bluuebunny/crossref_metadata_2025_split huggingface dataset:
The chirality-flow formalism
Authors: Lifson Andrew , Reuschle Christian , Sjodahl Malin 
Published: October 2020

AbstractWe take a fresh look at Feynman diagrams in the spinor-helicity formalism. Focusing on tree-level massless QED and QCD, we develop a new and conceptually simple graphical method for their calculation. In this pictorial method, which we dub the chirality-flow formalism, Feynman diagrams are directly represented in terms of chirality-flow lines corresponding to spinor inner products, without the need to resort to intermediate algebraic manipulations.
Hierarchical controlled quantum communication via the χ state under noisy environment
Authors: Wang Nian-Nian , Ma Song-Ya , Li Xiang 
Published: October 2020

Wang et al. first studied hierarchical quantum information splitting of an arbitrary single-qubit state via the [Formula: see text] state as the entangled channel. There exists a hierarchy among the three receivers as far as the power to recover the teleported state is concerned. But the scheme is considered in ideal environment. In this paper, we reinvestigate the scheme in amplitude-damping and phase-damping noises. The fidelity and average fidelity are adopted to quantify the effect of noise. It is found that they are both dependent on the coefficients of the teleported state and the noise parameter. Moreover, we put forward a novel deterministic scheme to realize hierarchical controlled remote preparation of an arbitrary single-qubit state. Comparing with the previous scheme via the [Formula: see text] state, the sender does not need to perform information dividing due to the subtly constructed measurement basis. We also consider the proposed scheme under noisy environment.
The Dunlin, Dunlin SW, Osprey and Merlin fields, Blocks 211/23 and 211/24, UK North Sea
Authors: Ball R. , Gluyas J. 
Published: October 2020

Abstract
Located 160 km NE of the Shetland Islands in the East Shetland Basin, the Dunlin Cluster comprises four produced fields, Dunlin, Dunlin SW, Osprey and Merlin, in addition to some near-field satellite discoveries, Skye and Block 6.
Dunlin was discovered in July 1973 and production began in August 1978. The field was developed using a concrete gravity-base platform, Dunlin Alpha, which also served as the production facility for the rest of the Dunlin Cluster. Osprey was discovered in 1974 but not tied-in until January 1991. Dunlin SW was discovered in 1973 but not brought onto production until 1996. Merlin was discovered in February 1997 and tied-in later that same year.
Fairfield Energy acquired the Dunlin Cluster in 2008, and a programme of investment and facilities improvements, primarily in fuel gas infrastructure and power generation, sought to boost water-injection rates and bolster production, thereby extending the life of the asset. Ultimately, the Dunlin Cluster ceased production on 15 June 2015 after having maximized economic hydrocarbon recovery. The total Dunlin Cluster production exceeded 500 MMbbl of oil (Dunlin and Dunlin SW, 395 MMbbl oil; Osprey, 92 MMbbl oil; and Merlin, 27 MMbbl oil).
The Acorn and Beechnut fields, Blocks 29/8a(S), 29/8b, 29/9a(S) and 29/9b, UK North Sea
Authors: Hagen F. , Gluyas J. G. , Goffey G. 
Published: October 2020

Abstract
Unocal discovered the Acorn South Field with wells 29/8b-2 and 29/8b-2s in 1983. The well and its side-track found a small accumulation of oil in Upper Jurassic, Fulmar Formation sandstones in an inter-pod setting. Well 29/8b-3 drilled two years later on what was thought to be the same structure found Acorn North, a larger accumulation of oil in a Triassic Skagerrak Formation reservoir on the crest of a Triassic pod. Premier discovered the Beechnut Field two years later, well 29/9b-2 finding oil in the Fulmar and Skagerrak formations in a faulted, inter-pod setting. Both Acorn and Beechnut are deep, high-pressure and high-temperature fields with complex reservoir stratigraphy due to halokinesis during sedimentation and post-depositional structuration. The Skagerrak Formation reservoir in Acorn North is appreciably poorer than similar-age reservoirs further north whilst the Fulmar Formation in Beechnut is relatively poorly developed.
Acorn's mid-case oil in place is 90 MMbbl in the Skagerrak Formation and 13 MMbbl in the Fulmar Formation and, for Beechnut, is 15 MMbbl in the Fulmar Formation. Neither field has been developed. Limiting factors include the resource size, variable reservoir development (Beechnut), modest reservoir quality (Acorn North), compartmentalization concerns and development costs.
The Goldeneye Field, Blocks 14/29a and 20/4b, UK North Sea
Authors: Stewart Nicola , Marshall John D. 
Published: October 2020

