Significant Oil Discoveries Research Articles

Oil and Gas Developments in South America, Central America, Caribbean Area, and Mexico in 1984

For the 25 countries described in the region, exploration activity continued to be centered in proven petroleum provinces in 1984. Exploration activity increased in Brazil, Colombia, and Venezuela. Important, successful exploration efforts continued in areas around Cano Limon field in Colombia, and Guafita and La Victoria fields in Venezuela. Notable discoveries in South America included the 42-46-IX San Martin Cretaceous discovery by Shell in the Ucayali basin in Peru, the significant oil and gas discovery at Palmar Largo ES-1 by YPF in Argentina, and the first offshore gas discovery, the Pecten 1-SPS-20 wildcat in the Santo basin in Brazil. Oil production increased in Barbados, Brazil, Colombia, Ecuador, Mexico, Peru, Trinidad and Tobago, and Venezuela. A notable increase (40%) in oil production occurred in Brazil. Gas production increased in Argentina, Barbados, Colombia, Peru, and Trinidad and Tobago.

Oil and Gas Developments in Louisiana Gulf Coast Offshore in 1984

In 1984 in offshore Louisiana, 1,145 wells were drilled, an increase of 137 wells from 1983. The overall success rate increased to 63.9% in 1984 from 62.5% in 1983. The success rate for wildcats increased to 25.5%, with 65 new-field discoveries. The success rate for new-pool and outpost drilling increased to 59.6%, with 34 discoveries. A deep-water drilling boom along the Flexure trend led to a number of significant oil discoveries with estimated reserves of more than 1 billion bbl of oil equivalent. At Federal Lease Sale 81 on April 24, 1984, $2.13 billion was bid on 529 leases by 80 companies. The total of accepted winning bids on 452 tracts (2,272,369 ac) was $1.32 billion. Geophysical activity fell 7% from 1983 to 1,133 crew-weeks, while liquids and gas production rose 10% and 13%, respectively.

Fort St. John - Stoddart Area An On-Going Petroleum Development Opportunity

Abstract Since the early 1950s, exploratory and development drilling has been continually rewarding within an 80 km radius of the city of Fort St. John, British Columbia. Although this drilling was originally gas-oriented, significant oil discoveries were made at Boundary Lake (Esso, 1957), Peejay (Sinclair Oil, 1959), Inga (Canadian Superior, 1965) and West Eagle (Scurry Rainbow, 1976). Scurry-Rainbow Oil Limited, now controlled by Home Oil Company Limited, has played an integral part in most of these field developments. Until the early 1970s there were a limited number of wells immediately north of Fort St. John with the exception of the Stoddart Belloy gas pool which was discovered in 1957. The possibility of oil regionally down dip was evidenced by production from the Uno Tex wells in Section 31-85-19W6M and oil shows at the Sun 8-l4-85-19W6M and Centrai Del Rio ll-29-84-18W6M wells (Fig. I). Although Triassic reservoirs have produced the majority of B.C.'s oil reserves to date, the Belloy (Permian) is now gaining importance as a major producing horizon (Table 1). Scurry-Rainbow's first well was drilled in 1971 on a farmout from Great Northern Oil Limited (6-3l-84-17W6M), exploring for what was hoped to be a regional extension of the Stoddart Belloy gas pool. Although the Belloy was tight at the location, a porous gas bearing Triassic North Pine sand was encountered, thus discovering the Cecil North Pine "A" gas pool. Further delineation drilling in 1972 confirmed the extent of the gas discovery, as well as proving the existence of an oil leg to the pool. ncouraged by the results of the North Pine drilling, Scurry- Rainbow and Placer CEGO Petroleum stepped out approximately mid-way between the originaI6-31-84-17W6M well and the Central Del Rio Belloy oil show at 11-29-84-18W6M, and discovered what is now known as the Eagle Belloy "B" pool in 1973 (6-27-84-18W6M). With attention then concentrated on extending the trend northwest back to the Uno Tex Stoddart wells discoveries were made at West Eagle, (Belloy "A" pool 1976) West Stoddart (Belloy "C" pool, 1977) and South Stoddart (Belloy "C" 1979). Undoubtedly, the most significant of these discoveries was the West Eagle field (6-36-84-19W6M). Subsequent to step-out drilling by other independent operators, early indications of the possible major size of the Belloy "A" pool sparked a flurry of lease acquisition of both Crown acreage and some of the only freehold acreage in British Columbia. Once most of the favourable acreage had been leased surrounding the discovery, development drilling began in earnest during 1977. By the end of 1980, sixty-seven wells had been drilled into the Belloy "A" pool. As the pool did not have either a natural water drive or a significant gas cap, reservoir pressures declined rapidly from 16742 kPa (2428 psi) in 1976 to 15 200 kPa (2204 psi) in 1980. The B.C. Petroleum Resources Division and the operators agreed that waterflood operations should commence as soon as possible. To that end, the pool was unitized with Scurry-Rainbow as operator and injection operations began prior to the end of 1980.

