Journal articles on the topic 'Southeastern Discovery and exploration'

Up to recent years, major targets of oil and gas exploration in Cuu Long basin have been carried ort at structural traps in anticlines or basement highs in PreTertiary basement, Oligocene / Miocene clastics. As petroleum resources from reservoirs of traditional types become exhausted after many years of production (the remaining unexplored potential targets do not have sufficient reserves for development and production), exploration activities in Cuu Long basin have being focused in Oligocene stratigraphic/combination traps that have been discovered in recent years. Since the 1980s, petroleum explorers have identified oil in pinchouts trap in the Southeastern Cuu Long basin. However, these prospects have been evaluated to be of low potential due to be concerned of poor reservoir quality or incomplete petroleum system (lacking of source rocks or seals). Recent exploration activities in the region have identified several stratigraphic/ combination traps not only as pinch-outs but also as traps formed by appropriate facies changes. This article discusses types of stratigraphic traps that have been recently discovered in the studied area as well as exploration methods for predicting the distribution of these traps.

Since the early 2000s, southeastern Senegal has emerged as a premier gold exploration and mining frontier. At present, the Sabodala gold mine, owned by the Canadian company Teranga Gold, is the only operational gold mine and mill in Senegal. But two more open-pit gold operations are scheduled to open this year, and several other companies have announced discoveries of industrial-scale deposits. By documenting the shifting ownership and exploration of the Sabodala deposit, this article draws attention to how the protracted phase of mineral research shapes the political life of mining operations in Africa and elsewhere in the global South. Geological exploration in colonial and post-colonial Senegal, as in much of Africa, has relied heavily on the expertise of indigenous miners and smelters. Mining Sabodala has thus unearthed multi-vocal and contested histories of gold discovery. Historians of science have established that field assistants and experts in Africa have produced agronomic and medical knowledge typically credited to “the West.” By extending this argument to gold exploration, the article brings African history into dialogue with an emergent anthropology of subterranean knowledge production.

The excavation report covers eight months of fieldwork at the site of Ghazali, which resulted in the clearing of the entire monastery and the discovery of three annexes located on the north and west of the complex. The spiritual part of the monastery included two churches located in the southeastern corner of the complex, a household compound on the west side and a refectory and dormitory in between. Conservation work focused on the reconstruction and restoration of water storage installations in Room Y, as well as north of the North Church. Excavation outside the monastic walls brought the discovery of an iron smelting area with several well-preserved furnaces. Exploration of the monks’cemetery uncovered regular box superstructures and an intriguing variety of substructures from simple vertical pit tombs to elaborate vaulted chambers.

Since the discovery of business flow in volcanic rocks of Yingcheng formation, the deep volcanic rocks of Songliao basin have become another advantaged target for oil-gas exploration. To reproduce the the development process of oil-gas generation, migration and accumulation, accurately calculating the oil-gas accumulation time is a very important work. To minimize the error, we must seriously study the regional tectonic evolution history and recover the eroded thickness. According to the actual situation of the study area, trend method can be used to recover the top eroded thickness of volcanic rocks in Yingcheng formation. Finally we get the maximum eroded thickness in the basin is between 120 m to 240 m, located in the southeastern basin.

Exploration of poorly known regions of the Australian continental margin has resulted in the discovery of two new species in the scale worm family Eulepethidae. Grubeulepis kurnai sp. nov. occurs in southeastern Australia while Proeulepethus payungu sp. nov. was collected at one site in the Indian Ocean on the continental margin of Western Australia. Pareulepis malayana (Horst, 1913), also collected from the continental margin of Western Australia, is newly recorded from Australia, representing a range extension of that species previously known from Madagascar, Malaysia and the South China Sea. Four species, and four of the six known genera of Eulepethidae are now known from Australian waters. The family Eulepethidae remains species-poor compared with most polychaete families, and now comprises 21 species world wide.

ABSTRACT Grassroots exploration has led to discovery of 10 porphyry copper prospects in the previously unexplored Jurassic arc of southeastern Ecuador. The prospects are located in steep, wet, jungle-covered terrain in the Pangui area, part of the Cordillera del Cóndor. The exploration program, initially mounted in search of gold in the Oriente foreland basin, employed panned-concentrate drainage sampling. Follow-up of the resulting anomalies utilized soil sampling combined with rock-chip sampling and geologic mapping of the restricted creek outcrops. Scout and infill drilling of two of the prospects, San Carlos and Panantza, has shown hypogene mineralization averaging 0.5 to 0.7 percent Cu overlain by thin (averaging <30 m) zones of chalcocite enrichment or oxidized copper mineralization. The prospects are centered on small, composite granocliorite to monzogranite porphyry stocks that cut the Zamora batholith or, in one case, a satellite pluton. The batholith is emplaced into Jurassic volcanosedimentary formations, which concealed Triassic extensional half-grabens before being incorporated into the Subandean fold-thrust belt along the western margin of the Oriente basin. North- and northwest-striking normal faults in the hanging wall of a major north-striking fault zone controlled the locations of most of the porphyry centers. K silicate and variably overprinted intermediate argillic alteration, containing chalcopyrite as the principal sulfide mineral, characterize the central parts of most of the porphyry prospects and grade outward to pyrite-dominated propylitic halos. Overprinted sericitic alteration is generally less widely developed, although apparently shallower erosion at the Warintza and Wawame prospects resulted in preservation of extensive pyrite-rich sericitic zones. All the prospects contain appreciable (60–250 ppm) molybdenum, but gold tenors are low except at Panantza and Wawame (~0.15 and 0.2 g/t, respectively). Supergene oxidation and chalcocite enrichment zones are immature because of inhibition by the rapid erosion prevalent in the Pangui area. Supergene profiles attain their maximum development on ridge crests but are essentially absent along major creeks. Discovery of the Pangui belt, along with other recently defined porphyry copper systems in northern Perú, Indonesia, and the Philippines, underscores yet again the efficacy of drainage geochemistry as an exploration technique in tropical and subtropical arc terranes as well as the outstanding potential for additional exposed deposits in poorly explored parts of the circum-Pacific region.

Recent ROV (Remotely Operated Vehicle) exploration and bottom sampling in the southern Adriatic Sea (Apulian and Montenegrin margins) resulted in the discovery of cnidarian-rich deep-sea habitats in the depth range of ca. 400-700 m. In particular, ROV inspection of Montenegrin canyons reveals the existence of megabenthic communities dominated by a variety of cnidarians, including scleractinians (Madrepora oculata, Lophelia pertusa, Dendrophyllia cornigera), antipatharians (Leiopathes glaberrima) and gorgonians (Callogorgia verticillata) as major habitat forming taxa, often in association with sponges and, subordinately, serpulids. All such cnidarians are new records for the southeastern side of the Adriatic Sea. Our investigation indicates that an almost continuous belt of patchy cold water coral sites occurs along the entire southwestern margin (Apulian), basically connecting the Adriatic populations with those inhabiting the Ionian margin (Santa Maria di Leuca coral province).

The accidental discovery of a seventeen-pound gold nugget by a trio of adolescents in Cabarrus County, North Carolina in 1799 spurred a fitful gold rush that spread throughout the southeastern United States. From the early 1800s to 1849 the search for the precious metal fomented exploration and various industries along the gold-bearing regions of the Piedmont and eastern Appalachian Mountains from Alabama to Maryland. The focus of the nascent gold industry was off-season, haphazard placer mining by individuals and small family groups who used primitive medieval mining techniques and backbreaking physical labor. By the 1820s, the part-time, untrained farmers, slaves, and "boomers" had depleted the easily found nuggets and lodes in the "branch" streams. New techniques and innovations in machinery were developed by a set of diverse, yet interconnected, events and individuals to bring forth the golden metal. Thus, the gold fields of the Southeastern United States were a proving ground for the placer mining techniques and technology that fostered economic and industrial expansion in the agriculturally dominated region, as well as substantially contributing to the wealth of the new nation. This fifty-year period of placer mining innovation and practical application in the Southern gold fields provided the skills and basic equipment that promoted the whirlwind of mining frenzy that was the 1849 California Gold Rush.

