Barrels Of Recoverable Oil Research Articles

Three Ancient Montana Fluvial Systems: Pennsylvanian Tyler, Lower Cretaceous Muddy, and Upper Cretaceous Eagle--Their Reservoir and Source Rock Distribution: ABSTRACT

The importance of using Holocene geology as a model in mapping reservoir and source rock distribution is demonstrated in three Montana river-related systems: alluvial valley, barrier bar, and distributary channel-prodelta. The Pennsylvanian Tyler Formation was deposited by a westward-flowing meandering-stream system controlled by an east-west-trending rift valley, and surrounded by backswamp deposits. It is underlain by its probable hydrocarbon source, the marine Mississippian Heath shale and limestone, and overlain locally by the lagoonal Pennsylvanian Bear Gulch Limestone. To date, about 90 million bbl of recoverable oil have been found in Tyler sands. The oil-producing Lower Cretaceous Muddy sandstones in the northern Power River basin are considered to be barrier bars, encased in organic-rich shales, which are most probably the source rock. The Upper Cretaceous Eagle Sandstone in north-central Montana is a distributary channel system, similar to that of the modern Mississippi, which dumped highly carbonaceous materials into an organic-rich delta system. The Eagle now contains possibly enormous amounts of biogenic methane. By using Galveston Island and the modern Mississippi delta as models, in conjunction with employing electric log shapes and porosity logs, it is possible to map ancient fluvial patterns in the study areas. One can then predict the location of possible hydrocarbon accumulations in porous and permeable sand bodies, along with their encasing hydrocarbon source rocks. End_of_Article - Last_Page 866------------

Point Arguello Field--History and Geology of a Giant Oil Discovery: ABSTRACT

The Point Arguello field is a giant field with more than 300 million bbl of recoverable oil. The biogenic, fractured Monterey Formation forms the primary source and reservoir in this major offshore California discovery. The trap is a complex, anticlinal structure and is difficult to delineate seismically at depth. As is often the case, the original exploration concept differs from the final discovery. Chevron's structural and stratigraphic concepts have changed from the early days to the present. The Point Arguello structure extends across a thick Miocene depocenter. A low influx of terrestrial clastics, general reducing conditions, high organic productivity, rapid burial, and a high heat flow created an extraordinarily productive oil-generating depocenter. Today, this small subbasin is ringed by announced and unannounced oil accumulations. Recognition of this cooking pot concept was a factor in Chevron's bidding strategy for OCS Federal Lease Sale 53. In addition, early silica diagenesis of the diatom-rich Monterey within this small subbasin created an attractive Monterey reservoir. By 1970, Chevron and others in the industry were aware of silica phases and their importance in creating a commercial fractured reservoir. By the end of the decade, university research seemed to confirm these earlier observations. However, based on field measurements, some silica-phase-fracture relationships have recently been questioned. A giant accumulation formed under a rare combination of favorable circumstances. Eight wells have delineated two major oil pools whose gravity ranges from 11° to 34° API. The primary reservoir is the middle and upper Miocene fractured cherts, porcellanites, and dolostones. The open-fracture system forms about 1.0 to 2.0% of the reservoir volume. Three production platforms may be in place by the end of 1986. Careful planning is necessary to ensure a timely development in an environmentally sensitive area. End_of_Article - Last_Page 2045------------

Significance of Coniferous Rain Forests and Related Organic Matter in Generating Commercial Quantities of Oil, Gippsland Basin, Australia

Contrary to the conventional belief that humic coal generates primarily gas, 3 billion bbl of recoverable oil has been discovered in the humic coaly succession of the fluviodeltaic Latrobe Group (Upper Cretaceous-Tertiary) that serves as both the reservoir and the source for hydrocarbons in the offshore Gippsland basin of southeastern Australia. Evidence for generation of liquid hydrocarbons from the coaly succession includes: (1) similarity of n-alkane distribution in the oil and in the coal extracts; (2) high wax content of oil (up to 27% by weight); (3) high ratio of pristane/phytane in oil (5-6); and (4) dominance of C29 steranes in the oil. In the Gippsland basin, coniferous rain forests dominated by kauri vegetation flourished in a raised bog setting. Present temperate climate and kauri vegetation of New Zealand are considered to be the modern analog to the Gippsland basin. The coniferous vegetation provided large quantities of hydrogen-rich exinite macerals, such as cutinite and resinite, with potential to generate oil. High rainfall, raised ground-water level, low oxygen, high acidity, and low-nutrient conditions of a raised bog setting were suitable for preserving organic matter. A comparison of gas chromatograms of oils in the Gippsland basin with gas chromatograms of oils generated by hydrous pyrolysis in the laboratory from the immature source rocks suggests that the paraffinic fraction of the oil was derived from coal, and the naphthenic fraction was derived chiefly from resin.

