bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improving quality in clinical placement studies in nursing homes (QUALinCLINstud): the study protocol of a participatory mixed-methods multiple case study design
Authors: Laugaland Kristin Alstveit , Thorsen Gonzalez Marianne , McCormack Brendan , Skovdahl Kirsti-Iren , Slettebø Åshild , Billett Stephen , Akerjordet Kristin 
Published: October 2020

IntroductionImproved quality in clinical supervision and assessment of student nurses in nursing home clinical placements is vitally important to effective recruitment and preparation for this healthcare sector. Knowledge regarding supervision and assessment practices within these settings is limited. Also, knowledge of evolving e-learning tools on the quality and effectiveness of these educational practices seems to be absent.Methods and analysisThe aim of the “Improving quality in clinical placement studies in nursing homes” (QUALinCLINstud) study is to develop and evaluate how a web-based programme can optimise supervision, assessment and learning during nursing home placements. The study applies a participatory, mixed-methods case study design, organised in four work packages (WPs). WP1 will explore how the nurse education institution address the quality of student nurses’ clinical placements in nursing homes. In WP2, clinical supervision and assessment practices will be explored, and described from multiple stakeholder perspectives. In WP3, based on the findings from WP1 and WP2, a web-based pedagogical supervision and assessment programme will be developed through a developmental co-productive process between nurse education institutions, practice settings and student nurses. In WP4, the web-based programme will be pilot-tested and evaluated through a mixed-methods approach. A range of data collection procedures will be used throughout the project, for example, questionnaires, interviews, observations and workshops.Ethics and disseminationThe ethical conduct of the study is approved by the Norwegian Centre for Research Data (2018/61309 and 489776). The results will be disseminated through scientific articles, three PhD theses, presentations at national and international conferences, and through publicly accessible trade journals and newspapers. The results will generate knowledge to inform supervision and assessment practices in nursing home placements. Moreover, the study will generate knowledge concerning the developmental process of a web-based supervision and assessment programme, and the value of e-learning tools applied in clinical nursing education.
Use of data from the Vascular Quality Initiative registry to support regulatory decisions yielded a high return on investment
Authors: Cronenwett Jack L , Avila-Tang Erika , Beck Adam W , Bertges Daniel , Eldrup-Jorgensen Jens , Resnic Frederic S , Radoja Nadezda , Sedrakyan Art , Schick Andreas , Smale Josh , Bloss Roberta A , Phillips Peter , Hasenbank Melissa , Wang Shengchun , Marinac-Dabic Danica , Pappas Gregory 
Published: October 2020

BackgroundReal-world data (RWD) from the Society for Vascular Surgery Vascular Quality Initiative (VQI) registry has been used to support US Food and Drug Administration (FDA) regulatory decisions regarding vascular devices. The variables of cost and time needed for these registry-based studies have not been previously compared to traditional, independent, industry studies that would otherwise have been conducted to support regulatory decisions.ObjectivesTo determine the potential value (cost and time saving and return on investment) created by device evaluation studies using the VQI registry infrastructure.MethodsWe compared studies that used data from the VQI registry with estimated costs of independent industry studies (counterfactual studies) using an established model using design specifications determined by FDA reviewers.ResultsWe analyzed the initial six studies evaluating vascular devices for regulatory decisions using data from the VQI registry that generated evidence for four device manufacturers. Return on investment for these studies was estimated to be 143% and cost saving as 59% based on an actual per patient (with 5-year follow-up) cost of US$11K using VQI data versus US$26K from the counterfactual when averaged across all studies. Significant enrollment time savings (45%–71%) were also realized compared with industry-based estimates.ConclusionsThe use of RWD from the VQI registry in this study and the transcatheter valve treatment coordinated registry network in a prior study indicates that substantial value was added to device evaluation projects by the reuse of registry data, with additional potential savings if linked claims data can be used instead of costly long-term in-person follow-up.
Standalone performance of artificial intelligence for upper GI neoplasia: a meta-analysis
Authors: Arribas Julia , Antonelli Giulio , Frazzoni Leonardo , Fuccio Lorenzo , Ebigbo Alanna , van der Sommen Fons , Ghatwary Noha , Palm Christoph , Coimbra Miguel , Renna Francesco , Bergman J J G H M , Sharma Prateek , Messmann Helmut , Hassan Cesare , Dinis-Ribeiro Mario J 
Published: October 2020

