bluuebunny/crossref_metadata_2025_split huggingface dataset:
Exploring barriers and facilitators of physical distancing in the context of the COVID-19 pandemic: a qualitative interview study
Authors: Farrell Karen , Durand Hannah , McSharry Jenny , Meade Oonagh ,   The Health Psychology Public Advisory Panel, Kenny Eanna , Noone Chris , O'Connor Laura L. , Lavoie Kim L. , Byrne Molly , Mooney Robert , McGuire Brian E. , Molloy Gerard J. 
Published: May 2021

Background: Physical distancing measures (e.g., keeping a distance of two metres from others, avoiding crowded areas, and reducing the number of close physical contacts) continue to be among the most important preventative measures used to reduce the transmission of severe acute respiratory syndrome coronavirus 2 (SARS-CoV-2) that causes coronavirus disease 2019 (COVID -19). Therefore, it is important to understand barriers and facilitators of physical distancing to help inform future public health campaigns. Methods: The current study aimed to qualitatively explore barriers and facilitators of physical distancing in the context of the COVID-19 pandemic using a qualitative interpretative design. Semi-structured one-to-one phone interviews were conducted with 25 participants aged 18+ years and living in the Republic of Ireland between September and October 2020. A purposive sampling strategy was used to maximise diversity in terms of age, gender, and socioeconomic status. Interviews were transcribed verbatim and analysed using inductive thematic analysis. Results: Analysis resulted in the development of six main themes related to barriers and facilitators of physical distancing: (1) Maintaining and negotiating close relationships; (2) Public environments support or discourage physical distancing; (3) Habituation to threat; (4) Taking risks to maintain well-being; (5) Personal responsibility to control the “controllables”; and (6) Confusion and uncertainty around government guidelines. Conclusions: Our study found that physical distancing measures are judged to be more or less difficult based on a number of internal and external psychosocial factors, including maintaining and negotiating close relationships, habituation to threat, risk compensation, structure of public environments, personal responsibility, and confusion or uncertainty around government guidelines. Given the diversity in our sample, it is clear that the identified barriers and facilitators vary depending on context and life stage. Messaging that targets sub-groups of the population may benefit from considering the identified themes in this analysis.
Application of paste-type acellular dermal matrix in hard-to-heal wounds
Authors: Kim Sang Wha , Shim Hyung Sup , Lee Jihye , Kim Youn Hwan 
Published: May 2021

Objective: The extracellular matrix (ECM) is one of the most important elements in wound healing. Absence or dysfunction of the ECM may impair wound healing. The application of acellular dermal matrix (ADM) as a substitute for ECM has been suggested. This study investigated the clinical application and wound healing effects of a paste-type ADM in patients presenting with hard-to-heal wounds due to various causes. Method: Patients with a hard-to-heal wound for >1 month, from September 2017 to February 2019, were included in this study. After debridement, the paste-type ADM was applied, at zero (baseline), two and four weeks. After application of the paste-type ADM, a conventional dressing was applied using polyurethane foam. Wound size, the formation of granulation tissue, re-epithelialisation, complete healing and adverse events were recorded at zero (baseline), one, two, four, eight and 12 weeks after the initial treatment. Results: A total of 18 patients took part (eight male, 10 female, mean age of 56±16.16 years). The mean wound area decreased from 17.42±10.04cm2 to 12.73±7.60cm2 by week one (p<0.05), to 10.16±7.00 by week two (p<0.0005), to 5.56±5.25 by week four (p<0.0001), to 2.77±5.15 by week eight (p<0.0001) and to 2.07±4.78 by week 12 (p<0.0001). The number of patients with >75% re-epithelialisation increased from two (11.1%) at two weeks to five (27.8%) at four weeks, to 11 (61.1%) at eight weeks and to 13 (72.2%) at 12 weeks. The number of patients showing complete wound healing was two (11.1%) at four weeks, nine (50.0%) at eight weeks and 12 (66.7%) at 12 weeks. No adverse events were reported during treatment. Conclusion: The paste-type ADM used in this study is a viable option for facilitating wound healing; it can shorten hospitalisation, and promote a faster recovery and return to normal life activities.
H. Brentwood Oil and Gas Field, Contra Costa County, California
Authors: Ditzler Clark C. , Vaughan Richard H. 
Published: May 2021

