bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development, validation and application of a patient satisfaction scale for a community pharmacy medicines-management service
Authors: Tinelli Michela , Blenkinsopp Alison , Bond Christine 
Published: May 2011

AbstractObjectiveTo develop, validate and apply a scale to measure patient satisfaction in a randomised controlled trial of community pharmacy service.MethodsPublished scales were reviewed to inform development of the patient satisfaction scale. Questionnaires were sent to patients in the control (n = 500) and intervention (n = 941) groups of a randomised controlled trial of community pharmacy-led management of coronary heart disease at baseline and 12-month follow-up. Any underlying main factors were assessed with exploratory factor analysis. Reliability and construct validity were tested. The 15-item scale was used to compare patient satisfaction across arms with their most recent pharmacy visit.ResultsResponse rates were 92% (461/500) for control and 96% (903/941) for intervention groups at baseline and 85% control (399/472) and intervention (810/941) at follow-up. At baseline satisfaction was very similar in the intervention and control groups (median scores of 42). At follow-up mean satisfaction had significantly improved for the intervention compared with the control (median scores of 46 compared with 43; P &lt; 0.01); intervention females were more likely to be satisfied with the service than males (49 compared with 44; P &lt; 0.01). Three main factors explained the majority of the data variance. Cronbach's alpha was 0.7–0.9 for both groups over time for all factors and total scale. An increase in the overall satisfaction corresponding to a decrease in subjects wanting that particular service to be provided during their next visit indicated construct validity of the scale.ConclusionA new scale of patient satisfaction with community pharmacy services was developed and shown to be reliable and valid. Its application showed increased satisfaction in the intervention group receiving a new pharmacy service.
Provision of advice on alcohol use in community pharmacy: a cross-sectional survey of pharmacists' practice, knowledge, views and confidence
Authors: McCaig Dorothy , Fitzgerald Niamh , Stewart Derek 
Published: May 2011

Abstract

Objective
Community pharmacists are well placed to provide advice to clients on public health issues such as alcohol use. The aim of the study was to characterise community pharmacists' current level of activity and views on providing such advice in Scotland.

Method
A postal questionnaire survey, covering provision of advice, knowledge and views on alcohol issues, was sent to all community pharmacies in Scotland (n = 1098).

Key findings
The response rate was 45% (497/1098). Knowledge of recommended alcohol-intake limits was high (79 and 84% correct for male and female limits, respectively), but few respondents (5%) currently advised clients on alcohol consumption once a week or more and 29% had never done so. Around a quarter were confident in explaining alcohol limits, binge drinking and confidentiality issues, but about 40% lacked confidence in screening and providing a brief intervention on alcohol. Respondents expressed mixed views on the appropriateness of pharmacist involvement in discussing alcohol use with clients. Attitudes to harmful or hazardous drinkers varied: some 20% of respondents felt uncomfortable with this group, whereas another 20% felt they could work with this group as well as with any other.

Conclusion
Community pharmacists in Scotland provide little advice on alcohol use, have a reasonable knowledge of recommended limits but lack the knowledge and confidence to provide a brief intervention. Implementation of a brief alcohol intervention in community pharmacy, therefore, would need to be underpinned by an appropriate training programme. Such a programme needs to provide factual knowledge but must also address pharmacists' attitudes to clients and promote confidence in service delivery.
The GeoControversies debates
Authors: Underhill J. R. 
Published: May 2011

Abstract
An opportunity to discuss and publically debate three critical issues of concern to oil company geologists was introduced into the Petroleum Geology Conference (PGC) programme for the first time in 2009. The debates selected focused on whether “peak oil” was already upon us; the relative role of National Oil Companies (NOCs) versus that of International Oil Companies (IOCs) and whether North Sea Exploration was finished. In each case, the arguments were delivered by two experts, who presented the case for and against each motion before answering questions and facing a vote by the audience, who showed coloured cards to indicate their support for what they had heard. All three debates proved to be extremely popular and were very well attended for all three days. The novel concept was deemed a great success and added significant value to the PGC.
North Sea hydrocarbon systems: some aspects of our evolving insights into a classic hydrocarbon province
Authors: Erratt D. , Thomas G. M. , Hartley N. R. , Musum R. , Nicholson P. H. , Spisto Y. 
Published: May 2011