Oil and Gas Developments in South America, Central America, Caribbean Area, and Mexico in 1983

Petroleum exploration in the region was generally less in 1983 than in 1982. Brazil, Colombia, Ecuador, and Barbados increased crude production, whereas Argentina, Bolivia, Brazil, Colombia, Ecuador, Mexico, and Trinidad-Tobago reported increases in gas production. Although drilling activities remained low compared to past years, significant oil discoveries were reported in Colombia, Mexico, and Brazil. In Colombia, Cano Limon field is reported to be the largest field found in the Llanos region. In Brazil, important oil discoveries were made offshore in the Para, Potiquas, and Ampos basins. In Mexico, discoveries were reported in the Cerro Azul, Poza Rica (Chicontepec, Villahermosa, and Tabasco) areas onshore and in the Bay of Campeche offshore. In Argentina, discoveries were made in the San Jorge basin and the Noreste Tarija basin.

Platform-Margin and Marginal Slope Relationships and Sedimentation in Devonian Reef Complexes of Canning Basin, Western Australia: ABSTRACT

Devonian limestone platforms in the Canning basin were generally rimmed by reef-margin and reef-flat deposits, constructed by stromatoporoids, algae, and corals in the Givetian and Frasnian, and by algae in the Famennian. However, some platforms were low-relief banks with little or no reef development. End_Page 516------------------------------ Reef rims were flanked by steeply dipping marginal-slope deposits that descended to depths up to several hundred meters. These deposits include debris flows, huge allochthonous reef blocks, scheck breccias, and reefal tongues and bioherms built primarily by sponges and algae. Platform margins are classified as advancing, retreating, upright backstepping, and roll-over types. Advancing margins are typical of the Famennian reef complexes; the others occur principally in the Frasnian and Givetian, where they are often associated with platform-margin unconformities resulting from submarine erosion or margin collapse. The reefs and slowly deposited parts of the marginal-slope facies were subject to pervasive early submarine cementation by fibrous high-magnesium calcite (now radiaxial spar). The strongly cemented reef limestones formed rigid wave-resistant rims to the platforms. Fracturing of these limestones, probably largely associated with earthquake shaking, gave rise to extensive networks of neptunian dikes and sills, and to the collapse of some sections of the margins. Such collapses in turn initiated debris flows and the deposition of allochthonous reef blocks on the adjoining marginal slopes. The reef complexes are being explored extensively for lead-zinc deposits in outcrop and oil in the subsurface. A significant oil discovery was made in a Famennian platform margin (the Blina field) in 1981. End_of_Article - Last_Page 517------------

Continental Margin of Eastern Canada--Geologic Framework and Petroleum Potential: ABSTRACT

The Atlantic-type continental margin of eastern Canada is underlain by a series of Mesozoic-Cenozoic sedimentary basins separated by basement highs or areas of thinner sediments. Regional and/or salt tectonics have structured the Mesozoic sequence, which is masked by a less-deformed wedge of prograding uppermost Cretaceous and Cenozoic sediments. The basins have been targets of active hydrocarbon exploration for over 2 decades. Data from 138 exploratory wells and over 680,000 km (420,000 mi) of multichannel seismic coverage have indicated four major geologic/geochemical regions: Scotian Shelf, southern Grand Banks, northeastern Grand Banks, and Labrador-Southeast Baffin Shelf. On the Scotian Shelf, 13 significant gas/condensate discoveries have been made out of 62 wildcats drilled since 1967. Five of the discoveries, including the Venture field, are in an overpressured zone that has been explored only since 1979. No commercial hydrocarbon accumulations have been found in the southern Grand Banks where 28 wildcats were drilled between 1966 and 1975. The northeastern Grand Banks region has been actively explored since 1971. The 22 wildcat wells drilled through late 1983 have yielded six significant light oil discoveries, including the giant Hibernia oil field. Labrador-Southeast Baffin Shelf exploration has yielded six gas/condensate discoveries in 26 exploratory wells drilled since 1971. The Geological Survey of Canada has developed hydrocarbon-generation models to explain the regional variation in oil and gas occurrence and to assess future potential in terms of the nature and thermal maturity of the source rocks, type of organic material, and time of trap formation. These factors are related to the geologic history of the margin, which is characterized regionally by diachronism in major basin inception and in the resultant stratigraphic record. We predict an exciting future for this vast petroleum province. End_of_Article - Last_Page 1203------------

