bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Natural Gas Reserves
Authors: Stephenson Eugene A. 
Published: May 2021

Abstract
All estimates of reserves depend upon certain basic scientific principles, of which Boyle's law is fundamental, though not rigidly applicable to natural gases; a correction for deviation is required.
Several methods of estimation are described herein, and illustrated with equations, diagrams, and maps. Methods are:
1. Volumetric or porosity-pressure method, based on sand thickness, pressure factors, and area.
2. Pressure-production decline method.
3. Changes in density of gas during production.
4. Associated or solution gas-cap method.
5. Comparison between fields.
Condensate reservoirs and reservoirs under water drive offer particular problems. Other considerations that must be taken into account in estimating gas reserves are operation losses, compressibility of liquids, and availability of gas reserves.
Natural Gas in Uinta Basin, Utah
Authors: Osmond John C. , Locke Robert , Dillé Alan C. , Praetorious Walter , Wilkins James G. 
Published: May 2021

Abstract
Extended, but still very incomplete, exploration of the Uinta basin has resulted in discovery of numerous gas fields for which outlets gradually are becoming available. However, disappointing performance of some (mainly Wasatch Formation) fields after pipeline connection recently has reduced interest in exploration. Three Tertiary formations, one Cretaceous group, and one Jurassic formation are capable of production in the basin; seven other formations of Cretaceous to Pennsylvanian ages produce nearby and, therefore, have an indicated gas potential in the Uinta basin. A long history of oscillating marine transgressions coupled with several tectonic episodes has produced many good reservoir rocks as well as potential source rocks in this area. Most of the gas accumulations discovered are in lenticular sandstone of Late Cretaceous and Tertiary ages. It is notable that the Tertiary strata are of lacustrine and fluviatile origin and the gas traps are almost entirely stratigraphic.
Gas Accumulations in Nonmarine Strata, Cook Inlet Basin, Alaska
Authors: Kelly Thomas E. 
Published: May 2021

Abstract
In less than ten years the Cook Inlet basm of south-central Alaska has become one of this nation's most promising sources of oil and gas. From 1957 to 1966, significant discoveries include 5 major oil fields, 1 gas-condensate field, and 10 dry-gas fields with total proved reserves in excess of 500 million bbls of oil and 3 trillion cu ft of gas.
Rocks ranging in age from Late Triassic to Recent are present in the basin; however, commercial oil and gas accumulations have been found only in Tertiary rocks assigned to the Kenai Formation, a thick heterogeneous deposit composed of sandstone, siltstone, conglomerate, shale, and abundant coal beds. Lateral variation of individual beds within the Kenai Formation makes correlation difficult; however, three arbitrarily defined stratigraphic units comprising at least five distinct lithologic zones are recognizable on the Kenai Peninsula where adequate well control is available. The United States Geological Survey, as a result of recent paleobotanical studies, has subdivided the Kenai Formation into three provincial stages which correspond to time-stratigraphic units. Although subdivisions of the Kenai Formation used in this paper may be roughly correlative with the provincial stages on the basis of distribution, spatial occurrence of coal within the section, and degree of lithification, they were chosen arbitrarily.
The Cook Inlet basin is an elongate, deep, moderately asymmetrical structural depression which overlies much of the Matanuska geosyncline, a Mesozoic sedimentary trough. The structure of the basin is mainly a result of Late Cretaceous-early Tertiary deformation; however, the major tectonic features are a result of middle Jurassic orogeny. The principal structural features within the basin are narrow, elongate, complexly faulted anticlinal belts which trend north-northeast parallel with the grain of the major tectonic features which flank the basin. All of the oil and gas fields are located near the crest of local structural closures on the anticlinal belts.
Accumulation of oil in the Hemlock Zone, the principal oil reservoir in the lower part of the Kenai Formation, probably is related to old fold belts which were uplifted before Late Cretaceous time and remained positive until Tertiary time. Gas accumulations in the middle and upper parts of the Kenai Formation are indigenous, and were generated from coal and lignite in the section. Time of structural uplift, diagenesis of carbonaceous source rocks, and stratigraphic relations between coal and reservoir host rocks control the accumulation of gas in commercial quantities.
Most of the proved gas reserves of the basin are shut in because there is no market. Planned facilities for methane liquefaction, anhydrous ammonia production, and pressure maintenance of oil reservoirs soon will greatly increase the use of natural gas and the demand may exceed the supply.
Occurrence of Gas on Northwest Flank of South Liberty Dome, Liberty County, Texas
Authors: Craig Jack W. 
Published: May 2021