Abstract
A review is given of the development of the understanding of the structure and stratigraphy of a classic petroleum province through 35 years of NW European Petroleum Geology Conferences, using new examples to illustrate the interplay between tectonics and sedimentation in the development of some of the major hydrocarbon plays. Cimmerian tectonics is discussed, with regard to the evidence for regional-scale truncation beneath the Mid Cimmerian unconformity, and the stratal motifs characteristic of rifting associated with the Early and Late Cimmerian events. New data revealing the structural geometries associated with polyphase rifting in the East Shetland Basin are presented. The seismic and sequence stratigraphy of Jurassic and Cenozoic sequences are reviewed and new data presented, with a discussion of generic play controls in North Sea Jurassic deepwater reservoirs. The development of integrated hydrocarbon system studies is reviewed, and the remaining challenges to predictive capabilities discussed. The impact of advances in geoscience and technology on North Sea creaming curves is discussed.
Source rock quality and maturity and oil types in the NW Danish Central Graben: implications for petroleum prospectivity evaluation in an Upper Jurassic sandstone play area
Authors: Petersen H. I. , Nytoft H. P. , Vosgerau H. , Andersen C. , Bojesen-Koefoed J. A. , Mathiesen A. 
Published: May 2011

Abstract

The principal exploration targets in the northwestern part of the Danish Central Graben have been Upper Jurassic sandstone reservoirs. The presence and effectiveness of the oil-generating rocks of the Upper Jurassic–lowermost Cretaceous marine shales of the Farsund Formation has generally not been considered as a significant risk. This study provides an evaluation of the source rock quality, maturity and distribution and of the oils in this area. The kerogen in the Farsund Formation is algal-derived, and kerogen type ranges from Type II to Type III. Generally the source rock quality is fair to excellent, but the petroleum generation potential varies considerably. In most wells the uppermost part of the Farsund Formation (Bo Member) consists of highly oil-prone shales. However, the presence of oil-prone kerogen may be masked by kerogen of poorer source quality. Favourable conditions for oil-prone kerogen preservation were present during the time of deposition of upper parts of the Farsund Formation, but exceptions are not unusual. Similar vitrinite reflectance gradients indicate a uniform thermal regime over the area. The oil window occurs from
c
. 3800–4000 to 4800 m, i.e. spanning approximately 800–1000 m. A general decrease in the generation potential from the top towards the base of the formation is caused by both generation and deterioration of kerogen quality. The Gertrud Graben and Feda Graben constitute the main kitchen areas, and oil compositions indicate sourcing from marine shales. In the shallow parts of the Outer Rough Basin the shales are mostly immature and the sourcing is dependent on kitchen areas outside the area or on Palaeozoic rocks. Mature Zechstein is indicated by a minor oil show probably locally sourced.
Architecture of an Upper Jurassic barrier island sandstone reservoir, Danish Central Graben: implications of a Holocene-Recent analogue from the Wadden Sea
Authors: Johannessen P. N. , Nielsen L. H. , Nielsen L. , Møller I. , Pejrup M. , Andersen T. J. 
Published: May 2011

Abstract

An unusually thick (
c
. 88 m), transgressive barrier island and shoreface sandstone succession characterizes the Upper Jurassic Heno Formation reservoir of the Freja oil field situated on the boundary of Denmark and Norway. The development and preservation of such thick transgressive barrier island sands is puzzling since a barrier island typically migrates landwards during transgression and only a thin succession of back-barrier and shoreface sands is preserved. Investigation of the development and geometry of the Freja reservoir sandstones is problematic since the reservoir is buried
c.
5 km and seismic resolution is inadequate for architectural analysis. Description of the reservoir sandstone bodies is thus based on sedimentological interpretation and correlation of seven wells, of which five were cored. Palaeotopography played a major role in the position and preservation of the thick reservoir sandstones. Using the nearest maximum flooding surface above the reservoir as a datum for well-log correlations, the base of the barrier island succession in the wells is reconstructed as a surface with steep, seaward-dipping palaeotopography. The relief is
c
. 270 m over a distance of
c
. 8 km and dips WNW.

