Littérature scientifique sur le sujet « North Shore Ferneries Company »

Born and raised in the Orkney Islands, Dr John Rae joined the Hudson's Bay Company and rose to be Chief Factor. Unusually tough and intelligent, he explored much of northern Canada, mapping the north eastern shore and finding controversial evidence of the lost Franklin expedition of 1845. A talented botanist, geologist, anthropologist and cartographer, he was northern Canada's most distinguished explorer.

The Long Island Research Institute was set up in 1992 to create and nurture enterprises based on technologies derived from its sponsoring institutions: the University at Stony Brook, Brookhaven and Cold Spring Harbor Laboratories, and North Shore University Hospital. An account of the organization's conception is followed by descriptions of its comprehensive approach to technology commercialization in three projects: a gene-finding methodology, an organ preservation device, and a wastewater treatment system. These experiences suggest that success for such an organization requires managers combining technical and business expertise, extensive contacts with local business and research communities, variable and ongoing company assistance, access to venture capital, knowledge of company needs, an entrepreneurial champion for each project, and, fundamentally, public and institutional funding.

Grizzly bears have been observed with increasing frequency in northern Manitoba, Canada over the last four decades (1980 – 2020), likely originating from the established population in Nunavut and the Northwest Territories. We summarize and present an interdisciplinary synthesis of documented observations of grizzly bears in northern Manitoba from historical records from the Hudson’s Bay Company Archives, published literature, direct observations, remote camera observations, government agency reports, the first author’s field notes, volunteered observations, and media and social media reports. A total of 160 observations were recorded, 140 of them since 1980. Spatially, these observations all fall within the Southern Arctic, Hudson Plains, and Taiga Shield ecozones within Manitoba and span from the northern limit of Manitoba at the Nunavut border to the south shore of the Nelson River. Grizzly bears were historically present in northern Manitoba prior to 1980, though in very low numbers, but the frequency of observations has increased significantly since then. Most observations (86%) were less than 1 km from the Hudson Bay coast. Grizzly bears appear to select for open habitats and against forested ones. Reported observations, however, have been largely opportunistic, and the geographical distribution of observer efforts was uneven, so our data likely contain spatial and temporal biases. All confirmed observations were of single bears, suggesting that the present population is likely maintained by dispersal from the population to the north. Understanding grizzly bear ecology, distribution, and demographics north and west of Churchill will be critical for more accurately assessing the status and conservation needs of grizzly bears in the province.

Hong Ngu Town is currently the only town of Dong Thap Province. Place name Hung Ngu dates back from early times and was officially recorded in many of Nguyen Dysnasty’s historical records. The place name Hong Ngu originated from Hung Ngu which was the name of the Nguyen Lords’ army troup assigned to guard the border and to collect taxes. The place where the Nguyen Lords’s army troup stationed was named Bao Hung Ngu. The land was garrisoned by the army troup of the same name. Through long-time contact, the land’s name was set as Hung Ngu. For convenience of sound pronunciation, “hung” was pronounced a little bit inclined to “hong”; thereby, “hung ngu” to “hong ngu”. The place name Hung Ngu (now called Hong Ngu) may have been formed in the late 18th Century or the early 19th Century. Bao Hung Ngu troup originally stationed at Rach Doc Vang rivulet mouth (at Thanh Binh rural district), then moved to the lower shore of Hiep An river, now is the Mekong resort of Dong Thap Tourist Company. Over 200 years, Hong Ngu constantly developed. It took 85 years sharp for the frontier military post in the Nguyen Lords’ times to become an administrative unit at rural district level (1029); now it has been the district-level town of the province for 5 years (2009-2014). The paper points out the continuity of the formation and development process as mentioned above. Hong Ngu continues to rise to become an urban area and the clue of an economic focal point of the North of Dong Thap Province, and towards the near future, a city in the sea area.

