bluuebunny/crossref_metadata_2025 huggingface dataset:
Μελέτη της μεθόδου "των συνεχών θωρακικών συμπιέσεων" σε σύγκριση με την "Αναλογία 3:1" στη νεογνική ασφυξία (πειραματική μελέτη)
Authors: Αγγελινά Αφροδίτη
Published: May 2021

Εισαγωγή: Η νεογνική ανάνηψη αποτελεί ένα από τα καίρια ζητήματα στην παγκόσμια βιβλιογραφία και χρήζει συνεχούς εξέλιξης για την επιτυχή έκβαση κι επιβίωση του νεογνού με συνοδό βελτίωση της νευρολογικής εικόνας, όσο αυτό είναι εφικτό. Αυτό αποτέλεσε το κίνητρο για την έναρξη της παρούσας ερευνητικής μελέτης ,η διερεύνηση και η σύγκριση δύο διαφορετικών μεθόδων καρδιοαναπνευστικής ανάνηψης σε χοίρειο μοντέλο ασφυξίας και η επιβίωση, σε κάθε περίπτωση. Υλικό και μέθοδοι: Τα χοίρεια μοντέλα που συμπεριελήφθησαν στη μελέτη ήταν είκοσι. Οι φάσεις του ερευνητικού πρωτοκόλλου ήταν έξι: η σταθεροποίηση, η πρόκληση καρδιοαναπνευστικής ανάνηψης, η καρδιοαναπνευστική ανάνηψη, η ανάκτηση αυτόματης κυκλοφορίας( ROSC), η παρακολούθηση κι έλεγχος στις 2 και στις τέσσερις ώρες. Σε όλα τα ζώα προκλήθηκε καρδιοαναπνευστική ανακοπή, ως κύρια αιτία την ασφυξία, έως ότου η καρδιακή συχνότητα να αγγίξει τις 60σφ/λεπτό ή η ΜΑΠ τα 15mmHg. Είκοσι νεογνά χοιρίδια χωρίστηκαν σε δύο επιμέρους ομάδες των δέκα, την ομάδα ελέγχου και την ομάδα παρέμβασης. Στην ομάδα ελέγχου ακολούθησε καρδιοαναπνευστική αναζωογόνηση με αναλογία 3:1 θωρακικών συμπιέσεων κι εμφυσήσεων ενώ στην ομάδα παρέμβασης ακολούθησε καρδιοανανπνευστική αναζωογόνηση με ασύγχρονη χορήγηση θωρακικών συμπιέσεων κι εμφυσήσεων, υπολογίζονται 90 θωρακικές συμπιέσεις και 30 εμφυσήσεις περίπου το λεπτό, κατά τη φάση της αναζωογόνησης, έως ότου καταφέρουν να ανανήψουν, με συγκεκριμένα κριτήρια όπως η καρδιακή συχνότητα να είναι περίπου 100/λεπτό ή η ΜΑΠ να αγγίζει τα 50mmHg. Αποτελέσματα: Η πίεση πλήρωσης των στεφανιαίων αγγείων στα πρώτα 30΄΄ της αναζωογόνησης φαίνεται να είναι υψηλότερη στην ομάδα παρέμβασης (45.7±16.9 vs 21.8±6, p<0.001) έναντι της ομάδας ελέγχου και παραμένει στα ίδια υψηλά επίπεδα καθ΄ όλη την διάρκεια του πειραματικού πρωτοκόλλου. Άλλη μία στατιστικώς σημαντική διαφορά φαίνεται στην Διαστολική Αρτηριακή Πίεση, στα 30΄΄, ανάμεσα στις δύο ομάδες κατά την διάρκεια της ΚΑΑ (50.6±17.5 vs. 25.8±6 ομάδα παρέμβασης έναντι ομάδα ελέγχου, αντίστοιχα,p<0.001). Επιπλέον, η Μέση Αρτηριακή Πίεση ήταν εμφανώς υψηλότερη στην ομάδα παρέμβασης (66.7±16.2 vs. 36.5±13, p<0.001) έναντι της ομάδας ελέγχου, ωστόσο δεν προέκυψε στατιστικώς σημαντική διαφορά στην Πίεση του Δεξιού Κόλπου (4.9±1.2 vs. 4±1.4, p=0.14). Επίσης, στη φάση των 4 ωρών μετά την αναζωογόνηση, 2 (20%) μόλις χοιρίδια επεβίωσαν από την ομάδα ελέγχου σε σύγκριση με την ομάδα παρέμβασης που επεβίωσαν 7 (70%). Συμπέρασμα: Η ακολουθία και η ασύγχρονη χορήγηση θωρακικών συμπιέσεων φαίνεται να υπερτερεί ως μέθοδος νεογνικής ανάνηψης τόσο στην αυτόματη ανάκτηση κυκλοφορίας και την πίεση πλήρωσης των στεφανιαίων αγγείων όσο και στην επιβίωση των ζωικών προτύπων στις 4 ώρες, σύμφωνα με το παρόν ερευνητικό πρωτόκολλο.
Long term Impacts of Effluents on Quality of the Kosi River Water at District Rampur, Uttar Pradesh, India
Authors: Nizami Gulrez , Rehman Shifa , Sayyed R. Z. , Fatma Ummul Khair , Enshasy Hesham El
Published: May 2021