Recent exploration of the foothills of the Cordillera del Cóndor, southeastern Ecuador, led to the discovery of an unknown species of Sarcoglottis, and subsequent study in Peruvian herbaria permitted to record it in Peru. Here we describe it as Sarcoglottis neillii and provide a detailed drawing and color photographs taken from live plants. We compare its morphology with that of similar members of Sarcoglottis and conduct a preliminary assessment of its conservation status. Sarcoglottis neillii belongs to a small group of species including S. metallica, S. maroaënsis and S. stergiosii, differing from the former two species in leaf coloration and from the latter in flower size and labellum morphology. The single known Ecuadorian location of S. neillii was destroyed by extensive open pit-mining activities, but the several records from Peru suggest that the species is widespread; three locations occur within the Yanachaga-Chemillén National Park, but information on its actual range and potential threats is lacking and we suggest for it the category of Data Deficient (DD) until further field studies permit a better-informed assessment of its risk status.

It is now 39 years since the first gas was discovered in Bass Strait’s Gippsland Basin. Advances in exploration and production technology mean that today Australia’s longest producing offshore basin is also one of Australia’s most prospective. Gippsland is now producing around 160,000 barrels of crude and 570 million cubic feet of gas per day. To date it has produced more than 3.5 billion barrels of oil and 5 trillion cubic feet of gas and the value of the infrastructure in place is estimated to be around A$16 billion.Australia’s evolving energy market means that gas demand continues to grow. Following the re-structuring of energy markets in southeastern Australia and the installation of new pipeline infrastructure, Gippsland gas now flows to Victoria, NSW, Tasmania and will supply into South Australia from 2004. To meet this growing demand the Esso/BHPBilliton joint venture partners are investing heavily and utilising a vast array of 3D exploration technology to unlock new opportunities. In 2002 they conducted the largest 3D survey ever undertaken in Bass Strait and expect to conduct another in early 2003. A program of exploration drilling is expected to commence in late 2003. With expanded market opportunities and a gas resource base of more than 5 trillion cubic feet, the future looks bright for Gippsland.

Origin Energy Resources Limited has been an active explorer of the onshore Otway Basin in southeastern Australia for over a decade. Since 1989, the company has acquired 1,893 km and 358 sq km of 2D and 3D seismic data respectively, and participated in the drilling of 21 exploration and appraisal wells, 18 of which it operated, at a net cost of over $25 million.The primary exploration targets have been fluvial sandstones developed axially in a series of elongate half grabens that formed in initial response to the separation of the continents of Australia and Antarctica in the Late Jurassic to Early Cretaceous. The most significant of these depocentres, in terms of established hydrocarbon potential, is the highly faulted, NW–SE trending Penola Trough where these reservoirs are informally referred to as the Sawpit Sandstone and the Pretty Hill Sandstone.As the company’s geological understanding of the Penola Trough improved over time, so its exploration efforts were rewarded with new commercial discoveries at Haselgrove, Haselgrove South and Redman, and through successful appraisal of Ladbroke Grove. With respect to the application of advanced technology, 2D and 3D seismic are now subjected to Prestack Depth Migration to improve imaging of the subsurface, and Amplitude Versus Offset, Seismic Variance, Seismic Attribute, Fault Analysis and 3D Visualisation processing and/or software are also used in an integrated manner to facilitate interpretation of these data sets. Nuclear magnetic resonance logs are run in most wells to characterise gas-bearing reservoirs.Technology, respect and persistence have all played key roles in optimising the exploration process. So too have corporate teamwork and collaborative research with representatives from academic institutions and government agencies, and with industry consultants and contractors. The complex interplay between many of these success factors is illustrated by way of a case history, specifically that of the discovery and commercialisation of a low quality gas resource at Ladbroke Grove.In the fullness of time, the company is confident that further exploration success in the onshore Otway Basin will see new market opportunities addressed in terms of both gas and electricity supply. It is also hopeful that oil will eventually be found in commercial quantities.

The Great American Biotic Interchange is considered to be a punctuated process, primarily occurring during four major pulses that began approximately 2.5 Ma. Central America and southeastern Mexico have a poor fossil record of this dynamic faunal history due to tropical climates. Exploration of submerged caves in the Yucatán, particularly the natural trap Hoyo Negro, is exposing a rich and remarkably well-preserved late Pleistocene fauna. Radiometric dates on megafauna range from approximately 38 400–12 850 cal BP, and extinct species include the ursid Arctotherium wingei and canid Protocyon troglodytes . Both genera were previously thought to be indigenous to and confined to South America and appear to represent an instance of large placental mammals, descended from North American progenitors, migrating back north across the Panama Isthmus. This discovery expands the distribution of these carnivorans greater than 2000 km outside South America. Their presence along with a diverse sloth assemblage suggests a more complex history of these organisms in Middle America. We suggest that landscape and ecological changes caused by latest Pleistocene glaciation supported an interchange pulse that included A. wingei , P. troglodytes and Homo sapiens .

As part of ongoing efforts to understand, document, and conserve the flora of southeastern North America, we propose two new species, the recognition of a usually synonymized variety, the acceptance of two species of Waltheria as being present in peninsular Florida, taxonomic acceptance of a sometimes deprecated species transferred with a new name into a different genus, and we clarify the distribution and ecology of a species. In Carex (Cyperaceae), we re-analyze infrataxa in Carex intumescens and recommend the recognition of two varieties, a taxonomic schema first proposed in 1893, but usually not followed in the 128 years since. In Euphorbia (Euphorbiaceae), a careful assessment of south Florida material of Euphorbia subg. Chamaesyce sect. Anisophyllum subsect. Hypericifoliae reveals the need for taxonomic changes to best classify endemic representatives of this group, resulting in the naming of a new species, and a new name at species rank in Euphorbia for a taxon first named in Chamaesyce and sometimes subsequently treated at only varietal rank in Euphorbia. Chamaecrista deeringiana (Fabaceae, subfamily Caesalpinioideae) has been repeatedly misinterpreted to include two different and disjunct population systems with differing morphologies and habitats, which are here interpreted as separate species, one newly named and the other Chamaecrista deeringiana returned to its original and narrower interpretation as a south Florida endemic. Waltheria (Malvaceae) has sometimes been interpreted as being represented in Florida by a single taxon, Waltheria indica, but we disentangle the concepts of the widespread W. indica and the West Indian W. bahamensis and clarify that both are present in the southeastern United States. We reconsider the occurrence and habitat of Toxicoscordion nuttallii (Melanthiaceae) in three states in which it has been reported as a rare species, Mississippi, Missouri, and Louisiana, and remove it from the Mississippi flora as a garbled and false report. In Louisiana, its occurrence in calcareous prairie complexes limits its potential occurrence in the state to a specialized and rare habitat, but careful exploration of habitat remnants may result in the discovery of additional populations. Taxonomic studies and re-assessments of this kind are critical in laying the best scientific foundation for regulatory, policy, and land conservation decisions. This paper names or makes the case for the renewed acceptance of six species with range-wide conservation concern: one Critically Imperiled (G1 – Euphorbia ogdenii), one Imperiled (G2 – E. hammeri), and four Vulnerable (G3 – E. garberi, E. porteriana, Chamaecrista deeringiana, C. horizontalis).