Energean Secures Rig for Multiwell Program off Israel Energean has signed a contract with Stena Drilling for an up to five-well drilling program offshore Israel, which is expected to target the derisking of unrisked prospective recoverable resources of more than 1 billion BOE. The contract is for the drilling of three firm wells and two optional wells using drillship Stena Icemax. The first firm well is expected to spud in early 2022. The firm wells are all expected to be drilled during 2022. “Our five-well growth program off-shore Israel, commencing in the first quarter of 2022, has the potential to double Energean reserve base with resource volumes that can be quickly, economically, and safely monetized,” said Mathios Rigas, chief executive of Energean. “Combined with first gas from our flagship Karish gas development project in mid-2022, the next 12 months are set to be truly transformational for Energean.” One of the firm wells is the Karish North development well. The scope includes re-entry, sidetracking, and completion of the previously drilled Karish North well and completion as a producer. The Karish North development will commercialize 1.2 Tcf of natural gas plus 31 million bbl of liquids and is expected to deliver first gas during the first half of 2023. The program also includes the Karish Main-04 appraisal well and the Athena exploration well, located in Block 12, directly between the Karish and Tanin leases. Athena is estimated to contain unrisked recoverable prospective resource volumes of 0.7 Tcf of gas plus 4 million bbl of liquids. Exxon Hits, Misses off Guyana ExxonMobil made another new discovery in the Stabroek Block offshore Guyana but came away empty with a well on the Canje block. The Longtail-3 well on the Stabroek block struck 230 ft of net pay, including newly identified reservoirs below those intervals found in the Longtail-1 probe. “Longtail-3, combined with our recent discovery at Uaru-2, has the potential to increase our resource estimate within the Stabroek block, demonstrating further growth of this world-class resource and our high-potential development opportunities offshore Guyana,” said Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil. Exxon operates the 6.6-million-acre Stabroek Block as part of a consortium that includes Hess and China’s CNOOC. The new well was drilled 2 miles south of Longtail-1, which was drilled in 2018 and encountered 256 ft of oil-bearing sandstone. The Uaru-2 well in the Stabroek Block was announced in April. That well struck 120 ft of pay. While Stabroek drilling success continues, the operator suffered a set-back on the nearby Canje block and its Jabillo-1 well. The Stena Carron drillship reached a planned target depth of 6475 m; however the well failed to encounter commercial hydrocarbons. According to partner Eco Oil and Gas, the well was drilled to test Upper Cretaceous reservoirs in a stratigraphic trap. Drillship Stena Drillmax will next mobilize to drill the Sapote-1 prospect located in the south-eastern section of Canje, in a separate and distinct target from Jabillo. Sapote-1 lies approximately 100 km southeast of Jabillo and approximately 50 km north of the Haimara discovery in the Stabroek Block, which encountered 207 ft of gas-condensate-bearing sandstone reservoir. Erdogan Touts Turkish Black Sea Natural Gas Discoveries Turkey President Recep Tayyip Erdogan announced the discovery of new natural gas deposits in the Black Sea, where the country plans to start production in 2023. State energy company Tpao found 135 Bcm of gas at the Amasra-1 off-shore well, bringing the total amount of deposits discovered over the past year to 540 Bcm, according to Erdogan. Turkey has ramped up offshore exploration for hydrocarbons over the past few years. Last year, explorers found 405 Bcm of gas at the Tuna-1 well in Sakarya field. Turkey currently imports nearly all the 50 Bcm of gas it consumes annually. Equinor Hits Oil Near Visund Equinor struck oil in Production License 554 with a pair of wells at its Garantiana West prospect. Exploration wells 34/6-5 S and 34/6-5 ST2 were drilled some 10 km north-east of the Visund field, with the former encountering a total oil column of 86 m in the