Marathon Oil Research Articles

The main approaches to valuation of the equity capital of oil and gas companies

Subject. This article analyzes the generally accepted approaches to assessing the value of companies on the basis of financial statements data of ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, BP, TOTAL, Eni, Equinor (Statoil), PetroChina, Sinopec, CNOOC, Petrobras, PJSC Gazprom, PJSC NK Rosneft and PJSC LUKOIL for 1999–2018. Objectives. The article aims to determine the specifics of using the methods of cost, income and comparative approaches in assessing the value of share capital of oil and gas companies. Methods. For the study, I used the methods of comparative, and financial and economic analyses, and financial reporting data summarizing. Results. The article finds that the cost approach is quite time-consuming, and it does not take into account the current market situation and future expectations of investors, but is based on financial information. Leading oil and gas corporations have a rather complex vertical and horizontal structure, so the cost approach is acceptable for assessing the minimum cost of small companies in the industry. The income approach takes into account the interests of investors, but its application complicates the reliability of medium-term forecasts for oil prices, which is caused by fluctuations in oil prices inherent in the industry. And the amount of net income and free cash flow in the industry largely depends on oil prices. The comparative approach does not take into account the future interests of investors, but it helps quickly determine the range of possible value of the corporation based on data on transactions and the current market situation. Thus, the analogue company method helps evaluate the cost of equity capital, and the transaction method provides insight into the level of premium for control characteristic of the industry. Conclusions and Relevance. Each of the standard approaches has its own characteristic advantages and disadvantages when assessing the value of oil and gas companies. The findings can be used to appraise the value of oil and gas assets.

The foreign practice of large merger & acquisitions transactions in the stock market sector of the oil and gas industry

Subject. This article analyzes 12 major M&A deals in the stock market sector of the oil and gas industry in 2000–2019. Industry indicators are measured on the basis of data from ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, BP, TOTAL, Eni, Equinor (Statoil), PetroChina, Sinopec, CNOOC, Petrobras, PJSC Gazprom, PJSC NK Rosneft and PJSC LUKOIL. Objectives. The article aims to examine the terms of M&A deals in the oil and gas stock market sector, as well as analyze the change and determine the current level of premium for control over equity capital in relation to market capitalization, and evaluate the consequences of concluded deals for the market capitalization of companies. Methods. For the study, I used the methods of comparative, financial and economic analyses, summarizing financial reporting data. Results. The article finds that market capitalization is the main benchmark for mergers and acquisitions in the stock market sector of the oil and gas industry, but the difference between the market valuation of assets and liabilities can also be used. An increase in the level of premium for capital control is noted in the industry, which exceeded half of the market capitalization. Thus, the least acceptable combination of conditions for entering into agreements is the totality of factors, such as high oil prices, commensurate capitalization of companies, cash compensation for equity capital and a high premium for control. On the contrary, transactions that took place during a period of low oil quotations with compensation in the form of shares had the most favorable effect on subsequent market capitalization. Conclusions and Relevance. It is necessary to pay close attention to the terms of mergers and acquisitions, in particular the control premium, as well as carefully calculate all the possible consequences of agreements concluded in the stock market sector of the oil and gas industry. The findings can help appraise the value of oil and gas assets as part of a comparative approach and decide on actions for raising the market capitalization of publicly traded oil and gas corporations.

Marathon Oil Corp.

Corporate Philanthropy ReportVolume 38, Issue 3 p. 4-5 Corporate Profiles Marathon Oil Corp. First published: 08 February 2023 https://doi.org/10.1002/cprt.31532Read the full textAboutPDF ToolsRequest permissionExport citationAdd to favoritesTrack citation ShareShare Give accessShare full text accessShare full-text accessPlease review our Terms and Conditions of Use and check box below to share full-text version of article.I have read and accept the Wiley Online Library Terms and Conditions of UseShareable LinkUse the link below to share a full-text version of this article with your friends and colleagues. Learn more.Copy URL Share a linkShare onFacebookTwitterLinkedInRedditWechat No abstract is available for this article. Volume38, Issue3March 2023Pages 4-5 RelatedInformation

Profitability ratios of the world's leading publicly traded oil and gas corporations as an indicator of the investment attractiveness of domestic vertically integrated oil and gas companies

