Academic literature on the topic 'Kodak (Far East) Ltd'

Westinghouse Electric opened a new research laboratory near the company’s main factory in East Pittsburgh, Pennsylvania, in 1916. Located in the suburban borough of Forest Hills, the laboratory was set up to provide scientific knowledge for the older materials testing and product development laboratories at the factory. Unlike its industrial counterparts, however, the Forest Hills laboratory was dominated by a strong engineering research tradition that disrupted efforts undertaken in the 1920s and again in the 1930s to build and sustain a diversified fundamental research program. Whereas Eastman Kodak, DuPont, AT&T, and General Electric had successfully integrated fundamental research into their corporate laboratories, the Forest Hills laboratory remained the site of recurring tensions between two cultures of innovation—one based on fundamental science, the other on engineering research. Although such tensions often resulted in competing research strategies, managerial conflicts, and mismatched corporate priorities, the long-standing culture of engineering research contributed far more to Westinghouse’s strategic growth than even the most advanced fundamental research. More generally, the interactions between the cultures of engineering and science that characterize the early history of industrial research at Westinghouse highlight the evolving and sometimes conflicting patterns of technological innovation and organizational change in American industry before World War II.

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

Recently, primitive-type pottery was discovered in the Russian Far East, China, and Japan. Radiocarbon ages of far earlier than 10,000 BP have been obtained, relating directly or indirectly to the pottery. As an example of these very old 14C ages for incipient pottery, we report here 14C ages of charred adhesions on five potsherds and three charred wood fragments that were collected with the archeological artifacts (stone tools from the Chojakubo Culture) in the loam layers at the Odai Yamamoto I site (41°03′44′′N, 140°33′20′′E) in Aomori prefecture, at the northern end of the Japanese main island. The carbonaceous remains on the surface of the potsherds could be ancient food residues or soot from fuel for cooking. These small carbon samples were dated at the Tandetron accelerator mass spectrometry (AMS) 14C dating facility at Nagoya University, as well as by Beta Analytic Co. Ltd. Except for two charred wood 14C dates, 7070 ± 40 and 7710 ± 40 BP, all five charred-residue samples and one wood charcoal sample gave older 14C ages of 12,680–13,780 BP, corresponding to the period of the Chojakubo Culture in Japan. This culture marks the beginning of the Jomon Culture, which is characterized by pottery usage and bow-and-arrow hunting.

Despite the attention that has been given to the role of economic sanctions in Japan's decision to launch the Pacific war, Australia's decision to ban iron ore exports to Japan has been given little attention, even though this was one of the earliest economic sanctions imposed onimperial Japan in the 1930s. To a degree this neglect can be traced to a preoccupation with the actions and objectives of the great powers and a failure to consider the opportunities available to small nations to take significant initiatives. The following article traces the origins of the iron ore embargo back to 1934 when Essington Lewis, the Managing Director of the Broken Hill Proprietary Company Ltd (BHP), Australia's iron and steel monopoly, visited Japan and subsequently advocated the development of an Australian armaments industry to counter probable Japanese aggression in the Pacific. In Japan Lewis crossed paths with J. G. Latham, the Minister for External Affairs, who was leading the Australian government's Eastern Mission. Latham returned to Australia with conclusions that differed fundamentally from those of Lewis, who came up with a plan to take advantage of Japan's dependence on imports of iron ore and other iron products to finance investment in Australian armaments manufacturing. In explaining this outcome the article discusses interactions between a number of conflicts: between Latham and Lewis; between the British Treasury and the Foreign Office; and between the Japanese army and navy. In London the Treasury wanted to focus on the European theatre, while also holding down military spending in order to achieve balanced budgets. The Treasury believed that the way to best defend British commercial interests in Asia was to appease Japan. On the other hand, the Foreign Office was committed to the protection of British interests in the Far East by a more forceful diplomacy, although it was only willing to counten-ance behavior short of military action. Consistent with Latham's recommendations to his government, the emerging consensus in London was that while a settlement in China would help to safeguard British interests there, as long as the Japanese were bound up in their war in China they were less likely to attack British colonies in Southeast Asia and the Pacific. In 1936 this orientation was challenged by a shift in the balance of power in Tokyo away from the army and in favor of the navy. Although priority continued to be placed on winning the war in China and guarding against an attack from the Soviet Union, now the navy's plan for southward expansion was given more careful consideration and credibility.

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.”

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.

Essential Cases: Contract Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Entores Ltd v Miles Far East Corporation [1955] 2 QB 327. The document also includes supporting commentary from author Nicola Jackson.

Essential Cases: Contract Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Entores Ltd v Miles Far East Corporation [1955] 2 QB 327. The document also includes supporting commentary from author Nicola Jackson.

Essential Cases: Contract Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Entores Ltd v Miles Far East Corporation [1955] 2 QB 327. The document also includes supporting commentary from author Nicola Jackson.

Essential Cases: Contract Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Entores Ltd v Miles Far East Corporation [1955] 2 QB 327. The document also includes supporting commentary from author Nicola Jackson.