Hydrocarbon Resources of United States Arctic: ABSTRACT

In April 1980, the National Petroleum Council, an advisory committee to the Secretary of Energy, was requested to estimate, among other directly relevant matters, the oil and gas resources of the United States Arctic regions. The evaluation was based on a review of publicly available information and a survey of the study participants. The results are a composite of anonymous estimates of 20 industry representatives. As of August 1980, 16.5 billion bbl of recoverable oil and oil-equivalent gas had been discovered on the North Slope. An additional 44 billion bbl of undiscovered, recoverable oil and oil-equivalent gas are estimated for the United States Arctic. Of these, 24 billion bbl may be oil and the remainder will consist of 109 tcf of gas and natural gas liquids. These undiscovered resources constitute as much as 40% of the total undiscovered recoverable oil and gas remaining within United States jurisdiction. A 1% chance exists that the undiscovered recoverable oil and oil-equivalent gas could exceed 99 billion bbl. Of 10 highly prospective areas, End_Page 525------------------------------ the largest resources occur offshore in the Beaufort shelf and the Navarin basin shelf. Basins appearing to have a relatively low potential should not be ignored. Future geologic information could cause significant revisions. Cost and technical considerations detract significantly from the apparent exploration merit of some resource-bearing basins, particularly in the arctic marine areas. Industry investment commitments since the study correspond with the study results. End_of_Article - Last_Page 526------------

HYDROCARBON HABITAT OF THE COOPER/EROMANGA BASIN, AUSTRALIA

The Cooper Basin is a complex intracratonic basin containing a Permian-Triassic succession which is uncomformably overlain by Jurassic-Cretaceous sediments of the Eromanga Basin. Abundant inertinite-rich humic source rocks in the Permian coal measures sequence have sourced some 3TCF recoverable gas and 300 million barrels recoverable natural gas liquids and oil found to date in Permian sandstones. Locally developed vitrinitic and exinite-rich humic source rocks in the Jurassic to Lower Cretaceous section have, together with Permian source rocks, contributed to a further 60 million barrels of recoverable oil found in fluvial Jurassic-Cretaceous sandstones.Maturity trends vary across the basin in response to a complex thermal history, resulting in a present-day geothermal gradient which ranges from 3.0°C/100 m to 6.0°C/100 m. Permian source rocks are generally mature to postmature for oil generation, and oil/condensate-prone and dry gas-prone kitchens exist in separate depositional troughs. Jurassic source rocks generally range from immature to mature but are postmature in the central Nappamerri Trough. The Nappamerri Trough is considered to have been the most prolific Jurassic oil kitchen because of the mature character of the crudes found in Jurassic reservoirs around its flanks.Outside the central Nappamerri Trough, maturation modelling studies show that most hydrocarbon generation followed rapid subsidence during the Cenomanian. Most syndepositional Permian structures are favourably located in time and space to receive this hydrocarbon charge. Late formed structures (Mid-Late Tertiary) are less favourably situated and are rarely filled to spill point.The high CO2 contents of the Permian gas (up to 50 percent) may be related to maturation of the humic Permian source rocks and thermal degradation of Permian crudes. However, the high δ13C of the CO2 (av. −6.9 percent) suggests some mixing with CO2 derived from thermal breakdown of carbonates within both the prospective sequence and economic basement.

