate and/or ice near the wellbore) and delivering sustainably large, long-term rates (10-15 MMSCFD).
The production strategy involves a cyclical process. During each cycle, gas production continuously increases, while the corresponding water production continuously decreases. Each cycle is concluded by a cavitation event (marked by a precipitous pressure drop at the well), brought about by the inability of the system to satisfy the constant mass production rate QMimposed at the well. This is caused by the increasing gas contribution to the production stream, and/or flow inhibition caused by secondary hydrate and/or ice. In the latter case, short-term thermal stimulation removes the blockage.
The results show that gas production increases (and the corresponding water-to-gas ratio RWGCdecreases) with an increasing (a) QM, (b) hydrate temperature (which defines its stability for a given pressure), and (c) intrinsic permeability. Lower initial hydrate saturations lead initially to higher gas production and a lower RWGC, but the effect is later reversed as the hydrate is depleted. The disposal of the large amounts of produced water does not appear to pose a significant environmental problem. Production from Class 2 hydrates is characterized by (a) the need for confining boundaries, (b) the continuously improving RWGCover time (opposite to conventional gas reservoirs), and (c) the development of a free gas zone at the top of the hydrate layer (necessitating the existence of a gas cap for production).
Internal Flow Induced Pulsation of Flexible Risers
Authors: Swindell R. , Belfroid S. 
Published: October 2008

Abstract
A Joint Industry Project, involving a number of operating companies and allied organisations (including ExxonMobil, BP, Statoil, the UK Health & Safety Executive, TNO and Bureau Veritas), is currently addressing the technical issues associated with high amplitude pressure pulsations generated by gas flow through flexible risers. Combining actual offshore measurement data; part and full scale test results at low, medium and high pressures; and both theoretical acoustic and flow simulations, a good understanding of the phenomenon has been achieved. Guidelines for existing and planned developments have been developed, based on precautionary measures, i.e. how to minimise the risk of this phenomenon occurring at the design stage, and practical assessment and mitigation measures for existing assets. This paper will describe the history of the concern and actual offshore experiences, review the work undertaken by the JIP and provide initial guidelines to address the issue.

Introduction
In the last 5 years, a number of offshore installations that utilise flexible risers for single phase gas service have experienced high levels of piping noise and vibration. This has resulted in at least two piping failures. The immediate means of minimising the risk of additional failures was to significantly reduce the gas export rate. The problem has been attributed to flow induced pressure pulsations from the flexible risers.
The pressure pulsations are generated due to vortex shedding on corrugations of the innermost layer of the flexible riser carcass. These pressure pulsations can be sufficiently extreme to cause vibration induced piping fatigue failures, for example to small-bore connections on both topside and subsea piping. The problem has been seen to occur for gas flow velocities as low as 1.5 m/s, which is potentially a severe limiting factor to an installation's production capabilities.
Fig 1 Typical flexible riser showing corrugated carcass (available in full paper)
As an example, one installation experienced severe noise and high frequency pipework vibration on the topsides gas export system once gas export commenced. A comprehensive measurement programme was undertaken which identified the cause as vortex shedding from the internal corrugated carcass of the riser locking on to discrete acoustic resonances of the gas within the export system pipework. The noise, vibration and dynamic pressure within the gas displayed clear tonal characteristics with the fundamental frequency varying with gas velocity (figure 2). The fundamental frequency varied from 84Hz to 208Hz over the range of gas velocities encountered; harmonics of the fundamental frequency were also seen.
Fig 2 Step change in pressure pulsation frequency with flow velocity increase (available in full paper)
Constructing the World's Longest Subsea Pipeline, Langeled Gas Export
Authors: Solberg Leif , Gjertveit Erling 
Published: October 2008

Abstract
Langeled is part of the development of the Ormen Lange Gas field, operated by Hydro in the development phase and by Norske Shell in the operating phase.
At plateau level, the Ormen Lange field will produce around 20 billion Sm3 gas per year, which is equivalent to 20 % of UK gas demand at the time of start-up of the gas deliveries.
The gas will be transported through the world's longest subsea pipeline over a distance of nearly 1200 kilometers, from Nyhamna on the west coast of Norway, via the Sleipner field in the North Sea, to Easington in the UK.
The Langeled project was developed by Statoil on behalf of the operator, Hydro, using personnel from both companies.
This paper covers the main technical, organizational and logistical challenges faced in developing the project. Key conceptual tasks, the massive construction task involving two of the world's largest pipe-laying vessels over two seasons; the logistics of producing, coating and transporting 100,000 pipe joints, the challenging riser installation and modification works on the Sleipner field and finally, the landfall and terminal construction in Easington UK are described.

