Significant Oil Discoveries Research Articles

Petroleum geochemistry and origin of shallow-buried saline lacustrine oils in the slope zone of the Mahu sag, Junggar Basin, NW China

Recently, significant oil discoveries have been made in the shallower pay zones of the Jurassic Badaowan Formation (J1b) in the Mahu Sag, Junggar Basin, Northwest China. However, little work has been done on the geochemical characteristics and origins of the oil in the J1b reservoir. This study analyzes 44 oil and 14 source rock samples from the area in order to reveal their organic geochemical characteristics and the origins of the oils. The J1b oils are characterized by a low Pr/Ph ratio and high β-carotene and gammacerane indices, which indicate that they were mainly generated from source rocks deposited in a hypersaline environment. The oils are also extremely enhanced in C29 regular steranes, possibly derived from halophilic algae. Oil-source correlation shows that the oils were derived from the Lower Permian Fengcheng Formation (P1f) source rocks, which were deposited in a strongly stratified and highly saline water column with a predominance of algal/bacterial input in the organic matter. The source rocks of the Middle Permian lower-Wuerhe Formation (P2w), which were deposited in fresh to slightly saline water conditions with a greater input of terrigenous organic matter, make only a minor contribution to the J1b oils. The reconstruction of the oil accumulation process shows that the J1b oil reservoir may have been twice charged during Late Jurassic–Early Cretaceous and the Paleogene–Neogene, respectively. A large amount volume of hydrocarbons generated in the P1f source rock and leaked from T1b oil reservoirs migrated along faults connecting source beds and shallow-buried secondary faults into Jurassic traps, resulting in large-scale accumulations in J1b. These results are crucial for understanding the petroleum system of the Mahu Sag and will provide valuable guidance for petroleum exploration in the shallower formations in the slope area of the sag.

Guiana: petróleo, disputas internas, EUA e Venezuela

Abstract Abstract: Guyana has a strategic geographic position in the Amazon and the Greater Caribbean area, as revealed in the strategic thinking and military presence of the United States (USA). Its territory also possesses abundant natural resources, especially after the recent and significant oil discoveries, having the American company ExxonMobil as protagonist. Meanwhile, the country is characterised by a domestic political and ethnic cleavage. In addition, Venezuela and Guyana are in a historical dispute for the Essequibo area, which is potentially endowed and surrounded by areas with strategic resources. The main argument of the paper is that the oil discoveries in Guyana are leading to geopolitical and geoeconomic impacts regarding the intensification of domestic and foreign disputes, involving American and Venezuelan interests and recent state actions. More broadly, it points out that the north of South America has become one of the stages of the global power strife, in view of the Sino-Russian and American presences, in a context of Brazil’s absence. To survey and evaluate the actors’ actions resulting from the oil findings in Guyana, the paper is based on geopolitical and geoeconomic concepts, energy data, specialised academic and journalistic bibliography.

E&P Notes (May 2022)

E&P Notes (May 2022)

Offshore Exploration For Hydrocarbons In Indonesia

Indonesian offshore areas in 1985 are still the loci of an active exploration program. Exploration activities are anticipated to be at the same level as in 1984. A new ofl field in the East Java Sea (the Madura field) began production in September 1985 with initial production of 10.9 MBOPD. The month of August 1985 is marked by the significant oil and gas discovery in the Banggai basin, offshore East Sulawesi, where the Tlaka-1 exploratory well flowed 3864 BOPD (29° API) and 1.1 MMSCF gas (60 ppm HS) from Middle Miocene plat-form carbonates. Together with exploration drillings in the area beyond the continental shelf which have been started since February 1984 such as in the area north of Lombok, the discovery will encrease enthusiasm for exploration of the frontier areas especially in the geologically complex reglon of Eastern Indonesia. It also reveals that potential accumulation of hydrocarbons could also occur within the collision complex.

