Recent Oil Discoveries Research Articles

Hydrocarbon Segregation from Well Logs, Northern Monagas, Venezuela

A methodology is described to determine vertical hydrocarbon density variations in recent oil discoveries in Northern Monagas state, using well logs. Similarities and differences are established for models obtained in El Carito and El Tejero fault block-s. These models were confirmed using independent information, such as PVT analysis, RFT pressures, oil gravity and GOR's from initial production tests. To explain differences between the models, an hypothesis is proposed for the migration/segregation/deformation sequence in these two blocks, which accounts for the presence of lighter hydrocarbons in El Tejero block, even though it is 1700 ft structurally lower than El Carito. Based on this hypothesis, westward projection of the models predicts lighter hydrocarbons and similar porosities for Casupal-Mata Granda and Tonoro blocks, at depths considerably greater than in El Tejero block.

The Search for Subtle Stratigraphic Traps with High Resolution Seismic Data: Examples from the Powder River Basin, NE Wyoming, U.S.A.

Optimizing the temporal resolution of seismic data in both the acquisition and processing stages increases the detection rate of subtle, multiple stratigraphic traps in complex lithologic sequences. Field sizes ranging from 1 MMBO to 40 MMBO are found in the coastal facies of eolian sandstone reservoirs of the Permian Minnelusa Formation in northeast Wyoming, U.S.A. Generally, three main trap styles exist: (1) an erosional unconformity providing the top and lateral seals with a shoreline marine carbonate acting as the bottom seal; (2) marine carbonates providing both the top and bottom seals; and (3) topographic relief at the top of dune complexes that lack a bottom seal but are overlain by marine carbonates. Usable frequencies in excess of 100 Hz from depths greater than 3300 m allow resolution of 10 m sandstone reservoirs with 15?20% porosity. With this frequency it is possible to distinguish not only porous sandstone reservoir signatures, but also the trapping mechanisms involved. High resolution seismic data acquired prior to a recent oil discovery is shown here to demonstrate a successful methodology used to discover and develop Minnelusa oil in subtle stratigraphic traps. Successful exploration in coastal deposits such as the Minnelusa Formation requires an integrated approach to exploration. This includes broad band, high frequency seismic data acquisition and processing with a combined geological and geophysical interpretation. Using these techniques, discoveries are possible even in mature basins at exploratory drilling success rates well above the U.S. onshore industry average of 8?12%.

Regional Stratigraphy and Petroleum Potential, Ghadames Basin, Algeria

The Ghadames basin in east-central Algeria extends over 65,000 km{sup 2} (25,000 mi{sup 2}), of which 90% is covered by dunes of the eastern Erg. This intracratonic basin consists of up to 6000 m (20,000 ft) of dominantly clastic Paleozoic through Mesozoic strata. The Ghadames basin is part of a larger, composite basin complex (Ilizzi-Ghadames-Triassic basins) where Paleozoic strata have been truncated during a Hercynian erosional event and subsequently overlain by a northward-thickening wedge of Mesozoic sediments. Major reservoir rocks include Triassic sandstones that produce oil, gas, and condensate in the western Ghadames basin, Siluro-Devonian sandstones that produce mostly oil in the shallower Ilizzi basin to the south, and Cambro-Ordovician orthoquartzites that produce oil at Hassi Messaoud to the northwest. Organic shales of the Silurian and Middle-Upper Devonian are considered primary source rocks. Paleozoic shales and Triassic evaporite/red bed sequences act as seals for hydrocarbon accumulations. The central Ghadames basin is underexplored, with less than one wildcat well/1700 km{sup 2} (one well/420,000 ac). Recent Devonian and Triassic oil discoveries below 3500 m (11,500 ft) indicate that deep oil potential exists. Exploration to date has concentrated on structural traps. Subcrop and facies trends indicate that potential for giant stratigraphic or combinationmore » traps exists for both Siluro-Devonian and Triassic intervals. Modern seismic acquisition and processing techniques in high dune areas can be used to successfully identify critical unconformity-bound sequences with significant stratigraphic trap potential. Advances in seismic and drilling technology combined with creative exploration should result in major petroleum discoveries in the Ghadames basin.« less