The present study was aimed to analyze the influence of industrial and agricultural wastes on quality ofKosi river water, Rampur, UP, India. The results of the present study revealed pH values of between 7.2 and 6.3 (neutral to slightly acidic), the electrical conductivity between 129.4 μs/cmto399.3 μs/cm. The maximum EC value was observed at S5 in spring season. The turbidity of each was 0.4 to 7.067 NTU. The highest turbidity observed at S5 in winters. Total hardness of 73 (mg/L) and 506.33 (mg/L) were evident at S4 and S7 sites respectively. The BOD values ranged from 10.5 (mg/L) at S4 to 137.4 (mg/L) at S5. Higher BOD values at each site are reflecting the great extent of pollution. The minimum COD recorded at S3 (32.60 mg/L) however maximum recorded at S5 (168.65 mg/L). The results of the heavy metals showed a significant increase in the concentration of Pb, Zn, Cu, Hg and As at S5 as compared to the other sites. The As concentration was 0.04, 0.08, 0.85, 0.72 and 0.71 at S2, S3, S5, S6, and S7 respectively. These values were higher than the value of Arsenic as per WHO guidelines.The average concentration of Zn obtained was 0.05, 0.786, 0.413, 0.06, 3.26,0.97 and 0.53 mg/L at S1, S2, S3, S4, S5, S6, and S7 respectively. The highest value of Zn was recorded at S5 (SDP) as compared to other sites. Only at S5 the zinc content is exceeding the normal value. The copper content found to be lower (1.0 mg/Ll) than permissible value according to WHO. The Cu concentration was 0.01, 0.06 0.01 at S4, S5 and S6 respectively, at S1,S2, S3 and S7 zero. The changed physicochemical parameters and occurrence of heavy metal ions indicated a significant level of pollution in Kosi River.
Influence of Sewage Treatment Plant Effluent on the Presence of Culturable Pathogenic Bacteria in the Water Body
Authors: Lemar Gulsanga , Shahar Saleha , Osman Abdul Rahman i
Published: May 2021

The purpose of the sewage treatment process is to decrease the concentration of contaminants, including pathogens, before discharging into the receiving streams. And the standard operating procedure of STP in Malaysia is to discharge the treated wastewater with low nutrient and low organic materials into the streams but the bacterial content of the discharge and its risk to the stream’s natural microbial verity or health is unknown. However, studies reported that pathogens could escape sewage treatment plants (STPs) processes and showed health risk of streams impacted by STP effluent. On the other hand, majority of these studies relied on metagenomic strategy, without assessing changes to culturable bacteria. Isolation of living microbes provides realistic risk assessment compared to metagenome survey alone. Therefore, this study aims to determine the presence of culturable pathogenic bacteria from water impacted by STP effluent to establish justifiable public health risk. For that, the presence of bile resistant bacteria was determined from water taken from surface water receiving effluent from STP-1 (Kolej 9, UTM) in Malaysia. Enumeration and isolation of bacteria were done on MacConkey agar through membrane filtration method, followed by partial identification, using Triple Sugar Iron agar (TSI). The result showed that STP effluent changes the diversity, and abundance, of bile resistant bacteria (specifically Enterobacteriaceae family) of receiving streams. Most of the isolated bile resistant bacteria are opportunistic pathogens for human. Findings from this study provide a snapshot of the bigger picture of microbial changes in a stream impacted by STP effluent painted initially by metagenome studies. And shows that despite of treatment, some contaminants (microbes) remained and released into surface waters, which contribute to the water pollutions.
Natural Gases of Appalachian Basin
Authors: Roth Ernest E.
Published: May 2021

The Appalachian basin or area embraces about 100 million surface acres within parts of eight states—New York, Pennsylvania, Ohio, West Virginia, Maryland, Kentucky, Tennessee, and Alabama. It also includes a section of southwestern Ontario, Canada,

Although petroleum and natural gas have been known to be present in the earth for centuries, it was their discovery in the Appalachian area a little more than a century ago that resulted in their general use and the development of the great petroleum and natural gas industries of today. Over the last 80 years, natural gas production from the area has averaged about 345 billion cu ft annually; this production was from a total estimated proved gas reserve of about 36,213 billion cu ft.

The gas has been found in Paleozoic rocks from Cambrian to Permian and in several types of geologic traps which, for the most part, are comparatively shallow. New reserves of appreciable quantity must be sought in the older and deeper formations where the rocks range in depth from a few thousand feet in the western part of the basin to possibly 25,000 ft in the eastern section. Natural gas should be present in this section of rocks, but it is extremely difficult to determine where the stratigraphic traps lie.

The gases of the area are generally of very good quality; methane makes up about 85 per cent of their composition and ethane and other higher hydrocarbons constitute much of the rest. Commonly, however, there is an appreciable percentage of inerts, especially in the deeper gases, and this fact should be considered when deep exploration is anticipated.
Methods for Supplementing Natural Gas Supplies
Authors: Elliott Martin A.
Published: May 2021

Natural-gas supplements are required today to meet peak-load demands near centers of consumption. They will be required on a much larger scale at some time in the future when the demand for gas exceeds the deliverability of domestic supplies.

Supplements for peak-load use include liquefied petroleum gases (LPG), particularly propane; liquefied natural gas; and high-Btu oil gas produced in cracking processes. The combustion characteristics of the supplemental gas determine the maximum concentration in the mixture distributed.

When it becomes necessary to supplement domestic supplies of natural gas to meet the demand, there will be two alternatives, (1) importation of liquefied natural gas, which is technically feasible today, and (2) production of synthetic high-Btu gas (primarily methane) from vast domestic reserves of coal and oil shale.