Abstract
The Goldeneye gas-condensate field lies in the Moray Firth Basin in the UK Continental Shelf (UKCS) approximately 100 km off the NE coast of Scotland. The field was discovered in 1996 as a normally pressured accumulation with estimated gas-initially-in-place (GIIP) of 810 bcf with a thin oil rim in the Lower Cretaceous Captain Sandstone Member in a three-way, dip-closed structure. Field development included five production wells, with first gas achieved in 2004. Goldeneye was steadily produced under moderate aquifer support until cessation of production (COP) in 2010 following water breakthrough at the wells. Over its lifetime Goldeneye has produced 568 bcf of gas and 23 MMbbl of condensate.
Around the time of COP, the UK Carbon Capture and Storage Commercialisation Competition was announced, and Goldeneye was evaluated as a candidate. The removal of significant volumes of hydrocarbons through production left remaining capacity that could be refilled without reservoir pressure significantly exceeding virgin conditions. However, following withdrawal of funding from the UK Government in 2015, the project was put on hold. Since then additional subsurface work has been conducted to support the successful abandonment of the development wells, which had previously been suspended since 2010.
UKCS exploration: 50 years and counting
Authors: Rouillard Pierrick , Bagley Graeme , Moseley David , Myers Keith , Harding Alyson 
Published: October 2020

Abstract
Exploration drilling activity, discovery history and creaming curves in the offshore UK are analysed for each UK Continental Shelf (UKCS) basin and each play in the North Sea from the earliest wells drilled in 1965 until the end of 2017. Around 52 Bboe of commercially recoverable oil and gas has been discovered, with around half of this volume found in the first 10 years of exploration.
UKCS exploration plays are generally at a mature or super-mature stage and the exploration challenges reflect this. Although technical success rates have steadily increased since the 1990s, pool sizes are becoming smaller. In the last 10 years the average commercial discovery size has been 27 MMboe recoverable, and since 2010 only 10% of discoveries have been bigger than 43 MMboe recoverable. The UK Oil and Gas Authority's 6 Bboe mid-case yet-to-find estimate, as published in 2018, would take 40 years to unlock at the current rate of discovery.
Future exploration in the mature UKCS is intertwined with prolonging the life of production infrastructure and is increasingly dependent on the development of new low-cost development concepts. Increased focus on the search for subtle traps, and more reliable pre-drill risk and volume estimation through improved benchmarking and calibration will be key to future exploration success.
The Chestnut Field, Block 22/2a, UK North Sea
Authors: van Oorschot R. , Fletcher A. , Basford H. , Stuart A. 
Published: October 2020

Abstract
The Chestnut oilfield was discovered in 1986 and lies within Block 22/2a, Licence P354, of the UK Central North Sea. The field is approximately 7 km south of the Britannia gas condensate field and 8 km SE of the Alba oilfield on the southern edge of the Witch Ground Graben. The field comprises injected Lower Eocene Nauchlan sandstone encased within Horda Formation shales. The Chestnut Field began production in 2008 through the Hummingbird floating production vessel by means of two producer wells and one injector well. The complex reservoir geometries present seismic imaging challenges, and production data have indicated a larger connected volume than mapped from seismic data. In 2017, an infill producer well was drilled to arrest production decline. This well proved the presence and connectivity of sandstone beyond the field interior and increased confidence in using seismic data for predicting the injectite reservoir distribution.
The Captain Field, Block 13/22a, UK North Sea
Authors: Hodgins B. , Moy D. J. , Carnicero P. A. 
Published: October 2020