Exploration breakthrough and its significance of Gulong lacustrine shale oil in the Songliao Basin, Northeastern China

Lacustrine shale oil resources are abundant in many petroliferous basins in China. The shale oil formations are characterized by low API gravity, high viscosity, poor mobility, high clay content, low brittleness and etc. Exploration of lacustrine shale oil started relatively late in China, but its progress is very rapid and breakthroughs have been made successively. In this short communication, we introduced the most significant shale oil discovery which is made recently in the Qingshankou Formation of the Gulong sag in the Songliao Basin. Key exploratory wells including Guye 1H (GY1H), Yingye 1H (YY1H) and Guye 2HC (GY2HC) tested stable and high oil flow in shale reservoirs, revealing the relatively stable and high oil production capacity of shale in the Gulong sag of Daqing Oilfield. It marks a leap of petroleum theoretical recognition from lacustrine shale generating oil to producing oil and from the theory of traditional oil migration and accumulation to the theory of indigenous oil accumulation in organic-rich shale. Although lacustrine shale oil exploration and development still faces many challenges in China, its prospect is quite promising.

E&P Notes (September 2021)

Eni Confirms Block 10 Oil Strike Offshore Mexico Eni confirmed it encountered oil shows in the Upper Miocene sequences on the Sayulita Exploration Prospect in Block 10 in the mid-deep water of the Cuenca Salina Sureste Basin. Preliminary estimates put the new find at between 150 and 200 million BOE in place. Sayulita-1 EXP is the seventh successful well drilled by Eni in the basin and the second commitment well of Block 10. It is located approximately 70 km off the coast and just 15 km away from the previous oil discovery of Saasken that will be appraised toward year-end. The well was drilled to a total depth of 1758 m by the semisubmersible Valaris 8505 in a water depth of 325 m. APA Touts Appraisal Success Off Suriname APA Corp. said its Sapakara South-1 appraisal well, located on the eastern edge of the Sapakara area, encountered approximately 30 m of net black-oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. Drillship Maersk Valiant will soon mobilize to the next exploration prospect at Bonboni, about 45 km to the north, before returning later in the year to flow-test Sapakara South-1. A second appraisal well encountered two thin intervals of black oil above water in the Campano-Maastrichtian at Kwaskwasi, impacting a small portion of the eastern edge of Kwaskwasi. The Campano-Maastrichtian intervals at Kwaskwasi and the Sapakara South-1 discovery are separate and unrelated. Shell Begins Barracuda Production Shell Trinidad and Tobago, through BG International, a subsidiary of Royal Dutch Shell plc, has started production on Block 5C in the East Coast Marine Area in Trinidad and Tobago. Block 5C, known as Project Barracuda, is a backfill project with approximately 140 MMcf/D of sustained near-term gas production with peak production expected to be about 220 MMcf/D. It is Shell’s first greenfield project in the country and one of its largest in Trinidad and Tobago since the BG Group acquisition. “Today’s announcement strengthens the resilience and competitiveness of Shell’s position in Trinidad and Tobago,” said Maarten Wetselaar, director of integrated gas, renewable, and energy solutions for Shell. “This is a key growth opportunity that supports our long-term strategy in the country as well as our global LNG growth ambitions.” Eni Strikes Oil With Eban Well Off Ghana Eni has struck a significant oil discovery on the Eban exploration prospect in CTP Block 4, offshore Ghana. The Eban-1X well is the second well drilled in CTP Block 4, following the Akoma discovery. Preliminary estimates place the potential of the Eban-Akoma complex between 500 and 700 million BOE in place. The Eban-1X well is located approximately 50 km off the coast and about 8 km northwest of Sankofa Hub, where the John Agyekum Kufuor FPSO is located. It was drilled by drillship Saipem 10000 in a water depth of 545 m and reached a total depth of 4179 m. The well encountered a single light-oil column of about 80 m in a thick sandstone reservoir interval of Cenomanian age with hydrocarbons encountered down to 3949 m. Talos Lines Up Gulf of Mexico Successes Talos Energy drilled a successful sidetrack of its Crown and Anchor well at Viosca Knoll Block 960. The probe was drilled to a true vertical depth of about 13,000 ft and encountered around 50 ft of net oil pay in the M62 Middle Miocene target horizon. The project has moved to the completion phase and will produce through existing subsea infrastructure to the nearby Marlin tension-leg platform. First production is targeted by the late third quarter of 2021. Talos holds a 34% working interest in the project along with Beacon Offshore Energy (operator) and Ridgewood Crown & Anchor LLC. Greenland Calls Halt to New Oil Exploration Greenland has ended its decades-long pursuit to become an oil-producing nation after announcing 16 July it would stop granting oil and gas exploration licenses, adding that “the future does not lie in oil.” Oil exploration began for the country in the 1970s, with several major operators coming in to test the area’s prospectivity. Exploration for hydrocarbons in Greenland peaked between 2002 and 2014, when more than 20 offshore licenses were granted. Those companies that drilled walked away empty-handed. “There’s no doubt that our subsoil is rich in oil resources,” the government said in the 16 July press release. “But oil extraction won’t only have positive effects on our society, it will adversely affect our nature and environment, and may adversely affect fisheries as well as contribute to the worsening global climate crisis.”

