Journal articles on the topic 'Norse Discovery and exploration'

Rapid advances in the seismic exploration method have allowed its application in metallic mineral exploration. However, 2D seismic profiles are often insufficient to describe the shape and areal extent of ore-bearing rock masses away from survey lines. Although more complete, collecting 3D seismic data is expensive, time consuming, and may require considerable investment in surface access. The combination of ambient noise tomography and 2D seismic reflection exploration methods can produce acceptable results relatively quickly and at a low cost. The enormous Ashele copper deposit in northwest China is a typical deposit formed by volcanic eruption. It is rich in resources and possesses good prospecting potential in its deeper and peripheral areas. We performed ambient noise tomography to investigate a near-surface 3D S-wave velocity ([Formula: see text]) structure above a depth of 0.7 km in the Ashele mining area (approximately 8 × 12 km) using 25 days of continuous ambient noise data. From the combined interpretation of the 3D [Formula: see text] structure and the existing 2D seismic reflection profile, we infer that there may be ore-bearing rock masses in the western and northern sides of the research area. We report the discovery of an ancient volcano at a depth of 500 m on the western side of this region. The banded velocity anomalies and the existence of the ancient volcano signify the formation process of a bimodal volcanic rock association. It has been proven that the combination of ambient noise tomography and 2D seismic reflection exploration methods can produce important results in metallic mineral exploration. Therefore, ambient noise tomography can be used as an economical, convenient, and efficient method for future explorations, complementing the 2D seismic reflection exploration method.

There are mass data in geology exploration, but it is vital to find useful information or knowledge from these data. This paper is concerned with the analysis of the seismic data by the multi-channel wiener filter algorithm and the wavelet denoising method using neighboring coefficients. Known the velocity of reflection event, utilizes the resemblance of reflection signals in each seismic trace, the multi-channel wiener filter algorithm is effective in enhance reflection events and suppress the random noise. But the wavelet denoising methods don’t need any assuming conditions. The computed simulations of these two kinds of algorithms are provided to prove the availability.

Noise is a basic ingredient in data, since observed data are always contaminated by unwanted deviations, i.e., noise, which, in the case of overdetermined systems (with more data than model parameters), cause the corresponding linear system of equations to have an imperfect solution. In addition, in the case of highly underdetermined parameterization, noise can be absorbed by the model, generating spurious solutions. This is a very undesirable situation that might lead to incorrect conclusions. We presented mathematical formalism based on the inverse problem theory combined with artificial intelligence methodologies to perform an enhanced sampling of noisy biomedical data to improve the finding of meaningful solutions. Random sampling methods fail for high-dimensional biomedical problems. Sampling methods such as smart model parameterizations, forward surrogates, and parallel computing are better suited for such problems. We applied these methods to several important biomedical problems, such as phenotype prediction and a problem related to predicting the effects of protein mutations, i.e., if a given single residue mutation is neutral or deleterious, causing a disease. We also applied these methods to de novo drug discovery and drug repositioning (repurposing) through the enhanced exploration of huge chemical space. The purpose of these novel methods that address the problem of noise and uncertainty in biomedical data is to find new therapeutic solutions, perform drug repurposing, and accelerate and optimize drug discovery, thus reestablishing homeostasis. Finding the right target, the right compound, and the right patient are the three bottlenecks to running successful clinical trials from the correct analysis of preclinical models. Artificial intelligence can provide a solution to these problems, considering that the character of the data restricts the quality of the prediction, as in any modeling procedure in data analysis. The use of simple and plain methodologies is crucial to tackling these important and challenging problems, particularly drug repositioning/repurposing in rare diseases.

KrisEnergy Pumps Cambodia’s First Crude in 17 Years A Cambodian concession has commenced production after years of delays in a venture between Singapore’s KrisEnergy and the government. The crude comes from oil fields in Block A, comprising 3083 km2 of the Khmer basin in the oil-rich Gulf of Thailand, off the southwestern coast of Sihanoukville. The concession will progress in phases once new wells are commissioned and completed. Kelvin Tang, chief executive of KrisEnergy’s Cambodian operations, called the 29 December event “an important strategic milestone” for the company, while Prime Minister Hun Sen hailed the first extraction as “a new achievement for Cambodia’s economy” and “a huge gift for our nation.” Ironbark Australian Exploration Well Declared Dry; Co-Owner Stocks Plummet BP has come up dry at its Ironbark-1 exploration well, the anticipated multi-trillion-scf prospect off the west Australian Pilbara coast. The disappointing prospect was once seen as a potential gas supplier to the emptying North West Shelf (NWS) LNG plant, where BP is a co-owner, within 5 to 10 years. After 2 months of drilling to a total depth of 5618 m, “no significant hydrocarbon shows were encountered in any of the target sands,” according to co-owner New Zealand Oil and Gas (NZOG). Petrorecôncavo Buys Petrobras’ Onshore Bahian Stake for $30 Million Brazilian operator Petrobras on 23 December signed a contract with independent producer Petrorecôncavo to sell its entire stake in 12 onshore E&P fields, the Remanso Cluster, in the state of Bahia. The sale value for the fields was $30 million; $4 million was paid on signing, $21 million at the closing of the transaction, and $5 million will be paid 1 year after that. The Remanso Cluster comprises the onshore fields of Brejinho, Canabrava, Cassarongongo, Fazenda Belém, Gomo, Mata de São João, Norte Fazenda Caruaçu, Remanso, Rio dos Ovos, Rio Subaúma, São Pedro, and Sesmaria. Zion Spuds the Israeli Megiddo-Jezreel #2 Well On 6 January, Zion Oil and Gas officially spudded the Megiddo­Jezreel #2 on its 99,000­acre Megiddo­Jezreel license area in Israel. “With unique operating conditions in the COVID­19 environment, our crews have performed an amazing task,” Zion CEO Robert Dunn said. “Mobilizing a rig into a new coun­try during a pandemic and rigging up is the most challenging part of the drilling operation,” Zion’s vice president of operations, Monty Kness, added. Exxon Declares a Dud at Second Guyana Well Exxon Mobil said on 15 January that its exploration well in the prolific Stabroek Block off Guyana’s coast did not find oil in its target area. Exxon, which operates the Stabroek Block in a consortium with Hess and China’s CNOOC, has made 18 discoveries in the area in 5 years, totaling more than 8 billion BOE, for a combined potential for producing up to 750,000 B/D of crude. The Hassa­1 exploration well was the giant’s second setback to its drilling campaign in recent months. Heirs Holdings Buys 45% of Shell Nigeria’s OML 17 Field Shell Nigeria announced on 15 January it had completed a $533 million sale of its stakes in an onshore OML 17 oil field in Nigeria to African strategic investor Heirs Holdings, Nigeria’s largest publicly listed conglomerate. The deal is one of the largest oil and gas financings in Africa in more than a decade, with a financing component of $1.1 billion provided by a consortium of global and regional banks and investors. Heirs Holdings, in partnership with Transcorp, one of the largest power producers in Nigeria with 2000 MW of installed capacity, purchased 45% stake in the field. It acquired the stakes of Shell, Total, and Eni to further its expansion into the oil and gas industry. Apex Discovers Oil in Egypt’s Western Desert Privately held independent E&P firm Apex International Energy, backed in part by UK energy investment firm Blue Water Energy, on 18 January announced a discovery in the Southeast Meleiha Concession (SEM) in the western desert of Egypt. The discovery was made at the SEMZ-11X well located 10 km west of Zarif field, the nearest producing field. The well was drilled to a total depth of 5,700 ft and encountered 65 ft of oil pay in the Cretaceous sandstones of the Bahariya and Abu Roash G formations. Testing of the Bahariya resulted in a peak rate of 2,100 B/D with no water. Additional uphole pay exists in the Bahariya and Abu Roash G formations that can be added to the production stream in the future. Kosmos Announces Oil at Winterfell Well Dallas-based E&P independent Kosmos Energy announced on 19 January an oil discovery in deepwater US Gulf of Mexico. The Winterfell discovery well, the product of infrastructure-led exploration (ILX), was drilled to a total depth of approximately 23,000 ft and is located in approximately 5,300 ft of water. This subsalt Upper Miocene prospect in off-shore Louisiana encountered approximately 85 ft of net oil pay in two intervals. ILX exploration, which has featured prominently in upstream operators’ portfolios in recent years of relatively low oil prices, is exploration around producing hubs that can be hooked up to those facilities easily and cheaply. The development sidesteps the need for costly and time-consuming individual hub construction. Equinor Gets Permit To Drill North Sea Wildcat Well The Norwegian Petroleum Directorate has granted Equinor a drilling permit for wildcat well 31/11-1 S in the North Sea offshore Norway, 62 km south of the Troll field. The drilling program is the first exploration well to be drilled in production license 785 S, awarded on 6 February 2015 (APA 2014). Operator Equinor and Total E&P Norge are 50/50 partners in the license, which consists of parts of Blocks 26/2 and 31/11. Petrobras, ExxonMobil Hit Hydrocarbons at Urissanê Well, Offshore Brazil Brazilian state-owned Petrobras announced on 29 January it had discovered hydrocarbons in a well located in the Campos Basin presalt off Brazil’s coast of Campos dos Gotyacaze in the State of Rio de Janeiro. Well 1-BRSA-1377-RJS (informally called Urissanê) is located in Block C-M-411, at a depth of 2950 m approximately 200 km offshore. Petrobras, which operates the block in a 50/50 partnership with Exxon Mobil, said it would analyze the well data to better target exploratory activities and assess the potential of the discovery. BP Offloads 20% Share of Oman’s Block 61 To PTTEP Marking another significant step in its divestment program, BP will sell a 20% participating interest in Oman’s 3950 km2 Block 61 in central Oman to Thailand’s national PTT Exploration and Production (PTTEP) for $2.59 billion. BP will remain operator of the block, holding a 40% interest.‎ The sale comprises $2.45 billion payable on completion and $140 million payable contingent on preagreed conditions.‎ After the sale, BP will hold 40% interest in Block 61, while OQ holds 30%, PTTEP ‎20%, and ‎Petronas 10%.‎ Block 61 contains the largest tight gas development in the Middle East.

Exploration efforts in the Nordland Ridge over the past two decades have resulted in the Norne, Urd, Alve, Falk, and Linerle discoveries. Besides these discoveries, several wells have failed expectations. Exploration efforts in this area are challenging because of the large variation in the rock properties of potential Triassic to early Jurassic traps that could be filled with viscous (heavy) oil. Application of controlled-source electromagnetic (CSEM) technology to derive the electrical resistivity distribution of the subsurface was thought by some oil companies to be the key that could unlock the exploration potential in the area. However, two dry wells in 2006 (6608/11-5 “Valkyrie”) and 2011 (6608/11-7s “Phoenix”) drew negative attention to CSEM within the exploration community because CSEM data were available in both cases prior to drilling. The wells targeted Jurassic Åre sands very close to the existing Linerle discovery with heavy oil in reservoir-quality Åre sandstones. The first well encountered less than 5 m of hydrocarbon traces in the Åre sands, while the second well was dry with a poorer-than-expected reservoir at target depth. This work examines the quality and reliability of the most recently acquired 3D CSEM survey. Previous interpretations are discussed in light of the 3D data and the latest drilling results. The CSEM-derived distribution of resistivity in the subsurface is in good agreement with all well log data proving that CSEM provides reliable information that can be used for interpretation and decision making. A strong and localized resistivity anomaly remains untested, although the last two wells drilled very close to it. Two interpretations were evaluated to explain the measured resistivity. The first inferred the presence of a localized sabkha evaporite in the late Carnian, while the second suggested the presence of a hydrocarbon-filled reservoir in erosional products near the base Cretaceous unconformity.

