bluuebunny/crossref_metadata_2025_split huggingface dataset:
Long-term safety of tofacitinib up to 9.5 years: a comprehensive integrated analysis of the rheumatoid arthritis clinical development programme
Authors: Cohen Stanley B , Tanaka Yoshiya , Mariette Xavier , Curtis Jeffrey R , Lee Eun Bong , Nash Peter , Winthrop Kevin L , Charles-Schoeman Christina , Wang Lisy , Chen Connie , Kwok Kenneth , Biswas Pinaki , Shapiro Andrea , Madsen Ann , Wollenhaupt Jürgen 
Published: October 2020

ObjectiveTofacitinib is an oral Janus kinase (JAK) inhibitor for the treatment of rheumatoid arthritis (RA). We report the largest integrated safety analysis of tofacitinib, as of March 2017, using data from phase I, II, III, IIIb/IV and long-term extension studies in adult patients with RA.MethodsData were pooled for patients with RA who received ≥1 tofacitinib dose. Incidence rates (IRs; patients with events/100 patient-years [PY]; 95% CIs) of first-time occurrences were obtained for adverse events (AEs) of interest.Results7061 patients received tofacitinib (total exposure: 22 875 PY; median [range] exposure: 3.1 [0 to 9.6] years). IRs (95% CI) for serious AEs, serious infections, herpes zoster (all), opportunistic infections (excluding tuberculosis [TB]) and TB were 9.0 (8.6 to 9.4), 2.5 (2.3 to 2.7), 3.6 (3.4 to 3.9), 0.4 (0.3 to 0.5) and 0.2 (0.1 to 0.2), respectively. IRs (95% CI) for malignancies (excluding non-melanoma skin cancer [NMSC]), NMSC and lymphomas were 0.8 (0.7 to 0.9), 0.6 (0.5 to 0.7) and 0.1 (0.0 to 0.1), respectively. IRs (95% CI) for gastrointestinal perforations, deep vein thrombosis, pulmonary embolism, venous thromboembolism, arterial thromboembolism and major adverse cardiovascular events were 0.1 (0.1 to 0.2), 0.2 (0.1 to 0.2), 0.1 (0.1 to 0.2), 0.3 (0.2 to 0.3), 0.4 (0.3 to 0.5) and 0.4 (0.3 to 0.5), respectively. IR (95% CI) for mortality was 0.3 (0.2 to 0.3). IRs generally remained consistent across 6-month intervals to >78 months.ConclusionThis represents the largest clinical dataset for a JAK inhibitor in RA to date. IRs remained consistent with previous reports from the tofacitinib RA clinical development programme, and stable over time.Trial registration numbersNCT01262118;NCT01484561;NCT00147498;NCT00413660;NCT00550446;NCT00603512;NCT00687193;NCT01164579;NCT00976599;NCT01059864;NCT01359150;NCT02147587;NCT00960440;NCT00847613;NCT00814307;NCT00856544;NCT00853385;NCT01039688;NCT02187055;NCT00413699;NCT00661661.For summary of phase I, phase II, phase III, phase IIIb/IV and LTE studies included in the integrated safety analysis, see online supplemental table 1.
Spermidine is not an independent factor regulating limb muscle mass in mice following androgen deprivation
Authors: Gordon Bradley S. , Rossetti Michael L. , Casero Robert A. 
Published: October 2020

Maintaining a critical amount of skeletal muscle mass is linked to reduced morbidity and mortality. In males, testicular androgens regulate muscle mass with a loss of androgens being critical as it is associated with muscle atrophy. Atrophy of the limb muscles is particularly important, but the pathways by which androgens regulate limb muscle mass remain equivocal. We used microarray analysis to identify changes to genes involved with polyamine metabolism in the tibialis anterior (TA) muscle of castrated mice. Of the polyamines, the concentration of spermidine (SPD) was significantly reduced in the TA of castrated mice. To assess whether SPD was an independent factor by which androgens regulate limb muscle mass, we treated castrated mice with SPD for 8 weeks and compared them with sham operated mice. Though this treatment paradigm effectively restored SPD concentrations in the TA muscles of castrated mice, mass of the limb muscles (i.e., TA, gastrocnemius, plantaris, and soleus) were not increased to the levels observed in sham animals. Consistent with those findings, muscle force production was also not increased by SPD treatment. Overall, these data demonstrate for the first time that SPD is not an independent factor by which androgens regulate limb skeletal muscle mass. Novelty: Polyamines regulate growth in various cells/tissues. Spermidine concentrations are reduced in the limb skeletal muscle following androgen depletion. Restoring spermidine concentrations in the limb skeletal muscle does not increase limb muscle mass or force production.
Experimental investigation and constitutive modeling of the behaviour of highly plastic Lower Rhine clay under monotonic and cyclic loading
Authors: Tafili Merita , Wichtmann Torsten , Triantafyllidis Theodoros 
Published: October 2020

