Offshore Exploration Activities Research Articles

Depositional model of the Holocene coquinas - Albardão platform, southern Brazil

For the past decade, giant deepwater oil discoveries in the pre-salt section of the Campos and Santos basins of Brazil, have brought significant attention to offshore exploration activities along the South Atlantic margins. The prolific Cretaceous coquina deposits in these basins are part of the pre-salt rock record and constitute an effective but complex and heterogeneous hydrocarbon reservoir difficult to predict and model. Parting from this context, an evaluation of the sedimentological, structural and taphonomic criteria for coquinas are essential to better understand and predict the facies distribution and depositional models of the pre-salt coquinas strata. Based on this premise, the present work aims to genetically interpret 133 mixed carbonate-siliciclastic bottom sediments of the Albardão shelf – a modern marine coquina analogue, using facies description, investigating the relationship with hydrodynamic forces, and accessing the influence of morphology and structural framework on their deposition. From these analyses, we recognized a hybrid facies, three modern carbonate facies in analogy to the carbonate rock classification and four siliciclastic facies. These eight facies were then grouped into three facies associations representing high, moderate, and low energy facies. The high energy facies association comprises rudstones (Rf) and grainstones (Gf) with highly fragmented bivalve shells and barnacles abundantly present in the beach system, above the fair-weather wave base limit (FWWB). These facies also occur offshore on bathymetric highs above the storm wave base limit (SWB) but display less reworking than the coastal high energy facies above the FWWB due to wave shoaling. The moderate energy facies association consists of hybrid sand (Hs), sand (S) and muddy sand (mS) occurring between the FWWB and SWB limits in the offshore transition zone with extensive winnowing action and low rate of reworking. The low energy facies association includes sandy mud (sM), mud (M) and micritic mud (Mc), characterized by the decantation of the fine sediments below the offshore SWB limit. The results confirm a bottom facies distribution controlled by depth, shelf profile morphology and energy from incident waves. The fragmented rudstone and fragmented grainstone facies are the best-recognized reservoirs with both having high porosity and high permeability.

Pathways of Oil Spills from Potential Cuban Offshore Exploration: Influence of Ocean Circulation

The DeepWater Horizon oil spill in the Gulf of Mexico (GoM) in 2010 raised the public awareness on potential spills from offshore exploration activities. It became apparent that knowledge of potential oil pathways in the case of a spill is important for preparedness and response. This study focuses on such scenarios from potential oil spills in the Cuban Exclusive Economic Zone (EEZ), a vast area in the GoM and the Straits of Florida that has not received much attention in oil spill studies, even though this region has been under evaluation for oil exploration. The Cuban EEZ is also in the crossroads of heavy tanker traffic, from the areas of intense oil exploration in the Northern GoM to the adjacent Caribbean Sea and Atlantic Ocean. The study also evaluates how the oil transport and fate are influenced by the main circulation patterns of the GoM, such as the Loop Current (LC) system and the mesoscale dynamics inside the Straits of Florida, such as the Florida Current (FC) and the accompanying cyclonic (along the northern Straits) and anticyclonic (along the Cuban coasts) eddies. We used oil spill numerical simulations, in tandem with high resolution data-assimilative ocean simulations, to test the fate of potential oil spills originating from different release sites within the Cuban EEZ during a six-year period (2011–2016) to exhibit certain aspects of interannual variability of ocean dynamics. The LC extended and retracted phases in the GoM interior revealed different impacts on the oil fate depending on the release site. The meandering of the FC, which is strongly related to the mesoscale eddies that evolve inside the Straits of Florida, controlled oil pathways either towards the northern Straits or along the Cuban coast. The most likely scenario for oil stranding at southern Florida is from oil released at the deep central Straits of Florida. Oil release near the Yucatan Strait and in the deep Gulf interior showed the highest risk of overall oil beaching at the Gulf beaches. The regional (e.g., LC) and local (e.g., eddies in the Straits) dynamics are proven to be significant indicators to predict the oil fate and stranding along the Gulf coasts, which should lead to improving planning and preparedness in the case of a spill in the Cuban EEZ.