Cook formation. The latter well encountered sandstones in the Nansen formation, but did not encounter commercial hydro-carbons. Recoverable resources are esti-mated at between 8 and 23 million BOE. “This is the first Equinor-operated well in the production license, and the fifth discovery on the Norwegian continental shelf this year,” said Rune Nedregaard, senior vice president, exploration and production south. “The discovery is in line with our roadmap of exploring near existing infrastructure in order to increase the commerciality.” Well 34/6-5 S was drilled using Seadrill semisubmersible rig West Hercules. Equinor operates the discovery; partners include Var Energi and Aker BP. ExxonMobil Eyes Flemish Pass Well ExxonMobil is looking to secure a semi-submersible to complete the drilling of a deepwater wildcat in the Flemish Pass offshore eastern Canada. The operator began drilling the Hampden K-41 probe in the spring of last year using Seadrill semisubmersible rig West Aquarius, but the unit was pulled off the well soon thereafter for reasons unknown. ExxonMobil is currently prequalifying companies to supply a mobile offshore drilling unit to continue the well at Hampden in Exploration License (EL) 1165A. The operator is targeting a mid-year 2022 start to the probe to be drilled in around 1175 m of water, some 454 km from St. John’s, Newfoundland. Meanwhile, China’s CNOCC has wrapped up drilling on its Pelles prospect, its first exploration well offshore Newfoundland. The prospect, in about 1163 m of water, is located within license EL 1144. The wildcat was originally set to spud in early 2020 but was delayed due to impacts of the COVID-19 pandemic. The company confirmed that drilling operations onboard drillship Stena Forth were complete and the rig plugged and abandoned the well. The results of the well were not released. Equinor To Drop Mexican Offshore Leases Equinor will exit two Mexican deepwater blocks as part its upstream investment strategy to focus on assets offering rapid and strong returns. The two blocks located in the Salina Sureste basin were acquired in Mexico’s 1.4 bid round in an equal equity split with BP and TotalEnergies. Block 3, where Equinor holds a 33% operating interest, has water depths ranging from 900 to 2500 m. Block 1, where BP is the operator, has water depths ranging from 200 to 3100 m. Exploration commitments include a single well on each block, not yet drilled. The announcement to exit Mexico was made by Executive Vice President for E&P International Al Cook during the company’s Capital Markets Day event held in June. The company also unveiled plans to leave Nicaragua and Australia, as part of its upstream investment plans. Cook added that Equinor will only operate offshore assets moving forward and will no longer operate onshore, unconventional projects. The company will instead opt to partner with others on those projects. Equinor will also look to offload its exploration assets in the Austin Chalk play in the US and Terra Nova in Canada, he said. Var Energi Strikes North Sea Oil Var Energi has confirmed a discovery at its King and Prince exploration wells in the Balder area in the Southern North Sea. Success at the combined King and Prince exploration wells lifts preliminary estimates of recoverable oil equivalents between 60 and 135 million bbl. King/Prince was drilled in PL 027 by semisubmersible rig Scarabeo 8. The Prince well encountered an oil column of about 35 m in the Triassic Skagerrak formation within good to moderate reservoir sandstones, while the King well discovered a gas column of about 30 m and a light oil column of about 55 m with some thick Paleogene sandstone. An additional King appraisal side-track further confirmed a 40-m gas column and an oil column of about 55 m of which about 35 m are formed by thick and massive oil-bearing sandstone with excellent reservoir quality. The licensees consider the discoveries to be commercial and will assess tie-in to the existing infrastructure in the Balder area. The wells are located about 6 km north of the Balder field and 3 km west of the Ringhorne platform. Var Energi operates and holds a 90% stake of the license. Mime Petroleum holds the remaining 10%.