Character of Ancient Petroliferous Lake Basins of the World: ABSTRACT

The principal oil- and gas-bearing lacustrine rocks in the world were formed from sediments deposited in or peripheral to ancient stratified lakes, of a variety of ages, which for millions of years maintained a size comparable to that of modern inland seas. In these lake systems, both lipid and woody organic matter were developed and preserved in large quantities. The lacustrine rock system commonly constitutes a depositional complex that includes indigenous hydrocarbon source, reservoir, and trap units. Lacustrine strata of China consist primarily of siliciclastic rocks; those of Brazil, Angola, and Cabinda are principally of siliciclastic rocks with abundant carbonate units; those of the End_Page 1680------------------------------ United States consist of at least 50% carbonate rock. Hydrocarbon resources of lacustrine depositional systems are greatest in the People's Republic of China (several billion barrels of recoverable oil). Hydrocarbon resources are also significant in the ancient lake basins of Brazil, Angola, Cabinda, and United States. Currently developed Chinese oil fields in nonmarine rocks are primarily in structural traps, those of South America and Africa are in combination structural and stratigraphic traps, whereas those of the United States are principally in stratigraphic traps. Available data suggest that hydrocarbons in the more deeply buried strata are contained in secondary pores which received oil or gas subsequent to significant episodes of cementation and/or compaction, and dissolution of minerals. Reservoir rocks with abundant primary porosity are most commonly preserved at relatively shallow burial depths, and many are intercalated with immature source units. Primary pores contain hydrocarbons that have migrated to reservoirs from mature source rocks (more deeply buried?). In China, oil is recovered in great quantities from sandstones with abundant primary porosity, particularly in those basins with high geothermal gradients. The oil apparently migrated to the primary pores from nearby source beds which reached thermochemical maturation at relatively shallow depths of burial and before significant early cementation and compaction of the sandstone units. Matrix porosity and permeability in sandstone units are best developed and preserved in those rocks composed of chemically stable minerals and few labile grains. Fluid-pressure gradients may be abnormally high in those lacustrine systems that have reached the stage of thermochemical maturation. In these cases, oil and/or gas are generated and expelled in quantities great enough to locally increase fluid pressures faster than pressure is released to adjoining rocks. Abnormally high fluid-pressure gradients in lacustrine units also occur in those impermeable hydrocarbon-bearing strata that have apparently been elevated at a rapid rate. In such a system, equilibration between fluid pressures in beds of low matrix permeability in the deep subsurface and permeable beds near the surface is restricted. In both cases, fractured overpressured rocks of low matrix permeability may yield oil and/or gas from pools whose boundaries are not restricted to loc l structures. Rather, they are restricted by relatively permeable beds that have provided access to the surface for pressure and fluid release (and invasion of water). Local avenues of permeability in overpressured rocks are greatest along natural, open fractures. Although reservoir rocks for fields developed in lake basins are commonly described as being of a lacustrine origin, others were formed from sediment deposited at the edge of a lake or in settings well removed from a lake. Principal reservoir rocks in the Uinta basin, Utah, represent the basal parts of coalesced fluvial channels formed at the fluctuating margin of lake Uinta. Red-colored oil-bearing strata in some Chinese fields whose reservoir rocks are channel-fill sandstones formed from sediment deposited on an alluvial plain several kilometers from the lacustrine shoreline. Lacustrine turbidite, bar, and deltaic rocks are important reservoirs in Brazil, Africa, United States, and China. Petroliferous sedimentary rocks formed in lake basins are known over much of the world where th y contain many billion barrels of recoverable oil and offer the promise of more. End_of_Article - Last_Page 1681------------

Oil and Gas Potential of Wyoming-Utah-Idaho Overthrust Belt--Relation to Canadian Foothills Province Analog: ABSTRACT

The Cordilleran orogenic belt is generally considered to be a single tectonic element extending from northern Alaska to Central America. Two segments of the North American part of this element are oil and gas producers--the Canadian foothills thrust belt and the Wyoming-Utah-Idaho Overthrust belt. Turner Valley was the first field discovered in the Canadian foothills. In the 55 years since that discovery, 32 fields have been found containing 9.3 Tcf of initially recoverable gas, 143 million bbl of natural gas liquids and 132 million bbl of oil. The first significant field discovery in the U.S. Overthrust belt was made in 1975 at Pineview. By the end of 1979 eleven new fields had been found, containing an estimated 500 million bbl of recoverable oil and 5.5 Tcf of recoverable gas, plus natural gas liquids. The Canadian province is considered to be an appropriate geologic analog to the U.S. Overthrust belt, based on a number of characteristics common to both provinces. These include general structural configuration, trap types, reservoirs, stratigraphy, timing of migration of hydrocarbons, depth of burial, and age of tectonic movement. However, significant differences include age of major source rocks and paleothermal histories. The future potential of the immaturely explored Wyoming-Utah-Idaho Overthrust belt is assessed by using a volumetric method, wherein hydrocarbon yields in barrels of oil and cubic feet of gas per cubic mi of sediments are established for the more densely explored Canadian foothills. These yields are applied to the less densely explored U.S. Overthrust belt. The usefulness of this method lies in the correct interpretation and analysis of similar, as well as dissimilar, geologic characteristics of the analog province. In addition, the assessment of the U.S. Overthrust belt is further refined by using the southerly productive part of this province as an internal analog which is applied to the remaining area of the province. End_of_Article - Last_Page 767------------

Tyler Sandstones (Pennsylvanian), Dickinson Area, North Dakota--A 24-Million Barrel Soil-Zone Stratigraphic Trap: ABSTRACT