Tullow Swings and Misses off Guyana Tullow Oil has come away empty with its Beebei-Potaro exploration well, drilled in the Kanuku license, offshore Guyana. According to the company, the well encountered good quality reservoir in the primary and secondary targets but both targets were water-bearing. Noble jackup Regina Allen drilled the well to a total depth of 4325 m in 71 m of water. The well has been plugged and abandoned. Tullow will integrate the well results into its regional subsurface models and work with its joint venture partners before deciding on next steps. Repsol is the operator of the Kanuku license with a 37.5% working interest. Tullow holds 37.5% with TOQAP—a joint venture between TotalEnergies and Qatar Petroleum—holding 25%. Tullow previously said it would limit capital exposure in Guyana. The company holds a 60% interest in the Orinduik block, its other licensed area in Guyana, with partners including TotalEnergies and Eco Atlantic Oil & Gas. Oxy Brings Horn Mountain West Online in GOM Occidental has successfully turned the taps on its Horn Mountain West subsea field in the Mississippi Canyon area of the Gulf of Mexico (GOM). The field is in about 5,400 ft of water. The $250-million project comprises a pair of wells tied back to the existing Horn Mountain spar in Block 126 via a 3½-mile dual flowline. According to Oxy, the project came in on budget and 3 months ahead of schedule. It is expected to eventually add approximately 30,000 BOPD. Horn Mountain initially came on stream in late 2002. Hess Strikes Miocene-Aged Oil at Huron in GOM Hess made an oil discovery with a well at its Huron prospect in the Green Canyon area of the deepwater GOM. The well, drilled in Block 69 to a target depth of 28,900 ft by Transocean drillship Deepwater Asgard, struck high-quality, oil-bearing Miocene-aged reservoirs and established the existence of a working petroleum system. An up-dip sidetrack to the initial probe is planned. Gregory Hill, Hess’ chief operating officer, told investors in July that … “as a result of what we’re seeing at Huron we see additional prospectivity in that northern Green Canyon area, and we have a very competitive leasehold position there.” The company had stated previously that its position in the northern Green Canyon area has a high potential for multiple, high-return hub-class Miocene opportunities. Hess operates Huron with a 40% interest. Partners Chevron and Shell each hold 30% stakes. Hess struck a deal with both Chevron and Shell to farm into the prospect in February 2022. The Huron well marks Hess’ return to exploration drilling in the deepwater GOM for the first time in around 2 years. Wintershall Dea Turns the Taps at Nova Wintershall Dea started production from the Nova oil field in the Norwegian North Sea. The field comprises two subsea templates, one with three oil producers and one with three water injectors, tied back to the Gjøa platform. The expected recoverable gross reserves from the field are estimated at 90 million BOE, of which the majority will be oil. The operator said the completion of Nova emphasizes its strength as one of the largest subsea operators on the Norwegian Continental Shelf. “With the startup of the major project Nova, Wintershall Dea is now operating three subsea production fields in Norway,” said Hugo Dijkgraaf, member of the executive board and chief technology officer. The Dvalin field and the partner-operated Njord Future project, in which Wintershall Dea holds a 50% share, are planned to come on stream later this year. The company also operates recent discoveries like Dvalin North, planned for PDO hand-in (Plan for Development and Operations) by the end of 2022, and several other discoveries which could be developed in the future. Wintershall Dea is a partner in the Aker BP-operated Storjo discovery in the Norwegian Sea. Wintershall Dea operates the Nova field with a 45% stake, of which it plans to transfer 6% to OKEA in Q4 this year; Sval Energi holds 45%, Pandion Energy Norge, 10%. Eni Touts Potential 3.5-Tcf Gas Find With First Offshore Abu Dhabi Well Eni believes it has discovered an additional 1.0 to 1.5 Tcf of raw gas in place, in a deeper zone, in its first exploration well drilled in Offshore Block 2 Abu Dhabi. The discovery follows an initial finding in a shallower zone of the same well, aggregating to a total gas in place of up to 3.5 Tcf. The Italian operator said gas-bearing reservoirs were tested with excellent flow rates and fast-track development options are currently under evaluation. Eni, operator, holds a 70% stake in Block 2; PTTEP holds the remaining 30%. Eni has been present in Abu Dhabi since 2018. It operates three exploration concessions and participates with ADNOC in three offshore development and production concessions: Lower Zakum (5%), Umm Shaif and Nasr (10%), and Ghasha (25%). Petrobras Makes Gas Discovery in Colombia Petrobras confirmed the discovery of natural gas accumulation in the Uchuva-1 exploratory well drilled in the deep waters 32 km off the coast of Colombia. The discovery is about 76 km from the city of Santa Marta in a water depth of approximately 830 m. The well was drilled in the Tayrona block, with operator Petrobras (44.44%) in partnership with Ecopetrol, who holds the remaining stake. The consortium will continue its activities in the block to assess the dimensions of the new gas accumulation. CNOOC Successfully Tests Offshore Shale Well China’s CNOOC Ltd. tested commercial flows of oil and gas from an offshore shale exploration well in the South China Sea, marking the first successfully drilled shale oil well offshore China, state media reported in early August. Exploration well Weiye-1, drilled at the southwestern trough of Beibuwan basin, tested daily production of 126 bbl of oil and 1589 m3 of natural gas. CNOOC estimated that the shale oil resources in the entire basin are about 8.8 billion bbl, suggesting good exploration prospects. With the Chinese government stressing added volumes for its domestic energy supply security, national oil companies are making greater efforts to tap shale deposits despite being tougher to drill and more expensive. As of late 2021, China produced only 35,000 B/D of shale oil, mostly in the onshore northern Ordos basin and northwestern Jungar basin. Eni Strikes Oil With Baleine East Well in Côte d’Ivoire Eni has encountered oil with its Baleine East 1X well, the first exploration well in block CI-802 and second discovery on the Baleine structure offshore Côte d’Ivoire. The results have prompted a 25% increase in the oil and gas volumes in place, which are now estimated at 2.5 billion bbl of oil and 3.3 Tcf of associated gas. The well was drilled in the block operated by Eni (90%), together with its partner Petroci Holding (10%), using the drillship Saipem 12000. The final depth reached was 3165 m measured depth, in a water depth of about 1150 m. Baleine East 1X is located about 5 km east of the Baleine 1X discovery well in the adjacent block CI-101 and represents the first commercial discovery in the CI-802 block, confirming the extension of the Baleine field. The well confirmed the presence of a continuous oil column of about 48 m in reservoir rocks with good properties. From the vertical borehole, a horizontal drain of 850 m in length was subsequently drilled into the reservoir to perform a production test that confirmed potential production of at least 12,000 BOPD from the Baleine East 1X well. A third well will be drilled to ensure the accelerated startup of production and confirmation of first oil in the first half of 2023. In addition to blocks CI-101 and CI-802, Eni owns interests in five other blocks in the Ivorian deep water: CI-205, CI-501, CI-504, CI-401, and CI-801, all with the same partner, Petroci Holding. Neptune Energy Kicks Off Ofelia Exploration Well Neptune Energy began drilling operations on the Ofelia exploration well in the Norwegian sector of the North Sea. The well, 35/6-3 S, is being drilled by the Odfjell Drilling-operated semisubmersible Deepsea Yantai. The prospect is located 13 km north of the Gjøa field within the Neptune-operated PL929 License. If commercial, Ofelia could be tied back to the Neptune-operated Gjøa platform and produce at less than half the average carbon intensity of Norwegian Continental Shelf fields, according to the company. Neptune said it could potentially be developed in parallel with Hamlet (PL153). Ofelia is positioned in one of Neptune’s core areas and close to existing infrastructure. The reservoir target is the Lower Cretaceous Agat Formation and is expected to be reached at a depth of approximately 2570 m. The drilling program comprises a main bore (35/6-3 S) with an optional sidetrack (35/6-3 A) based on the outcome of the exploration well. Neptune Energy operates Ofelia with a 40% working interest. Partners are Wintershall Dea (20%), Aker BP (10%), Pandion Energy (20%), and DNO (10%). Partners Continue Successful Drilling in Algerian Desert Eni and partner Sonatrach revealed a further discovery in the Zemlet el Arbi concession, located in the Berkine North Basin in the Algerian desert. The Rhourde Oulad Djemaa Ouest-1 (RODW-1) exploration well, in the Sif Fatima II research perimeter, is the third well in the exploration drilling campaign. It led to a discovery of oil and associated gas in the Triassic sandstones of the Tagi reservoir. During its production test, the well produced 1,300 BOPD and about 2 MMcf/D of associated gas. The RODW-1 discovery comes after the significant discovery of HDLE-1, announced in March 2022, and the successful second appraisal well HDLS-1 in the adjacent Sif Fatima II. Because of their proximity to existing BRN/ROD facilities, the development of these discoveries will be fast-tracked. The Zemlet el Arbi concession is operated by a joint venture between Eni (49%) and Sonatrach (51%). The discovery is part of the new exploration campaign which will include the drilling of five wells in the Berkine North Basin.

Dugong Reserve Estimate Tightens on New Well Results Neptune Energy redefined the estimated reserves at its Dugong discovery in the Norwegian sector of the North Sea to between 40–108 million BOE based on the results of appraisal well 34/4-16 S. Prior to this appraisal, the operator believed the prospect could hold as much as 120 million BOE. The main objective of the well was achieved by establishing the oil/water contact. Neptune Energy said the new range will be subject to further detailed analysis and review, and a drillstem test on the well is planned at a later stage. The appraisal well was drilled using the Odjfell-operated semisubmersible Deepsea Yantai in about 330 m of water. The Dugong discovery will either be linked to nearby infrastructure or developed as a standalone development. Dugong is located 158 km west of Florø, Norway, and is close to the existing production facilities of the Snorre and Statfjord fields. The Dugong license partners are Neptune Energy (operator and 45%), Petrolia NOCO (20%), Idemitsu Petroleum Norge (20%), and Concedo (15%). Oselvar P&A Work Underway Decommissioning of the DNO Norge-operated Oselvar field has kicked off with the operator contracting semisubmersible Borgland Dolphin for plug-and-abandonment work. Oselvar is in the southern part of the Norwegian sector in the North Sea, 20 km southwest of the Ula field. The water depth is 70 m. Oselvar was discovered in 1991, and the plan for development and operation was approved in 2009. The field was developed via a trio of subsea wells tied to Ula. Production started in 2012 and ended in 2018. The Borgland Dolphin was moved to the field on 20 March. The rig recently went through a series of upgrades including the installation of new shale shakers, new standpipe manifold, an upgraded drilling control system, and an upgraded helideck. Decommissioning must be completed by the end of 2022. Equinor Green Lights FPSO for Brazil’s BM-C-33 Development Equinor, together with license partners Repsol Sinopec Brasil and Petrobras, have approved an FPSO-based development concept for BM-C-33, a gas/condensate field located in the Campos Basin pre-salt in Brazil. Subsea wells will be tied back to the FPSO located at the field. Gas and oil/condensate will be processed at the floater to sales specifications and exported. Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A newbuild hull has been selected to accommodate the field’s planned 30-year lifetime. “BM-C-33 holds substantial volumes of gas,” said Veronica Coelho, Equinor’s country manager in Brazil. “A completion of the ongoing liberalization of the natural gas market in Brazil in line with the current plan, is key for the further development of the project. BM-C-33 is an asset that can generate value for the society, both through the creation of direct and indirect jobs, ripple effects, and through a gas supply that can induce industrial growth, as has happened in other countries.” Gas export capacity is planned for 16 million cubic meters per day with average exports expected to be 14 million cubic meters per day. Daily oil processing capacity is of 20,000 cubic meters per day. The gas-export solution is based on an integrated offshore gas pipe-line from the FPSO to a new dedicated onshore gas-receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas-transmission network. Lundin Makes Small Discovery Near Edvard Grieg Lundin Energy Norway encountered a 10-m oil column with its wildcat well 16/4-13 S about 15 km south of the Edvard Grieg field in the central part of the North Sea. The operator added that about 7 m of the encountered column was of moderate to poor reservoir quality. The oil/water contact was encountered 1950 m below the sea surface. The entire reservoir, including the water zone, comprises conglomeratic sandstones in a thickness of about 380 m. Preliminary estimates place the size of the discovery between 0.5 and 1.4 million cubic meters of recoverable oil equivalent. The licensees will assess the discovery regarding a possible tie-in to the Solveig field. The well was drilled by Seadrill semisubmersible West Bollsta and will be permanently plugged and abandoned. The rig will now move to drill the 16/4-BA-1H production well on the Solveig field. Wintershall Gets Permit for Bergknapp Appraisal The Norwegian Petroleum Directorate granted Wintershall Dea Norge a drilling permit for well 6406/3-10 A to spud a follow-up probe to a discovery made in April 2020. The Bergknapp appraisal will be drilled from the Odjfell semisubmersible Deepsea Aberdeen once the rig has concluded the drilling of wildcat well 6507/4-2 S for Wintershall in production license 211. The Bergknapp appraisal will be drilled about 8 km west of the Maria field in the Norwegian Sea. The discovery well 6406/3-10 intersected an oil column of at least 60 m in the Garn formation and an oil column of at least 120 m in the Tilje formation. Preliminary estimates of the Bergknapp discovery indicate it could hold between 26–97 million BOE. The find is in production license 836 S where Wintershall is the operator and holds a 40% stake. The other licensees are DNO Norge (30%) and Spirit Energy Norway AS (30%). The area in this license comprises parts of Blocks 6406/2 and 6406/3. Guyana Says Liza Hits First-Phase Capacity Guyana’s President Irfaan Ali announced that the first phase of the Liza offshore crude project had achieved its intended full-production capacity of around 130,000 B/D. Ali told virtual attendees at the Guyana Basin Summit that he expected an additional 10 exploration and appraisal wells to be drilled off Guyana this year. He said the second phase of the Liza project, operated by ExxonMobil, would begin in 2022. The consortium led by Exxon, which includes partners Hess and CNOOC Ltd., has made 18 discoveries containing more than 8 billion bbl of recoverable oil and gas in Guyana’s Stabroek block. Equinor and Partners in Barents Bounty Equinor and partners Vår Energi and Petoro have struck oil in exploration well 7220/7-4 in production license 532 in the Barents Sea. Recoverable resources are so far estimated at between 31–50 million BOE. The well was drilled about 10 km southwest from the well 7220/8-1 on the Johan Castberg field. “Succeeding in the Barents Sea requires perseverance and a long-term perspective,” says Nick Ashton, Equinor’s senior vice president for exploration in Norway. “This discovery strengthens our belief in the opportunities that exist, not least around the Castberg, Wisting, Snøhvit, and Goliat areas.” The well, drilled by semisubmersible Transocean Enabler, struck 109 m of oil in the Stø and Nordmela formations. The top reservoir was encountered at a vertical depth of 1788 m below sea level. The expected gas cap was not encountered in the well. The well was not formation tested, but extensive data acquisition and sampling took place. Equinor said further development of the discovery toward the planned infrastructure for the Johan Castberg field will be considered at a later stage. Exploration well 7220/7-4 is the first of four planned exploration wells for Equinor in the Barents Sea this year. Eni Strikes Light Oil at Cuica Eni has made a new light-oil discovery in Block 15/06 at its Cuica prospect in the deep waters offshore Angola. The prospect is located inside the Cabaça Development Area and close to the Armada Olombendo FPSO (East Hub). Eni estimates Cuica could hold between 200 and 250 million bbl of oil in place. The Cuica-1 NFW was drilled as a deviated well by Seadrill-operated drillship Sonagol Libongos in 500 m of water and reached a total vertical depth of 4100 m, encountering an 80-m total column of reservoir of light oil (38 °API) in sandstones of Miocene age with good petrophysical properties. The discovery well is going to be sidetracked up-dip to be placed in an optimal position as a producer well. According to Eni, data collection from the well indicates an expected production capacity of around 10,000 BOPD. Cuica is the second significant oil discovery inside the existing Cabaça Development Area. The well location, intentionally placed close to East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production. Eni expects the well could be on line within 6 months. Following the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the relaunch of the exploration campaign post-2020 COVID-19 pandemic. The discovery confirms the exploration potential of the block. A 3-year extension of the exploration period of Block 15/06 was recently granted until November 2023. The Block 15/06 joint venture comprises Eni (operator, 36.8421%), Sonangol P&P (36.8421%), and SSI Fifteen Ltd. (26.3158%). No Injuries Reported in West Mira Incident An equipment failure onboard Northern Ocean semisubmersible West Mira resulted in production equipment descending to the seabed. The rig owner said no one was injured and the well at the location was secured “with three barriers in place.” The unit was in the process of lowering the equipment on the Wintershall-operated Nova field. “While lowering a x-mas tree from West Mira, the winch wire snapped when the tree was five meters below the sea surface. The x-mas tree sunk to the seafloor 368 meters below water level. Eight people were working in the area of the rig where the incident occurred in safe distance from moving equipment,” said Wintershall. The rig manager, Seadrill Europe Management AS, and Wintershall are conducting investigations into the incident and have agreed to a plan to secure the production equipment. “A remote operated vehicle (ROV) was sent to the seafloor to assess the situation,” added the oil company. “The ROV survey showed no risk of discharge of well fluids or hydrocarbons and the x-mas tree has been localized on the template.”