As a complementary approach to investigation of the reservoir architecture, a Holocene–Recent barrier island system in the Danish part of the NW European Wadden Sea has been studied and used as an analogue. The barrier island of Rømø developed during a relative sea-level rise of
c.
15 m during the last
c.
8000 years and is up to 20 m thick. To unravel the internal 3D facies architecture of the island, an extensive ground penetrating radar (GPR) survey of 35 km line length and seven cores,
c.
25 m long, was obtained. Although the barrier island experienced a rapid relative sea-level rise, sedimentation kept pace such that the island aggraded and even prograded seawards and became wider and longer due to the large surplus of sand.
The Huntington discoveries: efficient exploration in the UK Central North Sea
Authors: Hollywood J. M. , Olson R. C. 
Published: May 2011

Abstract
The Huntington discoveries are an unusual exploration success in that two oil accumulations were tested in separate syn- and post-rift reservoirs with a single well. The discoveries are located 205 km east of Aberdeen in the East Central Graben some 35 km east of Forties Field in 300 ft of water. The 22/14-5 discovery well, drilled in May 2007, encountered a 122 ft oil column in the Paleocene Forties Sandstone and also a 136 ft oil column in the Upper Jurassic Fulmar Sandstone. Both the Forties and the Fulmar contain high-quality oil, 41 and 39° api gravity, respectively. Aggregate flow rates from the two zones exceeded 11 000 boepd on test. Appraisal drilling of the Forties was completed in late 2007 with first oil targeted for 2011. The Fulmar appraisal programme is currently in progress. The Forties reservoir is a high net to gross sandstone containing stacked channel sequences deposited in a submarine fan system. The Fulmar reservoir also contains a thick sand package deposited in a shallow marine shelf setting. Pre-drill mapping based on reprocessed 3D seismic indicated a structural closure on both horizons at the location tested by the well. At both the Forties and Fulmar targets, however, the oil column height exceeded the pre-drill prognosis. This overview will focus on pre-drill perceptions of the prospect relative to actual drilling results.
Prospectivity of the T38 sequence in the Northern Judd Basin
Authors: Rodriguez J. M. , Pickering G. , Kirk W. J. 
Published: May 2011

Abstract
A seismic amplitude anomaly has been identified at the Upper Paleocene T38 level in the northern Judd Basin and will be tested by the drillbit in 2009. Prospectivity at shallower levels has been largely ignored due to the fact that the main regional seal in the area was recognized to be the T35/T36 mudstones below the Kettla Tuff. Seismo-stratigraphic analysis of the T38 sequence directly above the tuff marker has identified the potential for a new play type, especially adjacent to fault zones where these mudstones are breached, allowing hydrocarbons to migrate from the Upper Jurassic source kitchen into any traps identified above the seal. In this area, the T38 is represented by a series of northerly prograding low-angle clinoforms representing the final marine infill of sediments into the basin from the south. Erosion of top sets in a more marginal setting is observed, along with deposition of basin floor fans at the toe of the prograding clinoforms. The overlying seals are basinal sediments as well as mudstones and siltstones of subsequent progradational sequences. Mild structural modification of potential stratigraphic traps in the Judd Basin occurred during the Oligo-Miocene inversion associated with continued opening of the North Atlantic. Drilling seismic amplitude anomalies in the West of Shetlands area has often been unsuccessful. Therefore, a fully integrated geophysical and geological evaluation was carried out on the T38 anomaly comprising rock physics, amplitude variation with offset analysis, fault seal analysis and the acquisition of a CSEM survey which, supported by a valid geologic model, have reduced the risk from high to moderate. The results indicate that the anomaly has the potential to be sand-bearing and contain oil and gas. It is proposed that an integrated evaluation can reduce the level of uncertainty associated with an anomaly much more effectively and so improve the chance of exploration success.
Can stratigraphic plays change the petroleum exploration outlook of the Netherlands?
Authors: Van Hulten F. F. N. 
Published: May 2011