Approximately 24 million bbl of recoverable oil have been found in stratigraphic traps in the Lower Pennsylvanian Tyler Formation at the Dickinson, South Heart, and eastern Green River fields, Stark County, North Dakota. Production is from a multiple sequence of quartzose sandstones 5 to 18 ft (1.5 to 5 m) thick deposited as barrier islands along regressive shorelines. Where a shoreline sandstone is fully developed, a typical vertical sequence consists, in ascending order, of the following. 1. 1 to 6 ft (0.3 to 2 m) of black to greenish-gray, sparsely fossiliferous shale. Thin interbeds of fossiliferous carbonate mudstone may be present (shallow-neritic environment). 2. 1 to 6 ft (0.3 to 2 m) of very fine to fine-grained sandstone containing small, deposit-feeding burrow structures. Stratification is finely laminated to ripple cross-stratified. Thin interbeds of siltstone and shale are common (lower-shoreface environment). 3. 3 to 12 ft (1 to 3.6 m) of fine to medium-grained, well-sorted sandstone which commonly exhibits medium to low-angle sets of cross-stratification. These genetic units are the principal reservoir rocks (upper shoreface environment). 4. 1 to 2 ft (0.3 to 0.6 m) of fine to medium-grained, well-sorted sandstone which commonly appears massive, but in a few cores exhibits parallel stratification. The upper few inches are clayey and mottled by root structures (foreshore environment). 5. 0.5 to 3 in. (2 to 7 cm) of coal (marsh environment). In a landward direction (south) the shoreline sandstones interfinger with thin fossiliferous limestones, black shales, and oxidized mudstones which are interpreted to be lagoon, marsh, and mudflat deposits. Throughout much of the subject area, porosity and permeability in the sandstones have been greatly reduced or completely destroyed by development of caliche paleosols. In the western part, the caliche consists of gray to brown limestone nodules or nodular layers of limestone in the sandstones and contains abundant pyrite. In the eastern part, the caliche has been strongly oxidized, and nodular to brecciated limestone in the sandstones is associated with reddish-brown to white clay, iron oxide cement, and scattered anhydrite nodules. It is estimated that the caliche destroys as much as 50% of the potential reservoir rock in the area and is an essential factor in the stratigraphic entrapment of the petroleum accumulations by providing an eastern (updip) barrier to migration. End_of_Article - Last_Page 485------------

WATER FOR OIL SHALE1

Although there may be as many as 600 billion barrels of recoverable oil locked up in the shale formations of the Rocky Mountains, the price of extraction of this oil will be high. The oil companies are unanimous in their view that the enormous risks involved in developing the industry should not be borne by the companies alone. Some kind of government subsidy, they say, is essential. A large scale oil shale industry will also have significant effects upon the clean air, water, and unique quality of life on the west slope of Colorado. A carefully constructed decision-making process is needed in order to make fundamental resource allocation decisions. The paper approaches the problem of development vs. the environment--by looking at one piece of it: water-intensive energy development in an arid rural area, in hopes of shedding some light on the range of institutional alternatives for making resource allocation decisions. The first section deals with the region itself; its resources and water supply capability, and at the projected impacts of a fully developed oil shale industry on the water resource. Then, with this context, the final section presents several examples of institutional allocation mechanisms that may suggest a conceptual rangemore » of approaches to resource allocation problems. (GMC)« less