Abstract
Exploration for gas-condensate reserves on the flanks of piercement salt domes in the downdip Yegua-Cook Mountain trend has not been very active because development to date has been rather disappointing. However, the fact that a commercially profitable reserve of gas now has been found on the northwest flank of South Liberty dome might encourage geologists to re-evaluate and give closer scrutiny to similar possibilities on the flanks of other piercement salt domes in this trend.
There is a paucity of test wells drilled to the Yegua-Cook Mountain on the flanks of the other piercement domes in this trend, and in most wells only the Cockfield or upper Yegua sections have been tested. When more wells in the 15,000-20,000-ft depth range are drilled in this trend, there is a good possibility that large reserves of hydrocarbons, especially gas and condensate, will be discovered on the flanks of the domes.
Port Acres and Port Arthur Gas-Condensate Fields, Jefferson County, Texas
Authors: Halbouty Michel T. , Hardin, Jr. George C. , Barber Thomas D. 
Published: May 2021

Abstract
The Port Acres and Port Arthur gas-condensate fields offer a classic contrast between an anticlinal closure, the Port Arthur field, and an adjacent stratigraphic trap, the Port Acres field; the two fields are separated by a large normal fault.
An exploratory test well drilled in 1941 would have found the Port Acres field had it been drilled only 20 ft deeper; however, the field was not discovered till 1957. The Port Arthur field, discovered in 1958, would have been found in 1954 had an exploratory test well been drilled less than 2,000 ft deeper. The Port Acres field area is approximately 3,200 acres and 60 wells have been completed. The proved productive area of the Port Arthur field is approximately 1,700 acres, with 10 wells completed.
Faulting separating the two fields was contemporaneous with deposition, and structural configuration probably is a result of deep-seated salt movement. As much as 700 ft of displacement is evident along the two normal faults. Gas in the Port Acres field is trapped because of lensing out of the upper sandstone unit of the lower Hackberry against a southeast-plunging structural nose. Gas in the Port Arthur field is trapped because of a northeast-trending anticlinal closure dipping northwest into a fault in lower Hackberry sandstone. Both fields are in what is known generally as the downdip part of the Frio producing trend of the Gulf Coast. In the area of the two fields, the lower Hackberry zone consists primarily of sandstone, although in most of the Gulf Coast section it is predominantly shale. The lithologic character of the sandstone suggests that it was deposited as a seaward-building delta.
Reservoir characteristics in the lower Hackberry are varied but generally are excellent. The middle Frio, or Nodosaria zone, also produces gas at Port Arthur; its reservoir characteristics are not as good as those of the lower Hackberry. Production from an upper Frio sandstone has been found in five wells in Port Acres field, but reservoir characteristics are poor and production is not significant. Both fields produce condensate with gas. Condensate has averaged approximately 50 bbls per million cubic feet of gas. Gases from both fields are predominantly methane, with between 9 and 10 per cent heavier hydrocarbons. Inert gases constitute less than one-half of 1 per cent.
There are possibilities for deeper production in the lower Vicksburg and Jackson sections, neither of which has been tested.
Occurrence of Natural Gas in Mesozoic Rocks of Northern California: A. Natural Gas in Sacramento and Northern San Joaquin Valleys
Authors: Jones Vern 
Published: May 2021

Abstract
The tremendous growth in population and industry in California has created a strong demand for natural gas. Present estimates are that California as a state will rank first in gas consumption by 1970.
California has three general sources of gas— wet gas associated with oil in southern and central California, generally from Tertiary strata; dry gas in the Sacramento and northern San Joaquin Valleys, most of which is produced from Upper Cretaceous (Mesozoic) and Tertiary (Eocene and Pliocene) strata; and out-of-state gas. There appears to be little chance of a significant increase in wet-gas deliverability. Dry-gas production has a very bright future in the Sacramento and the northern San Joaquin Valleys. Transmission of gas to California from outside the state began in 1947, and by 1964 gas from outside the state was 64 per cent of the total gas consumption. A line has been constructed from Canada to northern California. It is inevitable that gas from outside the state will increase its share of the market. Proposals are under consideration for one or more lines from the Texas Gulf Coast.
D. Stratigraphy and Tectonics of Sacramento Valley
Authors: Safonov Anatole 
Published: May 2021