Abstract
Fifty years after the discovery of the giant Groningen gas field, good insight into the remaining hydrocarbon exploration potential of the Netherlands is of great interest due to the aging infrastructure. In a review of prospective areas, the stratigraphic element of Dutch play areas has been summarized for conventional and unconventional formations. This is to answer the question of whether stratigraphic traps can contribute to future exploration. Complex faulting, very common in the Dutch subsurface, makes structural definition generally the highest prospect risk. With increase in 3D coverage over the country, many structures have now been drilled successfully. The success of structural traps has left the stratigraphic plays and prospects under-explored. Most hydrocarbon reserves in the Netherlands have been discovered in Permian Rotliegend and Triassic Bunter sandstone reservoirs, which are not prone to much stratigraphic trapping as a consequence of very gradual facies changes. Other prospective horizons and hydrocarbon reservoirs in the country range in age from Carboniferous to Cenozoic and can be found in clastic and carbonate rocks. They share an overall comparable basin setting but the varying interplay at basin margins creates varying stratigraphic elements. Rifting creates new facies variation during the Mesozoic. Salt movement is another factor that creates stratigraphic components in trapping. The various erosional events create other possibilities for stratigraphic trapping. This, combined with varying relative sea-levels through time, creates very distinct stratigraphic intervals often correlatable over large distances. The very limited contribution of stratigraphic traps to present-day gas finds may change in the future because of improved seismic. Risking of prospects needs better understanding of stratigraphic elements in various plays. This includes the stratigraphic aspects of reservoir sealing in dominantly structural traps and the nature of source horizons.
Laggan; a mature understanding of an undeveloped discovery, more than 20 years old
Authors: Gordon A. , Younis T. , Bernard-Graille C. , Gray R. , Urruty J.-M. , Ben-Brahim L. , Navarre J.-C. , Paternoster B. , Evers G. 
Published: May 2011

Abstract
Laggan, located in the west of Shetland, was discovered in 1986. There is now an improved understanding of Laggan, thanks to innovative and fully integrated geoscience studies and a successful appraisal campaign. Development studies are well advanced, with the discovery of Tormore in 2007 providing the potential for a combined development project. Laggan and Tormore are Paleocene gas condensate discoveries in approximately 600 m water depth. The traps are both mixed, stratigraphic with updip closure against bounding faults. The reservoir comprises sand-rich turbidite channelized lobes and lobes. Reservoir properties are good (permeability range 30–300 mD) due to the presence of chlorite and pre-sorting on the shelf. The geoscience evaluation of Laggan has matured over the last four years with the help of fully integrated studies using 3D seismic and well data. The depositional model has been defined on the basis of an evaluation of cores and seismic and supported by analogue studies. Seismic inversion studies have also helped constrain the reservoir architecture. Of particular value has been the application of AVO to quantify net gas sand, recognized as the principal static uncertainty. The main dynamic uncertainty is the risk of compartmentalization. This risk has been reduced through an improved definition of the fault configuration by re-processing the seismic and detailed seismic attribute analysis. The potential of Tormore was recognized by applying the geoscience understanding of Laggan to help de-risk the prospect. In particular, it was recognized that Laggan could be used as an analogue for the Tormore trapping configuration and reservoir potential and that AVO could be used to help define the Gas–Water Contact. The exploration well, drilled in 2007, was successful in finding a similar reservoir to that encountered in Laggan. The fluid encountered was a gas condensate, approximately three times richer than Laggan.
Maximizing production and reserves from offshore heavy oil fields using seismic and drilling technology: Alba and Captain Fields, UKNS
Authors: Hampson J. M. , Walden S. F. , Bell C. 
Published: May 2011