A new experimental series on the highly plastic (plasticity index, IP = 34%) Lower Rhine clay (LRC) is presented. The study comprises tests on normally as well as overconsolidated samples under monotonic and cyclic loading. The loading velocity has been varied to evaluate the strain rate dependency of the LRC behaviour, testifying the well-known reduction of undrained shear strength with decreasing displacement rate. Isotropic consolidation followed by a cyclic loading with constant deviatoric stress amplitude leads to a failure due to large strain amplitudes with eight-shaped effective stress paths in the final phase of the tests. The inherent anisotropy has been additionally evaluated using samples cut out in either the vertical or the horizontal direction. Furthermore, the behaviour of LRC is compared with the behaviour of low plastic kaolin silt (IP = 12.2%). A new visco-hypoplastic-type constitutive model with a historiotropic yield surface has been used to simulate some of the experiments with cyclic loading. Even the eight-shaped stress loops at cyclic mobility are reproduced well with this model. The data of this paper can be also used by other researchers for the examination, calibration, improvement, or development of constitutive models dedicated to fine-grained soils under monotonic and cyclic loading.
Digital Bifurcation Analysis of Internet Congestion Control Protocols
Authors: Beneš Nikola , Brim Luboš , Pastva Samuel , Šafránek David 
Published: October 2020

Digital bifurcation analysis is a new algorithmic method for exploring how the behavior of a parameter-dependent discrete system varies with a change in its parameters and, in particular, for the identification of bifurcation points where such variation becomes dramatic. We have developed the method in an analogy with the traditional bifurcation theory and have successfully applied it to models taken from systems biology. In this paper, we report on the application of the digital bifurcation analysis for analyzing the stability of internet congestion control protocols by inspecting their attractor bifurcations. In contrast to the analytical methods, our approach allows fully automated analysis. We compared the robustness of the basic Random Early Drop (RED) approach with four substantially different extensions, namely gentle, adaptive, gradient descent, and integral feedback RED. The basic RED protocol is well known to exhibit unstable behavior when parameters are varied. In the case of adaptive and gradient descent RED protocol, the analysis showed significant improvements in stability, whereas in the results for gentle and integral feedback RED protocols the improvement was negligible. We performed a series of model simulations, the results of which were in accordance with our bifurcation analysis. Based on our results, we can recommend both adaptive and gradient descent RED to improve the robustness of the RED protocol.
The Innes Field, Block 30/24, UK North Sea
Authors: Gluyas J. G. , Arkley P. 
Published: October 2020

Abstract
The abandoned Innes Field was within Block 30/24 on the western margin of the Central Trough in the UK sector of the North Sea. Hamilton Brothers Oil Company operated the licence, and Innes was the third commercially viable oil discovery in the block after Argyll and Duncan. It was discovered in 1983 with well 30/24-24. Three appraisal wells were drilled, one of which was successful. Oil occurs in the Early Permian Rotliegend Group sandstones sealed by Zechstein Group dolomites and Upper Jurassic shale.
The discovery well and successful appraisal well were used for production. Export of light, gas-rich crude was via a 15 km pipeline to Argyll. Innes was produced using pressure decline. It was abandoned in 1992 having produced 5.8 MMbbl of oil and possibly 9.8 bcf of gas. Water cut was a few percent.
Innes was re-examined between 2001 and 2003 by the Tuscan Energy/Acorn Oil and Gas partnership with a view to tying the field back to the newly redeveloped Argyll (Ardmore) Field but marginal economics and financial constraints for the two start-up companies prevented any further activity. Enquest currently owns the licence and the company has redeveloped Argyll/Ardmore, as Alma. There are no plans to redevelop Innes.
The Pilot, Elke, Blakeney, Narwhal, Harbour and Feugh fields, Blocks 21/27, 21/28, 28/2 and 28/3, UK North Sea
Authors: Brown Stephen A. , Wood Peter H. , Bamford Maurice L. F. , Gluyas Jon G. 
Published: October 2020