Abstract
Brentwood oil and gas field in Contra Costa County is California's northernmost commercial oil-producing area. It is about 40 mi east of San Francisco and 10 mi south of the Rio Vista gas field. The field was discovered in June 1962 by Shell, Occidental, and Brazos' joint well, Heidorn 4-4. The area was developed as a gas field until the discovery of oil in the Ginochio 2-16 well in December 1962. By December 1965, there were 50 producing wells in Brentwood field. Of these, 15 produced predominantly gas with small quantities of associated oil. The other 35 wells produced oil and gas at different ratios.
The Paleocene and Cretaceous reservoir beds dip north at a low angle and are truncated by a south-dipping unconformity surface, which is overlain by a widespread “Meganos gorge” shale unit that provides the major updip trap of the oil and gas pools. The field is traversed by a series of northwest-striking normal faults. The oil-producing portion of the Brentwood field consists of three producing zones in massive sandstone beds separated by shale bodies. These are the First Massive Martinez sand of Paleocene age, the Second Massive Martinez sand of Paleocene age, and the Third Massive Martinez sand of Late Cretaceous C- and D-l-Zone ages. The oil is in 25-100-ft columns over- lain by gas caps ranging upward to 250 ft in thickness. Thinly bedded Upper Martinez sandstone stringers, known as the “Heidorn” and “Ginochio” sands, are about 500-800 ft above the First Massive Martinez and produce essentially dry gas with only minor quantities of condensate.
Recent production from the field has been approximately 2,000 bbls of oil and 10 million cu ft of gas a day. Several gas wells that are completed in gas caps underlain by oil columns have been shut in to conserve reservoir energy. The quality of the gas produced from Brentwood field is exceptionally high for the Sacramento Valley. The Btu values range from 1,050 to more than 1,200.
Gas from the field is delivered by Shell-Dow pipeline to the Dow Chemical Company plant at Pittsburg, California, and the Shell Oil Company refinery at Martinez, California. By the end of 1965, the field had produced approximately 2,300,000 bbls of oil and 13,000 million cu ft of gas.
Introduction to Regional Geology and Typical Gas Fields of Western Anadarko Basin
Authors: Totten Robert B. , Horn Paul H. 
Published: May 2021

Abstract
The Texas and Oklahoma Panhandle areas encompass a vast area of stratigraphic and structural entrapment for gas and oil, principally gas. Significant reserves and production have been found continuously since 1918 and there should be no decrease in activity in the foreseeable future. The Anadarko basin, defined on the south by the buried Amarillo mountains and on the west by the Cimarron uplift, and rising into the shallow Hugoton embayment on the north, received a flood of sediments in the Pennsylvanian which provided the principal reservoir rocks. Morrow, Virgil, and Missouri rocks are the most important producing units.
Hugoton Panhandle Field, Kansas, Oklahoma and Texas
Authors: Mason John W. 
Published: May 2021

Abstract
The Hugoton-Panhandle gas field, in parts of Kansas, Texas, and Oklahoma, is an area of almost 8,500 sq mi and contains one of the world's largest known gas reserves. The field was discovered in 1918 by drilling on a surface structural feature and now includes almost 5.5 million acres which are being drained by 10,500 wells. Production is found in Permian and Pennsylvanian granite wash and carbonate rocks in the south and in Permian dolomite and limestone in the north. The primary controlling mechanisms for the accumulations are, in the south, a compaction anticline over the buried Amarillo ridge and, in the north, a hydrodynamic trap caused by a slight reduction in permeability at the western (updip) edge of the field. In the Kansas part production is limited both updip and downdip by water. The field is a volumetric reservoir and has produced a total of 24.5 trillion cu ft of gas. It now is producing at the rate of 1.4 trillion cu ft a year. Remaining reserve is estimated to be about 28 trillion cu ft.
C. Hardtner Field, Barber County, Kansas
Authors: Young Robert T. 
Published: May 2021

Abstract
The Hardtner field, in south-central Barber County, Kansas, was discovered in 1954. Two zones are productive, the “Conglomerate Sand” (Pennsylvanian) and the Mississippian “Chat.” Trapping is stratigraphic. Cumulative gas production at the end of 1963 was about 75 billion cu ft, and remaining reserves were 75 billion cu ft.
E. Glick Field, Kiowa and Comanche Counties, Kansas
Authors: Euwer Robert M. 
Published: May 2021

