Academic literature on the topic 'Burmah Oil Company'

Post-merger and Acquisition (M&A) integration often deals with significant transformational changes of merging companies in terms of development, communication, implementation and harmonization of a new shared vision, strategic objective, corporate culture, and also combination of best companies’ value practices. The transformational change is accentuated on facilitating the role of developing and executing an effective post-M&A Integration to build change cohesively with the strategic management of M&A, and also in terms of removing barriers to the success of M&A transaction. The aims of this study are to give a clear and deep understanding on how to manage the soft factors issues that address in M&A process especially in the post-M&A integration process and also to elucidate the critical success factor of M&A process by instilling the best characteristics and the effectiveness level of leadership aspect in M&A. The methodology used in this research is descriptive qualitative research with a method or approach of a case study of Henkel’s Acquisition of The Dial Corporation in 2004. The acquisition of a USA company Dial by a German company Henkel evidenced that both companies were successful in M&A transaction and employed the effectiveness of multi-culture integration strategy. Another case study used in this research is British Petroleum (BP) and American Oil Company (Amoco) (also Atlantic Richield Company (ARCO) and Burmah Castrol) in 1998-2000. The case of BP Amoco showed that the monoculture integration strategy or cultural imposition can also lead to a value creation. Both case studies showed that successful integration requires leadership as a foundation to build a solid execution of post-M&A integration projects in how they planned, communicated and delivered the objectives of the projects.

Exploration of the eastern Arabian Platform in the 1930s and 1940s by Chevron and its legacy company Gulf Oil resulted in discovery of Kuwait's super-giant Burgan Field by Gulf Oil in 1938 and Saudi Arabia's super-giant Ghawar Field by California Arabian Standard Oil Company in 1948. Ghawar Field and Burgan Field are widely regarded as the first- and second-largest oil fields in the world, respectively. Gravity methods featured prominently in Gulf's and Chevron's subsurface explorations. Gravity mapping identified the Burgan structure and was important in delineating the Ghawar structural complex. Gravimetric technology continues to provide value for deep exploration in Chevron's Partitioned Zone concession in Saudi Arabia and Kuwait.

The Canning Basin in northern Western Australia is a large, relatively remote, mainly desert-covered Phanerozoic basin covering 595 000 sq km. Aborigines probably first entered the basin area 30-40 000 years ago, but the main European expeditions were not until the nineteenth and twentieth centuries. Geological exploration in the basin has been largely devoted to the discovery and exploitation of natural resources, primarily oil. Earliest geological traverses were conducted by geologists of the Geological Survey of Western Australia (GSWA). The accidental discovery of traces of oil in a water well in 1919 in the northern part of the basin diverted exploration to assessment of sediments and structures for petroleum potential. The earliest phase of oil exploration was a pioneering phase, concentrating on surface mapping and surface delineated structures as drilling sites, that was dominated by the Freney Kimberley Oil Company. West Australia Petroleum Ltd became the most active oil exploration company in the 1950s, 1960s and 1970s, using geophysics as an exploration tool in petroleum search in the basin. The late 1970s and 1980s saw an influx of companies and the application of diverse scientific approaches to the oil search. Persistence was rewarded in 1981 and 1982 with the discovery of the Blina and Sundown fields, small commercial oil accumulations. Commonwealth Government involvement in exploration was initially in the form of financial aid to exploring companies or commissioning specialist consultants for special studies. In the 1940s and 1950s and again in the 1970s the Bureau of Mineral Resources carried out basin-wide regional geological mapping in conjunction with the GSWA; onshore and offshore geophysical surveys were conducted until the 1970s. Exploration has revealed exploitable resources in the basin besides oil - diamonds, lead-zinc, coal, salt, phosphate, uranium, and heavy minerals. Only lead-zinc has present economic viability.

This paper examines corporate tax ratio of manufacturing sector in Indonesia. In this study, we use firm level data from Industry Survey of Central Bureau of Statistics. The result shows that in small and medium company percentage of foreign ownership is a significant determinant of tax ratio, whereas in big companies capital is a significant determinant of tax ratio. This study also find that there is negative relationship between profitability and tax ratio. This indicates that there is tax avoidance risk in manufacturing sector in Indonesia. Further examination shows that industry of coal and oil refining product and also repair and installation of machinery and equipment has the biggest risk of tax avoidance. Therefore we recommend subsectoral tax audit for to prove the findings of this study. Penelitian ini menganalisis tax ratio perusahaan pada sektor manufaktur di Indonesia. Dalam penelitian ini digunakan data mikro perusaahaan manufaktur yang bersumber dari Survei Industri Badan Pusat Statistik. Hasil analisis menunjukkan bahwa terdapat hubungan positif antara kepemilikan asing dan tax ratio pada perusahaan menengah dan kecil, hal ini berbeda dengan pada perusahaan besar dimana kapital merupakan faktor yang mempengaruhi tax ratio. Hasil analisis juga menunjukkan bahwa terdapat hubungan negatif antara profitabilitas dan tax ratio. Hal ini mengindikasikan bahwa terdapat resiko penghindaran pajak pada sektor manufaktur di Indonesia. Penelitian lebih lanjut mengungkapkan bahwa industri produk dari batu bara dan pengilangan minyak bumi serta usaha reparasi dan pemasangan mesin dan peralatan merupakan industri dengan resiko penghindaran pajak yang terbesar. Oleh karena itulah kami menyarankan agar dilakukan pemeriksaan pajak subsektoral untuk membuktikan temuan pada penelitian ini.