Subject. The article focuses on the key profitability ratios of twenty five leading publicly traded oil and gas companies from 2006 through 2018. The analysis encompasses ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, BP, TOTAL, Eni, Equinor (Statoil), PetroChina, Sinopec, CNOOC, Petrobras, PAO Gazprom, PAO NK Rosneft, and PAO LUKOIL. Objectives. The aim of the study is to trace key trends in key profitability ratios of corporations in the oil and gas industry, to identify the key trends in their change within the studied period, and to establish those factors that led to this transformation. Methods. The study is based on methods of comparative and financial-economic analysis, summarizing financial reporting data. Results. I determined the dynamics of changes in key profitability indicators in the stock market sector of the industry and established the main factors that contributed to this transformation, based on the results of a comprehensive analysis of balance sheets of 25 oil and gas companies. I revealed a decrease in the profitability of the leading publicly traded oil and gas companies within the studied period, which was especially clearly manifested in the midst of the global financial and industry crises. The most difficult situation is observed in a number of independent US companies. The main reason for the drop in the profitability of the stock market sector of the industry is that the costs of core activities outstrip the corresponding revenue in terms of growth, mainly due to the costs of depreciation, depletion, and amortization. Another important factor was a significant increase in the book value of non-current assets. The study unveils that the specific burden of income tax per unit of net revenue from core activities is gradually decreasing in the stock market sector of the oil and gas industry. Conclusions. The profitability of the oil and gas stock market sector is deteriorating, however, the current price level allows the leading companies to generate net income.

What Is Really Happening When Parent and Child Wells Interact?

When trying to understand the well-to-well events known as frac hits and fracture-driven interactions (FDIs), the first idea to embrace is this: they are not all the same. “And the key physical mechanisms are not the same,” said Mark McClure, who added that, “Until you’ve really dialed in on what those are, you’re really in the dark.” McClure is the cofounder and CEO of ResFrac Corp. In March, the modeling firm began a multiclient study to diagnose the relationships between parent and child wells—or what many consider to be the ultimate subsurface challenge facing the shale sector. Participating operators are Marathon Oil, Hess Corp., Pioneer Resources, Arc Resources, Birchcliff Energy, SM Energy, and Ovintiv Inc. These independent E&Ps represent a cross section of some of the most active plays in North America: the Midland and Delaware basins and the Bakken and Montney shales. But what makes the study unique, McClure said, is that it involves 10 rich data sets from well pads that were subjected to a number of cross-validating diagnostics: tracers, pressure/interference monitoring, geochemistry, and fiber optics. ResFrac has been using that data to calibrate its coupled reservoir-fracture models to see what knobs clients might want to turn in the future to improve well economics. The study is also trying to unearth some firm answers about what is really happening during offset stimulations, why it is happening, and what can be done to mitigate negative outcomes. ResFrac and its clients expect to wrap up this part of the study by the year’s end and to submit an abstract for an SPE technical conference in 2022. As the study nears an end, McClure offered some of his key observations that he noted are supported by previous research found within industry literature. So, What’s the Worst That Can Happen? A growing chorus of subsurface experts consider unwanted chemical reactions in the fracture network as one of the major damage mechanisms resulting from FDIs. McClure is not only among them, he said chemical effects represent the “worst” that can happen when parents and children interact. “This is where you see wells get hit, they lose 80% of their production, and it doesn’t come back,” he explained. Some in the industry have taken to calling the byproduct of these chemical reactions “shmoo” or “gunk.” For answers as to why this is happening, McClure points to two technical papers in particular.

Refiners shift production to renewables

Phillips 66, Global Clean Energy, and Marathon Oil plan to convert their California petroleum refineries to production of renewable diesel from plant oils and animal fats. Prices for petroleum-derived fuels have been squashed by the economic impact of the novel coronavirus. In contrast, producers of renewable fuels expect to profit thanks to significant subsidies for climate-friendly transportation fuels. The renewables shift could create stiff competition for of cheap oils and fats, according to the energy consultancy Stratas Advisors. Any price increase would also affect the soap and detergent industry, which relies on animal fats as raw material for products like cationic surfactants. The American Cleaning Institute, a trade group, for biofuel mandates to exclude animal fats as a feedstock option. Phillips 66 plans to use fats and greases, along with used cooking oil and soybean oil, at its San Francisco Refinery in Rodeo. The firm says it will produce 19