Two high-Btu-gas production processes are under development. In one, synthesis gas, principally carbon monoxide and hydrogen, produced by gasifying coal with oxygen and steam, is converted catalytic ally to methane (methanation process). In the other, coal or oil shale reacts directly with hydrogen to produce methane (hydrogasification process).
L. Wilmington Field, Los Angeles County, California
Authors: Hamilton S. V.
Published: May 2021

The Wilmington field has the largest production in net barrels of oil of any field in California. The field extends southeast from approximately the northwest corner of Wilmington to a point beneath the tidelands southeast of Long Beach, in the vicinity of Humble's Monterey Island. It consists of about 7,825 proved acres and about 6,500 acres offshore, undeveloped until July 1965, when THUMS Long Beach Company began a development program. In area, Wilmington is potentially the state's fifth largest field.

Cumulative production to January 1, 1965, was 1,013,500,000 bbls of oil and about 843 billion cu ft of natural gas. Peak production was reached in 1951. The discovery well was completed in 1932, and by the end of 1964, 3,280 wells had been drilled in the field, 2,583 of which still were considered active.

The Wilmington field is on a well-developed, highly faulted anticline which trends northwest- southeast. Five major north-south-trending faults divide the field into six structural blocks. The faults have their major displacement at or near the axis of the anticline. All of the larger faults are normal.

The basement rock in the field is Jurassic schist. It is overlain by about 4,000 ft of Miocene rock; 2,000-2,500 ft of Pliocene rock; and 1,000 ft of sand, gravel, and clay of Pleistocene and Recent ages. Unconformities are present between the middle Pico and Repetto (both Pliocene) and between the Puente (Miocene) and the basement rock.
B. Natural Gas Provinces of North America and Estimation of Natural Gas Reserves
Authors: Knight G. L. , Beebe B. W.
Published: May 2021

There are numerous great geologic provinces which yield oil and gas on the North American continent. Within each of these provinces are numerous fields ranging in length from fractions of miles to hundreds of miles. The Panhandle-Hugo- ton field of Kansas, Oklahoma, and Texas is the outstanding example of one of the great fields. Each of the gas-producing provinces encompasses areas where there are uplifts and complementary basins of deposition in which great thicknesses of sediments have been deposited during geologic time. Some of these basins or geosynclines were not folded or greatly disturbed. Others have been uplifted and folded into great synclinoria. Still others are broad, commonly shallow, nearly symmetrical basins which were not downfolded into the form of a typical geosyncline, but which underwent varied degrees of differential subsidence and local folding. These provinces are discussed in more detail in other sections of this symposium, but must be described briefly in this section in order to emphasize the importance of thorough knowledge of the geological conditions encountered in estimating reserves and potential supply of natural gas.
Requirements for Making Gas And/or Oil Loans and Summary of Current Factors in Estimating Reserves
Authors: Vance Harold
Published: May 2021

A “gas and oil loan,” as the term generally is used, is a loan secured by a mortgage on a productive property capable of producing future net income from the production of hydrocarbons. The primary security is the expected income from the property; the secondary security is the net worth of the borrower. A gas and oil loan is self-liquidating. The loan is reduced each month by payments from runs. Such loans generally carry a higher rate of interest than other loans, because the cost of processing and servicing such a loan is greater. Operations of many producers could not be carried on if money were not available through bank loans on future production. Generally, an operator who has completed and paid for his interest in two producing wells may obtain a loan from a bank for drilling, equipping, and completing a third well; the bank takes all three wells as security for the loan. A development loan secured by several wells in several different fields is preferred by banks, because of the widespread security.

Evaluation of oil and gas properties includes estimation of recoverable reserves, future rate of production, annual net income, and economic limit of the property. An evaluation report should be realistic and should not be adjusted for “personal safety factors.” A property may be re-evaluated as each new well is completed. The objective in evaluation of gas and oil properties is to determine the present value of future net income from the property. Estimates must be made of future production, rate of production, future selling price, cost of producing, cost of additional wells and equipment to produce estimated future production, and present-value interest-discount factor.

Except for the present-value discount factor, which can be secured from standard tables, all the factors can be estimated if sufficient data are available. Methods used to estimate the volume of recoverable hydrocarbons vary slightly, depending on the content of the reservoir. Different methods are used to estimate recoverable reserves in a free-gas reservoir, a condensate reservoir, and an oil reservoir. The results of estimates should be checked by several different methods, e.g., volumetric, production-decline curves, rate-cumulative decline curves, reservoir pressure-cumulative production curves, and material-balance calculations.
Old Ocean Field, Brazoria and Matagorda Counties, Texas
Authors: Halbouty Michel T.
Published: May 2021

The Old Ocean field, in the prolific Frio producing trend, is one of the largest and most important gas fields on the Texas Gulf Coast. Oil first was discovered in November 1934 as a result of reflection- seismograph surveys. Most production from the field is from four major reservoirs, all of Frio age. Two of these are characterized by huge gas caps with oil rims. The other two are primarily gas and condensate reservoirs.

The field is on a large asymmetrical dome which probably is the result of deep-seated salt movement. Accumulation and entrapment are anticlinal. The two upper reservoirs have gas-expansion drive and no effective water drive. The lower reservoirs are of the simple volumetric-depletion type.

Original reserves in place are estimated to have been 4,466,000 million cu ft of gas, 198,200,000 bbls of condensate, and 276,400,000 bbls of oil. The average daily oil production, as of January 1, 1966, was 5,945 bbls of liquids from the field, 13,001 bbls of liquids from the plant, and approximately 15,239 million cu ft of gas, of which 6,493 million cu ft was used in pressure maintenance of two of the reservoirs. Net daily withdrawal was approximately 8,746 million cu ft of gas. Accumulative gas production to January 1, 1966, was 3,307,856 million cu ft of gas, of which 1,575,384 million cu ft was net after 1,736,472 million cu ft had been reinjected for pressure maintenance and cycling.