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.

Essential Cases: Public Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Burmah Oil Company v Lord Advocate [1965] AC 75, House of Lords. The document also includes supporting commentary from author Thomas Webb.

Essential Cases: Public Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Burmah Oil Company v Lord Advocate [1965] AC 75, House of Lords. This case, read together with the War Damage Act 1965, outlines the capacity of Parliament to enact retroactive legislation. The document also includes supporting commentary from author Thomas Webb.

Essential Cases: Public Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Burmah Oil Company v Lord Advocate [1965] AC 75, House of Lords. This case, read together with the War Damage Act 1965, outlines the capacity of Parliament to enact retroactive legislation. The case note discusses this in the context of the rule of law and parliamentary sovereignty. The document also includes supporting commentary from author Thomas Webb.

Essential Cases: Public Law provides a bridge between course textbooks and key case judgments. This case document summarizes the facts and decision in Burmah Oil Company v Lord Advocate [1965] AC 75, House of Lords. This case, read together with the War Damage Act 1965, outlines the capacity of Parliament to enact retroactive legislation. The case note discusses this in the context of the rule of law and parliamentary sovereignty. The document also includes supporting commentary from author Thomas Webb.

The given work describes the problem and the offered solutions for the NORM contaminated metal waste generated in the oil & gas and other non-atomic industries. The Russian Federation regulatory base, the fundamental metal LLW treatment scheme in accordance with Sanitary Rules and standards are given. It is shown, that one of the treatment ways is the processing at a specialized enterprise. Such an only enterprise in Russian Federation is the Joint-Stock Company (JSC) “ECOMET-S”. Its main activities are radwaste management, processing and disposal of the metal LLW. The operations’ main goal is to reduce the waste volume to its minimum before further burial and to return the clean metal to the unrestricted commercial turnover. The worked out technology and the enterprise industrial capacity are represented. JSC “ECOMET-S” activities results and processing and disposal schedule are given.

The petroleum leakage has been a serious problem these years in China. The leakage, mostly caused by human destruction, lasting a short time with a large amount of loss, is not only an economic loss for the petroleum company, but environmental pollution, a public issue. Thus a monitoring system, which can identify the leakage and locate the leak point in real time, is required. One of the challenges is the sensitivity of the system. The system is expected to respond quickly to locate the point so that the security personnel can find and mend the orifice in time. Another challenge is the accuracy of the locating result. Because of the features of Chinese petroleum: high viscosity, high wax content and high freezing point, the sound wave speed in the oil is not a constant along the pipeline and the leak point calculated by the traditional negative pressure wave method are invalid. In this paper, a modified negative pressure wave method was put forward according to the variation of the wave speed. A wavelet-based algorithm applied to calculate the leak point gives fairly satisfied results. The data acquisition, signal processing and the structure of the pipeline leakage monitoring system (PLMS) were analyzed. The system has played a big role on the pipeline network in Shengli Oil Field and long pipelines of East China Oil Bureau.

Many gas turbines commissioned in the late 1960’s and early 1970’s employ “first generation” electronic control systems. Usually a combination of analog-digital fuel and temperature control circuits and electromechanical relay sequencers, these systems (and the gas turbines they were designed to control) inevitably experience diminished performance as they age. This paper describes the project to design, construct, install, and commission replacements for the control systems on the main and auxiliary gas turbines and the propulsion controls for Chevron Shipping Company’s domestic tanker fleet. Since replacing the main gas turbine control system and propulsion controls on the oil tanker Chevron Colorado in the spring of 1993, both the main and auxiliary turbine and propulsion controls have been replaced on each of the other four (4) tankers. Triple modular redundant (TMR) digital systems were selected 10 replace the original analog-digital control systems on the main and auxiliary gas turbines (MGT & AGT). Required American Bureau of Shipping and US Coast Guard certification tests, as well as dock and sea trials for the new control systems are discussed. Economic results including maintenance repair action rates, start percentages, availabilities, and fuel savings are detailed.