Exploratory work for hydrocarbons along the southeastern Brazilian Margin discovered high concentrations of CO2 in several fields, setting scientific challenges to understand these accumulations. Despite significant progress in understanding the consequences of high CO2 in these reservoirs, the role of several variables that may control such accumulations of CO2 is still unclear. For example, significant differences in the percentages of CO2 have been found in reservoirs of otherwise similar prospects lying close to each other. In this paper, we present a hypothesis on how the rifting geodynamics are related to these CO2-rich accumulations. CO2-rich mantle material may be intruded into the upper crustal levels through hyper-stretched continental crust during rifting. Gravimetric and magnetic potential methods were used to identify major intrusive bodies, crustal thinning and other geotectonic elements of the southeastern Brazilian Margin. Modeling based on magnetic, gravity, and seismic data suggests a major intrusive magmatic body just below the reservoir where a high CO2 accumulation was found. Small faults connecting this magmatic body with the sedimentary section could be the fairway for the magmatic sourced gas rise to reservoirs. Mapping and understanding the crustal structure of sedimentary basins are shown to be important steps for “de-risking” the exploration process.

This article presents the results of petrographic studies into collections of artifacts from the Acheulean complexes located in the Darvagchai Geoarchaeological District in Southeastern Dagestan. Throughout the entire Stone Age, raw stone was a crucial resource for subsistence of ancient humans. The lack of high-quality flint raw materials had been previously considered to be the main factor for concluding that this area was rarely visited by ancient humans. Archaeological research over the past decade has shown the opposite. During the exploration works, over ten Paleolithic sites were discovered and studied. Analysis of raw material sources has revealed that there are several main types of rocks in the area of the sites. The petrographic composition of the collections indicates that the overwhelming majority of artifacts were made of flint, while sporadic artifacts were made of limestone and sandstone. Flint raw materials which were used at the sites are distinguished by large number of internal defects, primarily, fracturing. The raw material factor played a very important role in the area. All large, carefully shaped macro-tools were made of sandstone and limestone, while mostly poorly shaped small artifacts were made of flint. Thus, sizes, methods, and intensity of processing stone tools demonstrate direct dependence on the type of raw material.

A record level of offshore exploration activity was achieved during 1998, despite a significant fall in the oil price. Seventyfour offshore wells were drilled, far exceeding the previous record of 64 wells achieved in 1990. Conversely, only 94 onshore exploration wells were drilled during the year, 25 fewer than in 1997, resulting in a slight reduction in the total exploration wells drilled from 176 in 1997 to 168 in 1998, following what had been a steady increase since 1992. Seismic acquisition in 1998 was also at a record level, twice that recorded in 1997. In contrast, the final quarter of 1998 may reflect the reduced activity forecast by industry, with less exploration wells spudded and almost 10,000 line-km fewer than that shot during the 1997 December quarter.This increased offshore exploration activity was rewarded with several discoveries and appraisal successes. The Carnarvon Basin was again the most successful area for offshore exploration in 1998, with 35 wells spudded during the year. The discoveries included Gipsy–1, Rose–1, Lee–1, John Brookes–1, Vincent–1, Caribou–1, Legendre South–1 and Mutineer–IB. In addition, significant successful appraisal drilling included two Gorgon wells, Egret–2, Dockrell–2 and Woollybutt–2A ST1.The Cooper/Eromanga Basin continued to be the focus of onshore exploration in Australia. Fifty-two exploration wells were spudded during the year. Discoveries were heavily weighted toward gas, with only one oil discovery in the basin, Chilla–1. The most significant gas discoveries included Verona–1 and Cabernet–1.Other important oil and gas discoveries and appraisal successes occurred in the Bonaparte Basin, at Sunset West–1, Sunrise–2 and Evans Shoal–2; in the Browse Basin, at Caspar–IA and two of the Cornea wells; in the Otway Basin, at Killanoola–l/DWl; in the Bass Basin, at White Ibis–1; in the Bowen Basin, at Yandina–2; and in the Surat Basin, at Digger–1 and West Noorindoo–1. Three significant appraisal wells were drilled in Papua New Guinea during 1998: Hides–4 proved continuity of the Hides Field over a distance of 12.6 km, Moran–4X extended the Moran Field to the northwest and Moran- 5X constrained the southeastern extent of the field. There were also significant discoveries in two New Zealand basins and these are covered in greater detail in Plume (1999).The lower oil price presents a challenge for the industry to maintain these high levels of exploration activity. New technology and better data quality have allowed re- interpretation of previously uneconomic or sub- commercial discoveries to successfully confirm the existence of economic fields. Several of the recent commercial discoveries followed up uncommercial discoveries drilled as much as 30 years earlier and have highlighted the fact that potential still exists in these areas. Improved subsurface imaging through 3D seismic acquisition, high-resolution processing, pre-stack depth migration and advanced time-to-depth conversion together with improved geological understanding has contributed to many of the successful wells drilled in 1998.

The Yidun arc, located in the southeastern Tibetan Plateau, was formed by the westward subduction of the Ganze-Litang Paleo-Tethys ocean in Late Triassic. It is well-known for the formation of numerous Mesozoic porphyry-skarn Cu-Mo-(Au) deposits in the arc. To date, more than 20 Cu-Mo-(Au) deposits (>10 million tonnes Cu resources) have been discovered in the southern Eastern Yidun arc. However, few Cu-Mo deposits have been discovered in the northern Eastern Yidun arc. In recent years, some Cu-Mo deposits or occurrence are successively discovered in the northern Eastern Yidun arc, but their ore-forming ages are not well constrained. It remains unclear whether such Cu-Mo mineralization formed by similar metallogenic event and geodynamic setting as the Cu-Mo-(Au) mineralization in the south. In order to determine the metallogenic age and shed light on potential links between Cu-Mo mineralization and regional magmatic events, we present molybdenite Re-Os and zircon U-Pb ages to constrain the timing of two types of Cu-Mo mineralization in the northern Eastern Yidun arc (type I and type II). Molybdenite ICP-MS Re-Os dating results show that type I mineralization was formed at 217.7 ± 3.6 Ma, which is highly consistent with the formation ages of the host granite (218.1 ± 1.5 Ma, 2σ, n = 15, MSWD = 0.92) and aplite dyke (217.3 ± 1.3 Ma, 2σ, n = 16, MSWD = 0.50) within error. While the type II mineralization has a relatively younger formation age of 211.8 ± 4.7 Ma than the host granite (217.1 ± 1.5 Ma, 2σ, n = 14, MSWD = 0.96) and type I Cu-Mo mineralization. These data indicate that the Cu-Mo mineralization in the northern Eastern Yidun arc was temporally and spatially related to the Late Triassic magmatism in the region. Rhenium (Re) concentrations in the molybdenite from type I mineralization, ranging from 12.77 to 111.1 ppm (typically > 100 ppm), indicate that the ore-forming metals were derived mainly from a mantle source. However, Re contents in molybdenite from the type II mineralization, ranging from 7.983 to 10.40 ppm, indicate that the ore-forming metals were derived from a mixed mantle and crustal source with a predominantly crustal component. This study confirms that the northern Eastern Yidun arc exists Late Triassic Cu-Mo metallogenesis, and thus much attention should be paid on this region to find more Late Triassic Cu-Mo resources.