Abstract
The Glick field, in Kiowa and Comanche Counties, Kansas, produces from the Mississippian (Osage) “Chert.” The gas is trapped stratigraphically. Cumulative production to January 1, 1967, was 180,280 bbls of 60°-gravity condensate and 80.65 billion cu ft of gas.
Kinta Gas Field, Haskell County, Oklahoma
Authors: Woncik John 
Published: May 2021

Abstract
The Kinta gas field comprises the former Cartersville, McCurtain, Lewisville, West Milton, Lequire, and Kinta gas fields. It is in Haskell County in the northern shelf area of the Arkoma basin. There are approximately 200 gas wells with a total reserve of more than 1 trillion cu ft of gas. Production is from the Spiro Sand (200 wells) of early Atokan age and from the Cromwell Sand (34 wells) of Morrowan age. Production first was established in 1916 from the Hartshorne Sandstone. This reservoir has been depleted. Key discoveries in the deeper Spiro and Cromwell were made by Superior Oil Company in 1951 at Kinta and by Red Bank Oil Company at Cartersville in 1930.
Anticlinal structure is shown in surface and subsurface strata, but the accumulation appears to be controlled stratigraphically by porosity of both the Spiro and Cromwell Sands. Porosity is the result of erratic sandstone deposition and is independent of structure. The area is cut by normal “growth” faults which show greater deposition of Atoka shale in the downt'hrown blocks. Water sands are present in the Spiro and Cromwell north of the Mulberry fault in Haskell County, and south of the fault gas generally is found where these sandstone units are porous.
Natural Gas In Illinois Basin
Authors: Bond D. C. , Bell A. H. , Meents W. F. 
Published: May 2021

Abstract
Most of the natural gas produced in the Illinois basin has been solution gas, produced from oil wells as casinghead gas. Much of this solution gas was flared, especially in the early years of some of the larger fields. In more recent years most of it has been used in producing operations on or near the leases where it is produced.
Gas also has been produced from gas caps over oil reservoirs, and from gas reservoirs not associated with oil. Most of the marketed gas in the Illinois basin has come from such reservoirs. The reservoirs were generally small. Some have contained as much as a few billion cubic feet of gas, and only Midland, in western Kentucky, contained more than 100 billion cu ft.
Oil and Gas in Southwestern Ontario
Authors: Sanford B. V. 
Published: May 2021

Abstract
Southwestern Ontario, an area of about 40,000 sq mi, is underlain by marine sedimentary rocks with a maximum thickness of about 5,000 ft. All geologic systems from Cambrian to Mis- sissippian are represented. Both oil and gas have been produced commercially for more than a century; current production is about 1.3 million bbls of oil and 15 million cu ft of gas annually. Production is from 12 stratigraphic zones from the Cambrian through Devonian Systems. Most of the oil produced has been from shallow Devonian strata; gas has been mainly from reservoirs of Silurian age. In recent years, however, more attention has been directed to the prospects of the deeper Ordovician and Cambrian rocks, and about 28 per cent of the oil now produced is from these strata.
Stony Creek Gas and Oil Field, New Brunswick
Authors: Howie R. D. 
Published: May 2021

Abstract
The Stony Creek gas and oil field, about 9 mi south of Moncton, New Brunswick, is the only productive field in Canada east of the province of Ontario. Production is from deltaic sandstone beds in the Albert Formation of Mississippian age. The field has an area of only 1,830 acres and is on the gently dipping north limb of the Weldon syncline.
Use of Natural Gas and Natural-Gas Products in the Manufacture of Petrochemicals
Authors: Bunn George P. 
Published: May 2021

Abstract
The manufacture of petrochemicals, now a growing industry, is destined to become even more important economically. Natural gas, already the predominant source of raw material for petrochemicals because of several advantageous factors, will become an even more important source. Petrochemical fertilizers, plastics, detergents, textiles, and rubbers, in particular, yield a substantial part of the industry's income of more than $5 billion annually. The popular reception of petrochemicals, many of which are equal or superior replacements for natural products, has stimulated research from which phenomenal results promise the appearance of many new products,
Sulfur—its Occurrence, Production, and Economics
Authors: Myers John C. 
Published: May 2021