Guyana Prepares for Offshore Licensing Round The Guyanese government is preparing to launch its first bidding round for offshore exploration and production of hydrocarbon blocks. New fiscal terms and conditions are being finalized which the country hopes will allow it to gain the maximum economic benefits. The 2022 bidding round, which according to the nation’s Department of Public Information, is expected to be officially launched soon and will be opened for several months to give interested companies sufficient time to prepare their competitive packages and bid to win the available acreages offshore. With the upcoming bidding round the government expects Guyana’s offshore areas to emerge as a potential super basin with over 11 billion BOE discovered to date. The process seeks to ensure the country gets a fairer share of revenues from oil and gas resources through improved fiscal arrangements, as well as safeguard the safety of people and the environment by following international best practices in offshore development. The new round also aims to be competitive with other global energy projects and assure investors of stability, predictability, and security of any investment. The government seeks to balance its developmental agenda with its climate change goals. Ault Drills Successful Smackover Well in Mississippi Ault Energy completed drilling the Harry O’Neal 20-9 No. 1 in Holmes County, Mississippi, and logged productive oil results across multiple pay zones in the Smackover formation. Completion work has begun on the well, and it is expected to be on stream soon. Ault was formed by parent BitNile this past summer to make strategic oil and gas acquisitions. The company obtained participation rights with for the O’Neal No. 1 well and future oil wells when it invested $12 million in Ecoark Holdings in June. Ault Energy exercised its participation right and acquired a 40% working interest in the well, which is the first project in an expected long-term partnership between Ecoark and Ault parent companies White River and BitNile, respectively, with the intention to drill approximately 100 oil wells over 5 years. White River’s next drilling project is expected to be a 14,000-ft-deep vertical oil well in the Wilcox, Austin Chalk, and Tuscaloosa Marine Shale formations in the Coochie oil field in Concordia Parish, Louisiana. White River also plans to drill three consecutive deep vertical drilling projects at approximately 13,000 ft in the Rodessa and Hosston sand formations on the Pisgah Field Lease in Rankin County, Mississippi. Hess Brings Another Llano Well On Stream Hess brought its Llano-6 well in the Gulf of Mexico (GOM) on stream. The new well, like the other Llano wells, is tied back to Shell’s Auger facility. Hess is planning increased activity in the Llano area based on the success of Llano-6, quality of the reservoir, and adjacent high-value prospects. Hess holds a 50% interest in the long-producing Llano field, located about 150 miles off the Louisiana coast in the Garden Banks area in an estimated 2,600 ft of water. Shell, the operator, holds a 27.5% interest, and ExxonMobil has the remaining 22.5%. The field was discovered in 1997 and achieved first oil in 2004. Recent seismic reprocessing and analysis confirmed additional development opportunities in the field. Hess expects more high-value opportunities at Llano with wells planned for 2023 and 2024 and is finalizing plans for a year-long drilling campaign starting in early 2023 that will focus on tieback and hub-class opportunities in the GOM. Mubadala Discovers Gas Field Off Malaysia Mubadala Energy and its partners have announced a new gas discovery offshore Malaysia via the Cengkih-1 exploration well in Block SK 320. The exploration well was drilled to a total depth of 1680 m and encountered a 110-m gas column in the Miocene Cycle IV/V pinnacle carbonate reservoirs. The Cengkih-1 well is located nearly 220 km off the Bintulu coast in Sarawak. The discovery is near the Pegaga gas field, also located within Block SK 320. Mubadala Energy and its partners began production from the Pegaga field in March 2022. The Pegaga field has been developed with an integrated central processing platform built to handle throughput of 550 MMcf/D of gas plus condensate. A new pipeline transports gas from the platform into an existing offshore gas network and subsequently to the onshore Petronas LNG Complex. Mubadala Energy is the operator of Block SK 320 with a 55% stake. Partners Petronas and Sarawak Shell hold 25% and 20%, respectively. Petrobras Progresses Sale of Potiguar Basin Assets Petrobras entered the binding phase of the sale of 40% of its stake in the BM-POT-17 exploratory concessions, in which the Pitu well discovery assessment plan is being developed (Blocks POT-M-853 and POT-M-855), and the POT-M-762_R15 concession (Block POT-M-762), located in deep waters in the Potiguar Basin—Equatorial Margin–off the coast of Rio Grande do Norte. Petrobras currently holds a 100% stake in these concessions and will continue as operator of the partnership after the sale. Petrobras said the search for partnership in these assets is aligned with its portfolio management strategy and the improvement of the company’s capital allocation, aiming to maximize value. POT-M-853 and POT-M-855 are exploratory blocks acquired in the 7th Bidding Round of the National Petroleum Agency (ANP) in 2006. Petrobras is conducting the discovery assessment plan for the Pitu well, with a firm commitment to drill an exploratory well (Pitu Oeste) scheduled for 2023. POT-M-762 is an exploratory block acquired in the 15th ANP Bidding Round in 2018. Petrobras plans to drill the Anhangá well between 2023 and 2024. TotalEnergies Sews Up PSA on Oman’s Block 11 TotalEnergies, along with its partners, has signed an Exploration and Production Sharing Agreement (EPSA) with the Ministry of Energy and Minerals (MEM) of the Sultanate of Oman for onshore Block 11. The first stage of the EPSA activities will see seismic acquisition in late 2022, with a first exploration well planned to be drilled in 2023. TotalEnergies will hold a 22.5% interest in the block, OQ 10% and Shell with 67.5% will be the operator. Block 11 contains undeveloped discoveries and exploration potential. “Our recent activities in Oman are a demonstration of TotalEnergies’ strategy of transformation into a multi-energy company,” said Laurent Vivier, senior vice president Middle East and North Africa, exploration and production, at TotalEnergies. “Today’s entry into the Block 11 gives us the opportunity to unlock additional potential to meet domestic and export gas demand. It strengthens our strategic relationship with the Sultanate of Oman, as illustrated last December by our entry into the neighboring Block 10 gas concession and the start of construction last July of 17-MW peak solar photovoltaic systems providing power to a desalination plant.” In 2021, TotalEnergies’ production in Oman was 39,000 BOE/D. The operator produces oil in Block 6 (4%), as well as LNG through its participation in the Oman LNG (5.54%)/Qalhat LNG (2.04% via Oman LNG) liquefaction complex with an overall capacity of 10.5 mtpa. In 2021 TotalEnergies signed a concession agreement to develop natural gas resources on the onshore Block 10 (26,55%), with first gas expected in 2023. TotalEnergies also operates exploration Block 12 (80%). India Lets New Contracts Related to Small Discovered Fields, CBM The Indian government has signed contracts for 31 discovered small fields under the third round of bidding, and for four coalbed methane (CBM) blocks under the fifth round of bidding with 14 domestic companies. These blocks have been awarded. Among these blocks, the Oil and Natural Gas Corporation (ONGC) has signed six contracts for discovered small fields, with three each for fields in the Arabian Sea and Bay of Bengal. These include four contract areas as sole bidder and two contract areas in partnership with Indian Oil Corporation Ltd. The ONGC has also signed two contracts for CBM fields situated in Jharkhand and Madhya Pradesh. Cairn Oil & Gas has signed pacts for eight fields. The third round for discovered small fields was launched by the government in June 2021 where 75 fields were offered under 31 contract areas. The CBM bidding round was launched in September 2021, which concluded at the end of May 2022 with 15 blocks under offer.

Dimensionality reduction is standard practice for filtering noise and identifying relevant features in large-scale data analyses. In biology, single-cell genomics studies typically begin with reduction to 2 or 3 dimensions to produce “all-in-one” visuals of the data that are amenable to the human eye, and these are subsequently used for qualitative and quantitative exploratory analysis. However, there is little theoretical support for this practice, and we show that extreme dimension reduction, from hundreds or thousands of dimensions to 2, inevitably induces significant distortion of high-dimensional datasets. We therefore examine the practical implications of low-dimensional embedding of single-cell data and find that extensive distortions and inconsistent practices make such embeddings counter-productive for exploratory, biological analyses. In lieu of this, we discuss alternative approaches for conducting targeted embedding and feature exploration to enable hypothesis-driven biological discovery.

ABSTRACT The MeerKAT Exploration of Relics, Giant Halos, and Extragalactic Radio Sources (MERGHERS) survey is a planned project to study a large statistical sample of galaxy clusters with the MeerKAT observatory. Here we present the results of a 16-h pilot project, observed in response to the 2019 MeerKAT Shared Risk proposal call, to test the feasibility of using MeerKAT for a large cluster study using short (0.2–2.1 h) integration times. The pilot focuses on 1.28-GHz observations of 13 massive, low-to-intermediate redshift (0.22 < z < 0.65) clusters from the Sunyaev–Zel’dovich-selected Atacama Cosmology Telescope (ACT) DR5 catalogue that show multiwavelength indications of dynamical disturbance. With a 70 per cent detection rate (9/13 clusters), this pilot study validates our proposed MERGHERS observing strategy and provides twelve detections of diffuse emission, eleven of them new, indicating the strength of MeerKAT for such types of studies. The detections (signal-to-noise ratio ≳ 6) are summarized as follows: two systems host both relic(s) and a giant radio halo, five systems host radio haloes, and two have candidate radio haloes. Power values, k-corrected to 1.4 GHz, assuming a fiducial spectral index of α = −1.3 ± 0.4, are consistent with known radio halo and relic scaling relations.

Accurate identification and understanding of various metallic minerals are crucial for deciphering geological formations, structures, and ages. Giving their pivotal role as essential natural resources, a microscopic exploration of metallic minerals becomes imperative. Traditional analytical methods, while helpful, exhibit certain limitations. However, terahertz time-domain spectroscopy, distinguished by its high signal-to-noise ratio, expansive frequency band, and low incident wave energy, is a promising complement to conventional techniques in characterizing metallic minerals. This study employs terahertz time-domain spectroscopy to examine samples of Stibnite, Sphalerite, Galena, and Pyrite originating from diverse geological conditions. The vibrations of molecules within these metallic minerals induce discernible changes in the terahertz spectra. Our findings untiate the extensive potential of terahertz time-domain spectroscopy in the characterization of metallic minerals, affirming its considerable practical value in mineral resource exploration.

Shell’s Namibia Wildcat Encounters Light Oil Supermajor Shell has struck light oil with its Graff-1 exploration well offshore Namibia, according to the country’s national oil company, a partner in the probe. The National Petroleum Corporation of Namibia (Namcor) confirmed the discovery. Partners in the Orange Basin well included Shell Namibia Upstream and QatarEnergy. The probe was located about 270 km away from Oranjemund, and was drilled to a total depth of 5376 m in water depths of 2000 m. The drilling operations on Graff-1 utilizing the Valaris DS-10 drillship began in early December 2021 and were completed in early February. “While we can learn a great deal from the results of Graff-1, we anticipate that further exploration activity, including a second exploration well, will be required to determine the size and recoverable potential of the identified hydrocarbons,” Namcor said. TotalEnergies has drilled the Venus-1 well in a neighboring block to the west where results are imminent. Shell Namibia Upstream operates the Graff find with 45% interest; QatarEnergy also holds a 45% stake; Namcor holds the remaining 10% interest. Namcor said extensive laboratory analyses will be performed in coming months to gain a better understanding of the reservoir quality and flow rates potentially achievable. Eni’s First Offshore Exploration Well in Abu Dhabi Strikes Gas Eni has encountered gas shows in its first exploration well, XF-002, currently drilling in offshore Block 2, northwest of Abu Dhabi, in 115 ft water depth. The interim well results indicate a range of 1.5–2.0 Tcf of raw gas in place in multiple good-quality reservoirs of the Jurassic exploration targets. The drilling operations will continue targeting the deeper exploration targets of the Khuff and Pre-Khuff formations. Eni has a 70% stake and operates offshore Block 2, which was awarded in January 2019 as a result of the first-ever competitive bid round for exploration blocks launched by ADNOC. PTTEP holds the remaining 30%. Eni has been present in Abu Dhabi since 2018. The company is the operator of three exploration licenses and has a participation with ADNOC in three offshore development and production concessions: Lower Zakum (5%), Umm Shaif and Nasr (10%), and Ghasha (25%). W&T Offshore Acquires US GOM Producing Properties W&T Offshore closed an acquisition of oil-and-gas-producing properties in US GOM from ANKOR E&P and KOA Energy. The operator paid $30.2 million for stakes in the Ship Shoal 230, South Marsh Island 27/Vermilion 191, and South Marsh Island 73 fields. The deal adds (internally estimated) proved reserves of 5.5 million BOE (69% oil) and proved and probable, or 2P, reserves of 7.6 million BOE (75% oil). The deal also adds more than 50 gross producing wells (average working interest of 80%) across the three shallow-water fields. Myanmar Coup Leads to Operator Exodus Thailand state oil and gas explorer PTTEP looks set to take over Myanmar’s biggest gas field as TotalEnergies and Chevron confirmed their exits, citing the worsening humanitarian situation following a coup. A move by PTTEP to become operator of Yadana field, in which it already has a 25.5% stake, would keep vital gas supplies flowing to Thailand and Myanmar. Both TotalEnergies and Chevron were part of a group operating the Yadana gas project off Myanmar’s southwest coast along with the Moattama Gas Transportation Company that runs a gas pipeline from the field to Myanmar’s border with Thailand. PTTEP would have an 85% stake in Yadana if it took all the interest held by TotalEnergies and Chevron. PTTEP already operates Myanmar’s smaller Zawtika field with an 80% stake; Myanmar’s state energy firm Myanma Oil and Gas Enterprise holds the remaining 20%. Yadana produced 770 MMcf/D of gas in 2021, of which 570 MMcf/D was supplied to Thailand and the rest used to generate Myanmar’s electricity. New Malaysian Bid Round Launched State-owned Petronas is offering 14 exploration blocks, six clusters of discovered resource opportunities (DRO), and one cluster of late-life assets (LLA) in its Malaysia Bid Round 2022 launched in late January. The 14 exploration blocks on offer are in prolific geological provinces within the Malay, Sabah, and Sarawak basins. Most of these blocks contain existing oil and/or gas discoveries. The six DRO clusters are Meranti, Ubah, Baram Jr., A, C, and D, mostly in shallow water and near existing production infrastructure. In addition, the single LLA, which includes a cluster of three fields named the Abu Cluster, provides the opportunity for a new operator to sweat the remaining oil in place using existing facilities. Petronas is also offering technical study arrangements for two exploration areas in southern Malay Basin and northwest Sabah Basin to offer investors a better understanding of the potential of the acreages prior to submitting a bid proposal. Petronas is hosting a virtual data room which will be accessible from launch until the end of June 2022, allowing potential investors to conduct data review during the bid-round period. Equinor Secures 26 New Production Licenses Equinor has been awarded 26 new production licenses by Norway’s Ministry of Petroleum and Energy in the 2020 Award in Predefined Areas. A dozen of the licenses have the company as operator with the remaining 14 as partner. The production licenses are divided as follows: 12 in the North Sea, 10 in the Norwegian Sea, and four in the Barents Sea. In 2022, Equinor plans to take part in around 25 exploration wells, mainly near existing infrastructure. Most of the wells will be drilled in the North Sea, some in the Norwegian Sea, and a few in the Barents Sea. Petrobras Details Potiguar Cluster Asset Sale to 3R Petrobras has signed a deal to sell 100% of its interest in 22 concessions of onshore and offshore production fields, along with its infrastructure situated in the Potiguar basin (together called the Potiguar Cluster) in the Rio Grande do Norte, north of Brazil, to 3R Potiguar, which is a wholly owned subsidiary of 3R Petroleum Óleo e Gás, for $1.38 billion. The transaction also includes the Potiguar Clara Camarao refinery with a processing capacity of 39,600 BOPD. 3R Potiguar will pay Petrobras $1.04 billion at closure and four annual installments of $58.75 million each until March 2024. The agreement will require regulatory approval from Brazil’s National Agency of Petroleum, Natural Gas, and Biofuels (ANP). The Potiguar Basin comprises three subclusters (Canto do Amaro, Alto do Rodrigues, and Ubarana), having an aggregate of 22 fields across 19 onshore and three offshore concessions, and incorporates access to the infrastructure necessary for processing, refining, logistics, storage, transportation, and export of oil and natural gas. Ubarana subcluster concessions are in shallow waters around 10 km and 22 km off the coast of the municipality of Guamaré-RN, while subclusters Canto do Amaro and Alto do Rodrigues are onshore. The average output from three of these subclusters last year was 20,600 BOPD and 58100 m3/d of natural gas. Neptune Energy Increases Production From Gjøa Platform Production from the Neptune Energy-operated Gjøa platform in the Norwegian North Sea increased by 2 million BOE from 2020 to 2021. Gross production over the Gjøa platform ended on 42 million BOE in 2021, compared with 40 million BOE in 2020. Just over three-quarters (76%) of the production was gas, all of which is exported through the FLAGS pipeline to the St. Fergus Gas Terminal in the UK. The increased production was due mainly to production startup from the Gjøa P1 infill development in February and the Duva field tieback in August. In addition, production from the tieback field Vega, operated by Wintershall Dea, and the Gjøa field itself, has been better than expected. Estimated reserves on the Gjøa field have increased by 38% since the Plan for Development and Production was approved in 2007. Neptune expects to add a fourth tie-in field to the Gjøa facilities—Wintershall Dea’s Nova field. In addition, the operator plans to drill two exploration wells in the area and will continue to mature other nearby discoveries and exploration opportunities as tie-in candidates. Kuwait’s KUFPEC Makes First Operated Offshore Discovery in Indonesia Kuwait Foreign Petroleum Exploration Company (KUFPEC) has confirmed its subsidiary KUFPEC Indonesia has made a commercial discovery of natural gas and condensate in the Anambas Block, offshore Indonesia. The discovery was made via the Anambas-2X well, which was drilled using a jackup rig in 288 ft of water to a total depth of 10,509 ft. Located in the Natuna Sea near an existing block in which KUFPEC is a partner, the Anambas Block was awarded to KUFPEC Indonesia through a competitive bidding process in 2019. The block is fully operated by KUFPEC Indonesia with 100% interest. The company conducted two drillstem tests so far, one in the Lower Gabus formation and the other in the Intra Keras formation. These tests resulted in a stabilized combined flow rate of