AbstractThe Dunbar, Ellon and Grant oil and gas fields (also known as the Alwyn South area) are located in the southeastern part of the East Shetland Basin, approximately 140 km E of the Shetland Islands. Most of the accumulations lie in Blocks 3/9, 3/14 and 3/15, which are parts of Licence P090 operated by Total Oil Marine pic (33.33%) with Elf Exploration UK PLC as sole partner (66.67%). Ellon was discovered in 1972, Dunbar in 1973 and Grant in 1977. Dunbar consists of a number of generally N-S trending, westerly dipping Mesozoic fault blocks with variable amounts of crestal erosion. Reservoir is provided by fluvial, deltaic and shallow marine sandstones of the Middle Jurassic Brent Group, Lower Jurassic Statfjord Formation and Upper Triassic Upper Lunde Formation. The Brent oil composition of Dunbar varies with depth and evolves from volatile oil at the base of the column to gas condensate at the top without a discontinuity of composition. In addition there is a small gas accumulation within a Paleocene submarine fan reservoir in a compactional structure.Ellon consists of two westerly dipping fault blocks with gas condensate contained within the Brent Group. Grant is one westerly dipping fault block with gas condensate in the Brent Group. In both the Ellon panels and also in Grant, thin waxy oil 'rims' are found below the gas. The depth of the shallowest structural crest within the Alwyn South complex is 3100 m TVDSS, with the deepest proven hydrocarbon at around 3800 m TVDSS. Sealing for the Alwyn South accumulations is provided by various combinations of Cretaceous, Upper Jurassic (Heather and Kimmeridge Clay Formations) and Lower Jurassic (Dunlin Group) mudstones. The source rock for the hydrocarbons is the Upper Jurassic Kimmeridge Clay Formation, which is mature and adjacent to the fields.These accumulations are being developed from a tender-assisted minimally manned fixed platform with a total of 28 well slots located over the Dunbar Field, in a water depth of 145 m. The Ellon and Grant Fields are produced as sub-sea satellites to Dunbar from a well-head cluster located between Ellon and Grant, in a water depth of 135 m. First oil and gas production from Dunbar and Ellon was in December 1994 and gas production commenced from Grant in July 1998. The time lag between discovery and development reflects the complex geology (structure, compartmentalization, reservoir thickness variations, dia-genesis and differing hydrocarbon compositions) with a total of 28 exploration and appraisal wells being drilled in the Alwyn South area between 1971 and 1998. Total oil and gas initially in place is in the order of 850 MMBBL and 2.62 TCF respectively, with the current estimate for ultimate recoverable reserves being 200 MMBBL liquids and 1.28 TCF gas.

Basement exploration in India has seen increased interest after the recent discovery of a field in the Cauvery Basin in southeastern India, with an average individual well production of 700 b/d from a fractured basement reservoir. The field is presently under development, with several development well locations identified for drilling. Optimized development of a fractured basement reservoir requires identification of areas with a permeable fracture network. To meet this objective, we adopted a comprehensive integrated workflow involving the use of common reflection angle migrated seismic data, fracture modeling, a 1D mechanical earth model (MEM), identification of critically stressed fractures in 3D space, fracture permeability/connectivity analysis, and sweet spot identification. The workflow yielded a robust discrete fracture network model based on 3D directional fracture intensity, a 1D MEM that gave regional stress gradients (pore pressure, overburden, Shmin, and SHmax), and rock strength and elastic properties. In addition, we generated a critically stressed 3D fracture model and performed sequential stratal surface restoration for predictive strain modeling that was calibrated at wells. Our fracture permeability and connectivity analysis showed that existing hydrocarbon-producing wells are located within areas that have a fracture cluster/swarm with associated good fracture connectivity. A 3D basement facies model constructed by integrating well data and a poststack inversion impedance volume showed that major flow zones occur in weathered basement associated with low impedance. This model, in combination with fracture intensity data, provides good indication of the location of basement sweet spots in the Cauvery Basin. The understanding gained on the controls of occurrence of basement fractures explains why some wells in the field are producers and others are dry. This led to greater confidence in optimizing the locations of previously proposed new development wells.

Many of the commercial hydrocarbon accumulations discovered to date within the Pretty Hill Formation in the onshore Otway Basin of southeastern Australia rely on a semi-brittle top seal and fault seal. Therefore a detailed and integrated fault, stress field and fracture analysis is fundamental to prospect evaluation.A syn-kinematic interpretation of the 3D seismic data set, using variance cube and visualisation technology was augmented with interpretation of the dip-meter and high-resolution borehole images. This resulted in the interpretation of a more complex fault history than previously inferred from 2D seismic mapping and dipmeter analysis alone.There are two major prospect/field bounding fault sets within the Penola Trough. Northwest-trending faults are associated with two commercial fields and several palaeo-accumulations. East-west trending faults are associated with three major fields, two uneconomic fields and two possible palaeo accumulations.Hydrocarbon leakage is probably caused by the creation of structural permeability across the regional seal. The location of leakage depends on the interaction between the seal, associated faults, and the regional stress field. Faults deflect regional stress trajectories within the top seal, creating local areas of high differential stress which enables brittle failure and the development of structural permeability. Predicting stress trajectories, the magnitude of differential stress and thus the location of structural permeability within the top seal to the underlying Pretty Hill Formation reservoirs, will reduce exploration risk uncertainty.

The research of an analysis of aeromagnetic data collected in the middle Benue Trough in north-central Nigeria is presented. A detailed analysis of basement structures is conducted in order to identify regions with high hydrocarbon potential that is different from those discovered by earlier researchers. Aeromagnetic data were filtered by using the Butterworth and Gaussian filters, transformed by engaging the reduction to the equator technique, and subsequently enhanced. To estimate magnetic basement depths at various places throughout the basin, the Euler deconvolution depth weighting approach was used. Eleven (11) sub-basins with depths ranging from –2000 m to –8000 m were also identified by Euler’s findings. The sub-basins trend in the NE-SW direction while the average sediment thickness is found to be more than 3 km. The extracted structural features indicate areas like Kadi Blam and Kado areas in the southeastern part and Ogoja and Obudu in the southern part of the study area as regions with high structural densities. These areas coincide with the areas delineated as the sub-basins. The cross-sections generated reveal depressions caused by the action of some tectonic activities in the area. This study identified undulating basement topography believed to be due to tectonic activities as well as five areas that are possible targets for hydrocarbon exploration.

Aside from the recorded travels of Juan de Rivera in 1765 and the Dominguez-Escalante party in 1776, the earliest reports involving explorations into Utah were mostly those for proposed railroad lines and trade routes, or for general knowledge of the poorly known Western Territories (1840s to 1870s). These explorations were usually conducted under the auspices of the United States Army. Scientists, including geologists/paleontologists, commonly accompanied the survey parties. The first surveys whose prime objectives were to study geology and topography were commissioned by Congress in 1867. The earliest discovery of a vertebrate fossil in Utah apparently took place on the J. N. Macomb expedition of 1859 (which generally followed the Old Spanish Trail), when J. S. Newberry collected dinosaur bones in the southeastern part of the state. F. V. Hayden's 1870 survey may have extended into northernmost Utah. It is possible that a few of the Eocene age fossils which were reported by him from southernmost Wyoming, came from here. Fossils collected during the Hayden survey prompted a vertebrate fossil collecting trip headed by J. Leidy into the same area two years later. Also in 1870, O. C. Marsh discovered and named the Uinta Basin, making a significant fossil vertebrate collection there. Numerous Eocene mammals as well as reptiles and fish were collected in the Basin proper, while a turtle shell and dinosaur teeth were recovered from the upturned Mesozoic beds on the eastern rim of the Uinta Basin. A Jurassic crocodile humerus was found by Marsh along the eastern flank of the Uinta Mountains. In subsequent years before the turn of the century several institutions sent paleontological parties into this area. E. D. Cope in 1880 identified fossil fish and a crocodile from Eocene deposits of central Utah. Pleistocene mammals were first reported by P. A. Chadbourne (1871) and C. King (1878) from Salt Lake and Utah valleys. While early expeditions for vertebrate fossils concentrated largely on adjacent states, many of America's prominent 19th Century vertebrate paleontologists collected fossils in Utah. Their work pioneered the way for present-day paleontologists.