Deeper possibilities to 15,000 ft have been explored, perhaps efficiently, by a single dry hole. However, possibilities remain for production below this depth if favorable sandstone conditions are found.
West Bernard Area, Wharton County, Texas
Authors: Cooke, Jr. W. F.
Published: May 2021

The West Bernard area is in northern Wharton County, Texas, 60 mi west of Houston. It encompasses approximately 120 sq mi and includes eight gas fields. Total gas reserve (502 billion cu ft) is mostly in two fields—West Bernard, in which the structure is a large, low-relief Yegua anticline, and Spanish Camp, in which the structure is a prominent Miocene anticline. The most important and outstanding structural element is a Frio-Vicksburg isopachal anticline which covers the entire area. Stratigraphy is a major factor in effecting accumulation, particularly in the formation of many small pools. The most interesting and important stratigraphic feature is the West Bernard field Clodine (Yegua) sandstone bar, which contains approximately one-tenth of the area's gas reserves.

Gas first was discovered in December 1936 in Miocene sandstone at Spanish Camp field. East Bernard field, which first produced from the Yegua, was discovered in May 1940. West Bernard field, which contains most of the Yegua reserves, was found in 1947. The small South Lissie field is the most recent discovery (May 1958).

Total daily production from the area is 37 million cu ft of gas and 110 bbls of condensate. The condensate and half of the gas are derived from the Yegua, and the remaining (dry) gas is obtained from Miocene sandstone and from the Frio. Oil has not been found in commercial quantities, but a few wells did penetrate very thin oil columns.
Geology of Natural Gas in South Louisiana
Authors: Paine William R. , Spillers James P. , Waters Kenneth M. , Andrews Donald I. , Baysinger E. M. , Borland A. M. , Cotton James , Cristina, Jr. S. T. , Hall, Jr. Justin P. , Kimmey B. W. , McDougall John E. , Meyerhoff A. A. , Munchrath Marvin A. , Paffett David L. , Raspberry Francis L. , Rockwood D. N. , Roederer, Jr. Edward P. , Stipe Jack C. , Woodbury H. O.
Published: May 2021

Sedimentary rocks in the south Louisiana part of the Gulf Coast geosyncline contain at least 111 trillion cu ft of gas, which is one quarter of the proved ultimate natural gas reserve of the United States. The geosyncline, 750 mi long, began to form in Late Triassic time but did not attain maximum development until Cenozoic time. The stratigraphic section in south Louisiana is between 40,000 and 60,000 ft thick, and has a volume of approximately 400,000 cu mi.

The sedimentation rate within the geosyncline has increased steadily from Triassic time to the present. Since the Jurassic, the depositional axis has shifted progressively gulf ward. As a result, the optimum producing trends are in younger sedimentary strata toward the Gulf. Concurrently with gulf ward migration of the geosynclinal axis, the depocenter, since Paleocene time, has migrated from south Texas to southeast Louisiana.

The maximum thicknesses of the Cenozoic units, and possibly of some Mesozoic units, are on the downthrown sides of growth faults. Such faults, characteristic of the Gulf Coast geosyncline, permitted great thicknesses of sediments to accumulate in local depocenters.

The concurrence of a large provenance area, a great volume of sediment, abundant organic matter, rapid deposition and burial, basinal subsidence, and movements of an underlying salt layer— which produced syndepositional structural traps in the geosyncline—created optimum conditions for the generation and entrapment of huge hydrocarbon reserves in south Louisiana.

Statistically, more gas than oil is present below 10,000 ft and/or in association with sediments deposited in relatively deeper water. Gas is more abundant where shale is a major constituent of the producing section. Gas reserves generally are smaller where the sandstone percentage is greater. With increasing age and depth, the atomic hydrogen-carbon ratio of the gas decreases.
Effects of Contemporaneous Structural Movement on Sedimentation at Thornwell Field, Jefferson Davis and Cameron Parishes, Louisiana
Authors: Hardin Frank R.
Published: May 2021

The lower Miocene and Frio trends of southwestern Louisiana include some of the more prolific gas-productive units of the Gulf Coast province. Thornwell field, also known as South Thornwell, lies along the boundary between the two trends in Jefferson Davis and Cameron Parishes. The field was discovered in 1942 by Cities Service Oil Company. The discovery well produced gas and condensate from a Planulina palmerae sandstone at 9.605 ft. Subsequent drilling led to the discovery of deeper gas- condensate reservoirs in the Discorbis gravelli, Bolivina perca, Marginulina vaginata, Marginulina howei, and Miogypsinoides A sections.

The productive stratigraphic section consists of alternate sandstone and shale: its thickness more than doubles from northwest to southeast across the field. This thickening takes place across a series of contemporaneous faults. Prior to Camerina time, contemporaneous faults probably were not in existence, and the thickness of the pre-Camerina section is related to the structural position of individual sedimentary units on the dome. Beginning with Camerina time, contemporaneous faulting took place. The stratigraphic sections are relatively thin and the sandstone poorly developed in the structurally high fault blocks, whereas the section is thicker and the sandstone better developed in each successively lower fault block.

Thornwell is a domal structure with a complex fault pattern consisting of a large normal northeast-striking fault that enters the field from the southwest and branches into smaller radial faults toward the northeast. The structurally highest fault block is the northwestern block. Toward the southeast, each block is successively lower around the structure in a clockwise direction.