The effective monitoring and identification of existing subterranean termite populations within coarse woody debris and infested wood in service depend on accurate detection. These insects are often concealed within logs, wooden support structures, walls, and floorboards of buildings. In the absence of external mud tubes, termite infestations normally must be discovered through the destructive exploration of wooden structures to reveal the physical presence of these insect pests. Subterranean termite species are difficult to identify due to similarities in morphological features, but they may be readily distinguished by differences in volatile emissions from which they are divided into chemotaxonomic groups. Consequently, a more effective and nondestructive approach for detection and identification is to take advantage of unique species-specific emissions of volatile organic compounds (VOCs) from termite bodies which easily pass through wooden structures, allowing for detection without physical damage to wood and avoiding expensive DNA analysis. Electronic aroma detection analyses were conducted with an Aromascan A32S electronic-nose (e-nose) instrument, fitted with a 32-sensor conducting polymer (CP) sensor array, for discrimination between four common subterranean termite species based on differences in volatile emissions. Principal component analysis (PCA) of whole-body volatiles effectively distinguished between four termite species with the first two principal components accounting for more than 98% of sample variance (p < 0.01). Unique electronic aroma signature patterns (smellprints) were produced from e-nose sensor array outputs that allowed for the effective identification of termite species based on distinct differences in volatile metabolites released from their bodies. The e-nose methods were determined to be an improved means for rapidly detecting and monitoring termite species in wood. The method is cheaper than conventional detection methods and allows for the timelier discovery of species-specific termite infestations necessary for better management. The e-nose capability of detecting the Formosan termite in indoor living spaces was particularly significant due to the production of naphthalene, a volatile hazardous gas causing many adverse human health effects in enclosed environments.

Following the discovery of a hydrostatic pressure sensor with no associated gas phase in the crab, and the knowledge that several systems of cells in culture show long term alterations to small changes in hydrostatic pressure, we show here that vestibular type II hair cells in a well known model system (the isolated elasmobranch labyrinth), are sensitive to hydrostatic pressure. This new finding for the vertebrate vestibular system may provide an explanation for low levels of resting activity in vertebrate hair cells and explain how fish without swim bladders sense hydrostatic cues. It could have implications for humans using their balancing systems in hypobaric or hyperbaric environments such as in aircraft or during space exploration. Although lacking the piston mechanism thought to operate in crab thread hairs which sense angular acceleration and hydrostatic pressure, the vertebrate system may use larger numbers of sensory cells with resultant improvement in signal to noise ratio. The main properties of the crab hydrostatic pressure sensing system are briefly reviewed and new experimental work on the isolated elasmobranch labyrinth is presented.

This study examines shear-wave velocity structures in the Jeju region utilizing horizontal-to-vertical spectral ratios (HVSRs) of environmental noise, focusing on identifying significant low-velocity layers (LVLs). Although conventional methodologies predominantly involve borehole and active seismic exploration, recent advancements in the diffuse-field theory of seismic waves have offered a theoretical foundation for this approach. In the volcanic region of Jeju Island characterized by unique geological features, a pervasive LVL composed of quaternary marine sediments and the Seoguipo sedimentary layer has been observed. These components are crucial for site amplification and attenuation in seismic microzonation. The present study introduces a novel discovery of a distinct LVL, specifically at the UDO site, suggesting that its origin may be attributable to a local magmatic intrusion event. Advanced algorithms and HVSR curve analysis have enabled reliable inversion processes, enhancing the comprehension of the subsurface geology of Jeju. These insights are essential for seismic microzonation practices and contribute significantly to the development of seismic design standards in the Jeju region.

Abstract We report the discovery of Pegasus IV, an ultra-faint dwarf galaxy found in archival data from the Dark Energy Camera processed by the DECam Local Volume Exploration Survey. Pegasus IV is a compact, ultra-faint stellar system ( r 1 / 2 = 41 − 6 + 8 pc; M V = −4.25 ± 0.2 mag) located at a heliocentric distance of 90 − 6 + 4 kpc . Based on spectra of seven nonvariable member stars observed with Magellan/IMACS, we confidently resolve Pegasus IV’s velocity dispersion, measuring σ v = 3.3 − 1.1 + 1.7 km s−1 (after excluding three velocity outliers); this implies a mass-to-light ratio of M 1 / 2 / L V , 1 / 2 = 167 − 99 + 224 M ⊙ / L ⊙ for the system. From the five stars with the highest signal-to-noise spectra, we also measure a systemic metallicity of [Fe/H] = − 2.63 − 0.30 + 0.26 dex, making Pegasus IV one of the most metal-poor ultra-faint dwarfs. We tentatively resolve a nonzero metallicity dispersion for the system. These measurements provide strong evidence that Pegasus IV is a dark-matter-dominated dwarf galaxy, rather than a star cluster. We measure Pegasus IV’s proper motion using data from Gaia Early Data Release 3, finding (μ α*, μ δ ) = (0.33 ± 0.07, −0.21 ± 0.08) mas yr−1. When combined with our measured systemic velocity, this proper motion suggests that Pegasus IV is on an elliptical, retrograde orbit, and is currently near its orbital apocenter. Lastly, we identify three potential RR Lyrae variable stars within Pegasus IV, including one candidate member located more than 10 half-light radii away from the system’s centroid. The discovery of yet another ultra-faint dwarf galaxy strongly suggests that the census of Milky Way satellites is still incomplete, even within 100 kpc.

GOM Lease Sale Generates $121 Million in High Bids; Shell Offshore Takes Top Spot Regionwide US Gulf of Mexico (GOM) Lease Sale 256 generated $120,868,274 in high bids for 93 tracts in federal waters. The sale on 18 November featured 14,862 unleased blocks covering 121,875 square miles. With $27,877,809 spanning 21 high bids, Shell Offshore Inc. took the top spot among 23 competing companies. A total of $135,558,336 was offered in 105 bids. Among the majors, Shell, Equinor, BP, and Chevron submitted some of the highest bids. Each company claimed high bids of over $17 million, signaling the GOM remains a priority in their portfolios. Last year was a record year for American offshore oil production at 596.9 million bbl, or 15% of domestic oil production, and $5.7 billion in direct revenues to the government. Offshore oil and gas supported 275,000 total domestic jobs and $60 billion total economic contributions in the US. “The sustained presence of large deposits of hydrocarbons in these waters will continue to draw the interest of industry for decades to come,” Deputy Secretary of the Interior Kate MacGregor said. Still, as Mfon Usoro, senior research analyst at Wood Mackenzie, noted, “Although bidding activity increased by 30% from the March 2020 sale, the high bid amount of $121 million still trends below the average high bid amount seen in previous regionwide lease sales, proving that companies are still being conservative with exploration spend.” Although the Bureau of Ocean Energy Management has proposed another regionwide GOM lease sale in March 2021, Usoro predicted that Lease Sale 256 “could potentially be one of the last lease sales.” “With the Biden administration set to inaugurate next year and possibly ban future lease sales, a massive land grab might have ensued,” he continued. “But companies are constrained by tight budgets due to the prevailing low oil price. Additionally, companies in the region have existing drilling inventory to sustain them in the near term. The best blocks with the highest potential reserves are likely already leased. As a result, we do not expect a potential ban on leasing to materially impact production in the region until the end of the decade.” This was the seventh offshore sale held under the 2017–2022 National Outer Continental Shelf Oil and Gas Leasing Program; two sales a year for 10 total regionwide lease sales are scheduled for the gulf. Nine Areas on Norwegian Continental Shelf Open for Bids The 25th licensing round on the Norwegian Continental Shelf, comprising eight areas in the Barents Sea and one in the Norwegian Sea, has been announced by the Norwegian Ministry of Petroleum and Energy. Known for being a country with some of the greenest credentials and policies in the world, Norway surprised observers in June by announcing plans for a licensing round that signaled further oil exploration in the Norwegian sector of the Arctic Sea. In this round, 136 blocks/parts of blocks will be available: 11 in the Norwegian Sea and 125 in the Barents Sea. The application deadline for companies is 23 February 2021. New production licenses will be awarded in Q2 2021. Johan Sverdrup Capacity Increased to Half Million B/D Following positive results in a November capacity test, the Johan Sverdrup field is set to increase daily production capacity. Capacity will rise from today’s 470,000 to around 500,000 B/D in the second increase since the field came on stream just over a year ago. The move will increase the field’s total production capacity by around 60,000 bbl more than the original basis when the field came on line. Overall, the field is estimated to have resources of 2.7 billion BOE. “The field has low operating costs, providing revenue for the companies and Norwegian society, even in periods with low prices,” said Jez Averty, Equinor’s senior vice president for operations south in development and production, Norway. The Johan Sverdrup field uses water injection to secure high recovery of reserves and maintain production at a high level. An increase in the water-injection capacity should further increase production capacity by mid-2021, according to Rune Nedregaard, vice president for Johan Sverdrup operations. Phase 2 production starting in Q4 2022 will raise the Johan Sverdrup full-field plateau production capacity from 690,000 to around 720,000 B/D. Equinor operates the field with 42.6% stake; other partners include Lundin Norway (20%), Petoro (17.36%), Aker BP (11.57%), and Total (8.44%). ConocoPhillips Makes Significant Gas Discovery Offshore Norway ConocoPhillips announced a new natural-gas condensate discovery in production license 1009, located 22 miles northwest of the Heidrun oil and gas field and 150 miles offshore Norway in the Norwegian Sea. The wildcat well 6507/4-1 (Warka) was drilled in 1,312 ft of water to a total depth of 16,355 ft. Preliminary estimates place the size of the discovery between 50 and 190 million BOE. Further appraisals will determine potential flow rates, the reservoir’s ultimate resource recovery, and plans for development. “The Warka discovery and potential future opportunities represent very low cost-of-supply resource additions that can extend our multi-decade success on the Norwegian Continental Shelf,” said Matt Fox, executive vice president and chief operating officer. The drilling operation, which was permitted to ConocoPhillips in August 2020, was performed by the Transocean-managed Leiv Eiriksson semisubmersible rig. ConocoPhillips Skandinavia AS is the main operator of the license with a 65% working interest; PGNiG Upstream Norway AS holds the remaining stake. Lundin Energy Completes Barents Sea Exploration Well, Comes Up Dry Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest. Partners are Wintershall DEA Norge AS (25%), Inpex Norge AS (10%), DNO Norge AS (10%), and Idemitsu Petroleum Norge AS (7.5%). Polmak is the first of Lundin’s three high-impact exploration prospects drilled this quarter in the Barents Sea; the wells target gross unrisked prospective resources of over 800 million bbl of oil. The West Bollsta rig will now proceed to drill the Lundin Energy-operated Bask prospect in PL533B. Well 7219/11-1 will target Paleocene-aged sandstones, estimated to hold gross unrisked prospective resources of 250 million bbl of oil. Tullow Sells Remaining Stake in Ugandan Oil Field Tullow Oil has completed the 10 November sale of its assets in Uganda to French giant Total for $500 million. Tullow will also receive $75 million when a final investment decision is taken on the development project, calculated to hold 1.7 billion bbl of crude oil. Contingent payments are payable after production begins if Brent crude prices rise above $62/bbl. The completion of this transaction marks Tullow’s exit from its licenses in Uganda after 16 years of operations in the Lake Albert basin. The deal is designed to strengthen Tullow’s balance sheet, as tumbling crude prices combined with exploration setbacks have created problems for the company. In September, the company reported that it had lost $1.3 billion in the first 6 months of 2020 as falling oil prices forced it to write down the value of its assets. The deal cut Tullow’s net debt to $2.4 billion; it has $1 billion in cash.

