bluuebunny/crossref_metadata_2025_split huggingface dataset:
Old Ocean Field, Brazoria and Matagorda Counties, Texas
Authors: Halbouty Michel T. 
Published: May 2021

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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

Abstract
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.