Lone Pine Field--Exercise in Structural Geology: ABSTRACT

Lone Pine field, in the northwest part of North Park basin, Colorado, lies between the Park Range on the west and the Sheep Mountain-Delaney Butte thrust on the east. The oil field underlies a surface anticline mapped by Hale in 1965. Seismic work by a major oil company condemned this prospect, and it was farmed out to Burton-Hawks Exploration Company, who drilled the discovery well in November 1971. In general, the structural configuration and drilling depths conformed closely with Hale's cross section interpretation. The discovery well had a gas blowout from the Dakota Sandstone while coming out of the hole for a drill-stem test. After the well was controlled the Lakota Formation was drilled and completed as an oil producer with an I.P.F. of 515 BOPD. Subsequent drillin has found nine more oil wells and one gas well, all south of the discovery. The northern productive limit appears to have been found, with two dry holes just north of the discovery; however, the southern extent of the field remains to be determined. Present oil production extends 1.25 mi along both flanks of the structure, with a gas cap separating the two flanks. Some minor oil production is obtained from the Dakota Sandstone oil ring in two wells. The Lone Pine structure is a tightly folded, complexly faulted anticline, with 25-45° dips on the east flank and 45-60° dips on the west flank in the oil column. An oil column of approximately 300 ft has been established. Stratigraphic thickness of the Lakota is 70-75 ft, with 60-65 ft of effective pay. Average porosity of the Lakota is 18 percent. Drilling depths range from 2,400 to over 3,000 ft depending on topography and hole deviation. Wells are spaced about 800 ft apart along the east flank; optimum spacing on the west flank is yet to be determined. Each east-flank well proves up an estimated 300,000 bbl of recoverable oil, and west flank wells approximately 150,000-200,000 bbl of oil. A strong water drive hopefully will assure flowing wells throughout the life of the ield. Detailed structural analysis has been essential in guiding development drilling. Large scale, precise structural cross sections are built through each well. Logs are examined closely to determine even the smallest faults. All possible surface data are utilized. Concentric fold form, constant bed thickness and bed length, and a detailed analysis of fault behavior are combined to map as closely as possible the structural attitude in development wells while drilling. The target area for each well is a bank of production (oil ring) only 300-500 ft wide, and attempts are made to penetrate the oil ring near its midpoint to avoid water fingering from below and gas fingering from above. In addition, because of strong tendency for hole deviation in the steeply dipping strata, and the desire to penetrate the Lakota pay broadside where possible, the wells must be located at the surface (away from the axis) about 400 ft from the desired location at total depth. Frequent directional surveys while drilling have been necessary, particularly in the early development where unpredictable structural complexities were found. Despite the problems and additional expense of this type of development drilling, Lone Pine field should prove very profitable. Some of the wells are capable of flowing over 1,000 BOPD; however, all wells are choked back to 100-150 BOPD to prevent premature water fingering, or possible gas fingering. End_of_Article - Last_Page 906------------

Oil Boom in Indonesia--Too Optimistic?: ABSTRACT

Since the awarding of Indonesia's first offshore-production sharing contract to IIAPCO in August 1966 the boom has been on. Never before have so many End_Page 653------------------------------ different contractors searched so intensely for oil anywhere in southeast Asia. More miles of geophysical work have been done in the past 5 years than in all previous periods of Indonesian exploration. Even though oil drilling activity in Indonesia began in 1872, more widely scattered exploratory tests have been drilled in the current exploration cycle than during any comparable exploration period. The results have been variable. Although most exploration data remain confidential, it is known that some geologic interpretation and dogma have been disproved. Even though the majority of the exploratory ventures have resulted in economic failure, a measure of success has been recorded in 3 areas. The Ardjuna and Cinta fields are producing at the rate of 25,000 and 40,000 bbl/day of oil, r spectively, and the Ardjuna complex is expected to reach 75,000 bbl/day of oil in late 1972. Also, the Attaka field was scheduled at 30,000 bbl/day of oil by October 1971 and to exceed 100,000 bbl/day of oil during 1973. These do not appear to be giant oil fields, but they are economic ventures. The Attaka field, containing an estimated 300 million bbl of recoverable oil, appears to be Indonesia's best offshore discovery to date. Will another giant oil field like Minas be found? The applicable geologic criteria do not rule out the possibility, but the probability of several small giant fields being present appears better. The current search, with a fair measure of success, should discover them. End_of_Article - Last_Page 654------------

Economics of Prudhoe Bay Field--Comparison with Bell Creek Field: ABSTRACT

An economic model of Prudhoe Bay field based on the discounted cash-flow method uses the following assumptions: (1) 7.5 billion bbl of recoverable oil; (2) an average IP rate of 4,000 bbl/well/day; (3) a peak production rate of 1.6 million bbl/day; and (4) a discount factor of 15%. The model gives a producing cost (no exploratory or lease costs included) of $0.28/bbl. A similar economic model for the Trans Alaska Pipeline gives a pipeline cost of $0.45/bbl. for transport from Prudhoe Bay to Valdez. Tanker costs from Valdez to Los Angeles are estimated at $0.30/bbl. For comparative purposes a model of Bell Creek field, Montana, was made along the same lines as the Prudhoe Bay model. Actual producing rates of Bell Creek Field were used, and the expected ultimate recovery is assumed to be 150 million bbl. The model gives a production cost of $0.58/bbl at Bell Creek. End_of_Article - Last_Page 2499------------