Geological Controls on Oil and Gas Occurrence in Taranaki Basin, New Zealand

Taranaki basin contains all the commercial oil and gas fields in New Zealand as well as several marginal and subeconomic accumulations. The basin has a polyphase tectonic history, with different phases controlling specific aspects of hydrocarbon occurrence. Basin formation began with oblique rifting in the mid-Late Cretaceous. Principal petroleum source rocks are coal measures deposited in southern, central, and eastern parts of the basin during the rift and immediate postrift phase. In the Latest Cretaceous and early Cenozoic, the Taranaki basin was part of a western passive margin bordering proto-New Zealand, a large region of thinned continental crust separating from Australia and Antarctica. Clastic sediment supply to the basin progressively diminished as the sea transgressed the land to the south and east. Coastal and fluvial sandstones deposited during this phase are major petroleum reservoirs; a late Eocene turbidite reservoir in the north contains a noncommercial accumulation. In the mid-Cenozoic, the modern plate boundary began to propagate through New Zealand. In initial response, the Taranaki basin evolved into a submerged foreland basin. A recent significant oil discovery is reservoired in fractured limestones deposited in the foredeep. Taranaki basin Neogene development is characterized by structure reactivation, eversion, overthrusting, and differential subsidence alongmore » its eastern margin and in the south. Mountain building adjacent to the basin caused an increase in clastic sediment supply and concomitant regression, during which some minor reservoirs were deposited. However, the major significance of the Neogene tectonic phase lies in the formation of all proven traps, and in maturation of source rocks with increasing burial.« less

Cenomanian-Turonian Carbonate Reservoirs of Guerguett-El-Kihal, A New Discovery in the Southeast Constantine Basin, Algeria: ABSTRACT

Guerguett-el-Kihal is located on the marginal zone of the Saharian flexure in the Southeast Constantine basin. Recent discovery of oil in the carbonate reservoirs is of great importance to the explorationist in view of its depositional setting. With a net pay thickness of 115 m, the reservoirs have been considered Cenomanian-Turonian in age. Sedimentological studies have been done using well cuttings, cores, and the relevant data on this and adjacent wells. The Cenomanian reservoir that forms a major part of the Southeast Constantine basin is represented by biomicrites ranging from mudstone to packstone with peloidal structure. Planktonic and rarely benthic and agglutinated foraminifers, fragments of echinoderms, inocerams, oysters, and rudists represent the common faunal assemblages. Vertical and lateral lithologic variations in the sequence indicate that these carbonates may be attributed to rudistid reef-outer platform depositional belt. The Turonian carbonates, showing depositional textures similar to the Cenomanian, contain predominating planktonic foraminifers, caldispheres, filaments, and no rudistid. The carbonates might have been deposited in the outer platform belt. Results of the geochemical analyses show the presence of a number of layers capable of generating hydrocarbons in this stratigraphic sequence. The reservoir characteristics of these carbonates appear to be due mainly to interparticlemore » (matrix) porespaces and fractures. However, dissolution phenomena may be noted, and some layers show dolomitization with intercrystalline organic matter. This new discovery, along with those of the Djebel Onk in the Conaisian rudistic carbonates and Ras-Toumb in the Turonian rudistid dolomitized carbonates, make this basin very attractive for petroleum exploration.« less

Geological and Geophysical Evaluation of the Naricual Formation, Musipan-El Carito Area, Eastern Venezuela Basin: ABSTRACT

The recent giant oil discoveries in the lower Tertiary sedimentary sequence of the Monagas overthrust belt, Eastern Venezuela basin require short- and medium-term development plans based on technical production geological studies and models. The present study consists of a detailed geological and geophysical evaluation to define the reservoir in the producing Naricual Formation in the Musipan-El Carito areas, located west of El Furrial oil field. Due to its geological and reservoir characteristics, the northern Monagas area is considered as the top priority production alternative for the Venezuelan oil industry for the next 20 yr. The structural pattern of the area is related to major compressional stress applied northwest and from the northeast. Two fault systems are associated with this compression: (1) first-order, east-west-trending reverse faults dipping to the north, and (2) second-order, north-south-trending right-lateral strike-slip faults. The proposed sedimentological model is that of a paleodelta prograding from north to south. The depositional environment ranges from internal to continental shelf (barrier bars, tidal and distributary channels, lagoonal and associated facies). The STOIP in the Naricual Formation is 4.8 billion bbls, 52% of which is light-grade oil and 48% is medium-grade oil. The results of reservoir pressure analyses suggest lateral communication withinmore » the Naricual Formation between the Furrial and Musipan areas and give evidence of a permeability barrier between the Furrial-Musipan and El Carito areas. Depth vs. API gravity plots indicate a direct relationship between crude oil type and depth. The application of the results of the integrated reservoir studies gives precise answers to the production behavior of wells. An adjusted development plan is now under way to guarantee a rational, optimum recovery of the oil reserves.« less