Introduction
Ormen Lange is a large gas field located 120 km off the west coast of mid-Norway. The field has been developed with two subsea templates and with two 30" flowlines to shore at Nyhamna, where a gas treatment facility is being built. Hydro is the development operator, while Norske Shell will operate the field and the plant in the future.
As part of the Ormen Lange development, a dedicated large diameter export pipeline, called Langeled, has been installed to transport dry gas from Nyhamna to the east coast of England in order to supply gas to the UK market. The Langeled development project has been managed by Statoil on behalf of Hydro. Gassco, operating all the main gas export pipelines from the Norwegian continental Shelf, on behalf of the owners, is taking over the operator ship of Langeled in the operational phase. This was effective from September 1st 2006, when the Langeled South became operational.
Langeled is a 1200 km long pipeline from Nyhamna to Easington on the east coast of England, which is tied into the Sleipner field about midway across the North Sea. The northern half consists of a 42" diameter 250/215 bar pipeline, whilst the southern half from Sleipner to the UK comprises a 44" diameter 157 bar pipeline.
This paper will highlight the main challenges of the project;system description and concept selectionlandfall in UKright of wayenvironmental challengesexecution and market strategyconstruction and marine operationsmodifications and tie-in to Sleipnertie-in, testing and Ready for Operation (RFO) activitiessafety during the construction phase

System description and concept selection.

Market considerations.
The main driver for the concept selection of a gas field development is the market considerations. In case of Ormen Lange, several possible market scenarios and locations were evaluated.
The Setting and Possible Mechanism of the 2006 Green Canyon Seismic Event
Authors: Peel Frank 
Published: October 2008

Abstract
On February 10 2006, a significant seismic event occurred in the Gulf of Mexico within an area of vital interest for hydrocarbon exploration companies. The location of the event, in Green Canyon Block 344, is close to discoveries and producing fields, including Allegheny, Front Runner, Bison, K2, Marco Polo and Holstein, among others. This paper describes the structural context of the February 2006 event and reviews possible seismogenic process that could operate within the region.

Introduction
In order to define the possible influence of such an event on exploration or production, we need to know the strength, depth, displacement, rupture area, surface effect and likely recurrence interval of the event responsible. We cannot predict this from historical seismicity, because there is little historical data on natural seismic activity in the area, and the focal mechanism and depths are poorly defined. Therefore the best way to predict potential future activity is to understand the geological setting and structural mechanism of this event.

Seismological signal
The limited information made available by the USGS1 gives a location (27.632°N, 90.144°W, with lateral error +/- 10.8km) and an approximate depth (5km, with no vertical error margin quoted) but no information on focal mechanism. Assuming vertical positioning error is similar to the horizontal, the information provided by the USGS does not distinguish between an event at sea floor, one within the sediment sequence, or one at a shallow depth in the basement. The seismic effect of the earthquake was fortuitously detected by an OBS network in place over the Atlantis field. Dellinger2 et al. (2006) described the nature of the signal of the event as seen on the OBS data. An analysis of the teleseismic data by Nettles3 (2006) supports the general conclusions on the earthquake source, confirming the that general location lay within southeastern Green Canyon protraction area, with an indication that the source may have been 5-10 miles further north than reported by the USGS.
Nettles also concluded that the seismic signal does not permit a precise definition of the source signature, but the nature of the signal indicates that it is not that of a conventional deep seismic rupture (an effectively instantaneous slip event giving rise to the classic double-couple "beachball" with clear compressional first motion seen in two quadrants). Instead the signal is compatible with a seismological "landslide-type" mechanism. In this mechanism the movement takes a discrete length of time, such that the initiation of movement gives rise to a "beachball" with one polarity, and the cessation of movement gives rise to a signal of the opposite polarity. This is illustrated by the sequence of sketches shown in figure 1. The net effect of this as seen at a distance is a more confused signal, combining the responses from the start and end of movement, which does not have a conventional doublecouple signature.
Fig. 1 mechanism of the "landslide-type" source (available in full paper)
Oil Well Transient Testing by Injection of Miscible Fluid
Authors: Voelker Joseph James 
Published: October 2008

Abstract
This paper describes the general procedure and analysis of an oil well pressure transient test method in which a liquid that is miscible with reservoir oil is injected from the surface at constant rate. Injection significantly reduces surface production test separation and rate measurement equipment requirements, and flaring, thereby reducing testing costs, and safety and environmental risks. Injection of liquid provides for rate control to a precision difficult to attain during production, and although not strictly necessary, allows for a constant rate condition to be practically attained, potentially eliminating a time consuming shut-in and associated test duration and costs. Drilling non-aqueous fluid base oil is a viable miscible injection fluid. A well pressure model is developed that includes the effect of the viscosity difference between injected fluid and reservoir oil. The temperature effect on viscosity is also considered. The model indicates that the duration of the viscosity effect may be short under practical conditions, and is controlled by injection rate. Reservoir parameters estimated from the injection test are identical to those estimated with single-phase production pressure transient tests. A reservoir oil PVT sample must be obtained independently, prior to injection. Conventional pressure transient analysis applications may be used to analyze injection pressure transient data.