ObjectiveArtificial intelligence (AI) may reduce underdiagnosed or overlooked upper GI (UGI) neoplastic and preneoplastic conditions, due to subtle appearance and low disease prevalence. Only disease-specific AI performances have been reported, generating uncertainty on its clinical value.DesignWe searched PubMed, Embase and Scopus until July 2020, for studies on the diagnostic performance of AI in detection and characterisation of UGI lesions. Primary outcomes were pooled diagnostic accuracy, sensitivity and specificity of AI. Secondary outcomes were pooled positive (PPV) and negative (NPV) predictive values. We calculated pooled proportion rates (%), designed summary receiving operating characteristic curves with respective area under the curves (AUCs) and performed metaregression and sensitivity analysis.ResultsOverall, 19 studies on detection of oesophageal squamous cell neoplasia (ESCN) or Barrett's esophagus-related neoplasia (BERN) or gastric adenocarcinoma (GCA) were included with 218, 445, 453 patients and 7976, 2340, 13 562 images, respectively. AI-sensitivity/specificity/PPV/NPV/positive likelihood ratio/negative likelihood ratio for UGI neoplasia detection were 90% (CI 85% to 94%)/89% (CI 85% to 92%)/87% (CI 83% to 91%)/91% (CI 87% to 94%)/8.2 (CI 5.7 to 11.7)/0.111 (CI 0.071 to 0.175), respectively, with an overall AUC of 0.95 (CI 0.93 to 0.97). No difference in AI performance across ESCN, BERN and GCA was found, AUC being 0.94 (CI 0.52 to 0.99), 0.96 (CI 0.95 to 0.98), 0.93 (CI 0.83 to 0.99), respectively. Overall, study quality was low, with high risk of selection bias. No significant publication bias was found.ConclusionWe found a high overall AI accuracy for the diagnosis of any neoplastic lesion of the UGI tract that was independent of the underlying condition. This may be expected to substantially reduce the miss rate of precancerous lesions and early cancer when implemented in clinical practice.
A new symmetry of the spatially flat Einstein–Friedmann equations
Authors: Dussault Steve , Faraoni Valerio 
Published: October 2020

AbstractWe report a new symmetry of the Einstein–Friedmann equations for spatially flat Friedmann- Lemaître-Robertson-Walker universes. We discuss its application to barotropic perfect fluids and its use as a solution-generating technique for scalar field universes.
The Juliet Field, Block 47/14b, UK North Sea
Authors: Offer D. J. 
Published: October 2020

Abstract
The abandoned Juliet gas field is a small, highly compartmentalized, accumulation situated south and east of the Amethyst Gas Field. It was discovered in 2008 by well 47/14b-10 and flowed first gas on 5 January 2014. The field consists of at least two culminations within a very low-relief east–west-orientated fault-bounded anticline. The reservoir comprises aeolian sandstones of the Permian, Rotliegend Group, Leman Sandstone Formation. Reservoir quality varies from good to moderate, with a high production rate achieved from horizontal wells.
Seismic time-to-depth conversion is affected by Quaternary seabed channels, chalk burial history and a rapid thickening in the Basalanhydrit Formation located over the east of the field, associated with the edge of the Zechstein Basin.
Gas-in-place at pre-development was expected to be 105 bcf, with reserves of 67 bcf. The field was developed using two horizontal wells and a subsea tie-back to the Pickerill Field, 22 km to the east. Since development, the field appears to be more compartmentalized than initially expected.
The Golden Eagle, Peregrine and Solitaire fields, Blocks 14/26a and 20/01, UK North Sea
Authors: Pinnock S. J. , Dutton D. M. 
Published: October 2020