Mesozoic Hydrocarbon Source Rock Studies of North Tarim, South Junggar, and Turpan Basins, Xinjiang Uygur Autonomous Region, Northwestern China: ABSTRACT

Ongoing outcrop and accompanying pyrolysis studies of Mesozoic strata of the north Tarim, south Junggar, and Turpan retroarc foreland basins, northwestern China, have demonstrated the existence of potential oil-prone and gas-prone petroleum source rocks. Lithologies include Jurassic coals from all three basins and Triassic coals from Tarim. Jurassic coals collected from the Mesozoic depocenters of the Junggar and Tarim basins are oil prone, yielding S/sub 2//S/sub 2+3/ values that range from 0.80 to 0.99 and average 0.96, hydrogen index (HI) values that range from 117.9 to 213.4 and average 150.8, and oxygen index (OI) values that range from 1.1 to 31.6 and average 7.67. In contrast, Triassic coals of Tarim and Jurassic coals of Turpan contain more conventional type III gas-prone kerogens and yield S/sub 2//S/sub 2+3/ values ranging from 0.04 to 0.52 and averaging 0.22, HI values ranging from 3.2 to 130.2 with a mean of 33.6, and OI values ranging from 30.9 to 223.7 and averaging 115.9. Coals of all three basins are slightly immature to mature with respect to oil generation, as indicated by T/sub max/ values ranging from 425/degrees/ to 449/degrees/C (average = 343/degrees/C) and vitrinite reflectance values ranging from 0.51 to 0.64 (average = 0.57).more » Thus, given the widespread abundance and significant thicknesses of Mesozoic and especially Jurassic coals in all three basins, it is very likely that Mesozoic contributions to Xinjiang's oil and gas reserves are significant. This is particularly important in the north Tarim basin, where recent Chinese oil and gas discoveries have been made and the existence of significant pre-Mesozoic source beds remains unproven.« less

The Talgeberry Birkhead Reservoir — A Seismic Stratigraphic Study

Recent oil discoveries in the Jurassic-Cretaceous Eromanga Basin of south-west Queensland have been in a variety of zones and many are believed to be controlled mainly by stratigraphic variations. Talgeberry-1 was completed as a dual zone oil producer from the Cretaceous Wyandra Sandstone and mid-Jurassic Birkhead Formation. An appraisal well, Talgeberry-2, drilled at a structurally higher location, did not intersect either of these reservoirs but was completed as a producer from the Early Cretaceous Murta Member. This paper presents a model for the Birkhead reservoir, which has been the most prolific producer to date. At Talgeberry-1 the Birkhead reservoir is interpreted as a fining upwards channel fill sand overlain by a coarsening upward distributary mouth bar sand. The channel fill, with good reservoir parameters, is believed to be the main producing sand. Log analysis and core data support this interpretation. The 10 m sand has a recognisable seismic signature which has been confirmed by modelling. Mapping of this signature has identified a channel approximately 600 m wide meandering from east to west. Structural mapping shows an updip location but it would have poorly developed reservoir sand and should be avoided. Further drilling for development or pressure maintenance should be within the mapped channel.

Mixing Zone and Deep Burial Diagenesis: Relevance to Reservoir Porosity and Oil Migration, Middle Jurassic Great Oolite Formation, Wealden Basin, England: ABSTRACT