SPE Offshore Europe Industry Emerges as Revitalized, Digitally Motivated

SPE Offshore Europe 2019 brought together a noticeably upbeat set of 38,000 industry participants from all over the world during the first week of September. Held in Aberdeen, Scotland, attendance at the conference and exhibition was markedly higher than the 2017 event, which came on the heels of an industry downturn. Sustainability and the industry’s license to operate were primary themes during the conference, reflecting Europe’s aggressive commitment to the energy transition. But offshore technologies—especially those digital in nature—continued to carry the conversation among participants, who remain determined to make upstream work in the North Sea and elsewhere safer, more reliable, and more economical. • Hurdles to AI Adoption Transcend the Technical Stephen Whitfield, Associate Editor The concept of artificial intelligence (AI) has been around for several decades, but it’s only recently that discussion of its capabilities have escaped the realm of science fiction, as platforms have begun to permeate nearly every level of our day-to-day lives. Speaking at a panel discussion, Oil & Gas Technology Centre CEO Collette Cohen said AI tools could lead to big improvements in operational•efficiency. “If we got it right, and we really got involved, we could have safe operations, cheaper operations, and have huge cost savings,” she said. “With all of the bounty of data that we have, this would seem like the perfect opportunity to apply AI.” • As Oil and Gas Data Multiply, So Do the Cybersecurity Threats Matt Zborowski, Technology Editor The downside of the proliferation of data-fueled digital technologies in the oil and gas industry is the accompanying deluge of new cybersecurity threats. Internet of Things (IoT) devices are becoming commonplace as sensors and edge processing pervade the oil field. Data lakes now hold petabytes upon petabytes of reservoir and operational data in the cloud. Digital systems are being integrated across different wellsites, different business units, and different companies, including legacy systems that were not designed with security in mind. And with these changes come more opportunities for threat actors to gain access to critical information and equipment. • For Subsea Technology, “Necessity is the Mother of Invention” Matt Zborowski, Technology Editor The UK and Norwegian sectors of the North Sea have served as proving grounds for subsea technology. There, operators and service companies have spent decades overcoming a complicated mix of technical hurdles related to depth, pressure, temperature, and lithology to expand the region’s oil and gas bounty. As with other upstream segments, the financial crunch felt offshore in the region during the oil-price downturn only served to accelerate innovation, but many challenges remain. Offshore exploration activity is lower, field sizes are smaller, the “easy” oil and gas has already been extracted, and oil markets are still in flux. Natural Language Processing Improves Operational Risk Management Stephen Whitfield, Associate Editor Safe and efficient operations on an offshore facility require careful planning, often taking into account current conditions and the risk potential of any particular job. In the past, Equinor manually consulted multiple data systems with separate user interfaces to get a view of a facility’s technical status and previous incidents. On top of the time-consuming nature of such work, planners still could not get a complete overview of the full asset status, leading planners to focus individually on the tasks within their disciplines.

The hydrocarbon potential of the 2016 proposed Offshore Acreage Release Areas for petroleum exploration

The Australian Government usually releases new offshore exploration acreage once a year. The proposed 2016 Release Areas are located across various offshore hydrocarbon provinces and include mature basins with ongoing oil and gas production as well as exploration frontiers. In support of the annual acreage release, Geoscience Australia provides a variety of geological information with an emphasis on basin evolution, stratigraphic frameworks, and overviews of hydrocarbon prospectivity. Geoscience Australia’s petroleum geological studies are aimed at the evolution of hydrocarbon-bearing basins at a regional scale, and include a review of source rock occurrences, their distribution and geochemical characters. Following the recent oil discovery in the Roebuck Basin, a strong focus of Geoscience Australia’s work is being placed on the Triassic period, and any new findings will directly underpin the release of new exploration acreage. Recent updates to stratigraphic frameworks and new results from geochemical studies are regularly published, and are used by Geoscience Australia for prospectivity assessments. Furthermore, the Australian Government continues to assist offshore exploration activities by providing ready access to a wealth of geological and geophysical data.