Abstract
Chevron North Sea Limited operates Alba and Captain, two large, mature, heavy oil fields in blocks 16/26 and 13/22a of the UK sector of the North Sea, respectively. Although the fields are structurally and stratigraphically different, their development schemes have been similar. Common components to both fields are that they are marine sandstone reservoirs; have one steel jacket, plus subsea templates; are under water injection for pressure support; utilize long horizontal development wells; use pilot holes and logging while drilling (LWD) geosteering tools to optimize well locations; and have seismic resolution issues. New technologies and techniques have been developed and adopted to maximize production and reserves from the fields. The benefits to both Alba and Captain of previous and new technologies are reviewed below.
The Buzzard Field: anatomy of the reservoir from appraisal to production
Authors: Ray F. M. , Pinnock S. J. , Katamish H. , Turnbull J. B. 
Published: May 2011

Abstract
The Buzzard oil field in the Outer Moray Firth, Central North Sea was discovered in 2001 and rapidly appraised during 2001–2002. Pre-production development drilling began in 2005 and the field was brought on stream in January 2007 by operator Nexen Petroleum UK Ltd. The Buzzard reservoir consists of Upper Jurassic deep marine turbidites within the Kimmeridge Clay Formation. Sands were derived from the shelf to the west and the resulting mass flow deposits were contained within a fault-bounded basin, whose margins were prone to mass wastage. The deposits pinchout to the west and thicken eastwards into the basin and hydrocarbon source kitchen. Following appraisal drilling, the high net-to-gross reservoir was interpreted as well connected. Interbedded shale layers were thought unlikely to control flow through the reservoir. However, a biostratigraphic review indicated that a consistent biostratigraphic event, indicative of reworking, could be identified field-wide. This shale layer is interpreted as a large-scale, muddy slump, extensive enough to form a significant vertical barrier to flow. Subsequent production data, modelling and chemostratigraphy studies suggest greater subdivision and vertical baffling within the main reservoir. Interpretation of these data has led to a move away from early models of Buzzard as a tank-like reservoir to a model dominated by compensationally stacked lobes, where hydraulic flow is influenced by sand body geometry and extensive shales. A comprehensive understanding of the Buzzard Field has only been possible through full integration of core, log and dynamic data, benefiting from a high density of well control, an extensive data acquisition programme and early reservoir monitoring. Ongoing reservoir management, involving continuous update of both the geological and dynamic models in response to new data, has enabled an evolving understanding of the Buzzard reservoirs, and placed the operator in an excellent position to proactively address future development challenges.
An old field in a new landscape: the renaissance of Donan
Authors: Reekie R. R. A. , Davies E. L. , Hart N. J. , McInally A. T. , Todd J. R. , McAteer J. R. , Franoux L. , Ferguson E. L. M. 
Published: May 2011

Abstract

The Donan Field was discovered in 1987 by BP well 15/20a-4. Oil is reservoired in Paleocene Lower Balmoral Sandstones of the Lista Formation. First oil was achieved from Donan on 28 April 1992 via two crestal producers to the Single Well Oil Production System (SWOPS) vessel
O.P.V. Seillean
. Peak production rates of 15 mstb/day were achieved before high well watercuts caused a significant drop in gross rates. Further attempts at development proved unsuccessful at the time. No further infill attempts were made as the field continued to be produced until it reached its economic limit in 1997. The field had produced 15.3×10
6
stb. Subsequently, block 15/20a was awarded to a partnership led by Kerr–McGee (North Sea) UK Ltd (now Maersk Oil North Sea UK Limited) in 2002 as part of the twentieth licensing round. Drilling results whilst testing the prospectivity on the block led to a focus towards Donan redevelopment. A combination of Rock Physics modelling and AVO, calibrated by appraisal drilling, and the integration of high-resolution biostratigraphy, played a significant role in the successful first phase of the ‘Dumbarton Project’, consisting of five horizontal producers and one produced water reinjection well. ‘Second oil’ from Donan was achieved on 19 January 2007 to the Global Producer III FPSO. Early production performance was in line with expectations with the field producing 20×10
6
stb within the first two years. In 2008 and 2009 further phases of development drilling took place on Donan with 2009 also expected to deliver two development wells in the Lochranza Field, a smaller, structurally distinct field to the east of Donan.