Modeling of Tectonic-Thermal Evolution of Cretaceous Qingshankou Shale in the Changling Sag, Southern Songliao Basin, NE China

A series of significant shale oil discoveries have been made recently in the Upper Cretaceous Qingshankou Formation in the Songliao Basin, providing a new resource target for shale oil exploration in Northeast China. In this context, an understanding of the tectonic-thermal evolution and maturation history of the Qingshankou Formation is of great significance for shale oil exploration and evaluation. In this study, the thermal history of the Qingshankou Formation since the Late Cretaceous was reconstructed using the paleothermal indicator method. The results indicate that two stages of thermal evolution exist in the southern part of the Songliao Basin: 1) the gradual heating stage during the Late Cretaceous; the heat flow gradually increases during this period and reaches a maximum heat flow value at the end of the Cretaceous. 2) The decline stage since the Neogene; the tectonic activity is relatively stable and the geothermal heat flow is gradually reduced, and the present-day heat flow ranges from 60.1 to 100.7 mW/m2, with an average of 78.2 mW/m2. In addition, the maturity history of the organic-rich shale was reconstructed based on the new thermal history. The Cretaceous Qingshankou shales underwent deep burial thermal metamorphism at the end of the Cretaceous, whereas thermal has faded since the Neogene. The hydrocarbon generation and migration since the Late Cretaceous period of K2qn1 were modeled based on the maturity model. Two main cooling events took place in the late Nenjiang period and the late Mingshui period in the Changling sag. These two tectonic events controlled the structural style and the formation of shale oil reservoirs in the southern Songliao Basin.

E&P Notes (June 2021)

E&P Notes (June 2021)

E&P Notes (May 2021)

E&P Notes (May 2021)

Regional chronostratigraphic framework of sediments build-up in the Benin Basin: a guide for hydrocarbon prospecting

An attempt to understand the structural and sedimentation framework in the Benin Basin is made herein. Unlike in its contiguous basins in the Gulf of Guinea Province, no significant oil and gas discovery has been reported in the basin. The aim here is to provide a chronostratigraphic framework of sediments build-up as a guide to hydrocarbon prospectivity in the basin. Existing biostratigraphic and sedimentologic data as well as few proprietary reports were integrated to establish a chronostratigraphic correlation in six directions within the Nigerian portion of the Benin Basin. Isopach maps of the chronostratigraphic subdivision of the sequences in the basin were also made. Sedimentation in restricted grabens started in the western part of the basin. Only Ise-2 well penetrated the oldest Cretaceous (Neocomian to Albian) sediments in the area of study with a thickness reaching up to 869 m. During the Miocene the focus of sedimentation predominantly shifted towards the offshore in the basin. Significantly a missing Eocene/Oligocene section was observed both on the seismic section and the stratigraphic record of the basin. Only Epiya-1 shows gas occurrence in the Miocene. Based on this work and locations of hydrocarbons recovery in the other part of the basin, exploration effort should target the Cretaceous sediments in the Nigerian portion of the basin.