Shell Selling Onshore Egypt Assets Shell Egypt and one of its affiliates have signed an agreement with a consortium made up of subsidiaries of Cheiron Petroleum Corporation and Cairn Energy PLC to sell its upstream assets in Egypt’s Western Desert for a base consideration of $646 million. Additional payments of up to $280 million between 2021 and 2024 will be made contingent on the oil price and the results of further exploration. The transaction is subject to government and regulatory approvals and is expected to complete in the second half of 2021. The package of assets comprises Shell Egypt’s interest in 13 onshore concessions and the company’s share in Badr El-Din Petroleum Company. Shell will shift its exploration focus in Egypt offshore, which includes seven new blocks in the Nile Delta, West Mediterranean, and Red Sea. Chevron Begins Production From Sarta-2 Well in Iraq Chevron has started production from the Sarta-2 well at the Sarta field in the Kurdistan region of Iraq, partner Genel Energy said. Gross field production now stands at more than 10,000 B/D. Sarta production is expected to increase from the existing two producing wells as facility optimization continues after production startup. A fresh appraisal drilling campaign is scheduled to begin soon, with the Sarta-5 and Sarta-6 wells set to be drilled back-to-back. Chevron is operator of the Sarta production-sharing contract (50%) with partners Genel Energy (30%) and the Kurdistan Regional Government (20%). Colombia Eyes Licensing Round Results in November Colombia is expected to soon reveal the schedule for its 2021 licensing round offering 32 blocks for oil and gas exploration, with results expected in November. In 2020, the nation awarded three areas to Canada-based companies Parex Resources and Canocol Energy despite the double-whammy of crashing crude demand and a global pandemic. With oil prices on the mend and an aggressive vaccine dissemination program, Colombia is hopeful that interest in its oil and gas acreage returns to pre-pandemic levels. The National Hydrocarbon Agency (ANH) expects to award at least half of the available tracts, which are part of more than 500 areas identified by the ANH in the country and include mature fields, emerging basins, and bordering areas. Exploration in Colombia fell dramatically in 2020 with only 18 wildcats drilled vs. the 45 planned, with most of the expected investment deferred to 2021-2022. While the country has allowed pilot projects testing for unconventional oil, there currently is a ban on fracking operations in the country. Israel Begins Prep Work for Fourth Offshore Round Israel’s Ministry of Energy has announced plans to launch the fourth offshore bidding round (OBR 4) for exploration licenses in the country’s exclusive economic zone soon. OBR 4 is part of a multiyear program to encourage the exploration and development of Israel’s natural resources to provide low-cost, environmentally friendly energy to Israel’s consumers and businesses and to develop markets for Israeli natural gas beyond its borders. As in OBR 2, the Ministry is planning to offer several zones to qualified companies, with each zone comprising approximately four licenses having a total area of up to 1600 sq km. Around 25 exploration licenses (blocks) have been mapped and will be grouped into six clusters. The exact dates of the stages of the bid round and grouping of the licenses in clusters will be determined later. No decision has yet been made on the winner of the license for natural gas and oil exploration in Block 72 in the third competitive bid round carried out in 2020. The Ministry will announce the formal commencement of OBR 4 and its delineation in the near future and provide detailed information on its website www.energy-sea.energy.gov.il at that time. Exxon Drills Dud at Bulletwood Offshore Guyana Exxon encountered noncommercial hydrocarbons with a test of its Bulletwood prospect in the Canje Block in the Guyana-Suriname basin. The well, located in 2846 m of water, was drilled to its planned target depth of 6690 m using drillship Stena Carron. Data collection from the Bulletwood-1 well confirms the presence of the Guyana-Suriname petroleum system and the potential prospectivity of the Canje Block, said partner Westmount Energy. Bulletwood-1 was the first of three scheduled wells to be drilled on the block in 2021. Wells Jabillo-1 and Sapote-1 are expected to spud over the coming months. Exxon operates the Canje Block via its Esso Exploration and Production Guyana unit, which has a 35% stake. Total has 35%, JHI 17.5%, and Mid-Atlantic Oil & Gas 12.5. Westmount holds a 7.7% stake in JHI. While the well results were disappointing, Exxon’s success rate in the area is still around 80% from 18 wells and expects its production from the region to reach 750,000 B/D by 2026. Neptune Earmarks $150 Million for Exploration and Appraisal in 2021 UK-based independent Neptune Energy said its exploration and appraisal spend for 2021 will remain flat at around $150 million. The company said it had up to 11 wells planned for the year including followup wells at the Dugong and Maha discoveries as well as a wild-cat at Dugong Tail. Dugong was discovered in the Norwegian portion of the North Sea in 2020. Neptune believes the prospect holds between 40–120 million BOE. Dugong is located 158 km west of Florø, Norway, at a water depth of 330 m, and is close to existing production facilities. The Dugong prospect comprises two reservoirs that lies at a depth between 3250–3500 m. The Maha discovery offshore East Kalimantan is estimated to hold gas resources in excess of 600 Bcf. In 2019, Neptune and its partners, Eni (operator) and Pertamina, were awarded the West Ganal production-sharing contract that holds the Maya find. An exploration well targeting the Dugong Tail prospect, adjacent to the south of the Dugong find, is slated for the third quarter of this year and will be drilled using Odjfell semisubmersible Deepsea Yantai. Interest Wanes in Norway’s Arctic Frontier Seven companies applied for new acreage in the Barents Sea in Norway’s latest licensing round, down from 26 in a similar round in 2013. The government had offered 125 new blocks in eight frontier regions of the Barents. More than 60% of the undiscovered hydrocarbons offshore Norway are in the Barents frontier, according to the nation’s petroleum directorate. However, appetites for frontier drilling have diminished as oil prices weakened and recent results from the region have disappointed. Companies that applied for the new acreage round were Norske Shell, Equinor, Idemitsu Petroleum Norge, Ineos E&P Norge, Lundin Norway, OMV Norge, and Var Energi. Oman Transfers Ownership of Massive Block 6 The government of Oman has transferred its stake in one of the Middle East’s largest oil blocks to a newly established firm. By royal decree, the new, state-controlled Energy Development Oman (EDO) will hold the country’s 60% stake in Block 6. The stake was moved from Petroleum Development Oman (PDO), another government-run company. Oman, which is struggling under a soaring budget deficit, is looking to finance its spending by leveraging its energy assets. Block 6 has a production capacity of 650,000 BOED. Shell holds 34% in the block, while Total holds the remaining 4%. The government appointed Haifa Al Khaifi as head of EDO in January. She joined from PDO and is also chairwoman of the Saudi Arabian unit of State Street Corp., the Boston-based custodian and money manager. EDO will also be able to invest abroad and deal in renewable-energy products.

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.

Transocean Harsh-Environment Rig Scoops Contract Extension Equinor extended Transocean’s contract for use of the harsh-environment semisubmersible Transocean Spitsbergen. The additional nine wells plus two, one-well options extension is valued at $181 million and is expected to begin in October 2023. The work will keep the rig busy off Norway until April 2025. In the fall of next year, the rig is scheduled to start drilling a trio of production wells for the Haltenbanken Vest Unit, which is part of the Kristin South area in the Norwegian Sea. Transocean Spitsbergen has been working consistently for Equinor since 2019. Equinor Wildcat Comes Up Empty Equinor will plug and abandon its Cambozola exploration well in License PL1049 offshore Norway after failing to encounter commercial hydrocarbons. Exploration well 34/9-1S was targeting Lower Cretaceous turbidite sand lobes in the northern North Sea and had the potential to be a play opener, according to well partner Longboat Energy. The exploration will continue with the Oswig and Copernicus wells, both expected to spud this summer. The Cambozola well was drilled to a total vertical depth of 4393 m using Odjfell Drilling semisubmersible Deepsea Stavanger. Background gas readings were recorded throughout the overlying section, but the well failed to encounter effective reservoir. Equinor is analyzing the data collected to understand the observed bright seismic amplitude anomaly and any remaining Lower Cretaceous prospectivity in the area. Longboat had previously referred to Cambozola as a potential play opener and one of the largest gas prospects to be drilled in Norway in 2022. Gross unrisked mean prospective resources for the entire Cambozola prospect have been estimated at 159 million BOE. Western Gas’ Sasanof-1 Exploration Well Disappoints Western Gas failed to encounter hydrocarbons with its Sasanof-1 exploration well offshore Western Australia. The well was drilled to a total depth of 2390 m by semisubmersible Valaris MS-1, but no gas reservoirs were intersected. The well will be permanently plugged and abandoned. The Sasanof prospect was estimated to hold 7.2 Tcf gas and 176 million bbl of condensate. The prospect was seen as potential supply for the NW Shelf LNG project. Vaalco Adds Reserves at Etame off Gabon Vaalco Energy encountered multiple hydrocarbon-bearing sands with its South Tchibala 1HB-ST well drilled from the Avouma platform in the Etame field offshore Gabon. The well struck 18 m of hydrocarbons in the Dentale D1 sand, which is analogous to the Deep Dentale producing field in North Tchibala with similar porosity and permeability. Another 15 m of hydrocarbons was intersected in the Dentale D9. The well will be completed in the D1 sand and was scheduled to be online in June, while the D9 will be cased for future completion. The well also penetrated a thin section of Gamba sand which will not be economically feasible to complete. Current Etame production is fed through the recently extended FPSO Petroleo Nautipa. Success with the South Tchibala 1HB-ST potentially adds new future drilling locations in the Deep Dentale trend across the Etame block. Eni, TotalEnergies Begin Drilling Off Cyprus Partners Eni and TotalEnergies have begun drilling a natural gas wildcat dubbed Cronos-1 in Block 6 offshore Cyprus. The well, originally planned for 2020, was derailed by the COVID-19 pandemic. Vantage Drilling drillship Tungsten Explorer is on location and is conducting the drilling operations. In 2018, the partnership struck gas at the Calypso well in another part of Block 6. That well proved that the carbonate play present in Eni’s Zoar field off Egypt extended to the Cypress exclusive economic zone. Zoar was discovered in 2015 and is the biggest gas discovery to date in the Mediterranean Sea. Calypso-1 was drilled to a total depth of 3827 m and encountered an extended gas column in Miocene- and Cretaceous-aged sands. Eni operates Block 6 with a 50% participation interest. TotalEnergies holds the remaining 50% stake. ADNOC Makes Three Onshore Discoveries Abu Dhabi National Oil Company (ADNOC) has unveiled three new oil discoveries including one at Bu Hasa, Abu Dhabi’s biggest onshore field, with a crude oil production capacity of 650,000 B/D. The discovery in Bu Hasa includes 500 million bbl of oil from an exploration well in the field. The second oil find was in Abu Dhabi’s Onshore Block 3, operated by Occidental, and is estimated to be around 100 million bbl of oil in place. The onshore Al Dhafra Petroleum Concession yielded the third discovery—around 50 million bbl of light sweet Murban-quality crude. Ecopetrol, Oxy Prep Development Quartet Ecopetrol has an agreement in place to develop four deepwater blocks with a subsidiary of Occidental. The four blocks are located in deep waters some 150 km off Colombia’s northern Caribbean coast. Ecopetrol will take a 40% stake in the blocks while Occidental subsidiary Anadarko Colombia will hold the remaining 60% stake and will serve as the blocks’ operator. The deal remains subject to approval from Colombia’s Ministry of Mines and Energy. Equinor, ExxonMobil Plan Bacalhau Expansion off Brazil Equinor and partner ExxonMobil are considering adding a second drilling rig and a second floating production platform for the next phase of the Bacalhau development in the Santos basin, along with a 100-mile-long gas pipeline, according to Reuters. The companies want to boost future production from Bacalhau, Equinor’s largest project outside of Norway. A new appraisal well is planned in the north of the field next year “to better understand the reserves base for the Phase 2 development,” according to Equinor, and the partners are assessing awarding a contract for a second drilling rig. The partners sanctioned the $8-billion project a year ago. The field is situated across two licenses, BM-S-8 and Norte de Carcará. The resource is a high-quality carbonate reservoir containing light oil. The development will comprise 19 subsea wells tied back to an FPSO located at the field. The planned FPSO be one of the largest in Brazil with a production capacity of 220,000 B/D and 2 million bbl in storage capacity. The stabilized oil will be offloaded to shuttle tankers, and the gas from Phase 1 will be reinjected in the reservoir. First oil is expected in 2024. Equinor Transfers Krafla Operatorship to Aker BP Equinor and Aker BP have signed a memorandum of understanding (MoU) for transfer of the Krafla operatorship from Equinor to Aker BP, making Aker BP the operator of all discoveries in the NOAKA area: Krafla, Fulla, and North of Alvheim. Equinor and Aker BP are operators of one field development project each in the area and have agreed that one operator will be the best solution for further development. The MoU states that the owners of the relevant licenses will apply to the ministry for change of operator. A transfer of operatorship will be carried out when the investment decision has been approved by the license partners and the plan for development and operation has been submitted to the authorities. Equinor will still be a major license partner in the area and will retain its existing share of 50% in Krafla and 40% in the Fulla license. The companies will jointly submit the PDOs for NOA Fulla and Krafla as planned by the end of the year. Energean Strikes Gas at Athena off Israel UK-based Energean has discovered gas with its Athena probe in Block 12, 20 km from Tanin A in 1769 m of water. The probe was drilled in 51 days and encountered a gross hydrocarbon column of 156 m in the primary target. Preliminary analysis indicates that the Athena discovery contains recoverable gas volumes of 8 Bcm on a standalone basis. Energean will conduct analysis to refine the full resource potential (including volumes contained within thinner sands between the main reservoir units) and to confirm the liquids content of the discovery. The Athena well has been suspended as a future production well. Commercial hydrocarbons were not discovered in the deeper secondary target. Athena can be commercialized in the near term via tieback to the Energean Power FPSO, enhancing the profitability of the Karish-Tanin development. Alternatively, it could form part of a new development called the Olympus Area which consists of Block 12 and additional prospects on the Tanin lease. The discoveries and prospects in this area lie along the same geological trend; Athena was drilled on the same direct hydrocarbon indicator as Tanin. Energean is confident that the Athena discovery has de-risked the A, B, and C sands in the remaining prospects of the Olympus Area, estimated to be 50 Bcm of mean unrisked prospective resources. This estimate excludes the liquids component as well as any gas upside in the thinner sands between the main reservoir units. Drillship Stena IceMAX has moved to the Karish Main-04 appraisal well and will complete the Karish North development well.