Abstract
The Captain Field in Block 13/22a is in the Moray Firth region of the UK North Sea. The primary reservoirs are Lower Cretaceous turbidite sandstones of the Captain Sandstone Member. Upper Jurassic shallower-marine Heather Formation sandstones of Oxfordian age provide a secondary reservoir. Total oil in place exceeds 1 Bbbl; however, the oil is heavy and viscous, requiring the continuous application of innovative technologies to maximize economic recovery from the field. Captain has been producing since 1997, with reservoir waterflood planned from the outset. Captain has been developed using long horizontal producers to maximize reservoir contact. Water injectors provide pressure support, with the aim of full voidage replacement. The Captain development has been phased with facilities consisting of two bridge-linked platforms, a floating production, storage and offloading vessel, and two subsea manifolds. Peak oil rate (100 000 boepd) was achieved in 2002. Average production in 2019 was 28 000 boepd. Captain is executing a chemical enhanced oil recovery (EOR) project, a first for the UK North Sea. Conventional waterflood yields an estimated ultimate recovery of 30–40%. Chemical EOR is expected to improve this by 5–20% in areas of the reservoir under polymer flood.
The Donan, Lochranza and Balloch fields, Blocks 15/20a and 15/20b, UK North Sea
Authors: Ings R. J. , Davids D. , Shotton P. , Agnew C. 
Published: October 2020

Abstract
The Donan Field is a mature asset in the final phase of production, following the redevelopment facilitated by various advances in technology and subsurface understanding. The original development utilized an ingenious single-well oil production system vessel which made small hydrocarbon accumulations economic, while the use of a floating production, storage and offloading vessel to redevelop the Donan Field as the ‘Dumbarton Project’ allowed the previously stranded Lochranza and undiscovered Balloch fields to be developed.
Donan and Lochranza are typical Paleocene oilfields with excellent water drive from a large regional aquifer. Balloch is an Upper Jurassic oilfield of equivalent size to Lochranza supported by a large regional aquifer but has a considerably higher recovery factor on account of excellent reservoir properties combined with a more optimal geometry to effectively sweep the reservoir. Most of the fields have exceeded pre-development expectations, particularly Balloch on account of it being developed whilst considerable subsurface uncertainties remained.
Recognition of a seismic amplitude v. offset response across the Donan Field was key to redevelopment, significantly increasing the oil in place and guiding the locations of development wells. This was supplemented by the ability to geosteer the horizontal development wells in the shallowest possible reservoir sand to maximize the recoverable resources. The use of horizontal development wells facilitated the development of short, areally extensive, oil columns; while the design of the production facilities and wells to include permanent artificial lift and capacity to process large water volumes was essential.
The Perth Field, Blocks 14/25a, 15/21c, 15/21e, UK North Sea
Authors: Allan N. P. , Southwood D. A. 
Published: October 2020

Abstract
The Perth Field was discovered in 1983 and appraised from 1992 to 1997, but has remained undeveloped due to the lack of a suitable export solution for the sour fluids. The field is a combined structural–stratigraphic trap on the southern edge of the Tartan Ridge in the Outer Moray Firth. An oil column of >1000 ft is developed in the turbiditic Upper Jurassic Claymore Sandstone Member which is mostly 500–800 ft thick in the proven appraised Core Perth area. Reference case oil in place within Core Perth is estimated at 197 MMbbl. An undrilled northern terrace may contain a similar amount of oil, with an additional 40 MMbbl estimated to be in place in a separate, proven northeastern fault panel. Potential development by subsea tieback to the Scott platform became an option in 2017. P50 reserves for 15 years’ production from Core Perth (five producers and two water injectors) are estimated at 47.3 MMbbl (24% recovery factor). The preferred concept is for oil and gas to be processed on a new self-contained sour module located on a standalone structure at Scott with oil exported in the Forties Pipeline System. Sour gas would be incinerated in a dedicated flare with recovered hydrocarbon gas exported to Scott.
The Ketch, Schooner and Topaz fields, Blocks 44/26, 44/28, 49/1a and 49/2a, UK North Sea
Authors: Moscariello A. , Goffey G. 
Published: October 2020

Abstract
The Ketch, Schooner and Topaz fields were discovered between 1984 and 1987 and produced from Upper Carboniferous, Westphalian C/D (Bolsovian/Asturian) reservoirs. Gas production began in 1996, 1999 and 2009 for Schooner, Ketch and Topaz respectively. The low net-to-gross reservoir consists of discrete, low sinuosity fluvio-deltaic channels evolving upwards into an aggradational, distal fluvial fan setting, dominated by braided channels. Fault compartmentalization and variable sandbody extent mean that reservoir connectivity was a key subsurface uncertainty. The Ketch and Schooner fields gas-in-place estimates at development approval of 956 and 1021 bcf are now modelled as 581 and 654 bcf respectively. This reduction is due mainly to remapping (Schooner) and revised reservoir modelling reflecting production experience. Generally poor reservoir connectivity is demonstrated by the lower connected gas-in-place volumes, estimated at 351 and 481 bcf respectively, based on production data. Field recovery to cessation of production in 2018 was 263 (Ketch) and 310 bcf (Schooner) or 75 and 64% of the in-place volume connected to production wells. Topaz has 139 bcf gas in place, with recovery of 10.4 bcf from a connected volume of 14 bcf, equating to 74% recovery of connected volumes or 7.5% full field recovery.
The Maria Field, Block 16/29a, UK North Sea
Authors: Stephens I. N. , Small S. , Wood P. H. 
Published: October 2020