The Middle Jurassic Great Oolite Limestone of the Wealden basin, southern England, is a target of active exploration owing to recent discoveries of oil, such as the Conoco No. 1 Storrington location. Throughout the basin, similar lithologies in the Great Oolite have porosities ranging from less than 5% to greater than 20%. Hence, the principal control on porosity is a diagenetic history. In the Storrington No. 1 production interval, the porosity is mainly primary. Cement, isotopic, and trace element stratigraphies of that interval indicate that primary porosity is preserved through early mineralogical stabilization of limestones in the mixing zone between freshwater and marine phreatic environments. At the nearby Southwater No. 1 location, studies of the same types of data show a similar early diagenetic history. Following mixing zone diagenesis, further subsidence resulted in deep burial diagenesis, principally the occlusion of porosity by coarse calcite spar. The deep burial origin of the spar is based on fluid inclusion data, which also indicate that uplift followed the precipitation of spar. The amount of uplift varies depending on basin location. Oil-filled fluid inclusions also occur in the spar, indicating oil was in a mobile phase at the time of cementation. Reconstruction of basinmore » structure and maturation modeling show that cementation-oil migration was in the Cretaceous. That, together with the distribution of oil-filled inclusions, indicate the primary areas of the basin where migration and accumulation of oil occurred.« less

Oil-Productive Miocene Algal and Sea Grass Carbonate Mudbanks, South Sumatra, Indonesia: ABSTRACT

Ramba and Tanjung Laban oil fields, located about 70 km northwest of Palembang in southern Sumatra, produce from wackestones and packstones in the lower Miocene Batu Raja Formation. Reservoir rocks are part of relatively small, undolomitized, low-relief carbonate buildups that accumulated on a widespread platform facies. Rocks in the platform facies are dominantly shaly nodular wackestones, whereas rocks in the buildup are dominantly nonshaly wackestones and packstones. The regional setting, the abundance of micrite in the buildups, the absence of both coralline algae and marine cements, and the geometry of the buildups suggest that noncalcareous algae and/or sea grasses were the dominant organisms responsible for forming these mudbanks. The absence of shale in the mudbanks has been important in forming the secondary porosity that yields most of the oil. Vugs and molds form as much as 30% of the rock in the best reservoir zones. Fractures formed by dissolution and collapse greatly enhance reservoir quality in many places. Another type of porosity, microintercrystalline, occurs within chalky micrites scattered through the upper part of the buildups. Porosity in these micrites reaches 25%, but permeability is very low. The recent discovery of oil in these low-energy carbonate mudbanks of the Batu Raja Formation has opened a new exploration play in the South Sumatra basin. Many similar buildups will likely be found as exploration continues and the basin's paleogeography becomes better understood. End_of_Article - Last_Page 280------------

Stromatoporoid-Algal-Facies Hydrocarbon Traps in Upper Devonian (Fammenian) Wabamun Group, North-Central Alberta, Canada: ABSTRACT

Recent oil and gas discoveries in the Upper Devonian (Fammenian) Wabamun Group of the Peace River arch area, north-central Alberta, have led to a reevaluation of stratigraphic and structural trapping mechanisms. These discoveries have occurred at a number of different intervals within the Wabamun. In the Tangent, Teepee, and Eaglesham areas, fractured and dolomitized mudstones, and grainstones produce hydrocarbons. At Normandville, however, fractured stromatoporoid-algal boundstones form the reservoir. Stromatoporoid-algal boundstones in the Wabamun Group have not been reported previously in this area. The stromatoporoids consist of predominantly massive and bulbous growth forms that created shoals and mounds in the Wabamun epeiric sea. Encrusting algae constitute an addi ional major component of the boundstone. Sparry-calcite cemented pelletal, skeletal, and oolitic grainstones form the surrounding matrix. Although Wabamun carbonates are predominantly well-cemented mudstones and grainstones, the reemergence of relatively primitive stromatoporoid forms in the Late Devonian, after the extinction of the numerous Frasnian stromatoporoid families, provides potential for an interesting new exploration target. End_of_Article - Last_Page 293------------