A review of oilfield scale management technology for oil and gas production

Abstract The presence of formation water and the treatment methods (both water flooding and chemical treatments) employed during exploration and production operations have great potential for mineral scale formation. Scale deposition poses a lot of serious threat in field production and it is a menace to production flow assurance, which in turn reduces the production flow resulting in production losses. Although oilfield scale deposit is a long standing problem, oil and gas industry are facing new challenges in managing scale deposits created during offshore exploration activities in ultra-deepwater and other harsh environments. Traditional onshore chemistries for scale inhibitions are not viable under HT/HP conditions thereby making flow assurance a critical issue for deepwater project development. An ideal management program maximizes hydrocarbon production and minimizes the cost of scale deposits control, thereby maintaining the economic viability of the operations. This paper reviews various types of mineral scale deposits as well as the thermodynamics and kinetics prediction of mineral scale formation potentials. Also, the mitigation strategies of oilfield mineral scale deposits and chemical stimulation techniques used in oil industry to improve well productivity are discussed.

氷海域の石油探鉱―グリーンランドとカヌマス・プロジェクトの例

Activities by man-kind are limited in the Arctic, high latitude place more than North 66°33′, because of its hostile environment. Only military base, scientific observation station, resources production sites and ethnic community exist. Oil and gas E&P activities have been made in limited area such as Timan-Pechora area and Yamal peninsula in Russia, Mackenzie delta in Canada, North-Lope in Alaska and Barents Sea. Especially for offshore exploration activities in Arctic, it is highly affected by sea ice. As observed by satellite image in Arctic, no or less ice affected areas are defined such as Barents Sea and Norwegian Sea. Ice covered area in the Arctic and near of the Arctic requires serious counter measures against sea ice for putting oil and gas exploration into execution. In this lecture, recent oil and gas exploration activities in the ice covered Arctic offshore area are reviewed. In addition, history and challenge for future on new exploration license area in northeast offshore Greenland, where Greenland Petroleum Development Ltd. (GPX), Japanese Joint Venture Company established by JOGMEC, INPEX, JX, JAPEX and MOECO, are discussed. Although increase of exploration activities in Arctic is expected in the days to come, there are several technical challenges and difficulties for matter of environmental protection. It is an important mission for E&P companies to overcome those challenges and difficulties and to promote frontier oil and gas exploration in the Arctic area.

Implementing U.S. Arctic Policy: An Analysis of Federal Recommendations

ABSTRACT We outline U.S. Arctic policy recommendations, goals, and strategic plans promulgated by federal entities in recent years, then analyze the policies and determine the most commonly referenced policy recommendation. This analysis is valuable in the interest of identifying an overall direction for Arctic policy as suggested by the selected federal entities in the United States. We then delve into the oil and gas industry presence in the U.S. Arctic outer continental shelf and the existing federal permitting process by conducting a case study of Shell's 2012 Arctic offshore exploration activities in the Chukchi and Beaufort seas. We conclude with an assessment of key policies and recommend next steps for implementation.