Analyzing profitability ratios of leading global public oil and gas corporations

Subject. The article discusses the key profitability metrics of the largest public companies in the oil and gas (O&G) industry from 2006 to 2018. The analysis encompasses ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, BP, TOTAL, Eni, Equinor (Statoil), PetroChina, Sinopec, CNOOC, Petrobras, PJSC Gazprom, PJSC Rosneft Oil Company и PJSC LUKOIL. Objectives. The study assesses key profitability metrics of leading public corporations in oil and gas, identifies key trends in their developments as part of the analyzable period. We also determine what triggered such a transformation. Methods. We employed methods of comparative and financial-economic analysis, summarized official annual reports on financial and business operations prepared by major public O&G corporations. Results. Upon the comprehensive analysis of balance sheets prepared by 25 O&G corporations, we evaluated the dynamics of key profitability indicators in the public segment of O&G industry and determined what triggered the transformation. Conclusions and Relevance. For the analyzable period, major public O&G corporations were found to have become less profitable, especially manifesting this during the global financial and sectoral crisis. Some independent U.S. corporations are facing the most difficult situation. The public segment saw their profitability indicators fall, because the growth rate of operational expenses exceeded revenue predominantly due to costs of wear and tear, depletion and depreciation. What else affected the corporations was a considerable increase in the carrying amount of non-working assets. The public segment of O&G industry was discovered to observe gradually lowering income tax burden per unit of net revenue from core operations.

Main approaches to estimating the cost of shareholder equity of oil and gas producers

Subject. The study analyzes generally accepted approaches to assessing the value of companies on the basis of financial statement data of ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, Gazprom, Rosneft, LUKOIL, and others, for 1999—2018. Objectives. The aim is to determine the specifics of using the methods of cost, DFC, and comparative approaches to assessing the value of share capital of oil and gas companies. Methods. The study employs methods of statistical analysis and generalization of materials of scientific articles and official annual reports on the results of financial and economic activities of the largest public oil and gas corporations. Results. Based on the results of a comprehensive analysis, I identified advantages and disadvantages of standard approaches to assessing the value of oil and gas producers. Conclusions. The paper describes pros and cons of the said approaches. For instance, the cost approach is acceptable for assessing the minimum cost of small companies in the industry. The DFC-based approach complicates the reliability of medium-term forecasts for oil prices due to fluctuations in oil prices inherent in the industry, on which the net profit and free cash flow of companies depend to a large extent. The comparative approach enables to quickly determine the range of possible value of the corporation based on transactions data and current market situation.

The Foreign Practice of Large Merger & Acquisitions in the Public Sector of the Oil and Gas Industry

Subject. The article analyzes 12 major M&A deals in the public sector of the oil and gas industry in 2000–2019. Industry indicators are measured on the basis of data from ExxonMobil, Chevron, ConocoPhillips, Occidental Petroleum, Devon Energy, Anadarko Petroleum, EOG Resources, Apache, Marathon Oil, Imperial Oil, Suncor Energy, Husky Energy, Canadian Natural Resources, Royal Dutch Shell, BP, TOTAL, Eni, Equinor (Statoil), PetroChina, Sinopec, CNOOC, Petrobras, Gasprom, Rosneft Oil Company and LUKOIL. Objectives. I study on what terms M&A are concluded in the public sector of the oil industry and analyze the approval and changes in the current premium for control over the ratio of share capital to market capitalization. The article also evaluates how the above deals influenced the market capitalization of companies. Methods. The study employs methods of statistical analysis and summarizing official annual reports on financial and business performance and news releases of major State-owned oil and gas corporations. Results. Having analyzed 12 major M&A in the public sector of the oil and gas industry comprehensively, I traced trends in terms on which such deals are concluded and determined their consequences. Conclusions and Relevance. In the public sector of the oil and gas industry, M&A are found to depend on capitalization, but also sometimes refer to the difference between the market value of assets and liabilities. In the industry, share capital control premium is noted to grow, thus exceeding half of capitalization. Therefore, the least acceptable factors include a combination of high oil prices, commensuration of companies’ capitalization, compensation for share capital and high control premium. On the contrary, market capitalization significantly improved in case of deals implying the compensation with stocks, which took placed during low oil prices.

A Portrait of Corporate Social Responsibility in an Oil and Gas Corporation in the Kurdistan Region of Iraq

At present, a debate on the nature of corporate social responsibility (CSR) and its positive and negative impacts is taking place from various theoretical and practical perspectives. The purpose of this article is to reveal the contributions of Marathon Oil Corporation’s CSR by exploring “the good, the bad, and the ugly” face of CSR and to examine whether the oil and gas corporation is contributing positively to the environment and society of the Kurdistan Region of Iraq. A qualitative approach was employed by identifying the important effects of CSR activities on the environment and society, such as economic development, human rights protection, poverty alleviation, environmental protection, and employment. Furthermore, the contextual meaning of the CSR reports on the performance from 2011 to 2015 was studied by using content analysis. The article finding Marathon Oil Corporation has portrayed a good and strong impact, but it does not have visible contributions to the environment and society in Kurdistan.