Abstract While the study of Norse-derived terms in medieval English has benefitted from recent etymological advances (e.g. the Gersum project), the exploration of their process of integration lags behind. The latter requires the analysis of the dialectal and semantic distribution of the terms, as well as their interactions with other members of their lexico-semantic fields. This paper offers a case study of this approach by presenting the first comprehensive account of the Norse-derived terms included in La estorie del evangelie, an early Middle English poem from south Lincolnshire/north Norfolk. Besides identifying and classifying the Norse loans on the basis of the Gersum typology and the Historical thesaurus of English, the paper examines the different layers of scribal reworking in its seven fourteenth- and fifteenth-century manuscripts from various dialectal areas to separate the Norse-derived terms that can be attributed to the original composition from those that represent later lexical substitutions, thus tracing the terms’ fate into the late Middle English period. This work shows that this understudied text offers valuable information on the interaction between native, Norse and French terms both in the early Middle English period of the original Fenland author and the later period of the surviving copies. Given that the methodology showcased here should not be restricted only to the analysis of Norse-derived terms, the paper’s significance transcends its immediate focus, as it also contributes to our understanding of medieval English lexicology more broadly.

Abstract While the study of Norse-derived terms in medieval English has benefitted from recent etymological advances (e.g. the Gersum project), the exploration of their process of integration lags behind. The latter requires the analysis of the dialectal and semantic distribution of the terms, as well as their interactions with other members of their lexico-semantic fields. This paper offers a case study of this approach by presenting the first comprehensive account of the Norse-derived terms included in La estorie del evangelie, an early Middle English poem from south Lincolnshire/north Norfolk. Besides identifying and classifying the Norse loans on the basis of the Gersum typology and the Historical thesaurus of English, the paper examines the different layers of scribal reworking in its seven fourteenth- and fifteenth-century manuscripts from various dialectal areas to separate the Norse-derived terms that can be attributed to the original composition from those that represent later lexical substitutions, thus tracing the terms’ fate into the late Middle English period. This work shows that this understudied text offers valuable information on the interaction between native, Norse and French terms both in the early Middle English period of the original Fenland author and the later period of the surviving copies. Given that the methodology showcased here should not be restricted only to the analysis of Norse-derived terms, the paper’s significance transcends its immediate focus, as it also contributes to our understanding of medieval English lexicology more broadly.

Botanical exploration on ultramafic sites in Palawan, Surigao and Zambales has resulted in the discovery of a new hypernickelophore species (nickel (Ni) concentration >1%) of Phyllanthus (Phyllanthaceae). This paper reports in detail the Ni uptake of populations of P. erythrotrichus in Candelaria, Masinloc and Santa Cruz, Zambales, and confirms the status of P. securinegoides in Taganito, Surigao del Norte, which had been analysed only through herbarium specimens, and these were compared with a known hypernickelophore, P. balgooyi, which was collected in Narra and Puerto Princesa, Palawan. Nickel content of the dried leaves, stems and root tissues was quantified using atomic absorption spectrophotometer. P. erythrotrichus and P. securinegoides both had more than 10 000 µg g–1 Ni in the leaves, whereas the roots had 1195 µg g–1 and 4636 µg g–1. P. balgooyi accumulated 6319 µg g–1 of Ni in the leaves, whereas the roots had a higher Ni concentration of up to 8116 µg g–1, respectively. All three species had values of translocation factor and enrichment factor of >1.0, implying that all species have great potential in phytoremediation, specifically, phytoextraction of Ni. These three species of Phyllanthus are prominent in ultramafic scrub communities and, hence, should be used in ecological restoration of mined-out Ni lateritic areas. The implications of the unique adaptation of these species are also discussed in relation to a conservation strategy for their natural populations.

CNOOC Turns On the Taps at Two Bohai Sea Fields Production has begun at CNOOC Limited’s Luda 6-2 and Bozhong 26-3 oil field expansion in the Bohai Sea. Luda 6-2 is flowing ahead of schedule, utilizing existing processing facilities of the Suizhong 36-1 oil field. The project has built a new central platform. A total of 38 development wells are planned, including 29 production wells, eight water-injection wells, and one development-and-appraisal well. The project is expected to reach peak production of around 10,000 B/D in 2022. The Bozhong 26-3 oilfield expansion project has also come online. In addition to fully utilizing existing processing facilities, new unmanned wellhead and power platforms were built for the project. A total of eight development wells are planned, including five production wells, two water-injection wells, and one development-and-appraisal well. The project is expected to reach peak production of 2,670 B/D in 2021. CNOOC Limited holds 100% interest in both projects. PPL Awarded Abu Dhabi Offshore Exploration Block A consortium of four Pakistani companies led by Pakistan Petroleum Limited (PPL) was awarded the exploration rights for Offshore Block 5 in Abu Dhabi’s second competitive block bid round. The award marks the first Pakistani company investment in and planned exploration for oil and gas in an Abu Dhabi concession as well as the first partnership between the Abu Dhabi National Oil Company (ADNOC) and Pakistani energy companies. Other companies in the consortium include Mari Petroleum Company Limited, Oil and Gas Development Company Limited, and Government Holdings (Private) Limited. Under the terms of the agreement, the consortium will hold a 100% stake in the exploration phase, investing up to $304.7 million toward exploration and appraisal drilling, including a participation fee, to explore for and appraise oil and gas opportunities in the block that covers an offshore area of 6223 km2 and is located 100 km northeast of Abu Dhabi. “The PPL-led consortium is delighted to be selected for the concession award of Abu Dhabi’s Offshore Block 5,” said Moin Raza Khan, managing director and chief executive of PPL. “This award is not only a watershed moment for Pakistan and the Emirate of Abu Dhabi towards bilateral energy cooperation and economic links, but also offers an opportunity to strengthen strategic cooperation with ADNOC to share technical know-how and expertise.” Following a successful commercial discovery during the exploration phase, the consortium will have a production concession to develop and produce the discoveries. ADNOC has the option to hold a 60% stake in the production phase, which is 35 years from the commencement of the exploration phase. The block offers the potential to create significant in-country value for the UAE over the lifetime of the concession. In addition to drilling exploration and appraisal wells, the exploration phase will see the consortium leverage and contribute financially and technically to ADNOC’s mega seismic survey, which is acquiring 3D seismic data within the block area. The data already acquired over a large part of the block, combined with its proximity to existing oil and gas fields, suggest the concession area has promising potential. Hess Exits Denmark Upstream Hess Corporation has completed the previously announced sale of its subsidiary Hess Denmark ApS, which holds a 61.5% interest in the South Arne Field, to Ineos E&P AS for a total consideration of $150 million. “The sale of our Denmark asset enables us to further focus our portfolio and strengthen our cash and liquidity position,” said John Hess, chief executive of Hess. “Proceeds will be used to fund our world-class investment opportunity in Guyana.” The transaction was effective 1 January 2021. Beacon Offshore Secures Drillship for Shenandoah Work Beacon Offshore awarded Transocean a $252-million contract for use of its newbuild ultradeepwater drillship Deepwater Atlas to work in the Shenandoah field in the US Gulf of Mexico (GOM). The deal also includes a $30-million mobilization fee from Southeast Asia to the GOM. The Shenandoah program comprises two phases. Once delivered from the shipyard, the Deepwater Atlas is expected to begin operations in Q3 2022, initially using dual blowout preventers (BOP) rated to 15,000 psi. The duration of the drilling program is approximately 255 days and should result in $80 million in contract drilling revenue. Upon completion of initial drilling, a 20,000-psi BOP will be installed on the rig, making it Transocean’s second asset with a 20,000-psi-rated well-control system. The BOP installation and commissioning is expected to last 45 to 60 days, contributing $17 million in revenue. Following the 20,000-psi BOP installation, the Deepwater Atlas will begin the well completion program. The approximate duration of this phase is 275 days and should contribute $125 million in contract drilling revenue. Gambia Block Back on the Market The A1 block offshore Gambia is available for licensing again following a $29.3-million settlement with BP for failing to meet its drilling obligations there, according to the Gambian government. The oil major failed to drill a well before the initial exploration period expired on 29 July. “The A1 Block will revert to the government, free of all encumbrances,” the government statement said. “With BP’s exit, the A1 Block will now be on the market for licensing.” BP was awarded the block’s exploration rights in 2019. Brazil’s 3R Petroleum Negotiating Potiguar Purchase Petrobras is in talks with 3R Petroleum to sell a group of assets in the Potiguar basin for more than $1 billion. In a recent securities filing, Petrobras revealed that 3R presented the best offer in public bidding for the assets in the northeastern state of Rio Grande do Norte, known collectively as Polo Potiguar. The assets include 23,000 B/D of onshore and shallow-water oil production, according to 2020 bidding documents. It also includes the Potiguar Clara Camarao Refinery, which has installed capacity of 39,600 B/D. For 3R, the acquisition would more than double the company’s oil production and launch it into the top tier of Brazil’s independent producers, along with Enauta Participacoes and PetroRio. A successful sale would eliminate a noncore asset for Petrobras in a bid to reduce debt and focus on deepwater oil production. Petrobras Spuds Aram Block Wildcat Petrobras has started drilling a wildcat well in the Aram block of the pre-salt of the Santos Basin using Constellation drillship Brava Star, according to the National Petroleum Agency (ANP). The Aram block is operated by Petrobras (80%) in partnership with CNODC, a unit of China National Petroleum Corp. (20%). The two com­panies purchased the area in the only bid of the 6th Pre-­Salt Round in 2019. They paid $1.24 billion in signature bonuses and the minimum allowed profit oil of 29.96%. Drilling at Aram began on 24 August. With the new Petrobras well, Brazil returned to record levels in exploratory activity seen only in the pre­-pandemic period. In all, five wells were drilled in the country during August—the highest number in a single month since May 2019. DNO Begins Drilling at Gomez DNO has kicked off an exploration well at its Gomez prospect on PL006C license offshore Norway. The probe will be drilled to a depth of around 3300 m below sea level, targeting Paleocene-­age formations. DNO Norge AS holds a 65% operated interest in the license; Aker BP holds the balance. Aker BP originally had a 15% interest but recently acquired another 20% interest in PL006C from DNO under a swap agreement in which DNO picked up a 25% participating interest in PL1085 (Tanumåsen) and increased its share from 20 to 30% in PL906 (Mugnetind). The swap, pending government approval, will diversify Aker’s position in the southern North Sea. The Gomez well is being drilled using the Borgland Dolphin. The well is expected to take 45 days. Pre­drill reserve estimates range from 26 to 80 million BOE. The well is close to existing infrastructure, including the Tor and Ekofisk complexes. The Gomez well is one of three exploration wells scheduled this year. The first, Røver Nord (DNO 20%), resulted in what is likely a commercial discovery. Following Gomez, Mugnetind is expected to spud in Q4 2021. Petrobras Starts Production of FPSO Carioca in Sépia Field Petrobras began producing oil and natural gas from FPSO Carioca, the first platform in Sépia field, in the Santos Basin pre­salt. The FPSO is located approximately 200 km off the coast of Rio de Janeiro, in water depths of 2200 m. The FPSO, chartered from Modec, has the capacity to process up to 180,000 B/D and to compress up to 6 million m3 of natural gas. Seven producing wells and four injection wells will be hooked into the FPSO. The oil production will be transported by offloading vessels, while the gas production will be moved through the pre­salt gas pipeline routes. The project also has a system to remove CO2 from the gas produced and reinject it into the reservoir, reducing the release of carbon dioxide into the atmosphere and improving oil recovery. The Sépia shared reservoir comprises the Sépia and Sépia Leste fields, located in the Transfer of Rights and Concession (BM­S­24) areas, respectively, and operated by Petrobras (97.6%) in partnership with Petrogal Brasil (2.4%).

Abstract In the 1837 publication of Antiquitates Americanae by the Royal Society of Northern Antiquaries in Copenhagen, Carl Christian Rafn argued that indisputable evidence proved that Norse mariners had arrived in North America around the turn of the 11th century, making them—not Columbus and his crew—the first white people to colonize the hemisphere. For historical societies and intrigued readers in the U.S., evidence about Norse settlement around the turn of the millennium could stretch the chronological, geographical, and dramatic scale of the national history that was being actively archived and narrated in this period. Americans eager to be seen as trans-Atlantic intellectual peers seriously analyzed the evidence and narrative promoted by Rafn, but their ambivalence about both the precision of the evidence and the implications of the narrative ultimately led them to marginalize the theory of Norse discovery by the time of the Civil War. In constructing their archives and historical narratives, Americans were drawn into such trans-Atlantic intellectual currents and foreign nationalist historical projects as the theory of Norse discovery, but they also navigated and redirected these currents according to their own conceptions of what belonged within the nation’s archival record and what their nation’s historical narrative should be.

The first part of the above title was used in the Journal in 1953 for a paper by Captain Carl V. Solver. His special interest was to discover how the Norse navigators of the Viking age found their way across the North Atlantic. He was the first person to interpret the small wooden disc shown in Fig. i as a fragment of an early bearing-dial and investigations since his paper was published provide considerable supportive evidence. At the time, there was some strong opposition to his views, but he persisted with his theory and wrote a book, Vestervejen. This formed a basis for other researchers to carry his work further and, as a result, there have been many international contributions over some 40 years. The archaeological find from southern Greenland seems to show that the Norse navigator used the path of the Sun's shadow during the day as the basis of a compass.

The domain of underwater wireless communication (UWC) link is gaining much attention due to an increase in various underwater activities such as offshore hydrocarbon exploration, underwater unmanned vehicles (UUV), and military practices. Increased bandwidth and a reliable data link are mainly required for such activities. Both requirements of the domain are heavily affected by the highly conductive property of the seawater. This paper demonstrates the performance evaluation of radiofrequency-UWC, focusing on surface wave analysis, to propose a reliable solution for offshore activities. A constructive interference scheme can be useful due to the sharp difference in the properties of the two mediums (air and seawater). To that end, an experimental setup is created, and a corresponding finite element method (FEM) based simulation of the radio-based wireless link is run. This is because it has higher bandwidth and speed than acoustic and optical approaches. A conduction current mechanism transmits and receives data in a synthetic water tank containing a prepared conductive media (saltwater). The study of changing depths of transmitter-receiver nodes in saltwater shows that surface waves cause significant noise reception in shallow water (less than dipole length, below water level). During a series of experiments in the tank, the lowest bit error rate (BER) is observed only when the node’s submerged height was greater than dipole length. As a result, it is meant to provide a genuine data channel model. The discovery and analysis will aid in the development of a dependable underwater data link, with applications including short-range diver-to-diver communication, and UUV capability.