Abstract Oman's petroleum systems are related to four known source rocks: the Precambrian-Lower Cambrian Huqf, the Lower Silurian Sahmah, the Late Jurassic Shuaiba-Tuwaiq and the Cretaceous Natih. The Huqf and the Natih have sourced almost all the discovered fields in the country. This study examines the shale-gas and shale-oil potential of the Lower Silurian Sahmah in the Omani side of the Rub al Khali basin along the Saudi border. The prospective area exceeds 12,000 square miles (31,300 km2). The Silurian hot shale at the base of the Sahmah shale is equivalent to the known world-class source rock, widespread throughout North Africa (Tannezouft) and the Arabian Peninsula (Sahmah/Qusaiba). Both thickness and thermal maturities increase northward toward Saudi Arabia, with an apparent depocentre extending southward into Oman Block 36 where the hot shale is up to 55 m thick and reached 1.4% vitrinite reflectance (in Burkanah-1 and ATA-1 wells). The present-day measured TOC and estimated from log signatures range from 0.8 to 9%. 1D thermal modeling and burial history of the Sahmah source rock in some wells indicate that, depending on the used kinetics, hydrocarbon generation/expulsion began from the Early Jurassic (ca 160 M.a.b.p) to Cretaceous. Shale oil/gas resource density estimates, particularly in countries and plays outside North America remain highly uncertain, due to the lack of geochemical data, the lack of history of shale oil/gas production, and the valuation method undertaken. Based on available geological and geochemical data, we applied both Jarvie (2007) and Talukdar (2010) methods for the resource estimation of: (1) the amount of hydrocarbon generated and expelled into conventional reservoirs and (2) the amount of hydrocarbon retained within the Silurian hot shale. Preliminary results show that the hydrocarbon potential is distributed equally between wet natural gas and oil within an area of 11,000 square mile. The Silurian Sahmah shale has generated and expelled (and/or partly lost) about 116.8 billion of oil and 275.6 TCF of gas. Likewise, our estimates indicate that 56 billion of oil and 273.4 TCF of gas are potentially retained within the Sahmah source rock, making this interval a future unconventional resource play. The average calculated retained oil and gas yields are estimated to be 6 MMbbl/mi2 (or 117 bbl oil/ac-ft) and 25.3 bcf/mi2 (or 403 mcf gas/ac-ft) respectively. To better compare our estimates with Advanced Resources International (EIA/ARI) studies on several Silurian shale plays, we also carried out estimates based on the volumetric method. The total oil in-place is 50.2 billion barrels, while the total gas in-place is 107.6 TCF. The average oil and gas yield is respectively 7 MMbbl/mi2 and 15.5 bcf/mi2. Our findings, in term of oil and gas concentration, are in line or often smaller than all the shale oil/gas plays assessed by EIA/ARI and others.

Naturally fractured reservoir has important role in oil and gas development in onshore South Sumatra Basin Indonesia. There are several fields in Indonesia have hydrocarbon (oil or gas) potential in this type of reservoir. One of the fields is Northeast Betara operated by PetroChina International Jabung Ltd. The Northeast Betara structure consists of a basement high with tertiary burial that has been inverted due to compressive stresses during Late Miocene – Pliocene. The company plans to develop Lower Talang Akar Formation (LTAF) conglomeratic sand reservoir of Northeast Betara field which is believed to be naturally fractured. Well-B was drilled targeting conglomerate and fractured basement reservoir in the field. Unfortunately, even the Well-B intersected more fractures, the hydrocarbon test result was under expectation compared to previous Well-A 5 Km away, which encountered similar reservoir but shows better production test. Due to productivity discrepancy, this study is conducted to answer this issue by predicting natural fracture distribution across the field. An integrated structural restoration and geomechanical forward modelling is carried out thoroughly in order to better target the next well intersecting productive fractures. Structural restoration with finite element method provides layer geometries from initial deposition to the present day enabling explicit coupling with Stress Simulation engine at each geological time. Forward modelling could then be achieved by applying strain boundary conditions at the base of the model using known differential vertical displacement from one geological time to the next and lateral strain at the vertical boundaries of the model. Geomechanical forward modelling (GFM) simulates the evolution of structures of a geomechanical model from deposition up to present day and captures the geomechanical details with geological time. The main result of the study is plastic shear strains across the field, which subsequently converted into fracture density with orientation and inclination and can delineate the location of productive fractures. The fracture planes are defined by orientation and inclination matched over >85% of the observed fractures in the wells. Simulation results suggest that most fractures in the location of Well-A in the field are critically stressed and therefore expected to have better hydrocarbon production potential. This paper showcases approach of advanced geomechanical technique to predict 3D natural fracture distribution using existing data. The result will be used as reference to determine further development strategy.