Abstract
The productive Upper Cretaceous-Eocene section is very complex. The principal tectonic factor is the progressive southward tilt of the Great Valley of California, broken by the transverse Stockton fault, which constitutes the southern boundary of the Sacramento Valley. This tilt is reflected in a general southerly thickening and shaling out of the section. Another factor is progressive uplift of the west side, which gradually caused isolation of the Sacramento basin. The axis of the valley is near the west side. The third major factor is differential movements within the valley, which resulted in three sub-basins somewhat different in sedimentation conditions—Rio Vista, Colusa, and Chico. The Diablo uplift in the southwest is a homocline complicated by faulting and folding.
The main source of sediments was at the east, but additional sediments came from the rising west side. The sediments were reworked and redeposited by vigorous currents in an intricate and commonly unpredictable pattern determined in part by local structures. The major Midland fault zone runs west of north, from the south end of the valley to Winters and possibly farther north. It diminishes above the Domengine Sandstone.
A peculiar feature of the valley is the presence of erosional channels—Princeton gorge in the north near the west side (Capay fill in Upper Cretaceous rocks); Markley gorge (Sacramento Canyon; Markley fill in contact with progressively older Eocene-Cretaceous beds); and the newly discovered Brentwood gorge in the Diablo slope. There is considerable controversy about the nature of Meganos “shaleways” east of the Midland fault and north and south of the River Island area. The writer's contention is that these are remnants of the original Rio Vista basin on both sides of a Meganos delta. The other view ascribes their origin to density currents, surface erosion, and other factors.
E. Corning and South Corning Gas Fields, Tehama County, California
Authors: Safonov Anatole 
Published: May 2021

Abstract
The Corning anticline is one of the major structural features of the Sacramento Valley basin. It is in the north-central part of the valley just east of the city of Corning, and about 4 mi west of the Sacramento River.
The Corning anticline was recognized early in the exploration history of the Sacramento Valley because its trend is marked by topographically high areas. The Corning Hills constitute two groups, one just northeast of the city, the other centered approximately mi southeast of the city. The maximum elevation of the hills is slightly more than 300 ft, and they rise about 50 ft above the surrounding alluvial plain.
Carbon Gas Field, Alberta
Authors: Workman L. E. 
Published: May 2021

Abstract
The Carbon gas field is in a north-northwest-trending lenticular quartz sandstone body in the lower part of the Mannville (Blairmore) Group of Early Cretaceous age at the depth of the “Glauconitic Sandstone,” or Bluesky Member of the Clearwater Formation, in south-central Alberta. The sandstone ranges from 20 to 82 ft in gross thickness. Regional dip is westward. The pool is contained in a stratigraphic trap. Sandstone thickness and porosity decrease eastward. A normal fault, with approximately 30 ft downward displacement on the east side, borders the eastern edge of the field. The thickness of sandstone above the gas-water contact is as much as 46 ft. Reserves are estimated to be 124.1 billion cu ft of sweet gas.
Medicine Hat-Hatton Gas Field, Alberta and Saskatchewan
Authors: Hancock W. P. , Glass D. J. 
Published: May 2021

Abstract
The Medicine Hat-Hatton field was the first gas field to be discovered and developed in western Canada. It has supplied the local market for more than 62 years, but greatest development and extension have been in recent years. Estimated initial recoverable reserves of 1,964 billion cu ft and a total productive area of 775,000 acres make it the largest gas field in volume and areal extent in western Canada. It also is among the shallowest producing areas, with an average depth to the productive zone of 1,500 ft. Gas is obtained from the Medicine Hat Sandstone, a thin, very lenticular, argillaceous sandstone member of the Upper Cretaceous Colorado Group. This sandstone is limited to a fairly small area in southeastern Alberta and an adjoining part of Saskatchewan. Gas is contained in the more porous and permeable parts of this sandstone body by what was originally an updip pinchout. The accumulation probably occurred before the final uplift of the Sweetgrass arch.
Geology of Wind River Basin of Wyoming and its Relationship to Natural Gas Accumulation
Authors: Paape Donald W. 
Published: May 2021