Abstract
Sulfur is produced as elemental sulfur from the cap rock overlying salt domes; from sedimentary and volcanic deposits; and from hydrogen sulfide in sour-gas and sour-oil fields. It is produced as sulfur compounds from pyrite, pyrrhotite, and marcasite ores and as sulfur dioxide gas in the smelting of sulfide ores.
Salt domes are present in Texas and Louisiana along the north shore of the Gulf of Mexico, and on the Isthmus of Tehuantepec along the south shore of the Gulf of Mexico. The recovered sulfur—also classed as elemental—is produced with gas along the Foothills belt at the eastern edge of the Rocky Mountains, from the northern part of Canada southward to and including the Permian basin of Texas and New Mexico; along the south side of the Ouachita folded belt of Texas, Arkansas, and Mississippi; and on the eastern side of the Pyrenees Mountains in southern France. Many sedimentary deposits are found on several continents and iron sulfide ores also are found in numerous places.
Sulfide has more than 70 uses in industry, but the greatest is in the manufacture of sulfuric acid. The production from sources containing elemental sulfur is nearly equal to the production from sulfur compounds. In 1963, demand for sulfur had approached the capacity to produce; the demand should increase more rapidly than production and the finding of new deposits, unless an increase in price stimulates exploration and resultant discovery of new sources or revival of old ones.
Factors in Exploration for Nonassociated Natural Gas
Authors: Conselman Frank B. 
Published: May 2021

Abstract
Natural gas now is being sought independently of petroleum because of current market conditions. It is therefore appropriate to review exploration methods to determine the need for specialized gas-finding techniques.
Associated gas reserves will continue to share in the results of oil and gas exploration and development. However, nonassociated reserves, which either have never been associated with oil or have become dissociated from oil, appear to justify specific study.
Natural gas may originate entirely apart from oil. Significant data concerning both the origin and behavior of methane—the principal constituent of gas—are available from coal mines and from metal mines cutting carboniferous sediments.
Gases originating concurrently with crude oil may separate because of important physical and chemical differences between the two fluids. Migration need not be over long distances; there are many examples of commercial gas fields caused by short-range segregation.
New field discoveries in unlikely reservoirs, restudy of the old carbon-ratio idea, and information obtained from the formation of artificial gas caps by underground storage suggest that gas-finding may involve more than normal oil-finding criteria. New definitions may be needed of what is a source rock and what is a reservoir. Ideas of prospective territory and methods of prospecting can stand review. Techniques for detection and recognition of gas reserves when drilled need improvement. There is adequate gas in the ground awaiting discovery to take care of the needs for the near future, if the political and economic situation provides an incentive to find it.
Origin and Accumulation of Natural Gas
Authors: Haun John D. , Lucas George B. 
Published: May 2021

Abstract
This paper is intended to introduce the student or nongeologist to some of the concepts of the origin and accumulation of natural gas. Natural gases consist of methane, carbon dioxide, and nitrogen, and small quantities of hydrogen sulfide, heavier hydrocarbons, helium, and, very rarely, hydrogen. It appears most probable from geochemical considerations that the major gases result from bacterial action on organic and inorganic matter within the sedimentary rocks of the earth's crust. Thermal processes may account for some of the gases, notably methane and carbon dioxide, in special cases. The inert gas, helium, is unique in that it is the product of radioactive decay of uranium and thorium which are present in trace quantities in most rocks and sediments.
Migration of gases from source beds to reservoir rocks is a result of both solution in ground waters, with subsequent release as pressure decreases, and migration as gas through the saturated waters within porous rocks. Entrapment and accumulation occur where the rising gases meet strata impermeable to gas.
C. Homeglen-Rimbey Field, Alberta
Authors: Webb J. B. , White R. J. 
Published: May 2021