Oil and Gas Accumulation in Reconcavo Basin, Brazil: ABSTRACT

The Reconcavo basin, on the Atlantic coast near the city of Salvador, includes about 3,850 sq mi and is the principal petroleum province of Brazil. Since End_Page 528------------------------------ 1939, 255 wildcats have been drilled, resulting in the discovery of 43 areas of accumulation, accounting for 942 million bbl and 992 Bcf, respectively, of producible oil and gas. The API gravity of most of the oil ranges from 35° to 40°. The Bahia Supergroup, the principal objective for petroleum exploration, has a maximum thickness of 20,000 ft. These sediments are nonmarine, and range in age from Late Jurassic to Early Cretaceous. The Late Jurassic deposits consist of a typical redbed association, which is overlain by the blanket Sergi Sandstone, the best reservoir rock of the basin. The Early Cretaceous (Neocomian) sediments are composed largely of dark-gray and grayish-green shale of the Itaparica, Candeias, and Ilhas Formations, which are considered to be the source rocks for the hydrocarbons. The sandstone, the lenticular sandstone bodies of the Candeias Formation, and the Sao Paulo and Santiago Sandstones of the Ilhas Formation are the best reservoir rocks of the Neocomian section. The present architecture of the Reconcavo basin is an intracratonic half graben, developed chiefly during the times of deposition of the Candeias and lower Ilhas, when the basin became a rapidly sinking trough. The accelerated growth of the Salvador and Mata-Catu uplifts, the most prominent structural features, were responsible for the two principal northeast- and northwest-trending normal fault sets. A late phase of tectonic movements occurred near the end of, or after, deposition of the Sao Sebastiao, reactivating ancient faults and causing new ones to form. As a consequence, the tectonic pattern of the basin is a complex system of faulted blocks. The six major fields, in which 96 percent of the total producible oil is concentrated, are related to the structural evolution of the basin. It is believed that the early period of faulting, contemporaneous with the deposition of Candeias and lower Ilhas, was a decisive factor in the control of petroleum migration and accumulation in Sergi and sandstones. The horst blocks of Agua Grande, D, Joao, and Buracica fields, uplifted during this tectonic phase, trapped about 622 million bbl of recoverable oil in the two sandstones. Accumulation of Ilhas reservoirs was controlled mainly by the later phase of faulting. Folds, developed in the downthrown blocks of normal faults, but not related to compressional stresses, were the traps for accumulations in the Sao Paulo and Santiago Sandston s. Examples of such traps, which accumulated about 186 million bbl of producible oil, are Miranga and Taquipe fields. The genesis of the reservoir sandstone lenses in Candeias field, a stratigraphic trap, is related to syntectonic Candeias deposition. Fractured shale and limestone also constitute reservoir rocks in this field, where 94 million bbl of recoverable oil were trapped. End_of_Article - Last_Page 529------------

Critical Evaluation of Hardeman Basin and Its Environs: ABSTRACT

Geologically the Hardeman basin is the easternmost extension of the elongate, east-west-trending geologic province known as the Palo Duro basin. Although the Hardeman basin apparently has not been subjected to the same violent structural unrest as other parts of North Texas (therefore, almost no structure is related to faulting), it is an area of prolific oil fields having traps of a peculiar type. Except for Conley, the largest Hardeman County oil field, oil traps here have almost no primary porosity. They seem to be either erosion remnants or small biohermal reefs with 100-200 ft of relief which have been vigorously and effectively leached by dolomitizing waters, leaving the limestone with secondary porosity values ranging from pin-point vugular to cavernous. Since the 1959 discovery of Conley, it and 14 smaller fields have produced almost 10 million bbl of oil. This added to the 20 million bbl of oil produced from the Fargo and Odell fields of northwest Wilbarger County, raise the total for the Hardeman basin to 30 million bbl. Seismic methods still provide the most reliable evidence of structure in the Hardeman basin, though increased drilling continually adds to the possibility of subsurface geological leads. As more fields are discovered, and more is understood of their structural form, there seems an increased demand for greater seismic accuracy which, because of the stratigraphic nature of the upper beds in the basin, is beyond the capacity of seismic tools. Most fields in the basin before discovery appeared on seismic maps as small low-relief closures or noses on positive structural trends. Many more such features are known, and must be explored. Economically the Hardeman basin offers the highest return on investment of any area in North Texas. Because individual wells from various fields yield engineering reserve estimates as great as 1 million bbl of recoverable oil, a return as great as 30:1 is a reality. Such high returns normally are found, or anticipated, only in Gulf Coast exploration. Though exploration costs are high in order to test the commonly cavernous Lower Mississippian lime at 8,500 ft (this is the prolific oil producer of Hardeman County), the Hardeman basin has a multiple-pay stratigraphic section to that depth, as shown by the presence of producing reservoirs in the Cisco-Canyon section (beginning at 3,900 ft), the Canyon limestone (normally Palo Pinto) below 5,000 ft, the Des Moines (Strawn) section of sandstone and conglomerate (from 6,000-7,300 ft), the Mississippian conglomerate (Holmes Sand) at 7,700 ft, the Mississippian limestone (Chappel and Osage) from 8,000 to 8,500 ft, and the Ellenberger dolomite below 8,500 ft (now producing only at Conley). Exploration in the past has been aided by acreage and dry-hole support from major companies which control large blocks of leases. It is hoped this support will continue, but even without it exploration will continue in the Hardeman basin and westward into the Palo Duro basin, because positive exploration results in the Hardeman basin are already too great, and the promise for future successful exploration too strong, to discourage those men of vision who search for new oil. End_of_Article - Last_Page 196------------