Intense faulting and downwarping of Nanpu Sag in the Bohai Bay Basin, eastern China: Response to the Cenozoic Stagnant Pacific Slab

Abstract The Nanpu Sag (NPS), located in northwestern Bohai Bay Basin (BBB), East China, has significant oil discoveries in recent years. The effect of intense faulting and downwraping which generated the intense subsidence of NPS in the Dongying Formation (Fm.) (Ed) (28.5–23.8 Ma) of the Late Oligocene is presented in this paper. We analyzed the geochemical characteristics of the widespread Cenozoic basalts in NPS from drill core samples. Our results show that the magma experienced negligible crustal contamination and slight fractional crystallization, and the features of remarkable positive U, Pb, Sr and Ti anomaly, low Rb/Ba and Rb/Sr values of the NPS basalts were inherited from the source region. The NPS basalts in Ed have distinctive characteristics as sub-alkaline basalts with rare earth elements (REE) patterns parallel to enriched mid-ocean ridge basalts (E-MORB), and were generated from a mixture origin of garnet-lherzolite zone with relatively high degree of partial melting (30%–50%) and garnet + spinel-lherzolite transition zone with partial melting degree ranging from 3% to 15%. In contrast, NPS basalts of other Cenozoic periods or Ed basalts of other areas in eastern China are alkaline with light REE enrichment and oceanic island basalts (OIB)-like-pattern, their magmas originated from garnet + spinel-lherzolite transition zone with partial melting degree lower than 5%. Combined with previous studies of the mantle wedge in the mantle transition zone (MTZ) beneath northeastern Asia, forming around 30 Ma, we infer that the stagnating of the Pacific slab triggered the asthenosphere upwelling and increased the degree of partial melting in mantle source, and relatively weak areas of the North China Craton (NCC) like the Tanlu Fault (TLF) where NPS located on were reactivate and susceptible to be modified. Therefore, the intense faulting and downwarping of NPS in Ed, along with the igneous activities, was a response to the Cenozoic stagnant Pacific slab more than the result of tectonic effects from the Pacific subduction like other areas in northeastern China in Paleogene.

Petroleum systems framework of significant new oil discoveries in a giant Cretaceous (Aptian–Cenomanian) clinothem in Arctic Alaska

Recent oil discoveries in an Aptian–Cenomanian clinothem in Arctic Alaska demonstrate the potential for hundred-million- to billion-barrel oil accumulations in Nanushuk Formation topsets and Torok Formation foresets–bottomsets. Oil-prone source rocks and the clinothem are draped across the Barrow arch, a structural hinge between the Colville foreland basin and Beaufort Sea rifted margin. Stratigraphic traps lie in a favorable thermal maturity domain along multiple migration pathways across more than 30,000 km2 (10,000 mi2). Sediment from the Chukotkan orogen (Russia) filled the western Colville basin and spilled over the Beaufort rift shoulder, forming east- and north-facing shelf margins. Progradational shelf margin trajectories change abruptly to “sawtooth” trajectories at midclinothem, the result of reduction in sediment influx. Two stratigraphic trap types are inferred in Nanushuk basal topsets in the eastern part of the clinothem: (1) lowstand systems tracts, inferred to reflect forced regression, include a narrow, thick progradational stacking pattern perched on a sequence boundary on the upper slope; and (2) highstand-progradational systems tracts include a broad, thin wedge of shingled parasequences above a toplap surface. Both include stratigraphically isolated sandstone sealed by mudstone. Trap geometries in Torok foreset and bottomset facies in the same area include basin-floor fan, slope-apron, and slope-channel deposits that pinch out upslope and are sealed by mudstone. Significant potential exists for the discovery of additional oil accumulations in these stratigraphic trap types in the eastern part of the clinothem. Less potential may exist in the western part because reservoir–seal pairs may not be well developed.