Abstract
The, as yet undeveloped, heavy-oil fields of the Western Platform contain about 500 MMbbl of oil in place. The fields are reservoired in highly porous and permeable, Middle Eocene, deep-water sandstones of the Tay Sandstone Member, deposited as turbidite flows from a shelf immediately to the west.
Oil gravity varies from 19° API in the Harbour Field to 12° API in the northern end of the Pilot Field. The reservoirs are shallow: Pilot and Harbour are at about 2700 ft TVDSS, with the Narwhal, Elke, Blakeney and Feugh discoveries being deeper at about 3300 ft TVDSS. Overall, oil viscosity decreases and API oil gravity increases with depth.
To date, the high oil viscosity has precluded development of these discoveries, and many previous operators have considered various development schemes, all based on water flood.
The development of the Pilot Field is being planned using either a hot-water-flood, steam-flood or polymer-flood approach, which all have the potential of achieving a very high recovery factor of 35–55%. Steam has been evaluated in most detail and about 240 MMbbl could be recovered should all of these discoveries be steam flooded.
The Renee Field, Block 15/27a, UK North Sea
Authors: Tegerdine Graham 
Published: October 2020

Abstract
The Renee Field lies in Block 15/27 toward the eastern end of the Renee Ridge, a major intra-basinal high in the Outer Moray Firth separating the Witch Ground Graben and South Halibut Graben. The block was awarded to a Phillips Petroleum-led consortium in the fourth Round of UKCS Licensing in March 1972. The 15/27-1 discovery well was drilled in 1976, testing oil at rates of 8025 bopd from stacked Piper/Upper Scott sandstone reservoirs. The field was appraised in mid-1997 and an Annex B submitted to the Department of Trade and Industry in late 1997 for a joint Renee and Rubie Field development. Oil export was via a 21 km pipeline to the Ivanhoe/Rob Roy fields, north of Renee. The development comprised a three-well drilling programme, completed in August 1999. First production was achieved in February 1999 at rates of up to 20 000 bopd, the plateau period continuing until year end. Production continued to decline until the field was permanently shut-in during September 2006. Ultimate recovery was 8.9 MMbbl and recovery factor 49%, based on a final mapped stock tank oil-in-place of 18.2 MMbbl. Decommissioning of the Renee Field commenced in 2015 with the removal of the subsea infrastructure.
The Elswick Field, Bowland Basin, UK Onshore
Authors: Hampson Mathew , Martin Heather , Craddock Lucy , Wood Thomas , Rylands Ellie 
Published: October 2020

Abstract
The Elswick Field is located within Exploration Licence EXL 269a (Cuadrilla Resources Ltd is the operator) on the Fylde peninsula, West Lancashire, UK. It is the first producing onshore gas field to be developed by hydraulic fracture stimulation in the region. Production from the single well field started in 1996 and has produced over 0.5 bcf for onsite electricity generation. Geologically, the field lies within a Tertiary domal structure within the Elswick Graben, Bowland Basin. The reservoir is the Permian Collyhurst Sandstone Formation: tight, low-porosity fluvial desert sandstones, alluvial fan conglomerates and argillaceous sandstones. The reservoir quality is primarily controlled by depositional processes further reduced by diagenesis. Depth to the reservoir is 3331 ft TVDSS with the gas–water contact at 3400 ft TVDSS and with a net pay thickness of 38 ft.
The Vale of Pickering gas fields: Kirby Misperton, Malton, Marishes and Pickering, North Yorkshire, UK Onshore
Authors: Harrison D. , Haarhoff M. , Heath-Clarke M. , Hodgson W. , Hughes F. , Ware D. , Mortimer A. 
Published: October 2020

Abstract

The Vale of Pickering gas fields were discovered over a 20-year period. The development scheme was aimed to deliver 9.3 MMscfd gas to the Knapton Power Station nearby. Cumulative production is 30.3 bcf from an estimated 172 bcf gas initially in place. The gas fields comprise a series of low relief structures at depths around 5000 ft true depth subsea. The primary reservoir is Zechstein Group dolomitized and fractured carbonates of the Permian Kirkham Abbey Formation with average reservoir quality ranges of 12–13% porosity and 0.5–1.5 mD permeability. Secondary reservoirs exist in Carboniferous sandstones directly below the Base Permian Unconformity. The gas is sourced from Lower Carboniferous shales. The fields were discovered using 2D seismic data and subsequent 3D seismic data have been merged to form a 260 km
2
dataset. Zechstein production has been limited by early water breakthrough. Artificial lift is planned to enhance the gas flow rate on the Pickering Field and anticipated water influx will be re-injected. If this enhanced gas recovery scheme is successful it can be applied to the other fields. Plans to hydraulically fracture a number of zones in the Carboniferous Lower Bowland Section are in progress.
The Forties Field, Blocks 21/10 and 22/6a, UK North Sea
Authors: Rose P. T. S. , Byerley G. W. , College E. , Pyle J. R. , Ralph D. J. , Rowbotham P. S. , van Oorschot L. A. , Towart J. , Vaughan O. , Vermaas M. 
Published: October 2020