Thornwell field has not been drilled completely, but enough now is known of the field to make a reasonable estimate of ultimately recoverable reserves—approximately 600 billion cu ft of gas and 15 million bbls of condensate. Production has been established in at least 10 sandstone reservoirs. Until recently, the southern flank had not been tested, but drilling since 1960 on this flank extended production to Lakeside field on the south. The pre-Camerina, or Cibicides hazzardi and Marginulina texana, sections have been penetrated only in the structurally highest fault block where no standstone was found. Both of these sections may prove to have productive sandstone in the lower fault blocks if they can be reached by the drill.
I. Lathrop Gas Field, San Joaquin County, California
Authors: Teitsworth Robert A.
Published: May 2021

The Lathrop gas field is near the city of Stockton at the northern extremity of the San Joaquin basin in the area known as the Manteca arch. Continental Pliocene-Miocene strata unconformably overlie a thick series of Upper Cretaceous clastic rocks of mid-valley facies at Lathrop. The Stockton fault, a large cross-valley reverse fault with a complex structural history, nearly intersects the field's north limit.

Natural gas is trapped primarily in sandstone of Upper Cretaceous E Zone age because of anticlinal folding. Shallow drilling on the Lathrop fold dates back to 1937. Discovery of gas occurred 26 years later in October 1961 with the completion of Occidental Petroleum's Lathrop Unit A 1 for an initial rate of 13,550 Mcf a day. Nine distinct E Zone reservoirs are found at Lathrop, separated by thin bounding shale beds. The “3,700 Pound” Zone is the most extensive reservoir and has a productive closure of 2,400 acres with up to 600 ft of relief and gas-phase pressure continuity over 550 ft of section.

Thirteen dual-zone and seven single-zone wells have been completed for initial flow ratei of up to 42,000 Mcf a day per well. Individual wells penetrate up to 600 ft of net pay. Deliveries of gas began in January 1963 and averaged approximately 50,000 Mcf a day for 1963. Independent volumetric reserve estimates have ranged from 578 million to more than 700 million Mcf.
Solution-Gas Reserves in Pembina Cardium Oil Field, Alberta, Canada
Authors: Mills B. A.
Published: May 2021

The Pembina field is the largest oil and solution-gas field in Canada, both in reserves and area. It has an area of 755,000 acres. The field, discovered in 1953, contained approximately 1.6 billion bbls of recoverable 37° API gravity oil and 1.2 trillion cu ft of solution gas. The oil and gas are present in sandstone of the Cardium Formation of Late Cretaceous age at depths ranging from 4,000 to 6,000 ft. The reservoir is a stratigraphic trap which resulted from the updip “shale out” of the sandstone. Local structure had little or no control on the accumulation. The Cardium Formation is divided into five units which are, in descending order: upper shale, conglomerate, upper sandstone, middle unit, and lower sandstone.

The upper sandstone unit is the principal reservoir. It is a well-sorted, clean sandstone with good porosity and permeability. The conglomerate unit and stray sandstones, where developed, also contain some accumulations. Net pay thicknesses range from zero to 67 ft and average 13.9 ft. Average porosity is 12.2 per cent and permeability is 24 md.

Since the reservoir had no drive mechanism other than expansion gas, secondary-recovery projects were begun after the mid-1950's. Large gas conservation programs were inaugurated in 1958, five years after the discovery.
Provost Gas Field, Alberta
Authors: Suey Harry
Published: May 2021

The Provost gas field of east-central Alberta produces from sandstone in the Viking Formation of Early Cretaceous age. It was discovered in 1946 by Imperial Oil Ltd. Subsequent drilling determined the field outline and development drilling has continued to the present.

The field is of the stratigraphic-trap type; the sandstone ranges from zero to 25 ft in thickness. Local structure appears to have little bearing on the sandstone development. There are 106 wells capable of production within a proved area of 416,640 acres. Gas reserves are estimated to be 854 billion cu ft.
Geology and Occurrence of Natural Gas in Laramie and Hanna Basins, Wyoming
Authors: Mitchell Steven D.
Published: May 2021

Eibht small anticlinal gas fields have been discovered in the Laramie and Hanna basins.

During Paleozoic time carbonate, evaporite, and clastic sediments were deposited, but none of the Paleozoic rocks have yielded commercial gas. The Mesozoic was a time of repeated marine and continental transitions with predominantly clastic deposition. By the end of the Mesozoic Era recurrent basement uplift, followed by vigorous degradation, caused accumulation of thick sequences of nonmarine Upper Cretaceous rocks in the rapidly sinking Hanna and northern Laramie basins. Early Tertiary deposition followed a similar pattern. Extensive alluviation, periodically affected by regional uplift, tilting, and normal faulting, continued throughout the rest of the Tertiary.

Major tectonic features of the Laramie-Hanna basins region are basement controlled; both basins are downwarped asymmetrically and have divergent structural elements.