In 1893–1894, Albert Peter Low of the Geological Survey of Canada, along with D.I.V. Eaton and four indigenous assistants explored the Labrador Peninsula, then perceived as one of the last great unexplored wilderness areas of North America. The expedition left Lake St. John (now Lac St. Jean) on June 17, 1893, canoeing across the northeastern edge of the North American continent, arriving at Fort Chimo (now Kuujjuaq) on August 27, 1893. They departed Fort Chimo by steamer for Rigolet on the Labrador coast and the Hudson Bay Company post at North West River in the fall of 1893. On March 6, 1894 the party started up the Grand (now Churchill) River continuing through large central lakes into the Ashuanipi river system in western Labrador, then out via the Attikonak River to the Romaine River and finally the Saint Jean river system to arrive at Mingan on the north shore of the St. Lawrence River on August 23, 1894. Low described their fifteen-month journey as having covered over 8700 km including 1600 km on foot, over 4700 km in canoe, 800 km by dog team and 1600 km by steamer. The report from the expedition provides a compendium on the natural history of the region as well as the first geological maps. In terms of economic and scientific results, the greatest was documentation of the vast iron ore deposits of western Labrador; a world-class mining district that has been producing for sixty-three years since 1954. Low’s account also provides details on the essence of such an epic journey, which stands as a classic in the annals of Canadian geological surveying.RÉSUMÉEn 1893–1894, Albert Peter Low de la Commission géologique du Canada, accompagné du D.I.V. Eaton et quatre assistants autochtones ont exploré la péninsule du Labrador, alors perçue comme l'une des dernières grandes étendues sauvages inexplorées d’Amérique du Nord. L’équipe a quitté le Lake St. John (aujourd'hui le lac Saint-Jean) le 17 juin 1893, a traversé la bordure nord-est du continent nord-américain en canoë, et est arrivé à Fort Chimo (aujourd'hui Kuujjuaq) le 27 août 1893. À l'automne de 1893, ils ont quitté Fort Chimo à bord d'un vapeur pour Rigolet, sur la côte du Labrador, et le poste de la Compagnie de la Baie d'Hudson sur la rivière North West. Le 6 mars 1894, les membres de l'équipe ont remonté la rivière Grand (aujourd'hui Churchill), puis à travers les grands lacs centraux jusqu'au bassin de la rivière Ashuanipi, dans l'ouest du Labrador, puis, par la rivière Attikonak jusqu' à la rivière Romaine et, enfin, le réseau de la rivière Saint-Jean jusqu’à Mingan, sur la rive nord du fleuve Saint-Laurent, le 23 août 1894. L’excursion décrite par Low a duré quinze mois et parcouru plus de 8700 km dont 1600 km à pied, plus de 4700 km en canoë, 800 km en attelage de chiens et 1600 km en bateau à vapeur. Le rapport de l'expédition constitue un recueil sur l'histoire naturelle de la région ainsi que des premières cartes géologiques. En ce qui concerne les répercussions économiques et scientifiques, la plus importante en a été la documentation des vastes gisements de minerai de fer de l'ouest du Labrador, un district minier de classe mondiale, en production pendant soixante-trois ans depuis 1954. Le récit de Low fournit également des détails sur le caractère épique d’une telle expédition, laquelle est un classique dans les annales de la Commission géologique du Canada.

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31443, “Operator and Service Provider Collaborate To Successfully Introduce an Automated Advisory System in a Wildcat Exploration Well Offshore Mexico,” by Peter Batruny, SPE, M. Razali Paimin, and M. Arriffuddin Allauddin, Petronas, et al. The paper has not been peer reviewed. Copyright 2022 Offshore Technology Conference. Reproduced by permission. _ The authors of the complete paper describe a collaboration between an operator and a service company formed during a project’s well-planning phase to evaluate the feasibility of automation for a holistic drilling-advisory platform that facilitates real-time decision making based on downhole and surface data. The collaboration resulted in a successful deployment of an automation platform as a solution to manage and mitigate risks and optimize drilling operations in exploration wells. Introduction The probability of nonproductive time (NPT) and invisible lost time (ILT) occurring in exploration wells is higher because of a lack of experience in the area concerned. The operator estimates that NPT caused by hole problems accounts for 22% of total NPT (Fig. 1). The authors’ work aims to apply a novel, automated drilling-operation monitoring technique on a wildcat exploration well in the Gulf of Mexico through the collaboration of operator and service provider. A collaborative framework and technology integration is applied to minimize the effect of uncertainty on NPT and ILT. Description and Application of Equipment and Processes The well is in the Salina Basin, approximately 67 nautical miles north of shore, with an estimated water depth of 66 m below mean sea level. The maximum planned well total depth was approximately 4400 m true vertical depth subsea. The proposed well lies in a four-way anticline structure. Despite the abundance of wells around the location, most exploration activities performed in the area have been focused on the Middle and Lower Pliocene (shallower) interval, causing well correlation at the Miocene stratigraphic interval to be extremely limited. In addition, the disparate thicknesses of the Pliocene sediments in the area create significant challenges in terms of geological correlation. Five offset wells were used as stratigraphy correlation, with distances ranging from 8 to 31 km. Downhole losses and borehole instability were experienced in all offset wells, with well-control events experienced in three out of five offset wells.