Abstract
The Forties Field, discovered by BP in 1970, is the largest oilfield on the UK Continental Shelf. It is trapped in a simple four-way dip closure, with a Paleocene turbidite sandstone reservoir. The Forties Field originally contained between 4.2 and 5 billion bbl of oil, with 2.75 billion bbl produced to June 2017. Production has been supported by water injection and the influx of a regional aquifer. The original development contained equally spaced producers with peripheral injectors. As the field matured, production was concentrated in the crestal parts of the field with injectors tending to be moved upflank. With the development of seismic lithology prediction and fluid detection, together with 4D seismic technology, it became possible in the late 1990s to target bypassed oil in unexpected locations throughout the field. In 2003, BP sold the field to Apache who were able to rejuvenate production, adding over 170 MMbbl oil reserves, with an extended drilling campaign targeting bypassed pay identified using seismic technologies. Production at the Forties facility has been further enhanced by the development of four satellite oilfields, Bacchus (Jurassic reservoir), Brimmond, Maule and Tonto (Eocene reservoirs), together with Aviat (Pleistocene reservoir) produced for fuel gas supply.
The Blake Field, Blocks 13/24a and 13/29b, UK North Sea
Authors: Saundry E. , Colmenares J. 
Published: October 2020

Abstract
The Blake Field is subdivided into two discrete parts, the ‘Channel’ and the ‘Flank’ areas. The two areas are geologically different but also reflect the different levels of maturity in terms of their development. Blake Channel was discovered in 1998, with first production commencing in 2001. Blake Flank was discovered in 1974 and developed in 2003.
The field contains saturated light oil, with a field-wide oil–water contact and two significant gas caps. The reservoir comprises deep-water turbidite sands of Lower Cretaceous age.
The combination of complex depositional environment and dynamic data resulted in the decision in 2016, to create a new model incorporating a fully integrated approach to subsurface evaluation and modelling. The latest work summarized in this paper incorporates a new geological interpretation along with the addition of aquifer extensions to capture depletion from offset fields, and a palaeo-oil leg, to help limit aquifer influx and improve history match. 4D seismic has also been incorporated to support the evaluation. Blake Channel and Flank have oil-in-place of 230 MMbbl and 300 MMbbl and have produced 94 MMbl and 15 MMbbl, respectively, to date.
The Buchan Field, Blocks 20/5a and 21/1a, UK North Sea
Authors: Wynn T. , Saundry E. 
Published: October 2020

Abstract

The Buchan Oilfield is a large mature field, now suspended, located in the Moray Firth. The field is situated 153 km NE of Aberdeen in water depths of
c.
122 m. The reservoir comprises an overpressured and fractured Upper Devonian–Early Carboniferous fluvio-lacustrine sandstone. Production was via high permeability channel sandstones and permeable faults and fractures. The Buchan Field was brought onto production in May 1981 by BP Petroleum Development Ltd via the Buchan Alpha semi-submersible floating production vessel (FPV). The oil column is
c.
2000 ft in height with a matrix stock tank oil initially in place (STOIIP) range of 322–471–668 MMbbl. Production from the ten vertical development wells was driven by pressure depletion (over 5000 psi since first oil) coupled with weak aquifer influx. Production from the Buchan Field ceased on 13 May 2017 after having produced 147.8 MMbbl. The Buchan FPV was subsequently taken off-station during August 2017. A new facility or tie-back redevelopment option will be required to access the remaining resources which are in the range of 20–90 MMbbl depending on the STOIIP, the production mechanism and the potential development plan.
The Burghley Field, Block 16/22, UK North Sea
Authors: Heath R. , Robertson K. 
Published: October 2020

Abstract

The Burghley Field is a Paleocene oil field located in Block 16/22 on the UK Continental Shelf about 8.5 km NE of the Balmoral Field, in a water depth of
c.
143 m. Burghley produces undersaturated oil from sandstones of the Maureen Formation. It comprises a low relief four-way dip-closed structure located on the SE end of the Fladen Ground Spur. The field was discovered in 2005 by well 16/22-7. Overall nine well penetrations were drilled prior to the commitment to develop the field. The Burghley Field was brought on-stream in October 2010 as a single subsea horizontal well development tied back to the Balmoral floating production vessel. The current estimate for oil in place is
c.
20 MMbbl for the entire field, with approximately 12 MMbbl in the core area where the development well is located. The expected ultimate recovery is approximately 5.65 MMbbl.
The Enoch Field, Block 16/13a, UK North Sea
Authors: Robertson K. , Heath R. , McKenzie A. 
Published: October 2020