BIRKHEAD REVISITED: FETROLOGICAL AND GEOCHEMICAL STUDIES OF THE BIRKHEAD FORMATION, EROMANGA BASIN

Significant discoveries of oil have been made in Middle Jurassic sandstone reservoirs of the Birkhead Formation, Eromanga Basin, Australia.Some, or all, of this oil has been generated within the Birkhead Formation. A large proportion of the oil appears to be in relatively subtle traps. The source rock characteristics of the Birkhead Formation have been rated as fair to very good. In an attempt to improve the success rate in searching for less obvious reservoirs, a rating system based on the factors that control the location of hydrocarbon source rocks has been applied to many wells within the Birkhead Formation. The variables measured, which relate to source potential and maturation, were (1) thickness of shale units; (2) volume and type of dispersed organic matter; (3) volume and type of coal occurrences; and (4) rank.High values of source potential as measured by this rating system occur in the Birkhead Formation overlying the southwestern and northeastern parts of the Nappamerri Trough of the Cooper Basin. These areas include, or are close to, the known discoveries within the Birkhead Formation.In addition, investigation of the nature of the hydrocarbons produced from the Birkhead Formation using pyrolysis-gas chromatography (Py-GC) of whole rock samples and GC analysis of solvent extracts from the rocks indicates a terrestrial origin for the organic matter in most cases. Waxy oils could be expected from these samples under appropriate maturation conditions.

Hydrocarbon Potential of Intracratonic Rift Basins: ABSTRACT

Significant world oil reserves have been added in recent years from rift systems. Examples of petroliferous rift basins may be found on nearly every major continent. As our understanding of the mechanisms of sedimentation and structure in rift basins grows, more rift systems will be found. With a few notable exceptions, rifts that have been explored in the past are those that formed along continental margins. These contain marine sediments, and the conditions of source rock, sediment type, depositional environment, and structural style are well-known exploration concepts. Intracratonic rift systems containing continental sediments have received little exploration effort because few have been recognized, and also because of the problems perceived to accompany continental sedimentation. A good modern analog is the East African rift system. The source rock is lacustrine shale with an organic content that ranges from 5 to 20%. The organic materials are preserved by anoxic conditions of deep lake waters. Heat flow, as in continental-margin rifts, is moderate to high. Combined with a commonly thick section and depth of burial, the sediments can be well within the oil generation window for lacustrine shales. The volume of oil generated may be very large for a basin of limited areal extent. The oil is generally waxy, has an API range from the 20s to 30s, and h s a low sulfur content. The reservoir quality is highly dependent on the type of sediments deposited, because there is little energy available for sorting or winnowing. Possibilities include first-cycle arkoses derived from crystalline basement rock and second-cycle or multicycle sands derived from earlier pre-rift depositional episodes. Eolian sands are also possible reservoirs. There may also be sharp facies variations across the rift, and aspect ratios of these facies may approach 1:1. Seals for the reservoirs are either lacustrine shales or evaporites deposited under hypersaline, closed drainage conditions. Structures are genetically similar to those found in continental margin rift valleys. Accumulation zones are found in series of tilted blocks controlled by listric, down-to-the-ba in faults; in reverse drag anticlinal features on the downthrown side of growth faults; in basement high blocks with a sedimentary End_Page 1199------------------------------ cover; and if the basin is asymmetrical, in monoclines developed on the slope. Basin size is typically 20-60 km (12-37 mi) in width and 70-300 km (43-186 mi) in length. An intracratonic rift of this type is part of the Central African rift system. This system trends east-west, from the Benue trough in Nigeria to the Lamu embayment in Kenya. It is the result of the propagation of rifting from the triple junction that separated South America from the western margin of Africa, and also from the triple junction on the eastern margin where Madagascar separated from Africa. The rift system was tectonically active during the Cretaceous and Tertiary (Paleogene), and ceased after the initial faulting and coincident igneous activity but before any new crust was formed. The rifting along this trend was superseded in the Miocene by the East African rift system, which is still active. Several companies have made significant oil discoveries in different components of the Central African rift system. Average daily production for 1982 from the basins associated with the Benue trough was 107,928 BOPD. Conoco has drilled at least eight discovery wells in the Chari basin and Ngaoundere rift components, and zones tested flowed up to 1,900 BOPD. In the Abu Gabra rift component, where Marathon is currently exploring, Chevron has drilled approximately 60 wells. Nineteen of these were discoveries and tested an average rate per well of 3,500 BOPD. The oil in the Chari basin and Abu Gabra rift is found in multiple zones in the Upper Cretaceous and Tertiary continental sands, and is a typical derivative of lacustrine sediments. The Abu Gabra rift may contain up to 10 billion bbl of oil. Research indicates that this type of rift system is present in other areas of the world. Ongoing worldwide exploration has shown that intracratonic rift basins have the potential to make a significant contribution to world oil reserves. End_of_Article - Last_Page 1200------------