The Stag Oilfield is located approximately 65 km northwest of Dampier and 25 km southwest of the Wandoo Oilfield near the southeastern margin of the Dampier Sub-basin, on the North West Shelf of Western Australia,.The Stag-1 discovery well was funded by Apache Energy Ltd (formerly Hadson Energy Ltd), Santos Ltd and Globex Far East in June 1993 under a farmin agreement with BHP Petroleum Pty Ltd, Norcen International Ltd and Phillips Australian Oil Co. The well intersected a gross oil column of 15.5 m within the Lower Cretaceous M. australis Sandstone. The oil column intersected at Stag-1 was thicker than the pre-drill mapped structural closure.A 3D seismic survey was acquired over the Stag area in November 1993 to define the size and extent of the accumulation. Following processing and interpretation of the data, an exploration and appraisal program was undertaken. The appraisal wells confirmed that the oil column exceeds mapped structural closure and that there is a stratigraphic component to the trapping mechanism. Two of the appraisal wells were tested; Stag-2 flowed 1050 BOPD from a 5 m vertical section and Stag-6 flowed at 6300 BOPD on pump from a 1030 m horizontal section.Evaluation of the well data indicates the M. australis Sandstone at the Stag Oilfield is genetically related to the reservoir section at the Wandoo Oilfield. The reservoir consists of bioturbated glauconitic subarkose and is interpreted to represent deposition that occurred on a quiescent broad marine shelf. Quantitative evaluation of the oil-in-place has been hampered by the effects of glauconite on wireline log, routine and special core analysis data. Petrophysical evaluation indicates that core porosities and water saturations derived from capillary pressure measurements more closely match total porosity and total water saturation than effective porosity and effective water saturation.A development plan is currently being prepared and additional appraisal drilling in the field is expected.

The aim of this article is to present considerations on the technological and functional aspects of flint tools produced by the community of the Globular Amphora culture. These reflections are based on discoveries made in a box grave from site No. 33 in Stefankowice-Kolonia (southeastern Poland). During the exploration of the funerary feature, a skeleton was found. It belonged to a man in the Maturus age. The body was accompanied by an abundant set of flint products composed of five blades and three axes (including one half-product). These artefacts were subjected to a technological analysis aimed at determining the techniques employed in the production of the blades and core tools. The analysis was complemented with microscopic examination performed in order to determine the functions of the discovered products. As a result, it was stated that the grave had been furnished with a collection of blades and an axe half-product that probably had never been used. This was not the case for the other two axes. On one of them, there were patterns indicating that it had been used for a long time to process wood. The patterns found on the other one were the result of hafting only. This fact is interesting, since there are no traces of use damage on the cutting edge. It appears that this artefact was abraded (sharpened anew) before being deposited in the grave.

Eni Starts Area 1 Production off Mexico via MODEC FPSO MODEC said first oil has flowed through FPSO MIAMTE MV34 operating in the Offshore Area 1 block in the Bay of Campeche off Mexico. The contractor was appointed by Eni Mexico for the supply, charter, and operation of the FPSO in the Eni-operated Offshore Area 1 block in 2018. The charter contract will run for an initial 15 years, with options for extension every year thereafter up to 5 additional years. Moored in a water depth of approximately 32 m some 10 km off Mexico’s coast, the FPSO is capable of handling 90,000 B/D of oil, 75 MMcf/D of gas, and 120,000 B/D of water injection with a storage capacity of 700,000 bbl of oil. The FPSO boasts a disconnectable tower yoke mooring system, a first-of-its-kind design in the industry. The system was developed to moor the FPSO in shallow water, while also allowing the unit to disconnect its mooring and depart the area to avoid winter storms and hurricanes in the Gulf of Mexico. The mooring system was developed by MODEC subsidiary SOFEC Inc. The mooring jacket was fabricated in Altamira, Mexico. Eni Starts Production from Ndungu EP Development Italy’s Eni has started production from the Ndungu Early Production (EP) development in Block 15/06 of the Angolan deep offshore, via the Ngoma FPSO. With an expected production rate in the range of 20,000 B/D, the project will sustain the plateau of the Ngoma, a 100,000-B/D, zero-discharge, and zero-process-flaring FPSO, upgraded in 2021 to minimize emissions. A further exploration and delineation campaign will be performed in Q2 2022 to assess the full potential of the overall assets of Ndungu. Ndungu EP is the third startup achieved by Eni Angola in Block 15/06 in the past 7 months, after Cuica Early Production and the Cabaca North Development Project. Block 15/06 is operated by Eni Angola with a 36.84% share. Sonangol Pesquisa e Produção (36.84%) and SSI Fifteen Ltd. (26.32%) comprise the rest of the joint venture. Aramco Discovers Natural Gas in Four Regions Saudi Aramco has discovered natural gas fields in four regions of the kingdom, the Saudi Press Agency (SPA) reported, citing Energy Minister Prince Abdulaziz bin Salman. The fields were found in the Empty Quarter desert located in the central area of the kingdom, near its northern border and in the eastern region, he said, according to SPA. Saudi Arabia wants to increase gas production and boost the share of natural gas in its energy mix to meet growing electricity consumption and to make more crude available for export. The minister said an unspecified number of fields were discovered and he mentioned five by name: Shadoon, in the central region; Shehab and Shurfa, in the Empty Quarter in the southeastern region; Umm Khansar, near the northern border with Iraq; and Samna in the eastern region. Two of the gas fields, Samna and Umm Khansar, were said to be “nonconventional” and possibly shale finds. Lukoil Completes Area 4 Deal in Mexico Russian producer Lukoil has completed a deal to become a lead stakeholder in an Area 4 shallow-water asset adjacent to Tabasco and Campeche in Mexico. Under the deal, Lukoil has acquired a 50% stake in the asset from US independent Fieldwood Energy, which filed for US bankruptcy protection in August 2020, for $685 million. The original deal was priced at $435 million; the additional $250 million is related to expenditures Fieldwood incurred since 1 January 2021. Fieldwood committed to invest $477 million to increase oil production from the Ichalkil and Pokoch fields from the current level of 25,000 B/D to a plateau level of 115,000 B/D. Situated in water depths between 35 and 45 m, the fields’ recoverable hydrocarbon reserves amount to 564 million BOE, more than 80% of which is crude oil. Production started in Q4 2021; current average oil production has exceeded 25,000 B/D. The approved work program includes drilling three development wells (two on Ichalkil and one on Pokoch), upgrading three production platforms, and performing seismic reprocessing and petrophysical studies. The remaining 50% stake in Area 4 is held by operator PetroBal, a subsidiary of Mexico’s GrupoBal. Petrobras Sells Polo Norte Capixaba Field Cluster In line with its strategy to concentrate resources on deepwater and ultradeepwater assets, Brazil’s Petrobras has sold 100% of its interest in Norte Capixaba cluster to Seacrest Exploração e Produção de Petróleo Ltda for $544 million, including a $66-million contingent payment. The cluster comprises four producing fields—Cancã, Fazenda Alegre, Fazenda São Rafael, and Fazenda Santa Luzia—and produced 6,470 BOE/D in 2021. The deal also includes the Norte Capixaba Terminal (TNC) and all production facilities. NewMed Targets Morocco Market Entry Israel-based NewMed Energy, formerly Delek Drilling, has identified Morocco as “a country with enormous geological and commercial potential,” in particular the Moroccan coastal areas in the Mediterranean and North Atlantic. The announcement comes a day after the Moroccan Minister of Industry and Trade, Ryad Mezzour, and his Israeli counterpart, Orna Barbivai, signed an MOU aimed at promoting investments and exchanges between the two countries in the digital design, food, automotive, aviation, textile, water technologies and renewable energies, medical equipment, and the pharmaceutical industries. In September 2021, the Israeli oil and gas exploration company obtained from the Moroccan ministry the exploration and study rights of the Dakhla Atlantic Block, which has an area of about 109000 km2. ExxonMobil Sells Nigerian Assets to Seplat ExxonMobil has agreed to sell its shallow-water assets in Nigeria to Seplat Energy for $1.28 billion plus a contingent consideration of $300 million. Seplat said it is acquiring a 40% operating stake in four oil leases to nearly triple its annual net production to 146,000 BOE/D. The deal also includes the Qua Iboe export terminal and a 51% interest in the Bonny River Terminal and natural gas liquids recovery plants at EAP and Oso. It does not include any of ExxonMobil’s deepwater fields in Nigeria. TotalEnergies Discovers Large Oil Field off Namibia TotalEnergies has made a significant discovery of light oil with associated gas on the Venus prospect, located in block 2913B in the Orange Basin, offshore southern Namibia. The Venus 1-X well encountered approximately 84 m of net oil pay in a good-quality Lower Cretaceous reservoir. The find’s potential reserves are estimated at 2 billion bbl of oil. “This discovery offshore Namibia and the very promising initial results prove the potential of this play in the Orange Basin, on which TotalEnergies owns an important position both in Namibia and South Africa,” said Kevin McLachlan, senior vice president exploration at TotalEnergies. “A comprehensive coring and logging program has been completed. This will enable the preparation of appraisal operations designed to assess the commerciality of this discovery.” Block 2913B covers approximately 8215 km2 in deep offshore Namibia. TotalEnergies is the operator with a 40% working interest, alongside QatarEnergy (30%), Impact Oil and Gas (20%), and NAMCOR (10%). CNPC Scoops Ishpingo Drilling Contract The first drilling contract at the Ishpingo oil field near Ecuador’s Yasuni National Park has been awarded to China National Petroleum Corp. (CNPC), Energy Minister Juan Carlos Bermeo told Reuters. Following the approval of a new hydrocarbon law and legislation, Ecuador plans to move forward with auctions and competitive processes for securing foreign and domestic capital for oil and gas exploration, production, transportation, and refining projects. The first drilling campaign to start after an environmental license was granted for the sensitive area will involve 40 wells over the next 18 months. It will focus on the field’s allowed zone without touching an area protected by a court ruling that has prevented extending drilling. Ishpingo is the latest part of the ITT-43 oil field in Ecuador’s Amazonia region to start drilling after Tambococha and Tiputini. It is expected to produce heavy oil to be added to the nation’s output of flagship Napo crude, Bermeo said. BP Brings Hershel Expansion Project On Line in US GOM BP has successfully started production from the Herschel Expansion project in the Gulf of Mexico—the first of four major projects scheduled to be delivered globally in 2022. Phase 1 comprises development of a new subsea production system and the first of up to three wells tied to the Na Kika platform in the Mississippi Canyon area. At its peak, this first well is expected to increase platform annual gross production by an estimated 10,600 BOE/D. The BP-operated well was drilled to a depth of approximately 19,000 ft and is located southeast of the Na Kika platform, approximately 140 miles off the coast of New Orleans. The project provides infrastructure for future well tie-in opportunities. BP and Shell each hold a 50% working interest in the development. Petrobras Kicks off Gulf of Mexico Asset Sales Petrobras has begun an asset sale program in the Gulf of Mexico, in line with the company’s strategy of debt reduction and pivot toward Brazilian deepwater production. The package for sale includes the company’s 20% stake in MP Gulf of Mexico (MPGoM) which holds ownership stakes in 15 fields in partnership with Murphy Oil. In addition to partnership-operated fields, MPGoM owns nonoperated interests in Occidental’s Lucius, Kosmos’ Kodiak, Shell’s Habanero, and Chevron’s St. Malo fields. During the first half of 2021, Petrobras’ share of production was 11,300 BOE/D. ExxonMobil Liza Phase 2 Underway off Guyana ExxonMobil started production of Liza Phase 2, Guyana’s second offshore oil development on the Stabroek Block; total production capacity is now more than 340,000 B/D in the 7 years since the country’s first discovery. Production at the Liza Unity FPSO is expected to reach its target of 220,000 bbl of oil later this year. The Stabroek Block’s recoverable resource base is estimated at more than 10 billion BOE. The current resource has the potential to support up to 10 projects. ExxonMobil anticipates that four FPSOs with a capacity of more than 800,000 B/D will be in operation on the block by year-end 2025. Payara, the third project in the block, is expected to produce approximately 220,000 BOPD using the Prosperity FPSO vessel, currently under construction. The field development plan and application for environmental authorization for the Yellowtail project, the fourth project in the block, have been submitted for government and regulatory approvals. The Liza Unity arrived in Guyana in October 2021. It is moored in water depth of about 1650 m and will store around 2 million bbl of crude. ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is the operator and holds 45% interest. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd. holds 25%. Dragon Finds Oil in Gulf of Suez UAE’s Dragon Oil has discovered oil in the Gulf of Suez, according to a statement from the Egyptian Minister of Petroleum and Mineral Resources. The field contains potential reserves of around 100 million bbl inside the northeastern region of Ramadan. That estimate makes it one of the largest oil finds in the region over the past 2 decades. Development plans were not reported but reserve numbers could expand, the ministry said. The oil field is the first discovery by Dragon Oil since it acquired 100% of BP’s Gulf of Suez Petroleum assets in 2019. Dragon Oil, wholly owned by Emirates National Oil Co., holds 100% interest in East Zeit Bay off the southern Gulf of Suez region. The 93-km2 block lies in shallow waters of 10 to 40 m.