Time To Enlist in the Analytics Army

Data analytics is the future of getting ahead for engineers and geoscientists in the exploration and production (E&P) business. Three executives of large companies recently played up the growing importance of data-driven employee development, from data science boot camps at BP to the Citizen Data Scientist program at ConocoPhillips. “We have got a data science community that is growing by leaps and bounds,” said Michael Rowley, director of technology and innovation at BP, during a presentation at the recent Data Science Convention 2018 put on by the Data Analytics Study Group of the SPE Gulf Coast Section. “The most powerful way for us to pro-mote data analytics is to give our technical people training so they are fully armed with data analytics tools,” said Greg Leveille, chief technology officer of ConocoPhillips. Those willing to learn and apply these new tools “will have a disproportional impact on each of your companies,” Leveille said, adding “our industry will be populated by people who know and who can do data analytics well.” In a tough job market, data skills could offer a critical edge. If two people are interviewing for a job in unconventional exploration, and one has analytics skills and experience and the other does not, “guess who gets the job,” said Andy Flowers, director of advanced analytics for Marathon Oil. One sign of the times was the number of data scientists asking questions at the gathering. Another was the 400-person crowd at the first-ever gathering. They are building and maintaining the industry’s new data gathering and analysis infrastructure, putting large databases and analytical tools in the hands of engineers, geoscientists, and financial managers. They are a small part of the E&P workforce, are hard to find, and costly to hire. “We feel like we won the lottery when we get a new person in” for the data science team, Flowers said. But engineers and geoscientists will remain central to E&P companies because “you cannot outsource knowledge of the oil industry,” Flowers said. They will be asked to use their experience to focus the work on the most important problems, and apply methods drawing on both traditional and statistical approaches. “People with a good grounding and understanding of physics, combined with analytics, can solve problems that are very hard to solve” with first principles physics, Leveille said. Increasingly, the data-driven tools will also integrate the economic aspects of decision making. Engineering decisions need to be aligned with current corporate goals. An application integrating technical and economic information could help an engineer tailor a gas project development plan based on predicted demand. “Not everything is about geology and physics,” Rowley said. Another priority is to figure out “how to connect up data in the financial space,” he said.

The Quest CCS Project: 1st Year Review Post Start of Injection

In September 2012, the final investment decision was taken to move ahead with the Quest Carbon Capture and Storage (CCS) project in Alberta, Canada. Quest is the world's first CCS project linked to an oil sands bitumen upgrader. The operator is Shell and the project is part of a joint venture between Shell Canada Energy, Chevron Canada Limited, and Marathon Oil Canada Corporation. On the 23rd of August 2015, CO2 injection commenced at two of three available injection well sites. On 29th September 2015, the commercial operations’ certificate for Quest was issued. During the first year of operation, the target of injecting 1 million tonnes of CO2 per year was reached ahead of schedule. Individual components of Quest have been very reliable, including surface facilities related to the capture and transport of the CO2, wells, and the storage reservoir. The uptime during the first year of operation was over 99%. The CO2 is safely contained within the storage complex, as there has been no indication of a loss of containment. A key part of making this a successful project has been the on-going engagement with stakeholders.

Toxic Cities: Neoliberalism and Environmental Racism in Flint and Detroit Michigan

The consequences of neoliberal colorblind policies concerning environmental justice in Michigan are explored using critical race theorist Alan Freeman’s victim and perpetrator perspectives on legal decision-making. The victim perspective allows evidence of disparate impact to be proof of unequal protection under the law. The dominant perpetrator perspective requires proof of the intent to discriminate for a racial discrimination claim to be valid. Michigan’s environmental legal history is examined through the lens of these two perspectives, tracing how Michigan as a state, with the aid of the federal government, has institutionalized a racialized caste system of ‘worthiness’ for environmental protection through strict adherence to the perpetrator perspective. Specific attention is paid to the water crisis in Flint and a Marathon Oil refinery in Detroit. The injustices occurring at these locations are less the result of racist individuals than the product of decades of neoliberal colorblind policymaking supported and upheld in our court rooms.