Proximal Policy Optimization (PPO), a popular on-policy deep reinforcement learning method, employs a stochastic policy for exploration. In this paper, we propose a colored noise-based stochastic policy variant of PPO. Previous research highlighted the importance of temporal correlation in action noise for effective exploration in off-policy reinforcement learning. Building on this, we investigate whether correlated noise can also enhance exploration in on-policy methods like PPO. We discovered that correlated noise for action selection improves learning performance and outperforms the currently popular uncorrelated white noise approach in on-policy methods. Unlike off-policy learning, where pink noise was found to be highly effective, we found that a colored noise, intermediate between white and pink, performed best for on-policy learning in PPO. We examined the impact of varying the amount of data collected for each update by modifying the number of parallel simulation environments for data collection and observed that with a larger number of parallel environments, more strongly correlated noise is beneficial. Due to the significant impact and ease of implementation, we recommend switching to correlated noise as the default noise source in PPO.

A. S. Byatt’s Ragnarök (2011), a retelling of the Norse myth of the downfall of the gods and the end of the world, would seem to be a departure from her fictional narratives set in the nineteenth or twentieth century. However, this book is a natural development from her earlier novels that explored the Victorian crisis of faith resulting from the loss of religious certainty in the face of scientific discoveries. The author’s writing over the last twenty years has become increasingly involved with science, and she has long acknowledged her rejection of Christian beliefs. Byatt used the nineteenth century as a starting point for an exploration of twenty-first century concerns which have now resurfaced in the Norse myth of loss and destruction. This paper revisits "Possession" and "Angels and Insects" within the framework of her more recent writing, focusing on the themes of religion, spiritualism and science.

This article explores the challenge of acoustic drone detection in real-world scenarios, with an emphasis on the impact of distance, to see how sound propagation affects drone detection. Learning machines of varying complexity are used for detection, ranging from simpler methods such as linear discriminant, multilayer perceptron, support vector machines, and random forest to more complex approaches based on deep neural networks like YAMNet. Our evaluation meticulously assesses the performance of these methods using a carefully curated database of a wide variety of drones and interference sounds. This database, processed through array signal processing and influenced by ambient noise, provides a realistic basis for our analyses. For this purpose, two different training strategies are explored. In the first approach, the learning machines are trained with unattenuated signals, aiming to preserve the inherent information of the sound sources. Subsequently, testing is then carried out under attenuated conditions at various distances, with interfering sounds. In this scenario, effective detection is achieved up to 200 m, which is particularly notable with the linear discriminant method. The second strategy involves training and testing with attenuated signals to consider different distances from the source. This strategy significantly extends the effective detection ranges, reaching up to 300 m for most methods and up to 500 m for the YAMNet-based detector. Additionally, this approach raises the possibility of having specialized detectors for specific distance ranges, significantly expanding the range of effective drone detection. Our study highlights the potential of drone acoustic detection at different distances and encourages further exploration in this research area. Unique contributions include the discovery that training with attenuated signals with a worse signal-to-noise ratio allows the improvement of the general performance of learning machine-based detectors, increasing the effective detection range achieved, and the feasibility of real-time detection, even with very complex learning machines, opening avenues for practical applications in real-world surveillance scenarios.

Maha Appraisal Hits Gas for Eni in Indonesia Eni encountered natural-gas-bearing sands with its Maha 2 well in the West Ganal Block offshore Indonesia. Drilled to a depth of 2970 m in 1115 m water depth, the well encountered 43 m of gas-bearing net sands in levels of Pliocene Age, according to the operator. A production test, which was limited by surface facilities, recorded a gas deliverability of the reservoir flowing at 34 MMscf/D. The opera-tor collected data and samples during the test, to study in preparation of a field development plan for the Maha field. Two additional appraisal wells are planned for the discovery. Eni, along with partners Neptune West Ganal BV and P.T. Pertamina Hulu West Ganal, expect the field to be developed subsea and tied back to the nearby Jangkrik floating production unit (FPU), about 16 km to the northwest. Eni has been operating off Indonesia since 2001. Its current equity production in the region is around 80,000 BOE/D. Shell Sells Out of Philippines Gas Field Royal Dutch Shell has agreed to sell its stake in the Malampaya offshore gas field in the Philippines for $460 million. The major sold its 45% stake in Service Contract 38 (SC38), a deepwater license which includes the producing gas field, to a subsidiary of the Udenna Group, which already holds a 45% stake in the project. The divestment is part of the company’s strategy to narrow its oil and gas operations. The base consideration for the sale is $380 million, with additional payments of up to $80 million in 2022 and 2024 contingent on asset performance and commodity prices, according to Shell. The deal is due to complete by the end of 2021. The Malampaya gas field, discovered in 1991, currently supplies fuel to power plants that deliver about a fifth of the country’s electricity requirements, based on energy ministry data. Equinor Green Lights First Phase of Bacalhau Development Off Brazil Equinor, along with partners ExxonMobil, Petrogal Brasil, and Pré-Sal Petróleo SA, will move forward with a planned $8-billion Phase 1 development of the Bacalhau field in the Brazilian pre-salt Santos area. The Bacalhau field is situated across two licenses, BM-S-8 and Norte de Carcará. The target resource is a high-quality carbonate reservoir containing light oil. The development will consist of 19 subsea wells tied back to a floating production, storage, and offloading unit (FPSO) located at the field. The vessel will be one of the largest FPSOs in Brazil with a production capacity of 220,000 B/D of oil and 2 million bbl of storage capacity. The stabilized oil will be offloaded to shuttle tankers and the gas from Phase 1 will be re-injected in the reservoir. The FPSO contractor will operate the FPSO for the first year. Thereafter, Equinor plans to operate the facilities until the end of the license period. The development plan was approved by the Brazilian National Agency of Petroleum, Natural Gas, and Biofuels (ANP) in March 2021. First oil from the field is slated for 2024. Wintershall Strikes Gas at Dvalin North An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company’s operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m. The license partners, including Petoro and Sval Energi, are evaluating development options for the discovery, which could include a tieback to the Dvalin field. Third Odfjell Rig Tapped by Equinor Odfjell has been awarded a three-well, $40-million drilling contract for its semisubmersible drilling unit Deepsea Stavanger by Equinor. The rig will join sister units Deepsea Atlantic and Deepsea Aberdeen under contract with the Norwegian operator. The rig is scheduled to start drilling the first of three planned exploration wells in the North Sea in February 2022. The wells are expected to take about 4 months to complete. The contract includes continuing options after the initial phase. South Africa Shale Tests Encounter Gas at Karoo Pockets of shale gas were encountered during test drilling in the semi-desert Karoo region of South Africa, according to the nation’s energy ministry. A total of 34 gas samples had been bottled and taken to laboratories after the government’s Council for Geosciences set out to drill a 3500-m stratigraphic hole in the Karoo to establish and test the occurrence of shale gas. “The first pocket of gas was intercepted at 1734 m with a further substantial amount intercepted at 2467 m spanning a depth of 55 m,” said Gwede Mantashe, South African energy minister, during his budget vote in parliament on 18 May. In 2017, geologists at the University of Johannesburg and three other institutions estimated the gas resource in the Karoo was probably 13 Tcf. Earlier, the US Energy and Information Administration estimated the Karoo Basin’s technically recoverable shale-gas resource at 390 Tcf, then making it the eighth largest in the world and second largest in Africa behind Algeria. Seadrill Venture Nets New Drilling Contract Seadrill’s Sonadrill Holding Ltd., the 50/50 joint venture with an affiliate of Sonangol, has secured a 12-well contract with one option for nine wells and 11 one-well options in Angola for drillship Sonangol Quenguela. The $131-million contract before options is inclusive of mobilization revenue and additional services with commencement expected in early 2022 and running through mid-2023. The contract is contingent on National Concessionaire approval. Sonangol Quenguela is the second of two Sonangol-owned drillships to be bareboat-chartered into Sonadrill. The drillship is a seventh-generation, DP3, dual activity, e-smart ultradeepwater drillship delivered in 2019, capable of drilling up to 40,000-ft wells. A further two Seadrill-owned units are expected to be bareboat-chartered into Sonadrill. Seadrill will manage and operate the four units on behalf of Sonadrill. Shell Makes US Gulf Discovery at Leopard An exploration well at the Shell-led Leopard prospect in the deepwater US Gulf of Mexico encountered more than 600 ft net oil pay at multiple levels. Leopard is in Alaminos Canyon Block 691, approximately 20 miles east of the Whale discovery, 20 miles south of the recently appraised Blacktip discovery, and 33 miles from the Perdido spar host facility. Evaluation is ongoing to further define development options. According to Shell, Leopard is an opportunity to increase production in the Perdido Corridor, where its Great White, Silvertip, and Tobago fields are already producing. Meanwhile, the Whale discovery, also in the Perdido Corridor, is progressing toward a final investment decision in 2021. Shell operates Leopard with a 50% working interest. Partner Chevron holds the remaining 50% stake. Shell Could Leave Tunisia in 2022 Shell informed Tunisian authorities in May it will hand back upstream concessions and leave the country next year as it turns its focus to renewable energy, according to a Reuters report sourcing a senior official in the country’s energy ministry. The license in question is the Miskar concession in the southern city of Gabes. The operator has also requested the early hand-back of the Asdrubal permit, which expires in 2035. Recent reports suggest the operator may be looking for the Tunisian government to extend its permit on the field under more favorable terms ahead of its planned departure.

e14620 Background: Imaging mass spectrometry (iMS) is a promising technique for cancer biomarker discovery. Clinical translation of iMS requires advanced data treatment methods and efficient co-registration of histology and iMS imaging modalities. In this study desorption electrospray ionisation (DESI) iMS has been used to address four aims: 1. To develop a data processing workflow to address current limitations; 2. To design an interactive software platform for image co-registration; 3. To investigate region-specific lipid biochemistry in colorectal cancer (CRC) tissue using the strategy outlined in aims 1-2; 4.To introduce an automated tissue recognition system based on multivariate molecular ion patterns (MIPs). Methods: Fresh CRC tissue sections (n=49) were subjected to DESI-iMS using a Thermo Exactive mass spectrometer coupled with a DESI ion source. Mass spectra were collected in the range m/z = 200-1000. Sections were then H&E stained and scanned at high resolution. DESI-iMS data pre-processing involved peak detection, removal of noise/solvent related peaks and variance stabilising normalisation. An interactive image co-registration interface was developed using a feature-based image alignment algorithm for precise exploration of tissue region-specific biochemistry. A Recursive Maximum Margin Criterion (RMMC) algorithm was introduced for improved extraction of tissue specific MIPs. Results: CRC DESI-iMS profiles consisted mainly of complex lipids including phosphatidyl-inositols, phosphatidyl-serines, and phosphatidyl-ethanolamine plasmalogens. Different histological tissue regions showed characteristic lipid profiles. An automated tissue recognition system using multivariate MIPs derived by the proposed RMMC approach demonstrated highly accurate (classification accuracy >98%) identification of pixels according to tissue type (cancer, healthy mucosa, smooth muscle, fibrous tissue, stroma). Conclusions: This workflow permits accurate tissue-specific lipidomic characterisation of the CRC tumor microenvironment and permits accurate reconstruction of different tissue types based on MIPs.