Oil and Gas Possibilities Onshore and Offshore Ghana: ABSTRACT

Nearly half of the total area of the Republic of Ghana is covered by sedimentary rocks. These rocks are found mainly in four different parts of the country: Tano basin, Keta basin, Voltaian basin, and the continental shelf. The possibilities of finding oil and gas onshore and offshore Ghana have thus been concentrated in these four areas. Because oil seeps in saturated superficial sands were found in the Tano basin, efforts to find oil in Ghana started as far back as 1896 in this basin, which is located at the extreme southwestern part of Ghana and has an area of 1,165 km2 (450 mi2). Seventeen onshore wells have been drilled so far in this basin, which is underlain by Upper Cretaceous Apollonian sediments consisting mainly of thin alternations of sand and clay with a few thin beds of gravel and fossiliferous limestone. The Keta basin, located at the extreme southeastern part of Ghana, has an area of 2,200 km2 (850 mi2). It is covered in the north by Pliocene and in the south by Holocene deposits. Since 1966, three onshore wells have been drilled in this basin. The continental shelf of Ghana is at the southern part of the country and has an area of 27,562 km2 (10,640 mi2). Prospecting for oil in the shelf started in 1968. In all, 34 offshore oil wells have been drilled by foreign companies in this area, which has been divided into 24 concession blocks. At present, oil is being produced from wells in Block 10. The possibility of finding oil and/or gas at the extreme western part of the continental shelf cannot be overemphasized. The expansive Voltaian sedimentary basin, located in the central part of Ghana, covers an area of about 103,600 km2 (40,000 mi2). The basin is underlain by Precambrian to lower Paleozoic epicontinental Voltaian series comprised of a thick sequence of marine and continental sediments. Although no trace of hydrocarbon was found in the only well that has been drilled so far in this basin, the presence of traces of bitumen in some parts of the basin indicates that, despite of its age, the basin might prove to be an oil province. The recent discovery of oil in the Ivory Coast means that it is possible to find oil or gas in Ghana, inasmuch as Ghana's petroleum potential is closely associated with that of the Ivory Coast basin, which extends for 560 km (300 mi) along the entire Ivory Coast and persists eastward into Ghana for an additional 320 km (200 mi), terminating in the area directly west of Accra. The Ghanian part of the Ivory Coast basin, therefore, holds the greatest possibility of finding oil or gas in Ghana. End_of_Article - Last_Page 1204------------

Reef‐reefing in Canada

The Calgary Petroleum Club is large and comfortable. It serves the normal functions of a business and social site, but it is much more than that. It is a place to bump into those in the know. It’s a news exchange which does brisk business whenever there is a new oil find in Western Canada. On those happy occasions, it hums with much reef‐reefing, a sound not unlike a crowd of actors rhubarb‐rhubarbing. It’s the sweetest music an explorationist knows — the sweetest sound of success. It may seem odd that reef‐reefing can be the conclusive diagnosis for a major discovery, but many commentators say that no other criterion works as well. Indeed, when rumors of a recent oil discovery are abroad, the club begins to sound like an opera chorus.

Beaufort Sea energy production and environmental protection

Exploration permits in the Beaufort Sea-Mackenzie Delta Region were issued to the petroleum industry by the Federal Government beginning in 1965. The purpose of these permits was to encourage exploration for hydrocarbons in this region. To retain the permits, industry was obliged to carry out a certain minimum level of exploration-related activity. Since that time, almost $ 2 billion has been spent on exploration. Drilling results to date, and particularly the recent oil discoveries at Kopanoar, Tarsiut, Issungnak and Koakoak has led the major operators to commence the design of systems to extract the hydrocarbons and deliver them to market. Permanent islands built of sand, concrete and steel in waters up to 200 feet deep will provide the offshore platforms for producing and processing the hydrocarbons. Initially oil will be of primary interest, with the plan being to transport it via Arctic icebreaker tankers and/or pipeline(s) to markets. As the demand for gas develops, it will also be transported to market, most likely by pipeline. A significant shorebase infrastructure complete with quarries, roads, harbours, airports, maintenance facilities and other services will be required to support the impending development. All of the foregoing activities must be carried out in an environmentally and socially responsible manner. The proposed developments are presently being examined under the auspices of Canada's Federal Environmental Assessment and Review Process. This process is assisting by involving the public in the early identification of the major environmental and socio-economic concerns respecting proposed developments. The outcome of this effort, along with more specific reviews to be conducted by the appropriate regulatory agencies, should ensure that the final developments which take place will conform to the high environmental protection and socio-economic standards expected by all Canadians and the international community.