Abstract

The Enoch Field is located in the South Viking Graben and straddles the UK/Norway median line with 80% of the field in the UK and 20% in Norway. Enoch produces undersaturated oil from the Early Eocene-age Flugga Sandstone Member of the Sele Formation. Hydrocarbons have been trapped by a combination of compaction-related dip closure and sand pinchout. The current stock tank oil initially in place estimate is
c.
42 MMbbl with expected ultimate recovery of 11.5 MMbbl. The field was brought onstream in May 2007 via a single horizontal subsea gas-lifted well tied back to the Brae Alpha platform. Initial oil production rates were
c.
11 800 bopd. The field is currently in decline and in December 2018 production was
c.
1800 bopd with 80% water-cut. Cumulative oil production to the end of 2018 was 10.581 MMbbl.
The Blane Field, Block 30/3a, UK North Sea
Authors: Robertson K. , Heath R. , Macdonald R. 
Published: October 2020

Abstract

The Blane Field is located in the central North Sea in Block 30/3a (Licence P.111), approximately 130 km SE of the Forties Field, in a water depth of 75 m (246 ft). It straddles the UK/Norway median line with 82% of the field in the UK and 18% in Norway. Blane produces undersaturated oil from the Upper Forties Sandstone Member of the Sele Formation and contains good quality light oil within a four-way structural closure; it has a hydrodynamically tilted original oil–water contact. The field stock-tank oil initially in place estimate is 93 MMbbl with an expected ultimate recovery of 33 MMbbl. Blane first oil was achieved in September 2007. The field has been developed by two horizontal producers located on the central crest of the field supported by a water injector drilled on the NW flank. Oil production peaked at
c.
17 000 bopd in 2007 and the field is currently in decline. By the end of 2018 production was
c.
3000 bopd with 55% water-cut. Cumulative oil production to the end of 2018 was 26.6 MMbbl.
The Corringham, Gainsborough–Beckingham, Glentworth, Nettleham, Stainton and Welton fields, UK Onshore
Authors: Ward Kelsey L. , Folorunso Frank O. 
Published: October 2020

Abstract
This paper focuses on the southern part of the East Midlands oil province, in which most hydrocarbon reservoirs are in Carboniferous strata and are primarily oil producing. The oils are predominantly sourced from the Namurian interbedded shales in the Gainsborough Trough and are trapped within anticlinal structures.
Oil and gas exploration and production in the UK was marked by the Hardstoft-1 discovery in 1919. Since this discovery, more than 33 fields have been discovered in the East Midlands oil province, including the fields studied in this paper: Egmanton (in 1955), Bothamsall and Corringham (in 1958), Gainsborough and Beckingham (in 1959), South Leverton (in 1960), Glentworth (in 1961), and, the UK's second largest onshore field, Welton (in 1981). All of these fields produce from a Carboniferous petroleum system, sourced from Pendleian-age shales, reservoired in Namurian- and Westphalian-age sands, and trapped predominantly via structural, anticlinal traps.
The Pierce Field, Blocks 23/22a and 23/27, UK North Sea
Authors: Hale M. , Laird R. , Gavnholt J. , van Bergen P. F. 
Published: October 2020

Abstract
The Pierce Field lies 250 km east of Aberdeen, in the UK sector of the East Central Graben. The field comprises twin salt diapirs, forming the trap for oil and free gas in the Paleocene–Eocene Forties Sandstone Member reservoir. The diapirs exerted a strong influence over the sedimentation of the reservoir, with the construction of multistorey sandstone bodies forming a complex reservoir geometry further complicated by a hydrodynamic aquifer.
The field currently produces to the Haewene Brim floating production storage and offloading (FPSO) installation, and has undergone several phases of development as the understanding has matured. It was initially developed with six subsea horizontal oil producers tied back to the FPSO, with produced gas reinjected through two gas injectors. In 2004–05, water injection was introduced to South Pierce to provide increased pressure support and improve sweep. To maximize recovery, four additional oil producers were drilled between 2010 and 2016, with the final (third) gas injector drilled in 2010. Production is primarily constrained by topsides gas compression capacity leading to gas/oil ratio optimization being the focus of the current field management strategy.
The final phase of field development, included in the original field development plan, involves depressurization of the field with the installation of a gas export line.