A petroleum geological overview of the 2013 offshore acreage release for petroleum exploration

The Australian Government formally releases new offshore exploration areas at the annual APPEA conference. The previous two releases were characterised by several large, gazetted areas in underexplored regions, a trend that is maintained this year with several frontier areas comprising more than 100 graticular blocks on offer. The recent uptake of new exploration permits in the Bight Basin, the offshore North Perth Basin, and the Roebuck Basin indicates a continuing strong industry interest in offshore frontier exploration. A total of 31 areas in 13 geological provinces are formally released in 2013, and work program bids are invited for two rounds closing on 21 November 2013, and 22 May 2014. Area gazettal was, again, well supported by industry nominations. The areas on offer are represented by an even mix of shallow and deepwater areas, as well as by areas close and distant to previous discoveries and producing fields. The Northern Carnarvon, Browse, and Bonaparte basins dominate new exploration opportunities in the 2013 release, while only four areas were gazetted in the North Perth, Otway, and Gippsland basins. These also deserve attention as they have exploration potential in underexplored parts of the basins and offer opportunities to test new play concepts. Data coverage varies from being excellent in more mature areas to sparse in underexplored areas such as the North Perth Basin. The Australian Government continues to assist offshore exploration activities by providing free access to a wealth of open-file geological and geophysical data.

A Cost Effective and User Friendly Approach to Design Wireline Formation Tests

Problem statement: Wireline formation testing (also named Mini-DSTs) are gaining more and more popularity as a possible alternative to co nventional well testing especially where there are major environmental and economical constraints. The increased offshore exploration activity, which often implies highly risky and huge operational cos ts, makes the conventional well testing less attractive in favor of other technologies that can provide some of the key dynamic information about the well-reservoir system through relatively quick and less expensive operations. The design phase is recognized to be one of the most critical aspects i n order to guarantee an acceptable value of information in exploration scenarios where very lim ited data is available. The success of any mini- DST operation can be significantly compromised if t wo major issues are not addressed in the design phase: possibility to clearly identify the radial f low behavior and avoidance of noise in the pressure response due to the gauge resolution. Approach: The study consisted in the development of a new too l for mini-DST design to easily identify whether this technology can be successfully applied. The tool comprises dimensionless and dimensional charts, which are of general validity because they can be applied to any lithological environment and for any type of hydrocarbon. Results: Field applications proved the reliability of the charts: First of all the test durations were optimized to collect interp retable bottomhole pressures and to obtain valid reservoir characterizations. Besides, a cost saving effectiveness was achieved avoiding the acquisition of useless extra-data affected by noise due to gauge resolution. Conclusion/Recommendations: The use of the charts is strongly suggested at the early stage of decision making for new exploration/ appraisal operations; they are a user-friendly tool for assessing the feasibility of a mini-DST test. A dditionally, the charts are more versatile with res pect to available commercial software in managing uncertainties of the major input parameters.

EXPLORATION HIGHLIGHTS FOR 2006

Key business indicators show an upward trend in exploration activity in Australia during 2006. The year was marked by fluctuating high oil prices, a strong uptake of acreage in most basins, and increased levels of drilling activity and seismic acquisition. Market demand for product, production infrastructure and the fruition of several development projects have pushed the level of exploration activity in both offshore and onshore basins. Despite this trend and the spread of tenements, almost all petroleum discoveries made during 2006 were located within 15 km of existing (but often undeveloped) fields.The Carnarvon Basin continued to be the focus of most offshore exploration activity during 2006, with the highest levels of 3D seismic acquisition and exploration/appraisal/development drilling in the country. Discoveries in the Carnarvon Basin also covered the broadest range of water depths—extending from the oil and gas discoveries made by Apache on the inboard margin of the Barrow Subbasin, to the deepwater gas discoveries at Clio–1 and Chandon–1 by Chevron. Several large gas discoveries were made in the Carnarvon and Bonaparte basins and provide significant tie-back opportunities to existing and planned infrastructure. The Bonaparte Basin also saw significantly increased levels of 2D and 3D seismic acquisition during 2006. Onshore, the Cooper/Eromanga basins continued to experience the highest level of drilling activity and seismic acquisition, while maintaining an overall high drilling success rate. For the first time in many years, data acquisition also occurred in frontier basins like the Daly (Northern Territory), Darling (New South Wales), Tasmanian (Tasmania) and Faust/Capel basins (Lord Howe Rise region).Coal seam methane (CSM) exploration maintained a strong performance in 2006, particularly in Queensland, while South Australia, Queensland and Victoria continue to lead the way with large tracts of acreage gazetted for geothermal energy exploration.