The topic of sustainability within the oil and gas industry has dominated news agendas in recent years. As ‘Net Zero by 2050’ goals loom closer, the sector is under greater pressure than ever to decarbonize operations and source oil and gas via more sustainable methods. With the energy transition continuing at pace, the growth of renewable energy has been exponential. Energy sources such as nuclear and wind are set to account for a greater portion of the energy mix. Renewables expenditure is also expected to double over the next 10 years to more than $1,300 billion per year, and grid expenditure is likely to exceed $1,000 billion per year in 2030. However, oil and gas will undoubtedly play a crucial role in meeting global energy demand for the foreseeable future. A recent industry report highlighted that conventional hydrocarbons are set to comprise 49% of the energy mix in 2050, emphasizing the sustained requirement for traditional hydrocarbons. It is no secret the oil and gas sector is a high producer of carbon emissions, and according to the International Energy Agency, global production, transportation, and processing of oil and gas emitted the equivalent of 5.1 billion tons of CO2 in 2022. That’s almost 15% of total energy-related greenhouse gas emissions. So, how do we as an industry continue to extract this much needed energy source in a more-sustainable manner? Methods to curb this emission are already in practice, with operators utilizing new technology to reduce waste-gas production, return the gas to on-site product streams, and reinject methane into reservoirs. A notable example came from ExxonMobil in January of this year with the company announcing it had stopped routine flaring of natural gas from production in the top US shale basin, using compressors to push natural gas to a pipeline. It has also allocated $17 billion through 2027 to lower its greenhouse gas emissions globally. Electrification is also a hot topic, with operators investigating methodologies for how to reduce emissions from offshore assets. bp, Equinor, and Ithaca Energy recently signed a memorandum of understanding to explore electrification options for their offshore production facilities in the West of Shetland area in the North Sea. Electrification solutions could include power from shore, potentially from onshore wind, or from offshore wind. Full electrification would require in the region of 200 MW of power. If successful, the fields would become the first oil and gas developments on the UK Continental Shelf to be powered by electricity delivering a fully renewable solution. These latest industry moves are bold. They certainly show that much-needed action is now taking place and that industry is responding to social and environmental pressures to make changes.