Abstract
Latest Cretaceous and Tertiary beds constitute almost two-thirds of the maximum of 33,000 ft of sedimentary rocks in the Wind River basin. The marine Upper Cretaceous Cody Shale is overlain, with intertonguing, by the Mesaverde Formation. The next-overlying Lewis Shale and Meeteetse Formation intertongue also. In the western part of the basin, an unconformity associated with Laramide tectonism separates the uppermost Cretaceous Lance Formation from beds beneath it. The Paleocene Fort Union Formation is of primarily terrestrial origin, but the upper part contains the Waltman Shale Member, which was deposited in a lacustrine or restricted marine environment in the northeast part of the basin. From Paleocene until Pliocene time, sediments poured from bordering mountains to fill the basin, but an exhuming process, still in progress, began in post-Pliocene time.
It is concluded that the development of Laramide structural features during Late Cretaceous to earliest Eocene time influenced the contemporaneous patterns of sedimentation in the Wind River basin. Thrusting on the eastern and northern basin flanks followed in earliest Eocene, and some later superficial deformation also is recorded.
Only recently has exploration for gas been active in the Wind River basin. The efforts are directed toward the latest Cretaceous and Tertiary beds in the deeper parts of the basin, and significant shows or production has been found in all of these formations. Four fields are producing gas, and favorable economic conditions exist for future gas development in the basin.
Geology and Occurrence of Gas, Wamsutter Arch, Sweetwater County, Wyoming
Authors: Ritzma Howard R. 
Published: May 2021

Abstract
The Wamsutter arch, an east extension of the Rock Springs uplift, is a gently east-plunging nose separating the Red Desert and Washakie basins.
During Late Cretaceous time two major cycles of marine transgression and regression occurred in this area, producing intertonguing relationships between the marine Baxter Shale to nonmarine Mesa- verde Group, and the marine Lewis Shale to nonmarine Lance Formation. Reservoir sandstone beds of the new gas and oil fields of the western Wamsutter arch are in the transition zone between the nonmarine Mesaverde (Almond) and marine Lewis Shale.
The Wamsutter arch was structurally inactive during most of Late Cretaceous time. A broad uplift occurred near the south end of the Rock Springs uplift during latest Cretaceous through Paleo- cene (Lance-Fort Union) time; middle Hiawatha (Eocene) rocks unconformably overlie the Ericson Sandstone (Upper Cretaceous) with absence of 5,000) ft of beds. A northeast extension of this uplift, the Table Rock platform, coincides with the present northeast bulge of the Rock Springs uplift and the western Wamsutter arch. Thin strata of Lance, Fort Union, and Hiawatha were deposited over the Table Rock platform. These beds thicken markedly basinward to the east. All of the new prolific gas and oil fields of the area have been found on the Table Rock platform. The folding of the Rock Springs uplift and Wamsutter arch took place in late Eocene through Oligocene times, and perhaps extended into Pleistocene time. The resulting eastward tilt has masked older structure and has caused significant updip migration and readjustment of gas and oil from original areas of accumulation.
Table Rock field is a compound stratigraphic-structural trap localized along a broad anticline. In Desert Springs, West Desert Springs, and Patrick Draw fields, accumulations are trapped stratigraphi- cally. Regionally, major gas fields have been found in lower structural positions than large oil-productive areas. Locally, within individual closed reservoirs, gas and oil are in their usual structural positions.
Shallow gas was discovered at Table Rock in 1946 and deeper production was found in 1954 in the Lewis and Almond. Desert Springs gas field was discovered in 1958, followed in 1959 by Arch, West Desert Springs, and Patrick Draw. The latter two are major oil fields with large reserves of gas. Table Rock, on production since late 1958, is the only gas field with a pipeline outlet. Production and marketing are in a very early stage of development.
Geology of Natural Gas Occurrence in Tertiary and Late Cretaceous Rocks of Sand Wash Basin, Colorado and Wyoming
Authors: Masters Charles D. 
Published: May 2021