Petroleum Exploration and Resource Potential of Offshore Newfoundland and Labrador: ABSTRACT

The continental margin of Newfoundland and Labrador, encompassing a total area of 714,000 mi2 (1,849,252 km2) has been the target of exploratory activity since the early 1960s. Exploratory drilling began on the Grand Banks in 1966 and by 1974 a total of 40 dry wells had been drilled. This lack of success, accompanied by escalating drilling costs, resulted in the curtailment of exploratory activities. In 1979 wildcat drilling resumed on the Grand Banks and the Hibernia field was discovered with the drilling of the P-15 well. This well, with an estimated flow potential of more than 20,000 BOPD, was the first oil well drilled on the Atlantic shelf of North America capable of commercial production. Truly a giant, the Hibernia structure has a resource potential of 1.85 billion bbl of oil and 2.0 tcf of gas at a probability level of 50%. Six significant oil discoveries have been made on the Grand Banks. Of these, the Hibernia, Nautilus, Hebron, and Ben Nevis dis overies are located in highly faulted hinge zones on the western and eastern flanks of the northward plunging Avalon basin graben. The South Tempest structure is located on a ridge complex to the east of the Avalon basin. The Adolphus well drilled a salt piercement structure in the basin depocenter. The reservoirs are fluvial-deltaic and shoreline sandstones of Jurassic and Cretaceous age. Since 1971, 25 wells drilled on the Labrador Shelf resulted in one oil and five gas discoveries. The reservoirs are Paleozoic carbonates and Lower Cretaceous, Paleocene, and Eocene sandstones. All are capping or draping basement horst blocks. By the end of 1982, total exploratory efforts had resulted in the drilling of 86 wells and the acquisition of approximately 240,000 line-mi of marine reflection seismic. Provincial land permits on the continental margin are held by ten permittees. This land position represents 54 million acres (22 million ha.) and 133 exploratory permits. A total resource potential of these structures has been estimated at 14.7 billion bbl of oil and 88.6 tcf of gas at a 50% probability level. A commercial discovery was long in coming but the recent high success rates confirm this margin as a major frontier of enormous potential. End_of_Article - Last_Page 434------------