Historians of colonial Brazil have conventionally located the conclusion of the great era of bandeira-led conquest somewhere near the end of the seventeenth century. The onset of the colony's gold cycle, corresponding with a series of major inland mineral strikes, reoriented those most actively engaged in the bandeira enterprise. Concentrated in the southern coastal captaincy of São Vicente, later, São Paulo, these wilderness adventurers had explored Portuguese America's immense interior and hunted its indigenous inhabitants. When their accompanying search for alluvial riches finally had born fruit, the Paulista backwoodsmen remade themselves into miners and merchants. The bandeirantes had first discovered gold in 1693 in Brazil's southeastern interior, the region that would soon acquire the name Minas Gerais or the General Mines; they made secondary strikes far to the west in Mato Grosso and Goiás in 1718 and 1725. Many then found themselves quickly displaced by the tide of Portuguese fortune-seekers and their African slaves who followed the paths now opened to the mining zones. As gold and then diamonds flooded the Atlantic world in unprecedented quantities, the colony's subsequent historical legacy would accrue not to São Paulo's peripatetic rustics but to those who consolidated control over the flow of riches. During the second half of the eighteenth century, with the mineral washings already in decline, attention would shift still further away from wilderness exploits, supposed to reflect a bygone era, back toward the coastal agricultural export enclaves that had traditionally preoccupied the Portuguese crown. The scholarly concerns of a later era would generally follow suit. As a consequence, the persistence of armed expeditions of exploration and conquest, which continued to roam the unmapped interior of Portuguese America, would go all but unnoticed as a critical feature of the late colonial period.

The predominant hydrocarbons produced in the Taranaki Basin are gas condensates, although oil has been discovered at several widespread locations and therefore remains a priority exploration objective. Study of the oil geochemistry by means of bulk chemical characteristics, isotope and biomarker content improves our understanding of their source rocks and maturation histories. Results show that the oils and condensates throughout the region are similar in their bulk chemical character, source environment and levels of maturation suggesting a common source for all the hydrocarbons. The source environments as indicated by biomarkers were terrestrial fresh water swamps with low bacterial anoxic conditions. The primary plant material deposited was vascular plant debris, and onshore in northern Taranaki and in the Murchison Basin, angiosperm debris was an important additional component. These angiosperm indicators are absent from the West Coast and southeastern Taranaki oils and condenstates. The overall environment of the oil sources rocks is similar to that which formed the high volatile coals of the West Coast. These coals, on source rock analyses, also reveal a perhydrous character equivalent to the high hydrogen index normally associated with marine oil source rocks. Maturation levels of the oils, equivalent to a vitrinite reflectance level of Ro 1.0% are indicated by biomarkers. The highest maturation levels reached by drilling so far are 0.9%. suggesting that oil source rocks in Taranaki Basin are at or below the maximum drilled depth of 5.5 km. After generation, the oils of the West Coast were slightly biodegraded as suggested by their low paraffin wax content. However, valid biomarker interpretations for source and maturation conditions are still possible. The widespread occurrences of oil and the consistent nature of the detailed chemistry of the oils suggest that in addition to gas condensate there is a reasonable prospectivity for oil especially in and adjacent to the Central Graben are of the Taranaki Basin and in parts of the West Coast.