Natural gas has been found only in sandstone reservoirs. Hydrocarbon exploration has been focused on structural traps; stratigraphic drilling is just beginning. Proved natural gas reserves appear minor in comparison to the potential gas reserves in Upper Cretaceous and lower Tertiary rocks, particularly in the Hanna basin.
Gas Occurrence in Upper Cretaceous and Tertiary Rocks of Piceance Basin, Colorado
Authors: Millison Clark
Published: May 2021

In the Piceance basin of western Colorado, gas has been found in several sandstone zones in the Upper Cretaceous (upper part of Mancos and Mesaverde) and Tertiary (Fort Union, Wasatch, and Green River) beds. The first well in the basin was drilled in 1890 and the first important gas discovery was made in 1930, but lack of outlet retarded gas exploration until recent years. All producing beds in the Upper Cretaceous and Tertiary section have marked facies changes which are predominantly important in the trapping of gas, although some anticlinal features also are influential. Total gas production from these beds to January 1, 1966, was about 71 billion cu ft, and established reserves are probably nearly 12 times that quantity. Future prospects for the basin as a source of natural gas are good.
Natural Gas in Denver Basin
Authors: Beebe B. W.
Published: May 2021

Significant oil production has been developed from Lower Cretaceous sandstones of the Laramide Denver basin since 1949. However, gas production and reserves have not been significant. Only two nonassociated-gas fields have been found, each with estimated initial recoverable gas reserves of more than 50 billion cu ft. The largest natural gas deposit consists of dissolved and associated (gas cap) gas in the Adena field of Colorado, largest oil field in the basin. Initial recoverable gas at Adena, prior to pressure maintenance, was estimated to be more than 90 billion cu ft.

Much of the natural gas found in the basin is dissolved and a considerable quantity was vented because of lack of market during the early development of production in the basin. Furthermore, many fields produce small volumes of gas which do not warrant the expense of gathering. Reserves and production are declining.

Large areas of the basin have not been explored definitively in the Cretaceous. The eastern edge of the basin is believed to have good potential for discovery of nonassociated gas in the Lower Cretaceous. The Upper Cretaceous Hygiene Sandstone Member of the Pierre Shale may have potential for gas discovery.

The Lower Cretaceous reservoirs afford a laboratory for study of the origin, migration, accumulation, and entrapment of natural gas and its relationships with crude oil because of the amount and variety of data available for collection and analysis.

Most intriguing and promising for natural gas discovery in the Denver basin and vicinity are Paleozoic strata, unrelated in origin, character, or distribution to the Laramide Denver basin and associated features. Paleozoic carbonate rocks and sandstone yield both gas and oil on the edge of and adjacent to the Denver basin. Exploration problems, paucity of subsurface data, high costs, and inadequate markets, however, will deter exploration despite the good potential.
Fashing Field, Atascosa-Karnes Counties, Texas
Authors: Keahey Robert A.
Published: May 2021

Fashing field, as presently defined, is 10 mi long and 2 mi wide. The field is in the deep Edwards fault trend and extends from the southeast corner of Atascosa County to the northwest corner of Karnes County, approximately 50 mi southeast of San Antonio, Texas. Lone Star Producing Co. discovered gas in the Edwards Limestone (Lower Cretaceous) at Fashing in July 1956 when their No. 1-A L. T. Urbanczyk well reached the top of the Edwards at 10,210 ft and found 580 ft of productive section that had an initial potential of 26 million cu ft of gas a day and 24 bbls of 50.6°- gravity distillate per million cubic feet.

The Edwards structure at Fashing field is dominated by a simple, northeast-trending up-to- the-coast fault with effective closure against the upthrown side. This fault has a maximum vertical displacement of approximately 700 ft at the Edwards level, which decreases upward to a maximum of 320 ft at the Carrizo Sand (Eocene) level. The fault traps the Weigang field oil accumulation at the Carrizo level. The fault dips northwestward, with the angle of dip decreasing from 50° at the Carrizo to 38° at the Edwards.

Edwards gas production at Fashing is from two separate zones called the A and B Zones, respectively. The A Zone has an average porosity of 15.5 per cent, an average permeability of 12.6 md, and an average connate water saturation of 28 per cent. The B Zone has an average porosity of 13.2 per cent, an average permeability of 4.4 md, and an average connate water saturation of 24 per cent.
E. Thornton and Walnut Grove Gas Fields, Sacramento and San Joaquin Counties, California
Authors: Silcox John
Published: May 2021

This paper presents the history of exploration and development on the nose of the Thornton arch as specifically related to the West Thornton and Walnut Grove gas fields. These fields are in the east-central part of the Delta area of the Sacramento basin. The Delta area is within the general boundaries described by the latitude of the city of Sacramento on the north, the Sierran foothills on the east, the Mount Diablo foothills on the south, and the eastern foothills of the California Coast Ranges on the west. A thick Tertiary and Paleocene clastic section, which is absent because of thinning and truncation in the rest of the Sacramento basin, underlies the Delta area. Gas is trapped in these rocks by combinations of folding, faulting, and abrupt facies changes. Structural traps are predominant. Rio Vista, a complexly faulted dome is in the center of the Delta area directly west of the West Thornton and Walnut Grove fields. It is the largest gas field in the Sacramento basin, with estimated original reserves of more than 3 trillion cu ft.
Trawick Gas Field, Nacogdoches County, Texas
Authors: Townsend John V.
Published: May 2021

This paper summarizes the history, geology, and development of the Trawick gas field, northwest Nacogdoches County, Texas, from its discovery in June 1949 to January 1, 1966. Active field development followed completion of the discovery well, and 41 gas-condensate wells have been completed, producing from the Pettet Member of the Glen Rose at an average depth of 7,600 ft.