Oil and Gas Developments in Western Canada in 1982

In 1982, petroleum industry activity in western Canada continued to decline as a result of economic recession, dropping oil and gas prices, high interest rates, and a worldwide oil surplus. Many smaller companies disappeared, and staff cuts were common throughout the industry. The total number of wells drilled dropped 9% to 6,285. Exploratory drilling decreased by 26% to 2,288 wells, whereas development drilling increased 4% to 3,997 wells. The exploratory success rate increased from 62 to 65% in 1982, with 761 oil discoveries and 732 gas discoveries. The development success rate increased slightly from 88 to 89%, with 1,742 oil completions and 1,823 gas completions. A late surge in drilling resulted from provincial and federal incentive programs designed to stimulate act vity. Average well depth decreased in all areas, and total revenue from land sales continued to plummet. Alberta land sale bonuses totaled $334 million(FOOTNOTE 4), British Columbia $17 million, Saskatchewan $34 million, and Manitoba $1 million. Average price paid per hectare dropped substantially in the 3 westernmost provinces, but increased by 75% in Manitoba. Number of hectares for sale declined in all areas. Downward exploratory drilling trends, which began in 1981, were accentuated in 1982. Alberta, Saskatchewan, and British Columbia activity dropped markedly, but Manitoba activity more than doubled. In Alberta, drilling was more cautious, with increased development drilling and fewer dry holes. A significant Devonian pinnacle reef oil discovery was made by Gulf Canada in the Fenn-Big Valley-Rumsey area, and major activity continued to be concentrated in the Peace River arch, Shekilie, and West Pembina areas. The $13.5 billion Alsands project was canceled. No discoveries of major significance were made in either British Columbia or Saskatchewan. Manitoba activity continued to soar for the third consecutive year as a result of the 1980 Jurassic oil discovery at Waskada. In the Arctic Islands, a major stepout oil discovery was made at Cisco, off Lougheed Island, and gas was discovered at Sculpin, near Ellef Ringnes Island. Beaufort Sea stepout oil discoveries were made at West Atkinson and Tarsiut. Delineation drilling on the Tarsiut structure has been disappointing and estimated reserves are less than anticipated. Future major exploration activity in the Beaufort Sea will continue as a result of several large farmouts by Esso and Gulf to Canadian consortiums. Esso also has a major development drilling project in the old Norman Wells oil field astride the Mackenzie River. The year 1982 was a pronounced continuation of 1981, with exploration interest shifting from the provinces to the northern and eastern frontiers. Within the provinces, drilling shifted markedly to oil plays, because of the depressed gas market, while expenditures were down significantly. The downturn in exploration appears to have ended, in part due to provincial drilling incentives, but no major improvement in activity is predicted for 1983.

Oil and Gas Developments in New York in 1981:

In 1981, there were 646 wells completed in New York. This figure is partly estimated. In existing fields, 107 oil and 450 gas wells were completed. The results of exploratory drilling included 12 new gas field discoveries, 4 new gas pool discoveries, 3 deeper pool discoveries, 1 shallower pool discovery, and 36 extensions to existing gas fields. Two Medina Sandstone discoveries were made in Allegany County. Nine Devonian black shale wells were completed in western New York. An Onondaga reef discovery was made in Cattaraugus County. Three Trenton Limestone discoveries were made in central New York. Arco completed a dry hole in eastern New York near the Eastern Overthrust area. A significant oil discovery from the Bass Islands zone below the Onondaga Limestone was made in eastern Chautauqua County. Thirty-five extensions to Medina Sandstone gas fields were completed in 1981. There was also 1 extension to the Houghton, Marcellus black shale gas field. In all, 8 Devonian black shale discoveries, 8 Silurian Medina Sandstone discoveries, and 3 Ordovician Trenton Limestone discoveries were made in New York during 1981. Oil production in 1981 was 848,969 bbl and gas production amounted to 19,000 mmcf. The price for New York stripper crude was $38.00/bbl on January 1, 1981, and ended the year at $35.00/bbl. Wellhead gas prices ranged up to $3.18/mcf. In 1981, 6 companies accomplished 49 crew-weeks of reflection seismic work in New York. A portion of a state park was leased by competitive bidding. Leasing continued in the Eastern Overthrust area of eastern New York and in central and western New York. An amended oil and gas law was passed. One of the main effects will be to substantially increase fees for drilling permits. FERC Section 107, Tight Sands, recommendations for 2 separate applications involving the Medina and Queenston formations in 12 New York counties are pending and approval is expected in 1982. Drilling for Medina Sandstone gas production and Devonian black shale gas production will continue. However, it is expected that overall drilling will decline due to a softening in crude oil prices and an oversupply of gas. Federal government approval of leasing and drilling for gas in Lake Erie has still not been forthcoming.