Chapter 11 Myanmar petroleum systems, including the offshore area

This report does not claim to be an exhaustive review of the petroleum sytems of Myanmar but a brief summary of some of the salient points, based on: more than 40 years of experience by the author, with extensive fieldwork, drilling of wells and exploring for petroleum in most of the prospective basins in Mynmar; research in the laboratory as Chief Research Officer of Myanmar Oil & Gas Enterprise (MOGE); countless discussions and exchanges of views with Myanmar and foreign academics and petroleum explorers; and as participant in joint co-operations with foreign academic scientific teams and petroleum operators in Myanmar. The reader will excuse the author for not having covered some plays and basins for which too little published literature exists. Oil exploration and production in Myanmar date back to the thirteenth century, a time of manual excavation from hand-dug wells in the Yenangyaung District (now in the Magwe Division of Central Myanmar). According to Chinese accounts, extraction and local trading in the oil business began in the thirteenth century. Trade with the Ayeyarwaddy Delta started in 1824 and the export of crude oil commenced in 1853, earlier than ‘Colonel’ Edwin Drake's well in Pennsylvania, USA on 28 August 1859, widely regarded as the origin of the present petroleum industry. After the British annexation of Upper Burma in 1886, the Burmah Oil Company (BOC) was established and, in 1887, introduced mechanized drilling at Yenangyaung. This resulted in significant discoveries of oil, followed by drilling at Yenangyat in 1893 and at Chauk (Singu) in 1902. In 1918 the oil production of Yenangyaung Field was over 5.8 MMbbl per year and, in 1941, Chauk's production peaked at over 4 MMbbl. At that time Myanmar was ranked 14th among all the petroleum-producing nations in the world. In 1963 BOC was purchased by the …

Evolution of Marine Acquisition Technology after Wide Azimuth

Seismic exploration in the deep-water Gulf of Mexico was based for many years on the 3D acquisition method and, as a result, significant oil discoveries were made and most of the plays were found below salt or in intra-salt-body basins. The quality of the seismic data acquired in deep-water subsalt environments was occasionally satisfactory for exploration purposes, but, in most cases, it was not good enough to support an accurate earth model for reservoir development. The main challenges for data interpretation are: incomplete reservoir illumination, poor signal-to-noise ratio of the subsalt events and poor seismic resolution. Developments in the last decade in marine seismic acquisition and data processing were driven to solve these challenges. One reference point in the evolution of marine seismic technology in the last decade was the introduction of wide azimuth acquisition (WAZ). Introduced in 2006 by British Petroleum in the Gulf of Mexico, the method was quickly adopted by the industry as a seismic technology to explore the complex subsalt geologic structures where improved subsurface illumination and signal-to-noise ratio are required. The introduction of WAZ started a period of several innovations in the seismic industry: dual-sensor streamer acquisition, full-azimuth towed streamer acquisition, broadband seismic measurements on both the source and receiver sides, long-offset marine acquisition, simultaneous shooting, and multimeasurement streamers. Challenges in processing wide-azimuth data lead to new developments in velocity model building based on tomography and full-waveform inversion, 3D demultiple methods, 3D anisotropic imaging with reverse time migration, and other improvements in computational methods. The presentation will review the latest innovations in marine seismic acquisitions with examples of applications, and will discuss the geophysical benefits and limitations, as well as specific survey design and processing aspects related to each method.

Enduring silk ties

Due to China’s growing energy needs that stem from its unrelenting drive for economic development, Beijing stresses the importance of maintaining a continuous supply of energy, particularly oil, to maintain its impressive economic growth. However, seeing as China’s domestic resources are unable to satisfy its projected future oil demands, the Chinese government realise that, barring significant domestic oil discoveries, their dependency on oil imports, particularly from the Middle East, will continue to increase. As such, Chinese efforts to enhance relations with Iran have mainly stemmed from China’s search for energy resources, an opportunity to create a diverse portfolio of overseas market shares, and the desire to exert political influence in the Middle East. Yet, not all credit can be given to Beijing for establishing links with Tehran as Iranian officials have, by advertising the country as a reliable energy source and key strategic partner in the Middle East, managed to gain China’s attention and advance Sino-Iranian relations.