Abstract
The Homeglen-Rimbey field is in Tps. 42-43, Rs. 1-2, W. 5M., west-central Alberta, Canada. It is the southernmost in the chain of gas and oil fields extending south-southwest from Leduc field, all of which have large accumulations of gas and/or oil in the Leduc (D-3) formation, the well-known reef unit of the Upper Devonian.
The surface rocks in this area comprise sandstone and shale of Paleocene age which occupy the deeper part of the Alberta syneline. The strata have a regional southwestward dip of about 50 ft/mi. The subsurface section includes freshwater and marine Upper and Lower Cretaceous strata separated from Mississippian and Devonian limestone, dolomite, and shale by a pronounced regional unconformity. The top of the Upper Devonian Leduc reef formation is 7,500-7,700 ft deep, and the base of the accumulation (oil/water contact) at about 8,000 ft. The maximum thickness of gas pay found is 552 ft and the underlying oil column is about 26 ft thick. The field is approximately 12 mi long and generally 2 mi wide, and contains a major wet-gas reserve.
Rational Analysis of Future Rate of Natural Gas Production
Authors: Elliott Martin A. , Von Fredersdorff C. G. 
Published: May 2021

Abstract
An analysis of 1945-1957 gas-production statistics gave a quantitative correlation between cumulated production, P, and cumulated discoveries, D, of the form P = KDn, where K and n are constants. The recent trend of life index, L, with time, t, was represented adequately by the equation of a hyperbola, (L — A)(t — t&lt;sub&gt;o&lt;/sub&gt; + t8) = C, where to is a base year, A is a life-index asymptote, and t&lt;sub&gt;8&lt;/sub&gt; and C are constants. Combination of these correlations with the definition of the rate of gas production, rp = R/L, where R is proved reserves, formulates mathematical equations which closely fit the past yearly production data. This approach can be extended for computing future production rates mathematically. One significant result is the prediction of 1,500 trillion cu ft ultimate discoveries, for which the produc- tion-rate forecast, under conditions of a 15-yr life-index asymptote, shows a 16.4 trillion cu ft a year peak in 1980. Calculated effects on the rate forecasts can be explored over an illustrative 1,500-2,500 trillion cu ft range of ultimate discoveries, and 0-, 15-, and 20-yr life-index asymptotes.
Natural Gas Resources of the United States
Authors: Beebe B. W. , Hanley John M. 
Published: May 2021

Abstract
Natural gas requirements in the United States increased from 4 trillion cu ft in 1946 to 16.0 trillion in 1965. Projected demand calls for more than 25 trillion cu ft in 1980—1.5 times the consumption in 1965. The nation will have consumed 320 trillion cu ft of natural gas by 1980; this exceeds the estimated proved recoverable reserves at the end of 1965 by more than 30 trillion cu ft.
Potential supplies consist of estimated recoverable reserves replenished by new discoveries, extensions, and revisions; at the end of 1965, proved recoverable reserves in the United States were estimated to be 286.5 trillion cu ft.
Trends in reserve/production (R/P) ratio—estimated recoverable reserves divided by production for a given year—are important; a continuing downward trend indicates the industry can not meet demand because of decline in peak productivity. A declining trend can be decelerated or reversed provided that there is natural gas to be found, there is adequate incentive to find it, and technology permits its discovery, development, and production.
Total future potential supply consists of estimated proved recoverable reserves and undiscovered future supplies. Undiscovered potential supplies consist of several categories of increasing uncertainty (1) development of known deposits—lateral or vertical extensions, and revisions of estimates; (2) new discoveries in geologic provinces and formations, and types of traps already proved productive; (3) in geologic provinces known to be productive, but in remote areas, in new types of accumulation, and/or in formations not known previously to be productive in that area; and (4) the most speculative may be found in provinces or basins which have not yielded gas previously.
The estimation of undiscovered potential future supply at any particular time is strictly a problem in geology and reservoir engineering. Natural gas is found in rocks and not in mathematical curves, formulae, or economic theory. Most estimates extant have been based on questionable methods and have used obsolete and conflicting data.
How should the potential future supply of natural gas be forecast? There are two fundamental factors on which to rely—thorough knowledge of the relationship of natural gas to the detailed geology of each area examined, and experience.
The Supply Division of the Future Gas Requirements and Supply Comm. of North America is composed of nearly 100 skilled, experienced geologists and engineers, each assigned to study and analyze a local area of which he is completely knowledgeable.
Useful estimates of undiscovered potential future supply, like those of proved reserves, are dynamic and must be reviewed frequently in light of changing conditions. The Committee is satisfied that an adequate supply of natural gas can be made available continuously within the foreseeable future provided that there is adequate incentive coupled with technological progress.