Upper Devonian Reef Oil Field--Redwater, Alberta, Canada: ABSTRACT

The Redwater oil field discovered in 1948 has inplace reserves of 1,300 million bbl, about 64 percent of which will be recovered. The field is a single pool 58 sq mi in area along the updip edge of a large Late Devonian (Frasnian) limestone reef complex. The complex is more than 800 ft thick, roughly triangular in plan and about 225 sq mi in area. More than 900 wells have been drilled in the field area where normal forereef, reef, and backreef facies are recognized. Porosity and permeability were influenced by diagenesis, but conform with the primary facies patterns. The Redwater reef grew during a major subcycle within the Kaskaskian sequence. Transgression over shoal carbonate of the previous subcycle created a End_Page 529------------------------------ reef-prone shelf of moderate depth. The reef was enveloped by clayey and carbonate muds which prograded across the shelf. Nearly 3,000 million bbl of recoverable oil in Redwater and nine companion reefs attests to favorable trap-to-source relations in this basin setting. Recognition of reef-prone cycles of deposition and early understanding of the depositional/tectonic framework which affects reef distribution are important in guiding exploration for Redwater-like reefs in new areas. Local, less predictable factors can influence the effectiveness of the reefs as traps and the success of exploration. Subsequent basin history is critical, for depth of burial affects the feasibility of seismic exploration and imposes regional eometamorphic patterns of hydrocarbon distribution. End_of_Article - Last_Page 530------------

The North Sea and Its Environs: Future Reservoir of Fuel?

IN 1964 it was estimated that the output of crude oil in the non-Communist world was approaching 25 million barrels a day but would need to be supplemented by 20 million barrels a day by 1975 to keep abreast of the virtual doubling of demand that now appears to be taking place in every decade.' This increase can be met by the adoption of new techniques to raise the present recoverable rates of 20 to 40 percent from proved oilfields to 50 or 60 percent, by the establishment of economic methods for the release of usable oil products now locked up in extensive tar or oil-shale deposits, or by new discoveries. All three sources will unquestionably be required. Numerous secondary projects directed at the raising and utilization of very viscous oil, from both run-down and fully productive fields, are under way in the United States, Canada, the Middle East, Venezuela, the Netherlands, and other countries. Investigations are also proceeding on the feasibility of producing oil from the Athabaska tar sands of Alberta2 and from the huge tar belt of eastern Venezuela. The Venezuelan area, lying north of the Orinoco River, has a width of 25 to 30 miles over a length of more than 300 miles; its known in-place oil probably exceeds 100,ooo million barrels. In the Rocky Mountain-Colorado Plateau region of the United States the 15,600 square miles of oil-shale country, embracing parts of Colorado, Utah, and Wyoming, is believed to contain about 400,000 million barrels of recoverable oil in a total reserve of at least 200,000 million tons of oil within the shales of the Green River formation. There have been strong suggestions that a technological breakthrough enabling shale oil to compete with conventional crudes is imminent. In the exploration for conventional sources of oil the emphasis is shifting increasingly to marine areas; accordingly, offshore production from continental shelves, now reliably estimated to amount to about 16 percent of the total Free World output, should show an upward trend, possibly to more than 25 percent of the world's needs by 1990. It has been estimated that,