The new south margin area of Block B is a key risk exploration area in southeastern Pre-Caspian Basin. 4 risk exploration wells were drilled in 2013, and all they have seen oil flow from Carboniferous (KT-I, KT-II), indicating a good exploration prospect. This paper, based on petroleum geologic condition analysis and reservoir characteristic correlation, believes that the main control factors of petroleum accumulation are the hydrocarbon filling capacity deciding reservoir limit and the favorable shoal facies deciding reservoir distribution. Moreover, this paper believes that KT-I has better exploration potential than KT-II, and No.6 shoal developed in upper KT-I should be taken as the key target area of subsequent exploration; In addition, higher uplift possibly exists in the areas adjacent to the southern and southeastern study area, whose petroleum accumulation conditions may be superior to that of the study area, and it should be taken as the preferred area for conducting risk exploration expansion.

Sonadrill Lands Contract for Drillship Seadrill confirmed a new contract has been secured by Sonadrill Holding, Seadrill’s 50:50 joint venture with an affiliate of Sonangol for the drillship West Gemini. Sonadrill has secured a 10‑well contract with options for up to eight additional wells in Angola for an unknown operator. Total contract value for the firm portion of the deal is expected to be around $161 million, with further revenue potential from a performance bonus. The rig is expected to begin the work in the fourth quarter of this year with a firm term of about 18 months, in direct continuation of the West Gemini’s existing contract. The West Gemini is the third drillship to be bareboat chartered into Sonadrill, along with two Sonangol‑owned units, the Sonangol Quenguela and Sonangol Libongos. Seadrill will manage and operate the units on behalf of Sonadrill. Together, the three units position the Seadrill joint venture as an active rig operator in Angola, furthering the goal of building an ultradeepwater franchise in the Golden Triangle and driving efficiencies from rig clustering in the region. Petrobras Receives TotalEnergies, Shell Payments for Atapu TotalEnergies and Shell have formalized payments to Petrobras for separate, minority stakes in the pre‑salt Atapu field in the Santos Basin. TotalEnergies paid $4.7 billion reais ($940 million) while Shell paid closer to $1.1 billion. The Atapu block was acquired by the consortium comprising Petrobras (52.5%), Shell (25%), and TotalEnergies (22.5%) in the Second Bidding Round for the Transfer of Rights auction held 17 December 2021. The payments are compensation for monies spent thus far by Petrobras, which was granted contractual rights to produce 550 million BOE from Atapu in 2010. The partners will now work together to produce additional volumes from the field. Production at Atapu started in June 2020 via the P-70 FPSO. The unit is in about 2000 m of water and has the capacity to produce 150,000 BOED. CNOOC Brings New Bohai Sea Discoveries On Stream CNOOC Limited has kicked off production from its Luda 5‑2 oil field North Phase I project and Kenli 6‑1 oil field 4‑1 Block development project. Luda 5‑2 is in the Liaodong Bay of Bohai Sea, with average water depth of about 32 m and utilizes a thermal recovery wellhead platform and production platform tied into the Suizhong 36‑1 oil field. A total of 28 development wells are planned, including 26 production wells and two water‑source wells. The project is expected to reach its peak production of 8,200 B/D of oil in 2024. Kenli 6‑1 is in the south of Bohai Sea, with average water depth of about 17 m. The resource is being developed by a wellhead platform in addition to fully utilizing the existing processing facilities of the Bozhong 34‑9 oil field. A total of 12 development wells are planned, including seven production wells and five water‑injection wells. The field is expected to reach its peak production of 4,000 B/D of oil later this year. CNOOC Limited is operator and sole owner of the Luda 5‑2 oil field North and the Kenli 6‑1 oil field 4‑1 Block. Stabroek Block Bounty Off Guyana Gets Bigger The partners in the prolific Stabroek Block have again increased the gross discovered recoverable resource estimate for the area offshore Guyana. The owners now believe they have discovered reserves of at least 11 billion BOE, up from the previous estimate of more than 10 billion BOE. The updated resource estimate includes three new discoveries on the block at Barreleye, Lukanani, and Patwa in addition to the Fangtooth and Lau Lau discoveries announced earlier this year. The Barreleye‑1 well encountered approximately 70 m of hydrocarbon‑bearing sandstone reservoirs of which 16 m is high‑quality oil‑bearing. The well was drilled in 1170 m of water and is located 32 km southeast of the Liza field. The Lukanani‑1 well encountered 35 m of hydrocarbon‑bearing sandstone reservoirs of which approximately 23 m is high‑quality oil‑ bearing. The well was drilled in water depth of 1240 m and is in the southeastern part of the block, approximately 3 km west of the Pluma discovery. The Patwa‑1 well encountered 33 m of hydrocarbon‑bearing sandstone reservoirs. The well was drilled in 1925 m of water and is located approximately 5 km northwest of the Cataback‑1 discovery. “These new discoveries further demonstrate the extraordinary resource density of the Stabroek Block and will underpin our queue of future development opportunities,” said John Hess, chief executive of Hess and a partner in Stabroek. The co‑venturers have sanctioned four developments to date on Stabroek with both Liza and Liza Phase 2 on stream. The third planned development at Payara is ahead of schedule and is now expected to come on line in late 2023; it will utilize the Prosperity FPSO with a production capacity of 220,000 BOPD. The fourth development, Yellowtail, is expected to come on line in 2025, utilizing the ONE GUYANA FPSO with a production capacity of 250,000 BOPD of oil. At least six FPSOs with a production capacity of more than 1 million gross BOPD are expected to be on line on the Stabroek Block in 2027, with the potential for up to ten FPSOs to develop gross discovered recoverable resources. The Stabroek Block is 6.6 million acres. ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45% interest; Hess Guyana Exploration holds 30% interest; and CNOOC Petroleum Guyana Limited holds 25%. ConocoPhillips Gets Ekofisk License Extension Norway’s Ministry of Petroleum and Energy (MPE) has extended production licenses in the Greater Ekofisk Area from 2028 to 2048 with ConocoPhillips as operator. The company said the license extension provides long‑term operations and resource management aligned with the company’s long‑term perspective on the Norwegian continental shelf. Fields on the shelf are required to operate with a valid production license where the operator and licensees enter into an agreement with the authorities, including relevant field activities. The authorities may require commitments, leading to increased oil recovery. The existing production licenses 018, 018 B, and 275 in the Greater Ekofisk Area were set to expire on 31 December 2028; however, the MPE approved an extension through 2048. The new terms provide a potential for extending Ekofisk’s lifetime to nearly 80 years. The license partners are ConocoPhillips (operator, 35.11%), TotalEnergies EP Norge (39.896%), Vår Energi (12.388%), Equinor (7.604%), and Petoro (5%). BHP’s Wasabi Disappoints in US GOM Australian operator BHP encountered noncommercial hydrocarbons with its Wasabi‑2 well in the US Gulf of Mexico. BHP said the well in Green Canyon Block 124 was plugged and abandoned following the disappointing results. “This completes the Wasabi exploration program, with results under evaluation to determine next steps,” the company said. The well was targeting oil in an early Miocene reservoir. Transocean drillship Deepwater Invictus spudded the well in 764 m of water in November 2021. The previous Wasabi‑1 well had a mechanical problem and was plugged and abandoned 4 days earlier, prior to reaching its prospective targets. BHP operates Wasabi with a 75% interest. Lukoil Says Titonskaya Holds 150 Million BOE Russia’s Lukoil believes it has discovered around 150 million BOE following analysis of the two wells it drilled at the Titonskaya structure on the Caspian Sea shelf. Work is now underway to refine the seismic models of productive deposits and study deep samples of formation fluids. The results of the assessment will be submitted to the State Reserves Commission of the Russian Federation. The structure is in the central part of the Caspian Sea, not far from the Khazri field. Lukoil drilled the first well at the Titonskaya structure in 2020 and announced the new discovery in April 2021. According to that assessment, the probable geological resources of the Titonskaya are 130.4 million tons. In 2021, drilling of the second prospecting and appraisal well began to identify oil and gas deposits in the terrigenous‑carbonate deposits of the Jurassic‑ Cretaceous age. The well was drilled using the Neptune jackup drilling rig. The new find at Titonskaya will likely be tied into Khazri infrastructure. Petrobras’ Roncador IOR Project Comes On Line Petrobras has successfully started production from the first two wells of the improved oil recovery (IOR) project at the Roncador field in the Campos Basin offshore Brazil. The two wells are the first of a series of IOR wells to reach production. Startup is almost 5 months ahead of schedule and at half of the planned cost, according to partner Equinor. The wells will add a combined 20,000 BOED to Roncador, bringing daily production to around 150,000 bbl and reducing the carbon intensity (emissions per barrel produced) of the field. Through this first IOR project, the partnership will drill 18 wells that are expected to provide additional recoverable resources of 160 million bbl. Improvements in well design and the partners’ combined technological experience are the main drivers behind the 50% cost reduction across the first six wells, including the two in production. Roncador is Brazil’s fifth‑largest producing asset and has been in production since 1999. Petrobras operates the field and holds a 75% stake. In 2018, Equinor entered the project as a strategic partner with the remaining 25% interest. In addition to the planned 18 IOR wells, the partnership believes it can further improve recovery and aims to increase recoverable resources by a total of 1 billion BOE. The field has more than 10 billion BOE in place under a license lasting until 2052. The strategic alliance agreement also includes an energy‑efficiency and CO2‑emissions‑reduction program for Roncador. Gazania-1 To Spud Off South Africa Africa Energy will move ahead with its planned Gazania‑1 wildcat well offshore South Africa after securing partner Eco Atlantic’s $20 million in capital requirements for its portion of the probe. The well will be drilled in Block 2B. Island Drilling semisubmersible Island Innovator has been contracted for the work and is expected to mobilize from its current location in the North Sea for the 45‑day trip to South Africa. The Block 2B joint venture plans to spud the well by October with drilling expected to last 30 days, including a full set of logs if the well is successful. The block has significant contingent and prospective resources in relatively shallow water and contains the A‑J1 discovery that flowed light sweet crude oil to surface. Gazania‑1 will target two large prospects 7 km updip from A‑J1 in the same region as the recent Venus and Graff discoveries. Block 2B is located offshore South Africa in the Orange Basin where both TotalEnergies and Shell recently announced significant oil and gas discoveries offshore Namibia. The block covers 3062 km2 approximately 25 km off the west coast of South Africa near the border with Namibia in water depths ranging from 50 m to 200 m. The Southern Oil Exploration Corp. (Soekor) discovered and tested oil on Block 2B in 1988 with the A‑J1 borehole, which intersected thick reservoir sandstones between 2985 m and 3350 m. The well flowed 191 B/D of 36 °API oil from a 10‑m sandstone interval at around 3250 m. Africa Energy has a 27.5% interest in Block 2B offshore South Africa. The block is operated by a subsidiary of Eco Atlantic which holds a 50% interest. A subsidiary of Panoro Energy holds a 12.5% stake, and Crown Energy AB indirectly holds the remaining 10%. Brazil Grants New Exploration Blocks Brazil’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP) has granted 59 exploratory blocks of oil and natural gas to 13 companies, including Shell, TotalEnergies, and 3R Petroleum. The awards were part of a permanent bid offer round held in Rio de Janiero in April. The auction totaled 422.4 million reais in signature bonuses with leases granted in six Brazilian states: Rio Grande do Norte, Alagoas, Bahia, Espírito Santo, Santa Catarina, and Paraná. The awards will result in investments of 406.3 million reais in the exploratory phase of the contracts. Shell Brazil (70%) was granted six blocks in the Santos Basin in a consortium with the Colombian Ecopetrol (30%). The blocks leases were SM‑1599, SM‑1601, SM‑1713, SM‑1817, SM‑1908, and SM‑1910. TotalEnergies won two areas in the same basin while Brazilian company 3R Petroleum received six areas in the Potiguar Basin. Petro‑Victory was also awarded 19 new blocks in Potiguar, increasing its holdings in Brazil to 38 blocks (37 in Potiguar). The new blocks are nearby Petro‑Victory infrastructure at the Andorinha, Alto Alegre, and Trapia oil fields. Eni Finds More Oil in Egypt’s Western Desert Eni struck new oil and gas reserves with a trio of discoveries in the Meleiha concessions of Egypt’s Western Desert. The finds have already been tied into existing infrastructure in the region and have added around 8,500 BOED to overall production from the area. The operator drilled the Nada E Deep 1X well, which encountered 60 m of net hydrocarbon pay in the Cretaceous‑Jurassic Alam El Bueib and Khatatba formations Meleiha SE Deep 1X well, which found 30 m of net hydrocarbon pay in the Cretaceous‑Jurassic sands of the Matruh Khatatba formations, and the Emry Deep 21 well, which encountered 35 m of net hydrocarbon pay in the massive cretaceous sandstones of Alam El Bueib. The results, added to the discoveries of 2021 for a total of eight exploration wells, give Eni a 75% success rate in the region. The company added that additional exploration activities in the concession are ongoing with “promising indications.” With these discoveries, Eni, through AGIBA, a joint venture between Eni and EGPC, continues to pursue its near‑field strategy in the mature basin of the Western Desert, aimed at maximizing production by containing development costs and minimizing time to market. Eni is planning a new high‑resolution 3D seismic survey in the Meleiha concession this year to investigate the gas potential of the area. Eni is currently the leading producer in Egypt with an equity production of around 360,000 BOED.