We Gambled Everything: The Life and Times of an Oilman by Arne Nielsen. Foreword by Peter C. Newman (review)

Reviewed by: We Gambled Everything: The Life and Times of an Oilman by Arne Nielsen. Foreword by Peter C. Newman Allan Edward Ingelson We Gambled Everything: The Life and Times of an Oilman. By Arne Nielsen. Foreword by Peter C. Newman. Edmonton: University of Alberta Press, 2012. xxi + 273 pp. Photographs, illustrations, maps, index. C$29.95 paper. The author, a prominent retired Canadian oil geologist and senior industry executive, captures in his memoirs the excitement of oil discoveries on the Alberta and Saskatchewan plains during the 1940s and ’50s. He shares his experiences as a corporate executive for Mobil Oil in New York, while overseeing exploration programs on the plains in Alberta, Saskatchewan, Montana, Colorado, Utah, Wyoming, and Kansas. Nielsen reviews his childhood and teenage years growing up on the family farm during the 1920s and ’30s in an area subject to drought, dust storms, and poverty on the Alberta plains. After noting there were numerous unsuccessful attempts at drilling for oil on the plains near Leduc, Alberta, and the contribution of improved seismic technology, Nielsen describes the significant commercial oil discovery by Imperial Oil in 1947, that laid the foundation for a Canadian oil and gas industry. Through the eyes of a young geology graduate in the late 1940s he alludes to the increased employment opportunities in the emerging Alberta oil industry for individuals with a strong work ethic. Nielsen notes the significant contribution of US companies—in terms of investment and the deployment of technology on the plains—to the development of the oil and gas industry in western Canada. Through the eyes of a 28-year-old geologist who was a member of the exploration team that discovered an immense oilfield, he shares the excitement of locating the multibillion barrel Pembina oilfield in 1953, that has become one of the most productive fields in North America. In light of his role in the major oil discovery Nielsen was fast tracked to the Socony (Standard Oil of New York) corporate headquarters. Nielsen discusses his oil exploration experience on the plains in Saskatchewan and further south in the Williston Basin in North Dakota, South Dakota, and Montana. When analyzing the investment climate for oil exploration in Saskatchewan during the 1950s and ’60s, he notes that notwithstanding the stark political contrast to entrepreneurial free-market Alberta, overall the socialist Saskatchewan provincial government was fairly positive toward oil development. The government was aware of the significant economic benefits that neighboring Alberta had accrued from its conventional oil exploration and production activities on the plains. In the balance of the book Nielsen analyzes the changes in Canadian federal energy policies that have dramatically affected the level of oil and gas investment, exploration, and development in the Western Canadian Sedimentary Basin, eastern Canada offshore, and in the Northwest Territories. A key theme in We Gambled Everything is that US and Canadian oil companies assume substantial uncertainty in their search for commercial accumulations of fossil fuels. The high risk search that Nielsen describes in his book that was present in previous decades continues. Recently American and Canadian oil and gas developers have employed innovative horizontal drilling and fracking techniques to locate and evaluate unconventional energy resources on the plains that were previously uneconomic to produce on a significant scale, such as oil from the Bakken shales in North Dakota and Saskatchewan, in an attempt to satisfy the growing demand for fossil fuels in North America. Allan Edward Ingelson Canadian Institute of Resources Law, Faculty of Law University of Calgary, Alberta Copyright © 2014 Center for Great Plains Studies, University of Nebraska–Lincoln

The Tertiary evolution of the prolific Nanpu Sag of Bohai Bay Basin, China: Constraints from volcanic records and tectono-stratigraphic sequences