Oil and Gas Developments in Australia in 1981

During 1981, exploration and development drilling continued its trend upward from 1979 and 1980. In 1981, exploration drilling reached its highest level in the past 16 years of Australian oil and gas activity. The exploratory well record was set in 1965 when 157 wells were drilled. The states with the greater amounts of activity in 1981, as in 1980, were Queensland, South Australia, and Western Australia. In Australia overall, there were 125 exploration wells and 107 development wells drilled and/or commenced in 1981. Significant onshore oil discoveries were made in Queensland, South Australia, and Western Australia. The presence of commercial oil in apparently significant quantities in Cretaceous to Jurassic rocks of the Eromanga basin in South Australia and Queensland was greatly extended areally by discoveries at Merimellia 6, South Australia (2,738 BOPD), and at Jackson 1, Queensland (350 BOPD from the Cretaceous Murta Member of the Mooga Formation; 1,165 BOPD from the lower part of the Jurassic Westbourne Formation; and 2,616 BOPD from the top of the Jurassic Hutton Sandstone). There is perhaps up to 25,000 mi2 in the relatively unexplored Eromanga basin where Mesozoic oil might occur. In Western Australia, one of the more important geologic discoveries to occur onshore was the flow of oil (906 BOPD) from Devonian limestone at Blina 1 in the northeast part of the Canning basin. Geophysical work in all categories increased in Australia in 1981 relative to 1980 with nearly twice as much onshore seismic work being completed in 1981. Gravity and magnetic surveys showed a very marked increase also. Natural gas production increased 9.1% in 1981 relative to 1980 to 11,647.48 million m3. Oil production in 1981 increased 6.8% relative to 1980, or by 1,456,510 m3 to 22,773,323 m3 for an average daily production of about 392,500 bbl.

World Exploration Highlights

High petroleum prices have stimulated worldwide exploration. Better understanding of the basic principles of the origin and primary migration of hydrocarbons and of basin tectonic processes have aided in selecting areas that warrant intensive exploration. There is renewed interest in oil prospects of overthrust belts, and attention has been drawn to the high potential of buried Late Tertiary reefs in tropical regions. Advances in seismic data gathering and processing have greatly increased the usefulness of geophysical surveys, once essentially limited to the search for closed structures. Since 1979, oil production has been found in previously unproductive basins, such as the Grand Banks of Newfoundland, and even in newly discovered basins, including southwestern Sudan and the Gulf of Beibu (Tonkin) off southern China. The most significant oil discovery in recent years is the Hibernia field off Newfoundland. Large gas fields have been found in the Norwegian sector of the North Sea, off Cameroun in West Africa, onshore and offshore in Spain, and in Sharjah on the Arabian Peninsula. Numerous other fields have been found throughout the world, but data are insufficient for estimating the size of many of these discoveries, even though some will certainly prove to be in the giant class. Data on the Soviet Union are insufficient for commenting on recent exploration results. > Companies have been granted large new contract areas for petroleum exploration in many countries, some of them in basins already surveyed in reconnaissance, others untouched by modern geophysical methods. Availability of new land rights ensures that the present drive for new oil and gas resources will continue in future years, probably with a similar degree of success.

Petrography, Stratigraphy, and Petroleum Potential of Neocomian Missisauga Formation, Sable Island Area, Nova Scotia Shelf: ABSTRACT

The Canadian Atlantic margin has been an area of active drilling for more than 10 years. On the Scotian Shelf, the total number of wells drilled is now over 70, including several with significant discoveries of gas, wet gas, and light oil. The Lower Cretaceous (Neocomian) Missisauga Formation of the Sable Island area is composed of coarse clastics of a high-constructive lobate delta system. Sandstones vary from subarkose to volcanic sublitharenite, with rare quartz arenites. They are derived from mixed sedimentary, metamorphic, and igneous basement terranes on the north and northwest. Thickness variations in the clastic sequence are partly controlled by salt diapir growth. Regional marine transgression in the late Neocomian (Barremian) terminated delta progradation. Well log analysis, binocular and petrographic examination of cutting samples and cores, and stratigraphic map analysis, based on 13 offshore wells in the vicinity of Sable Island have delineated an area in the Missisauga Formation with high petroleum potential compared to that of adjacent areas, on the basis of (1) isopach trends; (2) proximity of good reservoir rocks to mature, marine source beds; (3) maximum sandstone thicknesses and numbers; (4) numerous possibilities of structural and stratigraphic traps; and (5) predominant delta front facies, most productive elsewhere in high-constructive deltas. Thus, despite earlier indications, from geochemical studies of source rock potential, that prospects for large accumulations of hydrocarbons are only poor to fair, the Sable Island area deserves further attention as an exploration target. End_of_Article - Last_Page 1673------------