Abstract
The Golden Eagle Field is located 18 km north of the Buzzard Field in the Moray Firth, and consists of oil accumulations in the Lower Cretaceous Punt and Upper Jurassic Burns Sandstone members. The development area comprises three fields, Golden Eagle, Peregrine and Solitaire, but up to 90% of the oil-in-place and ultimate recovery are in Golden Eagle. The two satellite fields are primarily structural closures, while the Golden Eagle Field reservoirs have a major element of stratigraphic pinchout. Production commenced in October 2014 and approximately 140 MMbbl of recoverable oil is anticipated over its field life from the 19 development wells (14 producers and 5 injectors) that form the initial development phase. Production performance to date has exceeded expectations, aided through the use of completions that provide zonal control of the reservoir units which has successfully supported reservoir management and improved sweep efficiency.
A number of significant lessons have been learned during the early stages of the field life from the integration of dynamic data (real-time downhole fibre-optic reservoir monitoring instruments, inter- and intra-well tracers, and well interference tests) and seismic data improvements (post-start-up acquisition of high-density ocean-bottom node seismic and depth-conversion improvements).
The Laggan and Tormore fields, Blocks 206/1 and 205/5, UK Atlantic Margin
Authors: Clark J. , Matthews P. , Parry C. , Rowlands M. , Tessier A. 
Published: October 2020

Abstract
The Laggan and Tormore fields are found within the Flett sub-basin of the Faroe–Shetland Basin. Situated 120 km west of the Shetland Islands in 600 m water depth, they are part of the deepest subsea development in the UK to date with a 143 km subsea tie-back to onshore facilities.
The reservoirs are found within the T35 biostratigraphic sequence of the Paleocene Vaila Formation and comprise sand-rich turbiditic channelized lobes with good reservoir properties, separated by metric to decimetric shale packages. Laggan is a gas-condensate field, whereas Tormore fluid is a richer gas with a saturated oil rim. Seismic reservoir characterization is a key to the field development where differentiation of fluid type proved challenging. Both fields came on stream in 2016 as part of the Greater Laggan area development scheme.
The Crosby Warren Field, Block DL001, UK Onshore
Authors: Johnson M. , Evans G. J. 
Published: October 2020

Abstract
The Crosby Warren Field is located onshore the UK, south of the Humber Estuary. It was discovered by RTZ Oil & Gas with the CW-1 (L46/12-3) well in 1986. The oil reservoir is Carboniferous, Namurian, Beacon Hill Flags sandstone, with gas found in Namurian sandstones of the Rough Rock, and the discovery well originally flowed waxy 40° API oil at rates of 45 bopd, which increased to nearly 700 bopd following fracture stimulation. The Beacon Hill Flags are a 10 m-thick group of laminated sandstones within a substantial gross thickness of sandstones, silts, muds and occasional thin claystones. The expected ultimate recovery for the field will be about 0.9 MMbbl of oil and 0.7 bcf of gas. Almost all of the oil and gas have already been recovered, and end of life for the field is expected to be in 2022.
The Britannia Field, Blocks 15/29, 15/30, 16/26 and 16/27, UK North Sea
Authors: Camm M. , Armstrong L. E. , Patel A. 
Published: October 2020

Abstract
The Lower Cretaceous Britannia Field development is one of the largest and most significant undertaken on the UK Continental Shelf. Production started in 1998 via 17 pre-drilled development wells and was followed by a decade of intensive drilling, whereby a further 40 wells were added. In 2000 Britannia's plateau production of 800 MMscfgd supplied 8% of the UK's domestic gas requirements.
As the field has matured, so too has its development strategy. Initial near-field development drilling targeting optimal reservoir thickness was followed by extended reach wells into the stratigraphic pinchout region. In 2014 a further strategy shift was made, moving from infill drilling to a long-term compression project to maximize existing production. During its 20-year history the Britannia Platform has undergone numerous changes. In addition to compression, production from five satellite fields has been routed through the facility: Caledonia (2003), Callanish and Brodgar (2008), Enochdhu (2015) and Alder (2016). A new field, Finlaggan, is due to be brought through Britannia's facilities in 2020, helping to maximize value from the asset for years to come.