Introduction: Polatuzumab vedotin (Pola) combined with rituximab (R) demonstrated activity and tolerability in a Phase (Ph) II trial of patients (pts) with relapsed/refractory (R/R) diffuse large B-cell lymphoma (DLBCL) (Morschhauser et al. Lancet 2019). The pro-survival MCL-1 protein has been identified as a mechanism of resistance to venetoclax (Ven), a potent inhibitor of BCL-2, in non-Hodgkin lymphoma cell lines. Preclinical studies have demonstrated that concurrent treatment with Pola promotes MCL-1 degradation and enhances anti-tumor efficacy in vivo, thus providing a strong rationale for the combination with Ven (Amin et al. AACR 2020). We sought to determine whether the combination of Pola-Ven-R might further enhance anti-tumor response. Here, we present the primary efficacy and safety analysis from a Ph Ib/II study of Pola-Ven-R in pts with R/R DLBCL (GO29833; NCT02611323). Methods: GO29833 is an open-label, multicenter study of pts with R/R DLBCL who had received ≥1 prior anti-CD20 chemo-immunotherapy regimen. The recommended Ph II dose (RP2D) combination for Pola-Ven-R was initially defined in a 3+3 dose escalation phase and was then expanded into Ph II. Pts in the expansion cohort received induction therapy with six 21-day cycles of: intravenous (IV) Pola 1.8mg/kg (Cycle [C] 1-6: Day [D]1), Ven 800mg by mouth daily and R 375mg/m2 IV (C1-6: D1). Responders received consolidation therapy for 8 months (Ven 800mg daily and R 375mg/m2 on D1 every 2 months). The primary safety objectives were to determine the RP2D for Pola and Ven when given in combination with R and to evaluate the safety and tolerability of the Pola-Ven-R combination. The primary efficacy endpoint was complete response (CR) at end of induction (EOI), as determined by the Independent Review Committee (IRC) based on positron emission tomography-computed tomography (PET-CT) scans using modified Lugano 2014 response criteria. Secondary objectives included CR-rate at EOI and best overall response (BOR) determined by the investigator (INV). Exploratory objectives included INV-assessed progression-free survival (PFS) and overall survival (OS). Results: At the primary analysis (January 30, 2020), 57 pts from the Ph Ib/II populations were enrolled and received at least one study drug; the median duration of follow-up was 7.0 (range 0.2-30.4) months. Baseline characteristics of the safety-evaluable pts are shown in Table 1: median age, 65 years; male, 49%; Ann Arbor Stage III-IV, 84%; International Prognostic Index (IPI) ≥3, 54%; median prior lines of therapy, 3; refractory to last line, 83%; primary refractory, 65%. Dose limiting toxicity was not observed in Ph I and the maximum dose level was chosen as RP2D. All except two pts experienced at least one adverse event (AE), 21 (37%) had a serious AE, and 45 (79%) had a Grade 3-4 AE. The most common Grade 3-4 AEs were neutropenia (30 pts, 53%), infections (9 pts, 16%), and anemia (6 pts, 11%). AEs leading to dose reduction or interruption of any drug occurred in 10 (18%) and 35 (61%) pts, respectively; the majority of dose modifications were changes to Ven dosing. Seven (12%) pts had an AE that led to the discontinuation of any study drug (Pola [n=5]; Ven [n=7]; R [n=6]). One grade 5 AE was reported (pneumonia); however, it was not considered related to study treatment as the pt had received new anti-lymphoma therapy following disease progression. In the primary efficacy-evaluable population (n=48), the IRC-assessed modified Lugano CR rate at EOI was 29% (Table 2). The INV-assessed CR rate at EOI and BOR were 31% and 65%, respectively, with a median duration of response of 5.8 months (95% confidence interval [CI]: 3.4-6.7). The median PFS and OS were 4.4 months (95% CI: 3.0-7.1) and 11.0 months (95% CI: 6.7-not evaluable), respectively. Conclusions: Our study of the novel triplet combination, Pola-Ven-R, demonstrates a safety profile consistent with the known profiles of the individual drugs. This first report of the full efficacy population showed promising activity in a heavily pre-treated and refractory population of pts with R/R DLBCL. Further evaluation of Pola-Ven-R and the impact of consolidation therapy is warranted to address the significant unmet medical need in this patient population. Disclosures Gritti: Autolus: Consultancy; Takeda: Honoraria; F. Hoffmann-La Roche Ltd: Honoraria; Amgen: Honoraria; Kite: Consultancy; Italfarmaco: Consultancy; Jannsen: Other: Travel Support; IQVIA: Consultancy. Marlton:Astellas: Membership on an entity's Board of Directors or advisory committees; Janssen: Membership on an