The Bohai Bay Basin, located on the eastern Asian margin, is the second largest oil-production basin in China. It contains numerous depressions and sags, among which Nanpu Sag has become particularly important because of significant oil discoveries in recent years. Geologically and tectonically, however, the rifting mechanism and geodynamic evolution of the basin remain uncertain. This paper uses detailed volcanic and stratigraphic records obtained through extensive drilling and sampling in Nanpu Sag to interpret tectono-stratigraphic sequences and discuss basin dynamic evolution and crust-mantle interactions of the Bohai Bay Basin. Nanpu Sag contains voluminous volcanic rocks of dominantly alkaline basalts. Drill core samples, well logs, and seismic profiles reveal three volcanic cycles between the Eocene and Miocene Epochs. These basalts were created during a transition from garnet- to spinel-peridotite. Five tectono-stratigraphic sequences produced by episodic continental rifting have been identified, each composed of a basal coarse clastic sequence, a lower volcanic sequence, a middle deep-water clastic sequence, and an upper infilling sequence. Tectonically, Nanpu Sag experienced four evolutionary phases. The first three corresponded to three rifting events revealed by cyclic volcanism and sedimentary depositional features. The fourth phase was marked by extreme thermal subsidence and prograding fluvial deposition followed by tectonic inversion. A diapiric upper-mantle upwelling model is proposed to explain the dynamics that controlled the multiple rifting processes, the cyclic volcanism, and the periodic tectonic evolution of Nanpu Sag and the greater Bohai Bay Basin.

Deep-water plays of the Mauritanian continental margin

The coastal basin of Mauritania is emerging as a potential major petroleum province as a result of renewed exploration activity over the past five years. Two significant discoveries of oil and gas have been made at Chinguetti and Banda, proving that an effective petroleum system exists in this passive margin basin. The successful play type comprises Miocene turbidite channel reservoirs, sealed by fine-grained channel abandonment facies or a hemipelagic shale drape. The most prospective structures are associated with diapiric salt, although a variety of other structural styles, including compressional toe thrusts and rotated extensional fault blocks, are also present. The only source rocks proven to be effective in the immediate area occur in Cenomanian to Turonian deep-marine mudstones. However, regional evidence suggests that other intervals, including the Albian and the Paleocene, may also contain source facies. Future drilling campaigns by Woodside and other operators in the region will focus on realizing the value of existing discoveries through appraisal and tie-back exploration, while at the same time targeting new plays, particularly Late Cretaceous turbidites. Some of the major challenges to would-be petroleum explorers and producers in this basin centre around operating in a remote location almost totally lacking in infrastructure, and conducting activities in an environmentally responsible and sustainable manner.

Angola Block 18: a deep-water exploration success story

Offshore Angola Block 18 was awarded to Amoco in October 1996 for an initial four-year exploration period with an associated four well commitment. This was subsequently extended in October 2000 for an additional three years and further two well commitment. Ownership is BP (operator) 50% and Shell 50%. The block covers an area of 4880 km 2 , the equivalent of some 35 UKCS blocks. Water depths range from 200m in the east to over 1600m in the west. Block 18 is almost entirely covered by over 5000 km 2 of high quality 3D seismic data. Exploration activity has, to date, focused on the western part of the block lying in 1200–1600m of water on the southward extension of the successful Tertiary play from Blocks 15 and 17. Reservoir targets occur in Miocene and Oligocene submarine slope channel sands associated with the evolving Congo River cone. Charge is derived from Upper Cretaceous–Tertiary marine shales of the Iabe Formation. Dominant trap styles are combined structural and stratigraphic domes and turtles associated with movement of Aptian salt. Since the BP–Amoco merger in January 1999, six exploration wells have been drilled to fulfil the first and second phase exploration commitments (Platina, Plutonio, Galio, Paladio, Cobalto & Cromio) all of which have been significant oil discoveries in turbidite channel and sheet sands of Miocene and Oligocene age. Given an unprecedented six discoveries out of six wells, it is clear that the working Tertiary fairway in Block 17 extends south into Block 18. Keys to success have been rapid integration of BP’s Block 15 and 17 experience with existing Amoco interpretation and technologies in Block 18. The learnings from the successful exploration campaign in Block 18 Angola, specifically in the use of high quality 3D seismic attributes as a risk reduction tool, have application in deep-water plays elsewhere, such as the Tertiary and Upper Cretaceous of the North Sea and offshore mid Norway.