The Trawick field is on a low-relief anticline in the southeast part of the East Texas geosynclinal basin. The field is off the southwest flank of the large Sabine uplift. Structural growth increases progressively with depth to a point where the Pettet producing member has structural closure approximately 140 ft. The trap for the gas accumulation in the Pettet Member is partially strati- graphic, and there is a gas column of 196 ft. Gas-condensate production has been established in the Rodessa Member of the Glen Rose by open-hole drill-stem tests during drilling operations. Nine completions have been made in the Rodessa Member. The gas-condensate accumulation in the Rodessa is confined to the structural closure above the gas-water contact at 6,367 ft subsea, with a gas column of approximately 95 ft. Lenticular porous zones in the Pettet-Travis Peak transition zone also contain gas-condensate, as proved by core data and open-hole drill-stem tests during drilling operations. The productive area of the Pettet reservoir is 8I/2 mi long at its longest point and 6 mi wide, and underlies approximately 28,000 acres. The estimated ultimate recovery from the Pettet reservoir is 375 billion cu ft of gas. Cumulative production to January 1, 1966, was approximately 243 billion cu ft of gas. Cumulative production from the Rodessa to January 1, 1966, was 4 billion cu ft. The estimated ultimate recovery from this reservoir is 50 billion cu ft of gas. Twelve wells are producing from the Pettet-Travis Peak transition zone reservoir. Cumulative production from this zone to January 1, 1966, was 3,928,369 Mcf. The estimated ultimate recovery from this reservoir is 22.5 billion cu ft of gas. The total estimated ultimate recovery from the three reservoirs is 444.7 billion cu ft of gas.

Surface mapping and subsurface studies first indicated the presence of favorable structure in the Trawick area. Seismic surveys in 1946 and 1947 confirmed the presence of low-relief anticlinal closure and led to the drilling of the discovery well in 1949.
F. Rio Vista Gas Field, Solano, Sacramento, and Contra Costa Counties, California
Authors: Burroughs Ernest , Beecroft George W. , Barger Ralph M.
Published: May 2021

Rio Vista gas field is in the Sacramento River delta about 30 mi southwest of Sacramento. The field was discovered by use of reflection-seismograph methods in 1936 and is the largest natural gas field in California in area, production, and reserves. There now are 182 potential wells on 22,560 proved acres. The structure of the field is a broad, fiat, somewhat elongate faulted dome, with the axis striking north-northwest. Gas is produced from six zones of Eocene and Paleocene age at depths from 3,700 to 5,300 ft. Total gas production through December 31, 1965, was 2,316,901,122 Mcf. The highest annual production was 159,577,428 Mcf of gas in 1945.
Natural Gas in Black Mesa Basin, Northeastern Arizona
Authors: Turner Daniel S.
Published: May 2021

A total of 97 wells has been drilled in the Black Mesa basin of Arizona—a drilling density of one test per 350 sq mi. Exploration started in 1920 and was slow until 1955, when interest was stimulated by discoveries in the Four Corners area.

In an unusually large percentage of all tests, shows of oil or gas have been found throughout the stratigraphic succession. Cretaceous to Cambrian Systems, except Silurian and Ordovician, are represented. The Pennsylvanian Hermosa Formation is productive in the Four Corners area. The Permian Coconino Sandstone yields helium, nitrogen, and carbon dioxide in the Pinta dome area near Holbrook, Rocks of reef facies and traps of the stratigraphic type may have hydrocarbon potential.
G. McDonald Island Gas-Storage Field, San Joaquin County, California
Authors: Lee Charles A.
Published: May 2021

The Pacific Gas and Electric Company's gas demand is widely varied throughout any given year. As the population of northern and central California has grown, so has the variation in demand. The existing gas supply lines from outside the state necessarily are operated at near-maxi- mum capacity on a year-round basis. Additional capacity is needed for winter peak loads, but it would not be utilized during the low-demand summer months.

One solution to this problem is storage of surplus gas during low-demand periods and withdrawal of the stored gas during peak-load periods. At McDonald Island, 50 billion cu ft of gas can be stored. An average of 150 million cu ft a day is the planned injection rate and withdrawal rates will range up to 200 million cu ft a day.
Lisbon Field Area, San Juan County, Utah
Authors: Parker John M.
Published: May 2021

The Lisbon field oil and gas accumulation is trapped in a faulted anticline. Reservoirs are in five zones—the McCracken and Ouray of Devonian age, the Leadville of Mississippian age, and the middle Paradox and Honaker Trail (upper Hermosa) of Pennsylvanian age. Only the Mississippian oil, condensate, and gas reservoir is of commercial importance at the present time. Oil production from the Mississippian from 1960 to September 1965 was 11,801,530 bbls. Remaining oil reserve is estimated to be 39 million bbls. Gas reserve is estimated to be 240 billion cu ft. The gas now being produced is injected into the Mississippian in a pressure-maintenance program. It is estimated that gas sales will begin in 1973. The gas has a high nitrogen and carbon dioxide content (775 ± Btu) and will require beneficiation.
Gas in Delaware and Val Verde Basins, West Texas and Southeastern New Mexico
Authors: Hills John M.
Published: May 2021

The Delaware and Val Verde basins are in the southeastern part of the Permian basin of West Texas and southeastern New Mexico. They have a combined surface area of about 21,000 sq mi and contain about 54,000 cu mi of possibly gas-bearing sedimentary rocks. At the beginning of 1965 there were 63 dry- or nonassociated-gas fields producing in the Texas part of the basins and 35 in the New Mexico part. Prospects for finding additional gas reserves of substantial size in this area appear to be good.

Exploration for oil in this area began in the early part of the century, but only in the last 10 years have market conditions justified the search for gas alone. In much of the basin area Ellenburger dolomite of Early Ordovician and Cambrian age rests on the Precambrian basement, although on the southeast clastic beds of Cambrian age intervene. The Ellenburger rocks contain some of the largest gas reserves in the region. Middle and Upper Ordovician strata are present in most of the basin area. Devonian and Silurian carbonate rocks are important gas-yielding reservoirs. Above the Woodford Shale, which lies on the Devonian carbonate beds, are the Mississippian and Pennsylvanian Systems. All series of the Pennsylvanian produce gas somewhere in the basins; the Morrow, Canyon, and Cisco are the most important.