entity's Board of Directors or advisory committees; Celgene: Membership on an entity's Board of Directors or advisory committees; Astra-Zeneca: Membership on an entity's Board of Directors or advisory committees; F. Hoffmann-La Roche Ltd: Membership on an entity's Board of Directors or advisory committees; Novartis: Membership on an entity's Board of Directors or advisory committees; AbbVie: Membership on an entity's Board of Directors or advisory committees. Phillips:Abbvie: Consultancy, Research Funding; Pharmacyclics: Consultancy; Cardinal Health: Consultancy; Bayer: Consultancy, Research Funding; BMS: Consultancy; Seattle Genetics: Consultancy; Incyte: Consultancy, Other: travel expenses; AstraZeneca: Consultancy; Karyopharm: Consultancy; Beigene: Consultancy. Arthur:Royal North Shore Hospital: Current Employment. Bannerji:Regeneron Pharmaceuticals: Research Funding; AbbVie: Research Funding; Sanofi-Pasteur: Other: Spouse is employee; F. Hoffmann-La Roche Ltd/Genentech, Inc and Pharmacyclics LLC, an AbbVie Company: Research Funding. Corradini:Incyte: Consultancy; Celgene: Consultancy, Honoraria, Other: Travel and accommodations paid by for; Janssen: Consultancy, Honoraria; Daiichi Sankyo: Consultancy, Honoraria; Sanofi: Consultancy, Honoraria; KiowaKirin: Consultancy, Honoraria; Servier: Consultancy, Honoraria; BMS: Other; Gilead: Consultancy, Honoraria, Other: Travel and accommodations paid by for; Takeda: Consultancy, Honoraria, Other; AbbVie: Consultancy, Honoraria, Other: Travel and accommodations paid by for; Novartis: Consultancy, Honoraria, Other: Travel and accommodations paid by for; F. Hoffman-La Roche Ltd: Consultancy, Honoraria; Kite: Consultancy, Honoraria; Amgen: Consultancy, Honoraria, Other: Travel and accommodations paid by for. Johnston:MSD: Membership on an entity's Board of Directors or advisory committees; F. Hoffmann-La Roche Ltd: Membership on an entity's Board of Directors or advisory committees. Seymour:Janssen: Consultancy, Honoraria, Research Funding; Celgene: Consultancy, Honoraria, Research Funding; AstraZeneca: Consultancy, Honoraria, Membership on an entity's Board of Directors or advisory committees; AbbVie: Honoraria, Membership on an entity's Board of Directors or advisory committees, Research Funding, Speakers Bureau; F. Hoffmann-La Roche: Consultancy, Honoraria, Membership on an entity's Board of Directors or advisory committees, Research Funding, Speakers Bureau; Gilead: Consultancy; Mei Pharma: Consultancy, Honoraria; Morphosys: Consultancy, Honoraria; Nurix: Honoraria. Hirata:Genentech, Inc.: Current Employment; F. Hoffmann-La Roche Ltd: Current equity holder in publicly-traded company. Musick:F. Hoffmann-La Roche Ltd: Current equity holder in publicly-traded company; Roche/Genentech, Inc.: Current Employment. Saha:Genentech, Inc.: Consultancy; Genentech, Inc.: Current Employment. Croft:Genentech, Inc.: Current Employment, Current equity holder in publicly-traded company, Divested equity in a private or publicly-traded company in the past 24 months. Flowers:OptumRx: Consultancy; Karyopharm: Consultancy; Gilead: Consultancy, Research Funding; Leukemia and Lymphoma Society: Membership on an entity's Board of Directors or advisory committees; BeiGene: Consultancy; Bayer: Consultancy; Denovo Biopharma: Consultancy; Genentech, Inc./F. Hoffmann-La Roche Ltd: Consultancy, Research Funding; Pharmacyclics/Janssen: Consultancy; Acerta: Research Funding; Spectrum: Consultancy; Millennium/Takeda: Consultancy, Research Funding; TG Therapeutics: Research Funding; Burroughs Wellcome Fund: Research Funding; Eastern Cooperative Oncology Group: Research Funding; National Cancer Institute: Research Funding; AbbVie: Consultancy, Research Funding; V Foundation: Research Funding; Cancer Prevention and Research Institute of Texas: Research Funding; Celgene: Consultancy, Research Funding; Kite: Research Funding. OffLabel Disclosure: Polatuzumab vedotin (Polivy) is approved in combination with bendamustine and rituximab or use in third-line or later treatment of relapsed/refractory (R/R) DLBCL in the USA and in second-line or later treatment in the EU. Venetoclax (Venclexta) is approved for the treatment of adult patients with CLL or SLL, and in combination with azacitidine or decitabine or low-dose cytarabine for the treatment of newly-diagnosed AML in adults >75 years, or who have comorbidities that preclude use of intensive induction chemotherapy. Rituximab (Rituxan) is approved for use in relapsed/refractory low-grade NHL and in previously untreated DLBCL with CHOP, but is not approved for use in R/R DLBCL.