Petroleum Potential of Basin and Range Province, Western United States: ABSTRACT

Five oil fields have been discovered within the Basin and Range province of the western United States. They are Eagle Springs (1954), Trap Spring (1976), and Currant (1978) fields in Railroad Valley graben of east-central Nevada, and in the Great Salt Lake area of Utah, Rozel Point (circa 1904) and West Rozel (1978) fields. Rozel Point and Currant fields are non-commercial accumulations. Reservoirs are either fractured Oligocene ignimbrites, Eocene lake sediments, or fractured Miocene-Pliocene basalts. Accumulations occur in truncation-fault traps or in drape over faulted structure. The source of the oil is believed to be Tertiary lake deposits and/or Chainman Shale of Mississippian age. End_Page 707------------------------------ Exploration for Tertiary accumulations is carried out by: (1) mapping source rocks in basins with proper depth for maturity, (2) establishing presence of reservoir rocks, and (3) delineation of traps by photogeologic-geomorphic techniques, gravity surveys, and seismic shooting. Numerous shows of oil and gas have been recorded in wells drilled in various basins, both in Paleozoic and Tertiary rocks. Other oil and gas indications include the Bruffey oil and gas seeps (Pine Valley, Nevada), the Wells oil seep (west of Wells, Nevada), an asphaltite dike in Mississippian sediments (Pinon Range, east of Pine Valley), the West Brigham City and Farmington gas areas (east of Great Salt Lake, Utah), and the Fallon gas area (Carson Sink, Nevada). Oil source units include Cretaceous to Tertiary lake deposits (Sheep Pass Formation, Elko Shale, Kinsey Canyon Formation, Newark Canyon Formation, and King Lear Formation), Mississippian Chainman Shale, Devonian Pilot Shale, and Ordovician Vinnini Shale. Several Paleozoic plays exist in Nevada, including the Mississippian Diamond Peak (Illipah, Scotty Wash) sandstone pinch-outs. Reef buildups may be present in the Silurian and Devonian section. Exploration in the Basin and Range province should result in significant discoveries of oil and gas in the future. End_of_Article - Last_Page 708------------

Petroleum Potential of Great Basin: ABSTRACT

The discovery in 1976 of Trap Spring oil field in Railroad Valley, Nevada, and the 1979 discovery of West Rozel oil field in the Great Salt Lake, Utah, have focused attention on the Great Basin. To date, five fields have been discovered which include, in addition to the mentioned fields, the Rozel Point (circa 1904), Eagle Springs (1954), and Currant oil fields (1978). All fields produce from either Tertiary lake sediments or fractured volcanic rocks. Accumulations occur in truncation-fault traps or in drape-over faulted structure. Exploration for Tertiary hydrocarbon accumulations consists of (1) mapping basin source rocks with proper depth for maturity, (2) presence of good reservoir rocks, and (3) delineation of traps by photogeologic-geomorphic techniques, gravity surveys, and seismic shooting. Wells drilled in many basins have recorded good shows of oil and gas both in Tertiary and Paleozoic rocks. Other oil and gas indications include the Bruffey oil and gas seeps (Pine Valley, Nevada), the Wells oil seep (west of Wells, Nevada), an asphaltite dike in Mississippian rock in the Pinon Range east of Pine Valley, and the West Brigham City and Farmington gas area (Carson Sink, Nevada). Oil source units include the various Cretaceous to Tertiary lake deposits (Sheep Pass Formation, Elko shale, Kinsey Canyon formation, Newark Canyon Formation, and King Lear Formation), Mississippian Chainman Shale, Devonian Pilot Shale, and Ordovician Vinnini shale. In addition to Tertiary prospects, some Paleozoic plays exist, which include the Mississippian Diamond Peak (Illipah, Scotty Wash) sandstone facies change to the east into the Chainman Shale, occurring in central Nevada east of the Antler orogeny. Structural prospects exist in the Basin and Range province, with potential Paleozoic reservoirs. In addition, reef prospects may be present in the Silurian and Devonian of Nevada. Continued exploration for both Tertiary and Paleozoic prospects should result in significant discoveries of oil and gas. End_of_Article - Last_Page 442------------