Abstract
The Maria oilfield is located on a fault-bounded terrace in Block 16/29a of the UK sector of the North Sea, at the intersection of the South Viking Graben and the eastern Witch Ground Graben. The field was discovered in December 1993 by the 16/29a-11Y well and was confirmed by two further appraisal wells. The reservoir consists of shoreface sandstones of the Jurassic Fulmar Formation. The Jurassic sandstones, ranging from 100 to 180 ft in thickness, have variable reservoir properties, with porosities ranging from 10 to 18% and permeabilities from 1 to 300 mD. Hydrocarbons are trapped in a truncated rotated fault block, striking NW–SE. The reservoir sequence is sealed by Kimmeridge Clay Formation and Heather Formation claystones. Geochemical analysis suggests that Middle Jurassic Pentland Formation and Upper Jurassic Kimmeridge Clay Formation mudstones have been the source of the Maria hydrocarbons. Estimated recoverable reserves are 10.6 MMbbl and 67 bcf (21.8 MMboe). Two further production wells were drilled in 2018 to access unexploited areas.
Secretory Mucin 5AC Promotes Neoplastic Progression by Augmenting KLF4-Mediated Pancreatic Cancer Cell Stemness
Authors: Ganguly Koelina , Krishn Shiv Ram , Rachagani Satyanarayana , Jahan Rahat , Shah Ashu , Nallasamy Palanisamy , Rauth Sanchita , Atri Pranita , Cox Jesse L. , Pothuraju Ramesh , Smith Lynette M. , Ayala Sudhua , Evans Christopher , Ponnusamy Moorthy P. , Kumar Sushil , Kaur Sukhwinder , Batra Surinder K. 
Published: October 2020

Abstract

Secreted mucin 5AC (MUC5AC) is the most abundantly overexpressed member of the mucin family during early pancreatic intraepithelial neoplasia stage I (PanIN-I) of pancreatic cancer. To comprehend the contribution of Muc5ac in pancreatic cancer pathology, we genetically ablated it in an autochthonous murine model (KrasG12D; Pdx-1cre, KC), which mirrors the early stages of pancreatic cancer development. Neoplastic onset and the PanIN lesion progression were significantly delayed in Muc5ac knockout (KrasG12D; Pdx-1 cre; Muc5ac−/−, KCM) animals with a 50% reduction in PanIN-2 and 70% reduction in PanIN-3 lesions compared with KC at 50 weeks of age. High-throughput RNA-sequencing analysis from pancreatic tissues of KCM animals revealed a significant decrease in cancer stem cell (CSC) markers Aldh1a1, Klf4, EpCAM, and CD133. Furthermore, the silencing of MUC5AC in human pancreatic cancer cells reduced their tumorigenic propensity, as indicated by a significant decline in tumor formation frequency by limiting dilution assay upon subcutaneous administration. The contribution of MUC5AC in CSC maintenance was corroborated by a significant decrease in tumor burden upon orthotopic implantation of MUC5AC-depleted pancreatic cancer cells. Mechanistically, MUC5AC potentiated oncogenic signaling through integrin αvβ5, pSrc (Y416), and pSTAT3 (Y705). Phosphorylated STAT3, in turn, upregulated Klf4 expression, thereby enriching the self-renewing CSC population. A strong positive correlation of Muc5ac with Klf4 and pSTAT3 in the PanIN lesions of KC mouse pancreas reinforces the crucial involvement of MUC5AC in bolstering the CSC-associated tumorigenic properties of Kras-induced metaplastic cells, which leads to pancreatic cancer onset and progression.