Introduction
This study originated from the desire to obtain reservoir permeability estimates as part of the exploration and delineation of an offshore basin in which the typical play is composed of stacked, fluvial sand reservoirs, forming three-way closures against trapping faults.
A method is desired to assess the productivity of as many of the stacked oil bearing intervals as may be discovered in many or all exploration and delineation wells in the drilling program. The success of future development depends on the exploitation of numerous small, vertically and laterally isolated reservoirs. Evaluation of the productivity of many hydrocarbon intervals allows the estimation of the local distribution of reservoir productivity in various regions of the basin.
Reservoir productivity estimates from production testing are more reliable than that from wireline flow testing and from core analysis, however the disproportionate costs associated with production testing, related to rig time and surface test equipment rental, discourages liberal use of this method. Production testing also carries safety and environmental risks, particularly from flaring. A flow test method that minimizes test duration, and eliminates the need for surface test equipment, is highly desired.
Development of Method for Measuring Susceptibility of Steel Plate to Lamellar Tearing
Authors: Wold Gunnar , Kristoffersen Thrøbjorn 
Published: October 2008

1. Introduction
During the construction of steel structures problems sometimes arise due to a cracking phenomenon that has been termed lamellar tearing". A case in point is the construction of drilling rigs and other offshore platforms where problems of this kind is known to occur quite frequently.
Lamellar tearing is a type of weld defect that may occur in a steel plate when it is subjected to appreciable strains in the short transverse direction (z-direction) due to shrinkage of the weld deposit. Since it is essential that the strains are predominantly in the z-direction, the defect is most often found in welded joints where the fusion boundary is roughly parallel to the surface of the plate. Typical examples of such welds are shown schematically in Fig. 1.
The appearance of lamellar tears occurred in illustrated in Figs. 2 and 3.
It is well established now that the main variables in lamellar tearing are:The mechanical properties in the z-direction of the plate,The design of the structure, in particular the joints, andThe welding parameters.
It is the intent of the present paper to deal only with the first and most important of these variables, namely the material properties.
The main factor in determining the z-direction properties of a steel plate is the non-metallic inclusions. Their effect, which is mainly to reduce the ductility in this direction, is caused by the inclusions being elongated and flattened in planes parallel to the plane of the plate, a feature which also gives rise to the stepped appearance of lamellar tears. A typical fracture surface of an opened lamellar tear is shown in Fig. 4.
Once lamellar tearing has occurred in a construction it is difficult to get rid of since removal of the crack by grinding or gouging and rewelding often results in new lamellar tears forming further into the material There pairwork is therefore complicated, time consuming and often very expensive. For these reasons there is a need for a testing method that will provide quantitative information about the susceptibility of steel plate to lamellar tearing. It has been the aim of the present work to develop such a method.

2. Test for assessing susceptibility to lamellar tearing.
In the literature a number of methods are described that have been suggested as a means for testing the susceptibility of steel plate to lamellar tearing. See for instance references (1), (2), (3), (4), (5), (6) and (7). Some of these methods are purely mechanical tests, others are weld-cracking tests that rely on welding strains to trigger off possible cracking, while others, again, are combinations of these methods.
In principle, however, all the methods have as a common objective the provision of information about the mechanical properties in the z-direction of the material being tested.
DST Design for Deepwater Wells with Potential Gas Hydrate Problems
Authors: Chen Shing-Ming , Gong William Xiaowei , Antle Geoff 
Published: October 2008

Abstract
The main objective of this paper is to present a proper DST design for deepwater gas wells with potential gas hydrate problems because of low seabed temperature.
Prior to discussing the DST procedures, the importance of selecting a proper mud for drilling and interval for testing are explained. Factors affecting gas hydrate formation are discussed. Then, requirements for gas hydrate prevention during DST are described. Actions required to prevent gas hydrate formation during DST startup, fluid sampling, well shut-in and restart are addressed. Finally, procedures for incorporating gas hydrate prevention in DST are outlined.
At the end of the paper, a gas well with hypothetical data is used to assist in illustrating the DST procedures.

Introduction
Hydrates are physical combinations of water and natural gas formed at pressures and temperatures considerably above the freezing point of water[1-5]. For deepwater gas wells, the risk for gas hydrate formation always exists due to the low seabed temperature and the coexistence of gas and water inside the wellbore.
Figure 1 shows one of the popularly used pressure-temperature-gas density correlations for gas hydrate predictions[2,6]. As it can be seen from this figure, the generally low temperature of less than 50 0F in the deepwater seabed, together with the normal gas well operating pressure of several hundreds to thousands of psi, will result in wellbore temperatures below the gas hydrate temperature curve.

DST and Gas Hydrate
Although a deepwater gas well may be operated at certain flow conditions to take advantage of the warm fluid coming out from the reservoir, the need for DST to shut in the well for pressure buildup tests or produce the well at low rates for fluid sampling often cool the fluid inside the wellbore to the extent that gas hydrate will form. For the deepwater DST, it has been well recognized that hydrate prevention is needed for flow assurance in order to complete the test[7-11].