Palo Duro Basin, An Exploration Frontier in the Texas Panhandle: ABSTRACT

Recent oil discoveries in the northwestern and central Palo Duro basin have renewed interest in this sparsely drilled area. Production in the northwest, in Oldham and Potter Counties, is from Pennsylvanian granite wash and carbonates. These fields are located in a highly faulted area south of the Amarillo uplift, and traps are structural. Discovery wells here produce oil at rates that range from 150 to 650 bbl per day. Oil production in the central basin, in Briscoe County, is from Pennsylvanian carbonate. The reservoir is probably a Strawn shelf-margin buildup or a debris flow into the basin from a younger Pennsylvanian shelf margin. The Palo Duro basin seems to contain potential reservoirs, traps, and source rocks; thermal maturity is probably the limiting factor for hydrocarbon production in the basin. The current geothermal gradient is relatively low, 1.1°F/100 ft (20°C/km), and it apparently has not been significantly different in the past. Vitrinite reflectance (Ro) measured in cores increases linearly with depth (temperature) by the relation: Ro = 0.00003 × depth (ft) + 0.36. Ro values seem to be in equilibrium with current depths and temperatures of the vitrinite. This suggests that (1) rocks in the basin are at or near their maximum burial depth, and (2) the geothermal gradient was not higher in the past. Shales of different ages that are at approximately the same depth have similar vitrinite reflectance values, an indication that increased time did not cause increased maturity in these Paleozoic samples. Deeply buried shales, 7,000 to 9,000 ft (213 to 2,743 m), from Pennsylvanian and Wolfcampian basin facies theoretically should have reached temperatures sufficient to generate hydrocarbons. Recent discoveries provide evidence that oil actually was generated in the Palo Duro basin. End_of_Article - Last_Page 454------------

Geology and Production History of Offshore Northwest Palawan, Philippines: ABSTRACT

The area of study is the continental shelf and rise off northwest Palawan and part of the southeastern margin of the South End_Page 982------------------------------ China Sea spreading center. A pre-Tertiary continental basement complex is separated from the accreted oceanic crust, outcropping on southern Palawan, by the Ulugan Bay fault, which is one of several north-south-trending strike-slip fault zones recognized in the area. A geologic section consisting, in the lower part, of limestones, volcanics and fine-grained clastics, ranging in age from pre-Tertiary to lower Oligocene, is encountered off northwest Palawan. This is unconformably overlain by the Nido Limestone and deep-marine shales of the Pagasa Formation (upper Oligocene to middle Miocene). The contact with the coarse clastic Matinloc Formation is an unconformity recognized on a regional scale and related to collision of the drifting margin with the remainder of the Philippine archipelago. The sequence is topped by the Carcar Limestone, described from many areas in the Philippines. A total of 30 wells have been drilled so far: 12 were dry, 10 were discoveries, 7 of which have been declared commercial, and 7 were delineation wells. Occurrence of hydrocarbons had been restricted to reef-related reservoirs of the Nido Limestone, until the recent discovery of oil in sandstone reservoirs in Galoc 1 heralded a new chapter in the Philippines search for hydrocarbons. Evaluation of the production performance from these reefs and analysis of the behavior of fractured limestones as reservoirs serves as a guide for future operations in the area. The future prospects of the northwest Palaway shelf and rise can be assessed from the current discovery success ratio in the exploration for reefs and from initial discoveries in turbidites. End_of_Article - Last_Page 983------------

Recent Regional Studies in Central Eromanga Basin Area in Southwestern Queensland, Australia: ABSTRACT

Interest in the petroleum potential of the central Eromanga basin area has been simulated by recent discoveries of oil and gas in the Eromanga and Cooper basin sequences in southwestern Queensland. The Bureau of Mineral Resources, in cooperation with the Geological Survey of Queensland, is assisting in petroleum exploration of this area by providing new regional information on the structural and depositional history of the Eromanga and underlying Cooper, Galilee, and Adavale basins. Several regional seismic reflection traverses up to 186 mi (300 km) long are being recorded over major structural features in the Eromanga basin, over the eastern margin of the Cooper basin, the southwestern Galilee basin, and the underlying Adavale basin. The seismic surveys are tied to existing seismic data to provide good quality structural and stratigraphic information. Seismic refraction, gravity, and magnetic, and magneto-telluric surveys are providing additional information on both sedimentary and basement structures; Landsat imagery studies are providing new perspectives on many regional features; and geochemical and source rock maturation studies are providing a basis on which a sound assessment of the petroleum prospectivity of the areas can be made. End_of_Article - Last_Page 977------------