Combined geophysical acquisition methods heighten hydrocarbon prospectivity of the Sea of Okhotsk

Erling M. Frantzen and Kjell E. Trommestad, TGS-NOPEC Geophysical Company, explain how a modern marine 2D seismic data being acquired in a multi-client survey in the Sea of Okhotsk is being combined with gravity and magnetic data to challenge previous ideas about the limited petroleum prospectivity offshore Far East Russia. Numerous onshore discoveries beginning with the revelation of the Okha field on Sakhalin Island in 1923 have indicated that active petroleum systems underlie a large part of the Sea of Okhotsk, a mostly unexplored epicontinental sea covering a 900 km x 1200-km area in the Russian Far East. When the Tockinsky 1 well encountered a significant oil show at a depth of 800 m on the Kamchatka peninsula in 1932, it touched off more than three decades of exploration in the region and by 1971, 35 onshore oil, gas, and condensate discoveries had been reported. Offshore exploration activity in the Sea of Okhotsk was initiated in the early 1970s and for the most part has been limited to areas offshore Sakhalin Island. Significant oil and gas discoveries offshore Sakhalin, including Odoptu in 1977, Chaivo in 1979, Lunskoye in 1984, Piltun-Astokhskoye in 1986, and Arkutun-Dagi in 1989, established offshore Sakhalin as a world-class hydrocarbon province with reserves exceeding 5.5 billion barrels of oil and 35 trillionft3 of gas. Total reserves in place in the area were estimated to be more than 90 billion barrels of oil equivalent in a narrow corridor east of the Sakhalin Island, where all of the above discoveries are located. Several international exploration companies joined the hunt in the late 1980s and early 1990s, including BP, ChevronTexaco, ExxonMobil, Rosneft, Shell, and others. A joint venture of BP and Rosneft announced in October 2004 that the Pela Lache 1 wildcat well had encountered significant volumes of oil and gas in several high-quality sandstone reservoirs on the 6000 km2 Kaigansky-Vasukansky exploration licence block about 40 km northeast of Sakhalin, marking the first successful drilling activity outside the established fairway offshore Sakhalin in what is considered the modern era of oil and gas exploration. BP and Rosneft announced in October 2005 that a second exploratory well, Udachnaya 1, had encountered hydrocarbons in three zones at a surface location about 15 km west of the Pela Lache 1 wildcat.

秋田‐新潟海域油・ガス探鉱への地震探査の寄与―１９６０年代後期からの２０年を振り返って―

Until the digital processing of seismic data was introduced to Japan in 1968, Japanese geologists had no means but to depend on the seismic depth profiles which displayed very short lines showing inclination of reflection planes picked up by seismologists. There was only a small discovery of the Tuchizaki-oki field those days. After the air-gun and digital processing became available in 1968, offshore exploration activities expanded and led to the discovery of the Aga-oki field in 1972. From the viewpoint of seismology, this discovery was based on stack sections and “hand-made depth sections” which displayed continuous curves indicating prominent reflections. Abnormal reflection patterns such as bright spots, flat spots and pull down began to attract geologists' attention in the mid-1970s, and various processing menus in addition to depth profiles were provided for geologists. In 1981, certain abnormal patterns were found in seismic record sections obtained in 1973, an exploratory well, Iwafune-oki SIM-1 was drilled at the center ofthe distribution area of such anomalies and became the discovery well of the Iwafune-oki field.Based on these experience, I emphasize the importance of stack sections in conjunction with wide and deep geological knowledge and thought.-Oil and gas fields are present in geologists' brains-

1998 EXPLORATION REVIEW—GEOLOGICAL SIGNIFICANCE OF NEW DISCOVERIES AND DEVELOPMENTS

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.