As Britannia marks 20 years of production it has produced
c.
600 MMboe – surpassing the original ultimate recoverable estimate of
c.
570 MMboe – and is still going strong today.
The Cygnus Field, Blocks 44/11a and 44/12a, UK North Sea
Authors: Dredge Ian , Marsden Gary 
Published: October 2020

Abstract
The Cygnus Field is located in Blocks 44/11a and 44/12a of the UK Southern North Sea. The field was first discovered in 1988 as a tight lower Leman Sandstone Formation gas discovery by well 44/12- 1. After the licences had sat idle for several years, GDF Britain (now Neptune E&P UK Ltd) appraised the field from 2006 to 2010. During the appraisal phase, the lower Leman Sandstone was found to be of better quality than first discovered and the gas-bearing lower Ketch Member reservoir was also encountered. The field development was sanctioned in 2012.
The field has been developed from two wellhead platforms targeting Leman Sandstone and Ketch Member reservoirs. Five main fault blocks have been developed, with two wells in each fault block planned in the field development plan. The wells are long horizontal wells completed with stand-alone sand screens. At the time of writing, the production plateau is 320 MMscfgd (266 MMscfgd when third-party constraints apply), producing from nine wells with the final production well to be drilled.
The Erskine Field, Block 23/26b, UK North Sea
Authors: Robertson I. 
Published: October 2020

Abstract
The Erskine high-pressure–high-temperature gas condensate field was the first such field developed in the UK Continental Shelf. Since production started in 1997, the field has produced over 350 bcf of gas and 70 MMbbl of condensate. The reservoir pressure has depleted from an initial pressure of 960 bar (13 920 psi) down to 140–400 bar (2030–5800 psi), resulting in some compaction and sand production in some of the wells. Free water production has led to the formation of wellbore scale, which has required interventions to remove.
The reservoirs are sandstones of the Jurassic Puffin, Pentland and Heather formations. Estimates of hydrocarbons in place made using production and pressure data compare favourably with the initial estimates made during field development planning, although the Pentland Formation volume is some 20% below the sanction estimate.
Several major field outages have occurred, such as a condensate fire in 2010 and a blockage of the multiphase export pipeline in 2007. In addition, the field has experienced flow assurance problems related to scale and wax deposition. A new pipeline section was installed in 2018 to bypass a full pipeline blockage which occurred due to wax deposition.
The Howe and Bardolino fields, Blocks 22/12a and 22/13a, UK North Sea
Authors: Liebnitz S. 
Published: October 2020

Abstract
The Howe and Bardolino fields lie in UK Blocks 22/12a and 22/13a, respectively, on the eastern flank of the Forties–Montrose High. The Howe Field was discovered in 1987 by well 22/12a-1, and Bardolino in 1988 with well 22/13a-1ST. Both share common Jurassic reservoirs, have Upper Jurassic Kimmeridge Clay Formation top seals, require some form of lateral seal and have similar fluids. Howe has been producing relatively dry oil throughout its production life, indicating relatively good connectivity across the field area. In contrast, the Bardolino accumulation is proven to be compartmentalized. Bardolino is likely to be segmented through some fault-related mechanism.
In place volumes at the Howe Field are 46.8 MMbbl, with 17 MMbbl produced thus far through a combination of natural aquifer and solution gas cap drive by subsea development well 22/12a-9Z. In place volumes at the Bardolino Field are 11.2 MMbbl, with 1.1 MMbbl produced to date through depletion drive by a subsea development well 22/13a-8. This represents recovery rates of 35% for Howe and 10% for Bardolino to date. In place volumes for the undeveloped Pentland Formation at Howe are 5 MMbbl. In place estimates for the undeveloped Kimmeridge Clay Formation sandstones at Bardolino are 8 MMbbl.
The Douglas Field, Block 110/13b, UK East Irish Sea
Authors: Bunce J. 
Published: October 2020