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.

Abstract Flame Treating was founded in 1940 by three Union Carbide employees to provide flame hardening services to the machine tool and capital equipment industry in the Connecticut River Valley. The market generally ran from Bridgeport to Providence and from New Haven to Springfield, VT with occasional opportunities in Worcester and the North Shore of Massachusetts. In 1956 the company purchased the first of its induction machines and expanded the services to induction hardening.

A plethora of codes, standards, and guidelines exist throughout the world offering a significant amount of input for the design engineer as he attempts to safely apply hydrocarbon processing equipment to hazardous areas. Fire suppression standards generated in and applicable to use in North America are also used throughout Europe. Off shore techniques are more stringent and must be carefully followed to protect the owner’s investment and for the safety of the equipment operators. This paper is a digest of all internationally recognized codes issued through commonly employed authorities extracting the peculiarities from each and building upon some basic premises to form a design specification that can be modified to suit the specific application or individual company policies. The discussion will be limited to enclosed and unenclosed gas turbine drivers and hydrocarbon gas processing compressors. Indoor and out door installations of this type equipment will also be considered.

Abstract Recognizing the challenge of renewable energy intermittency and energy security needs for offshore operations, the collaborative Renewables for Subsea Power (RSP) project has been developed to demonstrate delivery of low carbon power and communications to subsea production control systems and residential underwater vehicles. Reliable local renewable power generation enables more environmentally and economically viable operations. For example, for cost-effective clean power delivery to marginal fields, as a remedial power supply for degraded umbilicals, and for enabling underwater vehicle residency. This collaborative project is led by two United Kingdom (UK) based developers, a wave energy company and an energy storage and distribution device provider. The project consortium includes wider industry engagement from operators, an oil & gas service company, and the Aberdeen-based Net Zero Technology Centre. The demonstration project adopts a phased approach, with the ultimate objective of demonstrating a wave energy converter and seabed energy storage system for subsea power delivery. Phase 1 comprised the completion of a detailed front end engineering design (FEED) study. Phase 2 is ongoing and consists of system communication bench testing, assembly of the subsea systems, and onshore commissioning of both the wave energy device and the seabed energy storage system. Phase 3 will be the final part of the project, including offshore deployment and underwater demonstration. Focusing on the seabed battery storage element of the project, this paper will discuss the overall project objectives, energy security and safety considerations for seabed battery storage design and the novel outcomes expected upon completion of the full project plan. The results from Phase 2 are expected in May 2022. Phase 3 is scheduled to commence in Q3 2022 and it is planned for an initial 6 month duration offshore trial in the North Sea. This project will contribute significantly to the state of knowledge related to clean energy in the petroleum industry, with successful completion of the project demonstrating renewable power generation and seabed battery energy storage robustness for production control applications. This is understood to be the first such project to integrate existing subsea production control system (SPCS) technology to seabed energy storage and renewable energy production using remote control from shore. Importantly, it must be noted that this demonstration is not to be undertaken on a live producing well, instead representing the SPCS set-up using field proven subsea electronics modules (SEM) and DC load banks used to simulate maximum loading resulting from operation of a live system. By the end of the project, it is the intention to prove the first full scale prototype system to technology readiness level (TRL) 6 (American Petroleum Institute, 2017) by demonstrating reliable power generation, storage and delivery over a range of wave conditions representative of a typical live well installation location.