In the lower part of the overlying Permian System, coarse clastic rocks of Wolfcamp age form important gas reservoirs. One important field and several smaller ones yield gas from the upper part of the Delaware Mountain Group in the Upper Permian Guadalupe Series.

Upper Triassic continental strata lie on the evaporites of the Ochoa Series of the uppermost Permian. On the Triassic rocks lies the Cretaceous System, comprising both the Comanche and Gulf Series in the southeast but only the Comanche Series in the north. Cenozoic and Recent sand and gravel form much of the surface of the north and west parts of the Delaware basin, and piles of Tertiary volcanic material form the mountains in the southwestern part of the region. Brief resumes are given of Brown-Bassett, Clara Couch, Coyanosa, Gomez, Ozona, Puckett, Sonora, Toyah, Atoka Penn, Bell Lake, and Indian Basin fields.

A study of these fields indicates that there are two major classes of deep-gas prospects in the basin area. One consists of the very deep structural traps in the depths of the basins which form prolific reservoirs but are expensive to explore. The other class comprises the stratigraphic sandstone traps along the northwest and east sides of the Delaware basin. These offer opportunities for development of moderate reserves at medium cost. All exploration in the basin area is dependent on the maintenance of favorable marketing conditions.
Natural Gas in Devonian and Silurian Rocks of Permian Basin, West Texas and Southeast New Mexico
Authors: Salisbury Gerald P.
Published: May 2021

Gas and oil fields producing from Devonian reservoirs in the Permian basin of West Texas and New Mexico form a remarkably uniform pattern—fields producing only gas on the south and west, fields with high gas/oil ratios and gas-condensate fields near the center of the region, and fields which produce only oil on the north. The methane content of gases in these fields has a similar regional variation from more than 90 per cent methane on the south and west to less than 30 per cent on the northeast. Analysis of variation of other gas components and crude oil suggests that the methane variation is independent of both other gases and crude oil composition. Relation of methane variation to variation in gas volume suggests that variation in gas distribution is primarily a function of methane distribution. Limited data suggest that carbon dioxide may be anticipated in increasing volumes along the southern margin of the region.

Uniformity of the observed pattern indicates that only gas will be found in Silurian-Devonian reservoirs in the Delaware and Val Verde basins.

The gas-distribution pattern bears no consistent relation to Silurian-Devonian lithofacies or structural relief. There is simply an increase in the amount of methane toward the Marathon thrust belt. It is proposed that the gas pattern may have been effected by distribution of methane in solution in formation water migrating away from the Marathon thrust belt under the influence of supernormal pressures resulting from overthrusting. Carbon dioxide may have been distributed similarly at a later time and in smaller volumes than methane. Differential distribution of both gases may have been a function of volume of methane or carbon dioxide in solution in a given area and of the volume of gas-bearing water reaching the area.
Natural Gas in Permian and Cisco Beds of Red River and Electra Arch
Authors: Reutinger C. A.
Published: May 2021

This paper describes the shallow accumulations of solution and nonassociated gas along the Red River and Electra arch. The first commercial well in North Texas was a nonassociated-gas well completed in 1907 in this area. The first commercial oil well in North Texas was completed in 1910 in this area. Both the nonassociated gas and solution gas are practically depleted, but the history of a pioneer development and some of the “firsts” credited to the province are of interest.
Constructing Ideology through Modality in Newspaper Editorials on Security Challenges in Nigeria
Authors: Alfred Bukola
Published: May 2021

This paper explores Nigerian media’s deployment of modality on editorials on security challenges in Nigeria. The study examines how such impress on the ideological position of the media on the security issues in Nigeria. The study relates to how well Nigerian newspaper organisations attempted to reveal or mask security cases across different regions of the country through modal options. The editorials were sourced from The Punch and The Guardian (South-Western region), Vanguard and The Sun (East) and Leadership and Daily Trust (Northern Region) between 2014 and 2016. The frequencies and percentages of occurrences of these modality markers were examined and their implications were interpreted to reflect the attitudes and dispositions of the newspapers to security issues. Our findings show that the six newspapers expressed unbiased concerns over the Boko-Haram Insurgency whether or not the newspaper is situated in the northern region. However, the fact that certain security issues emanated from particular regions also prompted the kinds of modal markers employed by specific newspapers representing such regions. The Sun’s choices of modal indirectly expressed support for their plights and protests of the pro-Biafra agitators. The Punch’s choices of modal verbs portrayed President Buhari as sharing some ethnic affinity with herders.
La estructuración prosódica del discurso leído en los neolectores y lectores jóvenes
Authors: Recio Pineda Sara
Published: May 2021

En aquest article, presentem els resultats d'analitzar l'entonació prelingüística de 72 escolars de primària (de 2n, 4t i 6è curs), provinents de dues escoles públiques de Catalunya, quan llegeixen per primera vegada un text narratiu adequat a la seva edat. Expliquem fins a quin punt la seva forma d'estructurar el relat en grups fònics persegueix empaquetar i / o detectar les unitats nocio-fonètiques del text. Per a això, proposem una metodologia en la qual les estratègies prosòdiques dels escolars es comparen amb una plantilla que recull i explora les diferents possibilitats fòniques dels textos. Els resultats evidencien que la prosòdia és una estratègia molt poc utilitzada o desenvolupada en l'etapa primària. A més a més, es distingeixen dues franges diferents de desenvolupament prosòdic: la dels escolars de 2n d'EP, que en aquest treball anomenem franja de neolectors i la de 4t i 6è d'EP, que hem anomenat franja de lectors joves.