Developments in Four Corners-Intermountain Area in 1979

Exploratory drilling in the Four Corners-Intermountain area increased slightly in 1979 with 170 wells drilled. Forty-four of the wells were successfully completed for a success rate of 26%, up from 17.1% successes in 1978. Although drilling activity was down in Arizona, Nevada, and southwest Colorado, there were sharp increases in western New Mexico and Utah. Total exploratory footage drilled was down 11% in 1979, with 840,260 ft drilled in all exploratory categories. Development drilling decreased 5% from 1978, with 955 holes drilled, most of which were in the San Juan basin. The region's most significant discovery was again in the Overthrust belt of northern Utah, where Amoco's 1 Bountiful Livestock produced oil and gas from the Jurassic Nugget Sandstone. Two other wild at tests in the area reported significant shows. The large Pineview field in the Overthrust belt produced 3.9 MMBO and 4.4 BCFG in 1979. Seven oil and gas discoveries were made in the Uinta basin, and 2 significant oil discoveries were reported from the southern Paradox basin. Nevada's third oil field went on production in 1979 from Tertiary volcanic rocks. Six offshore wildcat wells drilled in Utah's Great Salt Lake by Amoco in 1979 have been temporarily abandoned. At least 2 of the wells had significant oil shows in Tertiary basalt. Exploratory and development drilling trends indicate that activity will remain high in the area for 1980.

Namorado Field, Major Oil Discovery in Campos Basin, Brazil: ABSTRACT

The Campos basin is located offshore the State of Rio de Janeiro, between parallels 21 and 23°S. In 1974, while drilling the ninth wildcat in the basin, Petrobras discovered the Garoupa oil field. This field was the first in a new and important oil province in one of the little explored Atlantic-type basins. Between 1974 and 1978, 10 other significant oil discoveries have been made, but most of these new fields are still in the process of either delimitation or early development. At present only the 20-sq km Namorado oil field has proved reserves (recoverable oil volume) of 250 million bbl. The Namorado oil field was discovered in 1975 by the 1-RJS-19 wildcat (22°27^primeS, 40°25^primeW) in 166 m of water. The prospect was located on a seismic structural high associated with an amplitude anomaly at the level of the Macae Formation (Albian carbonate rocks). In the interval between 2,980 and 3,080 m, the wildcat penetrated thick, oil-bearing sandstones interbedded with calcilutites in the upper part of the Macae Formation. In this well, an oil flow of about 6,000 bbl/day from the high-porosity (30%) and high-permeability (1 darcy) sandstone was estimated. From sedimentologic analysis, the reservoirs were classified as deep-water marine deposits (turbidites) associated with the first major transgression over the Albian carbonate shelf. From this model, the first assumption was of variable sand distribution and strong stratigraphic control of the oil accumulation, which is now confirmed. Today, six wells have been drilled in the field, some of them located by detailed interpretation of specially processed seismic data, such as synthetic acoustic impedance sections. This method proved to be very useful and accurate in mapping reservoir extension. The reservoir rock, the Namorado Sandstone, was the result of coalescent deep-water channels and fans over a rough depositional surface when the area was a relative low containing several turbidite layers. In some places, there are continuous clean sandstone bodies 100 m thick. As a result of active faulting during the Late Cretaceous and because of different compaction over the reservoir, the relative low became an elongate dome-shaped high, partly limited by faults. End_of_Article - Last_Page 412------------

Developments in West Coast Area in 1977

West Coast exploration accelerated in 1977, except in Washington where no wells were reported completed by year end. One significant oil discovery was made onshore in California on the west side of the San Joaquin Valley. Two additional discoveries were made offshore in the Santa Barbara Channel, 1 oil and 1 gas. These were reported by the media, but are not reflected in the CSD statistics. Additions to reserves in California outstripped production by 45 million bbl in 1977. Development activity increased in California and was concentrated in shallow drilling relating largely to steam-flood projects. Geothermal activity included the possible discovery of a new resource area in Inyo County, California. Development drilling continued at The Geysers and in Imperial Valley. The Geysers capacity will be raised to 908,000 kw over the next few years. Two 50-Mw plants are being planned for the Heber area in Imperial Valley.

Developments in West Coast Area in 1976

West Coast exploration continued at about the same pace as in 1975. The only exception was in Oregon, where no wells were drilled for oil or gas. No significant oil or gas discoveries were made in the California onshore. A major oil field may have been discovered in the southern California outer continental shelf. Geothermal development at The Geysers continued to expand the area of production. An additional 271,000 kw of generating capacity is under construction. When completed, generating capacity at The Geysers will be 773,000 kw.