Abstract
The Sand Wash basin of northwestern Colorado and south-central Wyoming yields natural gas from rocks of Tertiary and Cretaceous ages. The first discovery of gas was from the Tertiary in 1927, but because of market conditions, development has been slow. In recent years an active exploration program has resulted in markedly increased reserves which, as of 1965, exceeded 550 billion cu ft of high-methane gas.
The accumulation of hydrocarbons in the basin is controlled chiefly by structural closure, but only parts of the total Tertiary and Cretaceous stratigraphic column yield gas. A detailed knowledge of the distribution of selected reservoir rocks in relation to the structural configuration will be important in the discovery of new reserves within the basin.
Bethel Field, Anderson County, Texas
Authors: Krusekopf, Jr. H. H. 
Published: May 2021

Abstract
The Bethel field is in northern Anderson County. It encloses the Bethel salt dome; most production is from the west and east sides. The field was discovered by Texaco Inc. in 1956, when oil was found in the Woodbine Formation. In 1957 Texaco discovered gas in the Rodessa. The total gas reserve in the Rodessa at Bethel field is estimated to be about 95 billion cu ft.
Geology of Gas Accumulations in Paleozoic Rocks of Alberta Plains
Authors: Prather R. W. , McCourt G. B. 
Published: May 2021

Abstract
More than forty per cent of Canada's known natural gas resources, or 18.5 trillion cu ft of indicated gas reserves (Oil and Gas Conservation Board, Alberta, 1965), are contained in Paleozoic rocks of the Alberta Plains. The constant growth of Alberta's reserves since 1947 has encouraged the gas industry to seek extensive markets in Canada and the United States.
The Paleozoic rocks are predominantly shelf carbonates, limy marine shale, and evaporites. These strata are on the eastern flank of the Alberta syncline and dip southwestward at an average of 40 ft/mi. They form a wedge which is more than 5,000 ft thick near the Rocky Mountain Foothills and thins to the outcrop in the northeastern corner of the province. Emergence of the Alberta Plains between the end of Cambrian time and Middle Devonian time, plus periodic emergence and erosion between Missis- sippian time and Cretaceous time, resulted in the removal of considerable parts of the Paleozoic systems.
The major Paleozoic reservoirs are organic and clastic carbonates of the Devonian and Mississippian Systems. They form three types of stratigraphic traps—reefs, lithological pinchouts and unconformity traps. “Draped” anticlinal structure also aided in localizing accumulations in Nisku reefal reservoirs, which overlie Leduc bioherms.
The Devonian reefs of the Swan Hills, Leduc, and Nisku units mark the areas where shoaling occurred as the later Devonian seas transgressed the evaporite-filled Elk Point basin. The reef fields contain gas reserves of 8 trillion cu ft.
In the lithologic pinchout fields, gas accumulations of the Wabamun Group commonly include hydrogen sulfide gas up to 35 per cent by volume. The indicated reserves in these fields are 1.8 trillion cu ft of nonassociated residue gas and 35 million long tons of sulfur.
Gas accumulations associated with the post-Paleozoic unconformity have reserves of 8.2 trillion cu ft in Mississippian rock.
Production from Paleozoic gas reservoirs has been from both nonassociated-gas fields and dissolved gas from oil-producing areas. Paleozoic gas reserves are expected to increase considerably as exploration continues in the deeper drilling areas and in the more northerly areas of the Alberta Plains. An estimate of the ultimate potential gas resources in the Paleozoic rocks of the Alberta Plains, based on criteria similar to those used in recent forecasts for Canada and the United States, is 45 trillion cu ft.
Invariant descriptors for intrinsic reflectance optimization
Authors: Baslamisli Anil S. , Gevers Theo 
Published: May 2021

Intrinsic image decomposition aims to factorize an image into albedo (reflectance) and shading (illumination) sub-components. Being ill posed and under-constrained, it is a very challenging computer vision problem. There are infinite pairs of reflectance and shading images that can reconstruct the same input. To address the problem, Intrinsic Images in the Wild by Bellet al. provides an optimization framework based on a dense conditional random field (CRF) formulation that considers long-range material relations. We improve upon their model by introducing illumination invariant image descriptors: color ratios. The color ratios and the intrinsic reflectance are both invariant to illumination and thus are highly correlated. Through detailed experiments, we provide ways to inject the color ratios into the dense CRF optimization. Our approach is physics based and learning free and leads to more accurate and robust reflectance decompositions.