HYDRODYNAMICS AND HYDROCARBON MIGRATION — A MODEL FOR THE EROMANGA BASIN

Recent oil discoveries in the Eromanga Basin in sediments ranging in age from Early Jurassic to Early Cretaceous provide strong evidence for an oil source within the basin.A recent study of the thermal history of Eromanga Basin sediments within the licence areas of Delhi Petroleum Pty Ltd and Santos Limited indicates that generation and primary migration of oil within the basin occurred within a period ranging approximately from late Cretaceous to Early Tertiary and that these events pre-dated the artesian system, which developed in Plio-Pleistocene times. Generation is believed to have occurred within deeper basin depocentres; migration toward the shallower marginal areas followed.The present artesian system is unlikely to have flushed oil out of existing traps. However, there is evidence that the artesian flow was stronger previously, and may have influenced secondary migration of oil. A mound spring has furnished evidence of possible migration to the western margin of the basin.

Geology and Bouguer gravity anomalies of the Gulf of Tonkin and vicinity

Outcrops of rock types around the Gulf of Tonkin range in age from Cambrian to Recent. The basement complex of the Gulf of Tonkin consists of Carboniferous carbonates and Lower Paleozoic metamorphic rocks. The Gulf of Tonkin and vicinity are comprised of three tectonic units: 1.(1) the Caledonian South China-North Vietnam Foldbelt,2.(2) the Variscan Southeastern Maritime Foldbelt and3.(3) the Indosinian Foldbelt of Vietnam. The Gulf of Tonkin subsided after the Cretaceous period. Up to 5 km of Tertiary sediments has accumulated in the Gulf of Tonkin. A distinct Bouguer gravity anomaly of +10 mgal is present in the middle of the Gulf of Tonkin and is also associated with shallow depth to Moho. Recent discovery of natural gas and oil in the Gulf of Tonkin may indicate major oil and gas fields.

A Model Study of Iceberg Scouring in the North Atlantic

A model has been developed to predict the maximum depth of iceberg scour in the north Atlantic Ocean. A prior knowledge of the environmental parameters: -such as the bathymetry, seabed properties, iceberg dimensions, and Ocean current data would be required to compute safe burial depth for blowout preventer stacks and pipelines. Introduction The seasonal presence of icebergs on the Canadian east coast is a potential threat to any possible production of offshore oil or gas. With the recent discovery of oil on the Grand Banks1 and promising results on the Labrador Shelf,2 solutions to the iceberg problem have to be found speedily before production can commence. Existing technology must be improved or new techniques devised for operations in these iceberg-infested waters. Atlantic icebergs appear in different shapes and usually weigh millions of tons. Underwater depths (drafts) as much as 500 ft (150 m) are common for such bergs. Conventional gravity or jacket-type production platforms are not likely to withstand a direct hit from a drifting iceberg unless protected by auxiliary structures3 or artificial islands. An iceberg drifting freely will tend to ground in the course of its travel when the bathymetry changes either gradually or abruptly, causing the water depth to be shallower than the draft of the berg. Bottom scours as deep as 21 ft (6.4 m) and as long as 9,850 ft (3 km) have been measured4 off the Newfoundland coast. Thus, buried offshore installations such as foundations and pipelines are susceptible to damage and are likely to be torn out by bottom-dragging and scouring icebergs unless buried sufficiently deep. Alternative production systems such as a floating rig in combination with various forms of subsea installations currently are being examined1 by the oil industry. A drillship likely to be in the path of a drifting iceberg can be moved off location by disconnecting the riser pipe. If the iceberg is large, the blowout preventer (BOP) stack itself could be knocked off or scoured out by the berg. Duval5 has reported that an iceberg forced the drillship Pelican to disconnect below the BOP stack during the 1973 drilling season. Even if safe methods are available to avoid a direct hit from an iceberg by moving the rig away from the collision course, gouging icebergs still would be a problem unless ocean-bottom structures are buried sufficiently deep. This paper describes a mathematical model and the associated laboratory tests for estimating iceberg scour depths. Methods of Estimating Scour Size It is believed that as many as 40,000 icebergs are produced6 yearly from the Greenland glaciers. They drift along the west Greenland and Baffin Island coasts (Fig. 1) and finally are caught in the Labrador current. In this process a large number of bergs are trapped in the bays and coastal indentations en route and grounded permanently. About 2,500 bergs are believed7 to cross the 60th parallel each year. A detailed description of the iceberg production, drift, and decay is given by Smith8 and reviewed by Chari.9