History of Oil Development in Libya: ABSTRACT

Concessions were first granted in Libya during late 1955. At that time 14 companies obtained concessions totaling 130 million acres. By November 19, 1959, concession areas had increased to 265 million acres, but they decreased to 174 million acres by September 1, 1965. On July 29, 1965, 98 individual blocks totaling 147,589,617 acres were made available for bidding. As of September 1, 1965, no additional acreage had been granted. Exploration activity has been concentrated in two basins. Of primary interest is the Sirte basin in east-central Libya. Since drilling activities commenced in 1956, 1,572 wells have been completed in Libya, of which 44 per cent were wildcats. In the Sirte basin 12 per cent of the wildcat wells have been successful, and in the Ghadames basin of western Libya 18 per cent have been successful. No oil has been found in the Murzuck or Cufra basins. More than 11 million feet of hole has been drilled, 4.84 million feet of which has been wildcat drilling. Eighty-five oil fields, 59 in the Sirte basin and 26 in the Ghadames basin, have been discovered by means of wildcat drilling. It is estimated that more than 9 billion barrels of oil in place have been found. Individual pool reserves range from a few thousand barrels to more than one billion barrels of recoverable oil. The largest reserves are in Eocene and Cretaceous rocks of the Sirte basin. At the end of 1961, one company was producing at the rate of 40 thousand barrels per day. Today five companies are producing more than 1.25 million barrels per day. Industry has spent over 1.3 billion dollars in the search for oil, increasing from 33 million dollars in 1957 to more than 270 million dollars in 1964. End_of_Article - Last_Page 635------------

O.S.A. and Gillian Pools, Sedgwick County, Kansas: ABSTRACT

Regionally the O.S.A. and Gillian pools, producing End_Page 1561------------------------------ from the upper Simpson Sand, lie on a prominent northeast-southwest-trending anticline that plunges toward the southwest. This 25-mi.-long structural trend is an asymmetric fold bordered on the western flank by a normal, down-to-the-west fault possessing an average throw of 180 ft. at a Simpson datum. Discontinuous normal faulting, downthrown toward the east, exists on the more gentle eastern flank of the trend. The Gillian pool accumulation is attributed entirely to structural closure, whereas that of the O.S.A. pool is primarily stratigraphic, because of the presence of the updip beveled edge of the upper Simpson Sand which regionally circumvents the northwestern portion of the buried pre-Mississippian Chautauqua arch. Locally in the O.S.A. sector, this sandstone edge strikes nearly north-south and parallels the crest of the anticline, thus providing a preserved sandstone section on the western flank. The combined structural-stratigraphic relationship of these pools is significant. It is estimated that a reserve in excess of 3,500,000 barrels of recoverable oil has been proved to date. End_of_Article - Last_Page 1562------------

Williston Basin Developments, 1951-1953: ABSTRACT

The phenomenal rate of development in the Williston basin can best be visualized by remembering that at the end of 1950 there was not one producing oil well within the basin parts of North Dakota, South Dakota, Montana, Saskatchewan, or Manitoba. During three years of unprecedented exploratory drilling which followed the first commercial production of oil in the Williston basin (Virden field, T. 10 N., R. 28 WPM., Manitoba, Canada), 55 oil fields, 20 field extensions, and 4 gas fields have been discovered. During this period, production has been established from 16 different formations. One of the most spectacular discoveries during this period came in August, 1953, when End_Page 945------------------------------ flush production at 2,100 feet was developed in the Lodgepole (Mississippian) in the Roselea field, 56 miles north of the North Dakota line in Manitoba. Subsequent wells in the Roselea field have reported initials as high as 2,500 barrels of oil per day. The lack of sufficient well information makes it impractical to calculate the reserves represented by the fields thus far discovered; however, the most conservative estimate places this figure between 500 million and 1 billion barrels of recoverable oil. The year 1953 witnessed the completion of the 300,000 barrels per day Interprovincial Pipe Line from Edmonton, Alberta, to Sarnia, Ontario, and marked the beginning of construction of three new refineries in North Dakota, which on completion will process 33,500 barrels of basin crude daily. 1953 also saw the completion of the 100,000-barrel-per-day common carrier Service Pipe Line from the Beaver Lodge-Tioga area to Mandan, North Dakota, the beginning of construction of a natural-gasoline plant at Tioga, North Dakota, and the completion of Stanolind's products line from Mandan to Fargo, North Dakota. There remains, however, an urgent need for additional marketing facilities before the full economic potential of the basin can be realized. Judged from recent official and unofficial anno ncements, plans to create new facilities are under way and the next five years should show marked progress in this direction. With geophysical activity maintaining its record-breaking pace, and millions of acres of leases approaching one year closer to the expiration date of their primary terms, it is expected that 1954 will witness an unprecedented wildcat and field development program in the Williston basin. Excellent shallow production in Manitoba, the discovery of the first commercial oil in South Dakota, plus continued success in Montana, North Dakota, and Saskatchewan will serve as an incentive to substantiate this 1954 prediction. End_of_Article - Last_Page 946------------