Coal as a source rock for oil: a review

The geological debate about whether, and to what extent, humic coals have sourced oil is likely to continue for some time, despite some important advances in our knowledge of the processes involved. It is clear that not only liptinites, but also perhydrous vitrinites have the potential to generate hydrocarbon liquids in the course of natural coalification. Some liptinites, especially alginite, cutinite, and suberinite, contain a higher proportion of aliphatic moieties in their structure than other liptinites such as sporinite and resinite and are, therefore, more oil-prone. It is of potential value to be able to predict the several environments of deposition in which coals with high liptinite contents or containing perhydrous vitrinites may have been formed. Review of the distribution of oil-prone coals in time and space reveals that most are Jurassic–Tertiary with key examples from Australia, New Zealand, and Indonesia. Methods based both on experimental simulations and the examination of naturally matured samples have been used to determine the order of generation of hydrocarbons from different macerals. Results are not entirely consistent among the different approaches, and there is much overlap in the ranges of degradation, but it seems probable that in the natural environment vitrinites begin to generate early, followed by labile liptinites such as suberinite, then cutinite, sporinite, and, finally, alginite. Petroleum potential may be determined by experimental simulation of natural coalification or inferred through various micro-techniques, especially fluorescence and infrared (IR) spectroscopy, or bulk techniques such as elemental analysis and 13C NMR spectroscopy. The latter three techniques enable a measure of the polymethylene component of the coal, which now appears to be one of the best available approaches for determining petroleum potential. No method of experimental simulation of petroleum generation from coals is without criticism, and comparative results are highly variable. However, hydrous pyrolysis, confined pyrolysis, and forms of open-system hydrous pyrolysis approach acceptable simulations. Whether, and to what degree generated liquid hydrocarbons are expelled, has long been the central problem in ‘oil from coal’ studies. The structure of vitrinite was believed until recently to contain an interconnected microporous network in which generated oil would be contained until an expulsion threshold was attained. Recent studies show the pores are not interconnected. Combined with a dynamic model of pore generation, it now seems that expulsion of hydrocarbons is best explained by activated diffusion of molecules to maceral boundaries and ultimately by cleats and fractures to coal seam boundaries. The main reason for poor expulsion is the adsorption of oil on the organic macromolecule, which may be overcome (1) if coals are thin and interbedded with clastic sediments, or (2) if the coals are very hydrogen-rich and generate large quantities of oil. The existence of oil in vitrinite is attested to by solvent extractions, fluorescence properties, and by microscopic observations of oil and bitumen. Experimental simulation of expulsion of oil from coals has only recently been attempted. The relative timing of release of generated CO 2 and CH 4 could have considerable importance in promoting the expulsion of liquid hydrocarbons but the mechanism is unclear. As it is universally agreed that dispersed organic matter (DOM) in some shales readily generates and expels petroleum, it is curious that few consistent geochemical differences have been found between coal macerals and DOM in interbedded shales. Unambiguous evidence of expulsion from coals is limited, and in particular only a few commercial oil discoveries can be confidently correlated to coals. These include Upper Cretaceous Fruitland Formation coals in the USA, from which oil is produced; New Zealand Tertiary coals; and Middle Jurassic coals from the Danish North Sea. It is likely that coals have at least contributed to significant oil discoveries in the Gippsland Basin, Australia; in the Turpan Basin, China; and in the Kutei and Ardjuna basins in Indonesia, but this remains unproven. Early reports that early Jurassic coals in mid-Norway were a major source of the reservoired oils have been shown to be inaccurate. None of the proposed ‘rules of thumb’ for generation or expulsion of petroleum from coals seem particularly robust. Decisions on whether a particular coal is likely to have been an active source for oil should consider all available geological and geochemical information. The assumptions made in computational models should be well understood as it is likely with new understandings of processes involved that some of these assumptions will be difficult to sustain.