Significance:
This study elucidates that de novo expression of MUC5AC promotes cancer cell stemness during Kras-driven pancreatic tumorigenesis and can be targeted for development of a novel therapeutic regimen.
Hormonal Regulation of Semaphorin 7a in ER+ Breast Cancer Drives Therapeutic Resistance
Authors: Crump Lyndsey S. , Wyatt Garhett L. , Rutherford Taylor R. , Richer Jennifer K. , Porter Weston W. , Lyons Traci R. 
Published: October 2020

Abstract

Approximately 70% of all breast cancers are estrogen receptor–positive (ER+ breast cancer), and endocrine therapy has improved survival for patients with ER+ breast cancer. However, up to half of these tumors recur within 20 years. Recurrent ER+ breast cancers develop resistance to endocrine therapy; thus, novel targets are needed to treat recurrent ER+ breast cancer. Here we report that semaphorin 7A (SEMA7A) confers significantly decreased patient survival rates in ER+ breast cancer. SEMA7A was hormonally regulated in ER+ breast cancer, but its expression did not uniformly decrease with antiestrogen treatments. Additionally, overexpression of SEMA7A in ER+ cell lines drove increased in vitro growth in the presence of estrogen deprivation, tamoxifen, and fulvestrant. In vivo, SEMA7A conferred primary tumor resistance to fulvestrant and induced lung metastases. Prosurvival signaling was identified as a therapeutic vulnerability of ER+SEMA7A+ tumors. We therefore propose that targeting this pathway with inhibitors of survival signaling such as venetoclax may prove efficacious for treating SEMA7A+ tumors.

Significance:
SEMA7A predicts for and likely contributes to poor response to standard-of-care therapies, suggesting that patients with SEMA7A+ER+ tumors may benefit from alternative therapeutic strategies.
Effects of HER Family–targeting Tyrosine Kinase Inhibitors on Antibody-dependent Cell-mediated Cytotoxicity in HER2-expressing Breast Cancer
Authors: Collins Denis M. , Madden Stephen F. , Gaynor Nicola , AlSultan Dalal , Le Gal Marion , Eustace Alex J. , Gately Kathy A. , Hughes Clare , Davies Anthony M. , Mahgoub Thamir , Ballot Jo , Toomey Sinead , O'Connor Darran P. , Gallagher William M. , Holmes Frankie A. , Espina Virginia , Liotta Lance , Hennessy Bryan T. , O'Byrne Kenneth J. , Hasmann Max , Bossenmaier Birgit , O'Donovan Norma , Crown John 
Published: October 2020

Abstract

Purpose:
Antibody-dependent cell-mediated cytotoxicity (ADCC) is one mechanism of action of the monoclonal antibody (mAb) therapies trastuzumab and pertuzumab. Tyrosine kinase inhibitors (TKIs), like lapatinib, may have added therapeutic value in combination with mAbs through enhanced ADCC activity. Using clinical data, we examined the impact of lapatinib on HER2/EGFR expression levels and natural killer (NK) cell gene signatures. We investigated the ability of three TKIs (lapatinib, afatinib, and neratinib) to alter HER2/immune-related protein levels in preclinical models of HER2-positive (HER2+) and HER2-low breast cancer, and the subsequent effects on trastuzumab/pertuzumab-mediated ADCC.

Experimental Design:
Preclinical studies (proliferation assays, Western blotting, high content analysis, and flow cytometry) employed HER2+ (SKBR3 and HCC1954) and HER2-low (MCF-7, T47D, CAMA-1, and CAL-51) breast cancer cell lines. NCT00524303 provided reverse phase protein array–determined protein levels of HER2/pHER2/EGFR/pEGFR. RNA-based NK cell gene signatures (CIBERSORT/MCP-counter) post-neoadjuvant anti-HER2 therapy were assessed (NCT00769470/NCT01485926). ADCC assays utilized flow cytometry–based protocols.

Results:
Lapatinib significantly increased membrane HER2 levels, while afatinib and neratinib significantly decreased levels in all preclinical models. Single-agent lapatinib increased HER2 or EGFR levels in 10 of 11 (91%) tumor samples. NK cell signatures increased posttherapy (P = 0.03) and associated with trastuzumab response (P = 0.01). TKI treatment altered mAb-induced NK cell–mediated ADCC in vitro, but it did not consistently correlate with HER2 expression in HER2+ or HER2-low models. The ADCC response to trastuzumab and pertuzumab combined did not exceed either mAb alone.

Conclusions:
TKIs differentially alter tumor cell phenotype which can impact NK cell–mediated response to coadministered antibody therapies. mAb-induced ADCC response is relevant when rationalizing combinations for clinical investigation.