Wonnich, a new gas and oil discovery was drilled in July 1995 within exploration permit TP/8 Part 1 in the Barrow Sub-3asin. The well was logged using emerging wireline technology which resulted m significant im­provements in understanding the quality of reservoir rocks, their genesis and post depositiunal alterations. Both the Combinable Magnetic Resonance Imaging Tool (CMR™) and the Formation Micro-Imager (FMI™) data were acquired in the 216 mm hole section of the well. The interval between 2.575 and 2,525 m. which forms the basis of this technology review, comprises an aquifer sandstone which was logged with the CMR tool to inves­tigate the pore size and distribution and to provide a comparison between the CMR porosity and standard porosity derivations. The CMR data presented in this paper was p-ocessed by Schlumberger using the stan­dard sandstone settings. The high resolution, density derived porosity and the CMR porosity showed good agreement in both magnitude and vertical resolution. The aquifer sandstones reached a maximum of 18 per cent porosity with a CMR permeability maximum of 400md between 2,544-2,551 m. The T2 relaxation times distribution in sands, occurs between 33 and 250 ms with the peak and mean coinciding at 100ms. Several shale intervals show T2 attenuation due to hole washout. Utilising both the FMI azimuthal images and the CMR permeability curve it was established that some of the permeability barriers shown by the CMR and 'regular' open hole logs are in fact nodular formation components, rather than beds. These would thus not impact fluid flow and completion design. Further image analysis within the aquifer sands shows that the palaeocurrent direction is northwest, with a southeasterly sediment provenance. The larger scale process signatures within the lower sand are replaced by friction dominated and low energy pro­cesses towards the upper portion of the sand. This fining upwards profile is reflected not only in the GR logs but also in the pore size reductions shown by the CMR T2 relaxation profiles extending the application of these technologies to depositional environment analysis and grain size distribution. Post depositional influences in­clude siderite and clay diagenesis and fracturing associ­ated with aquifer seals.

Autonomous agents have many applications in familiar situations, but they also have great potential to help us understand novel settings. In this paper, I propose a new challenge for the AI research community: developing embodied systems that not only explore new environments but also characterize them in scientific terms. Illustrative examples include autonomous rovers on planetary surfaces and unmanned vehicles on undersea missions. I review two relevant paradigms: robotic agents that explore unknown areas and computational systems that discover scientific models. In each case, I specify the problem, identify component functions, describe current abilities, and note remaining limitations. Finally, I discuss obstacles that the community must overcome before it can develop integrated agents of exploration and discovery.