Angola Opens Congo, Kwanza Blocks in Ongoing Bid Round Angola’s National Oil, Gas, and Biofuel’s Agency has opened blocks for licensing in the Onshore Lower Congo Basin and the Onshore Kwanza Basin as part of its 2020 oil and gas licensing round. This latest call to tender is part of the agency’s ongoing 2019–2025 hydrocarbons licensing strategy. The Onshore Lower Congo Basin Blocks include CON1, CON5, and CON6; while the Onshore Kwanza Basin Blocks comprise KON5, KON6, KON8, KON9, KON17, and KON20. The round aims to expand research and evaluation activities across sedimentary basins, increase geological knowledge of Angola’s hydrocarbon potential, and invite a new wave of explorers to yield new discoveries. Raven Field Startup for BP in Egypt Natural gas has begun flowing from the BP-operated Raven field, the third stage of the company’s major West Nile Delta (WND) development off the Mediterranean coast in Egypt. The $9-billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. Raven is currently producing approximately 600 MMcf/D with a peak potential of 900 MMcf/D and 30,000 B/D of condensate. Raven follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019, respectively. It produces gas to a new onshore processing facility, alongside the existing WND onshore processing plant. In total, the WND development includes 25 wells producing gas to the onshore processing plant via three long-distance subsea tiebacks. The onshore facilities—including the new Raven facility—now have a total gas processing capacity of around 1.4 Bcf/D of gas. All gas produced is fed into Egypt’s national grid. BP is the operator and has an 82.75% stake in the WND development, with Wintershall Dea holding the remaining 17.25% interest. CGX Secures Rig for Kawa-1 Well off Guyana CGX Energy and Frontera Energy, joint venture partners in the Petroleum Prospecting License for the Corentyne block offshore Guyana, have secured semisubmersible Maersk Discoverer to drill the Kawa-1 well. An early third quarter spud for the exploration well is targeting a Santonian age, stratigraphic trap, interpreted to be analogous to the discoveries immediately to the east on Block 58 in Suriname. The well is anticipated to be drilled to a total depth of approximately 6500 m in a water depth of approximately 370 m. The contract has an estimated duration of 75–85 days and has a one-well option attached. If exercised, that probe would spud in the nearby Demerara Block and take an estimated 40 days to reach its target. Talos’ Bulleit Reservoir in US Gulf Smaller Than Expected A technical assessment of the main producing sand performance at Talos Energy’s Green Canyon Block 21 Bulleit field in the US Gulf has indicated a smaller reservoir than originally anticipated. Project partner Otto Energy said the assessment included detailed bottomhole pressure and reservoir performance data collected after hookup and first production. The Block 21 field is flowing via a single subsea well tied back to a platform in nearby Green Canyon Block 18. While additional technical work is ongoing, the currently favored path forward is to move away from the current sand and execute a recompletion of the well in the shallower DTR-10 sand. A DTR-10 recompletion will require the procurement of long-lead items from manufacturers, which are expected to cost $3.5 million with payment expected in mid-2021. The recompletion is expected to begin in mid-2022, with production from the DTR-10 immediately following in mid-to late 2022. Captain Field EOR Stage 2 Project a Go Ithaca Energy, operator of the Captain field, has sanctioned the Captain Enhanced Oil Recovery (EOR) Stage 2 project in the UK Central North Sea after receiving Field Development Plan Addendum consent from the Oil and Gas Authority. EOR Stage 2 is designed to significantly increase hydrocarbon recovery by injecting polymerized water into the reservoir through additional subsea wells, subsea infrastructure, and new topsides facilities. Stage 1 of the project demonstrated that polymer EOR technology can work, with the production response in line with or better than expected across all injection patterns, helping maximize economic recovery. The Captain field was discovered in 1977, in Block 13/22a located on the edge of the outer Moray Firth. The billion-barrel field achieved first production in March 1997—over 24 years ago. Ithaca Energy holds 85% working interest, while partner Dana Petroleum holds the remaining 15%. Equinor Touts new Tyrihans Field Discovery Equinor and partners Total E&P Norge AS and Vår Energi AS have struck oil and gas in a new segment belonging to the Tyrihans field in the Norwegian Sea. Exploration well 6407/1-A-3 BH in production license 073 was drilled from sub-sea template A at Tyrihans North. The well was drilled to a measured depth of 5332 m by semisubmersible drilling rig Transocean Norge and struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. In the Tilje formation, moderate to good quality water-bearing reservoir was struck. The Tyrihans field is in the middle of the Norwegian Sea, some 25 km southeast of the Åsgard field and 220 km northwest of Trondheim. The licensees consider the discovery commercial and intend to start production immediately. Recoverable resources are so far estimated at between 19 and 26 million BOE. Maersk Awarded Intervention Work off Brazil Maersk Drilling has been awarded a contract with Karoon Energy Ltd. for the semisubmersible rig Maersk Developer to perform well intervention on four wells at the Baúna field offshore Brazil. The contract is expected to begin in the first half of 2022, with a firm duration of 110 days. The value of the contract is $34 million, including rig modifications and a mobilization fee. The contract contains options to add up to 150 days of drilling work at the Patola and Neon fields. Carnarvon Completes Farmout of Buffalo Project Carnarvon Petroleum has completed the farmout of 50% of the Buffalo project to Advance Energy PLC. On 17 December 2020, Carnarvon announced that Advance Energy would acquire 50% of the Buffalo project off the west coast of Australia by funding the drilling of the Buffalo-10 well up to $20 million on a free carry basis. Advance met this funding requirement and now has a 50% interest in the project. The well is on track to be drilled in late 2021, subject to securing a drilling rig, where the tendering process is already underway. Following the well, the joint venture will acquire development funding from third-party lenders and any additional funding will be provided by Advance as an interest-free loan. The current plan is to suspend a successful well as a future producer and begin early development studies during 2021. Shell Hires Seadrill Rig for Brazilian Campaign Shell has contracted Seadrill’s drillship West Tellus for a new drilling campaign offshore Brazil this year. The program is expected to start in BC-10 of the Campos Basin, where Shell operates the Parque das Conchas made up of the Abalone, Argonauta, and Ostra fields. BC-10 has produced more than 100 million bbl since oil first started flowing from the block in 2009. The drillship will be used on the third phase of BC-10 activity, which includes five additional production wells and two water-injection wells at the Massa and Argonauta O-Sul fields, with the wells connected to the Espirito Santo FPSO. Shell owns a 50% operating stake in BC-10. India’s ONGC retains a 27% minority share and Qatar Petroleum the remaining 23%. Following the BC-10 work, the operator is expected to drill the first wells in the Campos Basin’s C-M-791 block, which was acquired during the 15th bid round held in 2017. Shell owns a 40% operating stake in the block, with Chevron retaining a 40% interest and Portugal’s Galp Energia the remaining 20%. Panoro Energy Kicks Off 2021 Drilling Campaign Offshore Gabon Panoro Energy has initiated its 2021 Gabon drilling campaign with the spudding of the Hibiscus Extension well on the Dussafu Marin Permit. That well will be followed by drilling at Tortue and Hibiscus North. Hibiscus and Tortue are two out of a total of six discovered fields within the Dussafu Permit offshore Gabon. Panoro currently holds a 7.5% interest in the license and has entered into an agreement to acquire an additional 10% working interest in the Dussafu Permit, bringing its total ownership to 17.5% following completion of the transaction. The Extension well is being drilled with the jackup Borr Norve and is the first well in a three-well campaign planned on Dussafu during 2021. The well is planned as a vertical well to test structure, oil, and reservoir presence in what is believed to be a possible northerly extension of the Gamba reservoir in the Hibiscus field. The well is positioned about 3 km northwest of the Hibiscus discovery well drilled by the joint venture in 2019. The initial well and its appraisal sidetrack established a 2P gross recoverable reserves of just over 46 million bbl at the Hibiscus field. The Extension well is expected to take around 30 days to drill and log to a total depth of 3500 m. Success at the probe could prompt one or two appraisal side-tracks to further delineate the field. Following the Hibiscus Extension, the rig will move to drill a horizontal production well, DTM-7H, at the Tortue field. This will complete the Phase 2 development of Tortue and, along with DTM-6H, will bring the total number of production wells at Tortue up to six. An exploration well at the Hibiscus North prospect, located approximately 6 km north-northeast of the initial Hibiscus well is also scheduled. Hibiscus North is a separate 10–40 million bbl prospect that could be tied into the Hibiscus/Ruche development project. Puma West Strike for BP in the US Gulf An exploration well at the Puma West prospect in the deepwater US Gulf has yielded a significant oil discovery for operator BP. The well, on Green Canyon Block 821, was drilled using Seadrill drillship West Auriga to a total depth of 23,530 ft and encountered oil pay in a high-quality Miocene reservoir with fluid properties like productive Miocene reservoirs in the area. Preliminary data supports the potential for a commercial volume of hydrocarbons. The Puma West partners will begin planning an appraisal program to better define the discovered resource. The discovery well has been suspended as a keeper well to preserve future utility. Puma West is located west of the BP-operated Mad Dog field and is approximately 131 miles off the coast of Louisiana in 4,108 ft of water. The Puma West is operated by BP with a 50% working interest. Partners include Chevron with 25% and Talos Energy with the remaining 25%. Petrobras Pushes First Oil at Mero Into 2022 Petrobras has postponed first oil from its Mero 1 field via the FPSO Guanabara in the Santos Basin offshore Brazil due to delays with the production system. Startup at Mero 1 was originally expected in the fourth quarter of this year and is now expected to begin flowing during the first quarter of 2022 due to COVID-19 pandemic-related delays with the buildout of the production system in China. The FPSO will be installed in the Mero field, which belongs to the Libra Block, in the Santos Basin pre-salt area, with a processing capacity of 180,000 OPD. The field is operated by Petrobras (40%) in partnership with Shell Brasil Petróleo (20%), Total E&P (20%), CNODC Brasil Petróleo e Gás (10%), CNOOC Petroleum Brasil (10%), and Pré-Sal Petróleo, which is the contract manager.

This paper offers an in-depth exploration of a group of small Viking Age figurines commonly referred to as ‘valkyries’ in Viking and Old Norse scholarship. After presenting an overview of the long research history pertaining to these finds and their varying definitions, this study re-analyses their various formal and stylistic features and proposes a new typological system based on a comprehensive investigation of the current find corpus. This is followed by a deconstruction and discussion of the ambiguous gender characteristics of the figurines and an exploration of the potential new avenues of their interpretation. The study is supplemented by detailed catalogues of all presently known finds of so-called armed ‘valkyrie’ figures as well as high-quality illustrations that demonstrate their great iconographic value for studies of Viking Age clothing, martial equipment and ritual behaviour.

Eight lecture summaries:The discovery of a Norse horizontal mill at Orphir, OrkneyBritain and the Mediterranean in Late AntiquityScottish prehistoric 'jet' jewellery: some new workMedieval embroiderersField survey and excavation at Dunbeath, CaithnessThe post-medieval burial vault 1450-1715Post-glacial hunter/gatherers in Europe and their adaptation to changeBrochs: domestic architecture and changing social configurations in prehistoric and Early Historic Scotland

The article examines the mythopoetic concept of the ‘world’ (Old Norse heimr) and its derivatives — toponyms with the suffix -heimr in the Poetic Edda. It involves a thorough analysis of their meanings and their significance in the Eddic mythopoetic framework. The methodology for studying this lexical unit and its derivatives is based on a thesaurus description of folk terminology, alongside an exploration of polysemy within epic texts and lexicological investigations of key concepts in the Rigveda. Employing an integrated approach, the analysis considers various factors such as statistical distribution, grammatical case paradigms, syntactical functions of predicates, etymology to understand semantic motivations, mythology to reveal connections to mythological elements, poetic devices like alliteration and repetitions, and the relationship between linguistic signs and referents in the extralinguistic world. The predominance of singular forms (28) over plural forms (8) suggests two significant points: the existence of multiple worlds in the Eddic mythopoetic model initially, and an evolutionary progression from a collection of similar objects towards a unified whole. This semantic evolution is exemplified by the transition from ‘dwellings of giants’ (plural iǫtna heimar) to ‘Dwelling of giants’ = ‘World of Giants’ (singular Iǫtun-heimr). The Old Norse term heimr is associated with the universal world model depicted as a world tree (nine worlds = nine roots of Iggdrasill in Völuspá). It contributes to the construction of the Eddic chronotope in which the world tree, along with its roots (representing worlds), is described as located “under the earth,” signifying its origin. It also demonstrates temporalization, being linked with the temporal concept of age (Old Norse ƍld) and exhibits anthropocentric orientation.

Abstract BACKGROUND Medulloblastoma, a malignant brain cancer predominantly affecting children, possesses a high propensity for metastasis and is frequently fatal. Through studies on RNA translation, a core biological process, we aim to uncover the disease biology of cancer in order to design therapeutic targets. Yet, the exploration of canonical protein-coding genes has thus far yielded few viable targets in medulloblastoma, where non-canonical open reading frames (ORFs) are increasingly being investigated for their regulatory role. METHODS To address the significant challenge in delineating novel translated ORFs in individual cells or tissues, we have designed RIBO-former, a best-of-its-class machine learning model that leverages ribosome profiling data to detect translated open reading frames. Through RIBO-former, we expanded the proteome of healthy prenatal (n=30) and adult (n=42) samples, which are notoriously hard to process due to low read depth and noise, in addition to medulloblastoma cancer tissue (n=8) and cell line (n=15) data. RESULTS Across all medulloblastoma cell lines, we determine an initial selection of 3,638 non-canonical ORFs. Unsupervised clustering of the ribosome profiling read counts within these non-canonical ORF regions group samples according to the described subtypes of medulloblastoma cancer, hinting at the significant role these ncORFs play in protein homeostasis. Looking into distinct expression profiles between cell lines with high and low MYC expression, we revealed 201 non-canonical ORFs that are differentially expressed. We evaluate our data through various analyses including testing of which ORFs have a viable sequence context for translation, achieved through another in-house tool (TIS Transformer). CONCLUSIONS By taking advantage of advances in machine learning, we were able to uncover new sites of translation in medulloblastoma that can aid the future discovery of therapeutic targets. As such, we were able to find 22 highly promising non-canonical ORFs that show unique expression profiles in relation to MYC in medulloblastoma.

Abstract Fetal hemoglobin (HbF) can inhibit the polymerization of sickle hemoglobin, and the HbF level is an important modulator of the severity and course of sickle cell anemia. Genetic regulation of HbF levels is complex and under active investigation. Although multiple quantitative trait loci have been discovered, it is estimated that half of the genetic variance of HbF levels remains unaccounted for. Genomic copy number variations (CNVs), defined as inherited duplications or deletions of kilo-to mega-base lengths of DNA, represent a significant source of genetic heterogeneity among humans that might be involved in HbF regulation. Additionally, CNVs can significantly alter assumptions about genotype frequencies in their genomic region, and are therefore important to locate for multiple types of genetic association studies. Here, we present a novel method for the high-resolution discovery of CVNs related to HbF levels in sickle cell anemia, using genome-wide association study (GWAS) data. We used the Illumina 610K single nucleotide polymorphism (SNP) genotyping array to examine 727 adult subjects with sickle cell anemia, with or without a thalassemia, who were enrolled in the Cooperative Study of Sickle Cell Disease (CSSCD; aged 18 to 69 years, mean age 31 years; 44% male; not on hydroxyurea therapy). The Illumina array consisted of ~610K probes spread across the entire genome. At each locus, the relative amount of DNA detected was compared to a reference and expressed as the log R ratio score (LRR). Normal diploid regions of DNA have LRRs close to zero, whereas regions with CNVs have LRRs that are either higher for areas of duplication or lower for areas of deletion. Using LRR information in the context of a GWAS, we developed a novel, two-step signal-processing technique that combines CNV discovery with subsequent phenotypical association analysis. First, the distribution of LRR values at each locus is stratified using a +/− 1.5 standard deviation band-pass filter. This created three groups: a central major group comprised of people with diploid amounts of DNA, and two minor variant groups, one composed of people with elevated LRRs, suggesting &gt;2 DNA copies, and one of people with decreased LRRs, suggesting &lt;2 DNA copies at that locus. To reduce noise, loci without at least one minor group containing &gt;5% of the sample were excluded from further analysis. In the second step, a two-sample Student’s t-test was used at each locus to examine the variation in distributions of HbF between the major, diploid group and any variant groups with &gt;5% of the population. Using this method, we examined chromosomes 2, 6, and 11, which include regions known to modulate HbF in patients with sickle cell anemia, individuals with β thalassemia, and in the normal population. We successfully detected multiple clear duplications and deletions (approx. 1 per 6–22 mbp, depending on the chromosome) that showed typical CNV LRR distributions with &gt;10% of the population exhibiting the polymorphism. Several of these were mildly related to HbF levels (p&lt;0.05), including deletions in ASB1 on chromosome 2, and HACE1 on chromosome 6, both ankyrin motif containing proteins involved in the ubiquitin ligase system, as well as an upstream duplication and intragenic deletion involving HLA-DRB5 on chromosome 6. None of these clear CNVs, however, overlapped regions known to affect HbF concentration. Additional potential CNVs were detected throughout each chromosome, many exhibiting atypical LRR distributions not easily classified as either a normal diploid or clear CNV region. Further studies are required to confirm the presence of a CNV at these atypical loci. With this method, we were able to detect CNVs and CNV breakpoints across a population with a single-probe resolution, to within &lt;1kb in some cases. This resolution offers a distinct advantage over other detection methods that utilize a multiple-probe, sliding-window approach to detect LRR deviations in an individual sample. In conclusion, this two-step method of high-resolution detection of CNVs followed by analysis of phenotypical associations shows promise for explaining variations in expressed protein levels, such as those typical of HbF in sickle cell anemia, and possibly for future exploration of differences in HbF responses to therapeutics in sickle cell anemia.

Abstract: Travel is often thought to be an adventure, an exploration, a way of knowing self and world, a break from the stresses of everyday life, a vacation. But there can be a dark side to travel, as in voyages that are part of invasion, conflict and enforced transport. Here, I wish to concentrate on conflict, domination, murder and genocide and do so, at various moments, by referring to the Norse sagas, including the encounter with the Skrælings in the New World and, more briefly, Columbus’ and the Spaniards’ violent treatment of the Natives in the New World and the German transport, torture and murder of Jews in the Shoah, or Holocaust.

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.

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.