Abstract

The Douglas Field is located in Block 110/13b in the East Irish Sea. It was the first oilfield to be discovered and produced in the region, having been found in 1990 and brought on stream in January 1996. The field structure comprises a series of north–south-trending, tilted, extensional fault blocks. The reservoir interval is the Triassic Ormskirk Sandstone Formation comprising good quality aeolian and fluvial sandstones. The field is relatively shallow, with the top reservoir at
c.
2120 ft true vertical depth subsea. The hydrocarbon is a light oil of 44°API gravity with a maximum column height of
c.
400 ft. The Douglas Field contains an estimated stock tank oil in place of 248 MMbbl and was developed with 22 wells: 15 producers, six water injectors and a single sour gas and condensate disposal well. Electric submersible pumps are installed in oil producers for artificial lift and water injection was utilized from field start-up for pressure maintenance. A water-alternating-gas pilot was implemented on the field in 2017 as an enhanced oil recovery scheme. The field currently produces at a rate of
c.
4000 bopd, with approximately 90% water cut. The field has produced 103 MMbbl to date, giving a current oil recovery of
c.
41%.
The Endurance CO
2
storage site, Blocks 42/25 and 43/21, UK North Sea
Authors: Gluyas Jon G. , Bagudu Usman 
Published: October 2020

Abstract

The Endurance, four-way, dip-closed structure in UK Blocks 42/25 and 43/21 occurs over a salt swell diapir and within Triassic and younger strata. The Lower Triassic Bunter Sandstone Formation reservoir within the structure was tested twice for natural gas (in 1970 and 1990) but both wells were dry. The reservoir is both thick and high quality and, as such, an excellent candidate site for subsurface CO
2
storage.

In 2013 a consortium led by National Grid Carbon drilled an appraisal well on the structure and undertook an injection test ahead of a planned development of Endurance as the first bespoke storage site on the UK Continental Shelf with an expected injection rate of 2.68 × 10
6
t of dense phase CO
2
each year for 20 years. The site was not developed following the UK Government's removal of financial support for carbon capture and storage (CCS) demonstration projects, but it is hoped with the recent March 2020 Budget that government support for CCS may now be back on track.
Phase I Clinical Trial of Combination Propranolol and Pembrolizumab in Locally Advanced and Metastatic Melanoma: Safety, Tolerability, and Preliminary Evidence of Antitumor Activity
Authors: Gandhi Shipra , Pandey Manu R. , Attwood Kristopher , Ji Wenyan , Witkiewicz Agnieszka K. , Knudsen Erik S. , Allen Cheryl , Tario Joseph D. , Wallace Paul K. , Cedeno Carlos D. , Levis Maria , Stack Suzanne , Funchain Pauline , Drabick Joseph J. , Bucsek Mark J. , Puzanov Igor , Mohammadpour Hemn , Repasky Elizabeth A. , Ernstoff Marc S. 
Published: October 2020

Abstract

Purpose:
Increased β-adrenergic receptor (β-AR) signaling has been shown to promote the creation of an immunosuppressive tumor microenvironment (TME). Preclinical studies have shown that abrogation of this signaling pathway, particularly β2-AR, provides a more favorable TME that enhances the activity of anti–PD-1 checkpoint inhibitors. We hypothesize that blocking stress-related immunosuppressive pathways would improve tumor response to immune checkpoint inhibitors in patients. Here, we report the results of dose escalation of a nonselective β-blocker (propranolol) with pembrolizumab in patients with metastatic melanoma.

Patients and Methods:
A 3 + 3 dose escalation study for propranolol twice a day with pembrolizumab (200 mg every 3 weeks) was completed. The primary objective was to determine the recommended phase II dose (RP2D). Additional objectives included safety, antitumor activity, and biomarker analyses. Responders were defined as patients with complete or partial response per immune-modified RECIST at 6 months.

Results:
Nine patients with metastatic melanoma received increasing doses of propranolol in cohorts of 10, 20, and 30 mg twice a day. No dose-limiting toxicities were observed. Most common treatment-related adverse events (TRAEs) were rash, fatigue, and vitiligo, observed in 44% patients. One patient developed two grade ≥3 TRAEs. Objective response rate was 78%. While no significant changes in treatment-associated biomarkers were observed, an increase in IFNγ and a decrease in IL6 was noted in responders.

Conclusions:
Combination of propranolol with pembrolizumab in treatment-naïve metastatic melanoma is safe and shows very promising activity. Propranolol 30 mg twice a day was selected as RP2D in addition to pembrolizumab based on safety, tolerability, and preliminary antitumor activity.