Impact of the Prairie Evaporite dissolution collapse on McMurray stratigraphy and depositional patterns, Shell Albian Sands Lease 13, northeast Alberta

Abstract The Cretaceous McMurray Formation in NE Alberta contains nearly a trillion barrels of bitumen, a significant portion of which is being developed via surface mining and in-situ thermal methods. The focus of this report is the structure and stratigraphy of the Cretaceous McMurray Formation and its relationship to the configuration of the underlying Devonian section in the area of Shell Canada’s Albian Sands Lease (Township 95, ranges 9 and R10W4M), a joint oil sands mining venture between Shell Canada (60%), Chevron Canada Limited (20%) and Marathon Oil Canada Corporation (20%). The structural and stratigraphic relationships between the two intervals has been the source of several recent investigations due to industry related incidents that demonstrated the integrity of the underlying Devonian succession can be compromised by vertical pathways associated with faults, sinkholes, or other features. Key findings of this work include the following: The present morphology of the Pre-Cretaceous unconformity is primarily due to structural deformation (differential subsidence) related to dissolution and collapse of the underlying Prairie Evaporite Formation and overlying Devonian units of the Beaverhill Lake Group rather than erosion relief. Two types of collapse structures are recognized: a) large scale sag folds that are 1-to-10 kilometres in extent; and b) small scale breccia pipes that are 10- to-100 metres in diameter. The sag folds are interpreted to have formed in response to the dissolution of halite. The breccia pipes, which postdate the sag folds, represent sinkhole features that formed in response to the dissolution of gypsum. Rather than onlapping the unconformity, Lower McMurray strata thin and converge across structural highs and thicken and diverge across structural lows, demonstrating much of the dissolution driven subsidence was contemporaneous with the deposition. The subsidence produced up to 80 metres of accommodation and involved the coherent sagging and faulting of large intact segments of the underlying Devonian section. The arrangement of major stratigraphic packages indicates subsidence features shifted locations through time rather than persisting through the entire Lower McMurray. Changes in sedimentation style between sand-rich fluvial packages to mud-rich lacustrine dominated packages within the lower McMurray reflect changes in relative rates of subsidence. Sand-rich fluvial units are localized in settings with low-to-moderate subsidence rates, while mud-rich fluvial-lacustrine units are localized in settings with moderate-to-high subsidence rates. The Middle-to-Upper McMurray section is composed of four high relief unconformity bound units that display flat/horizontal stratal relationships with the underlying structure of the Pre Cretaceous unconformity. In contrast to the Lower McMurray, stratigraphic relationships indicate it was largely impacted by falls and rises in relative sea-level (cycles of negative and positive accommodation) rather than dissolution driven subsidence that, while still active, had begun to wane.

EOR-For-Shale Ideas to Boost Output Gain Traction

Low oil prices may not be the biggest threat to the long-term sustainability of the North American shale business. Some are more concerned about the low recovery rates of horizontal shale wells, estimated to be about 7% on average— far short of the 40% achieved through primary and secondary (waterflooding) production in conventional reservoirs. Refracturing has been touted as the next big thing to improve ultimate recovery, but such operations remain relatively expensive and may only temporarily reset production to initial rates once or twice in a well’s life. To see long-term results and a doubling or tripling of current recovery rates, a number of experts say enhanced oil recovery (EOR) technologies must be developed to work in tight shale reservoirs. And due to persistently low natural gas prices, current efforts appear to be exclusively focused on oil and condensate producing wells. It is early days for this area of EOR research. There is no consensus on which approaches will work best, how much they may cost, what the most pressing challenges are, or exactly when an EOR operation should begin. “Our understanding is really small,” said Todd Hoffman, an assistant professor of petroleum engineering at Montana Tech University. “We’re coming from the conventional world where ‘this’ is how we did EOR and we may just have to throw all that out.” Hoffman is one of several researchers trying to figure out how EOR methodologies can be adapted or reinvented for the oil-rich shale fields of North Dakota, Texas, and Canada. One of the most popular ideas being studied is a huff-and-puff approach that uses a single horizontal well to alternate between producing oil and injecting natural gas or CO2 to re-pressurize the reservoir and displace oil. Another idea is to apply continuous injections into one well and use an offset well as the producer. Others are looking into flooding the wells with surfactants and possibly acid to stimulate production. In May, EOG Resources laid claim to the first economic demonstration of an injection-based EOR technology for tight oil in the US. The company said the development may have long-term production benefits and is competitive with drilling new wells. But other than making it clear that the process has been successful and uses dry gas produced in the same field, EOG is withholding key operational details such as whether it involves the huff-and-puff technique or continuous injections. A number of other innovative shale producers including Statoil, Nexen Energy, Continental Resources, and Marathon Oil have also either funded research or are known to be running pilots, but have not made their results public. As most shale producers remain silent about their EOR efforts, there are a growing number of technical papers being published by university petroleum departments and reservoir engineering consultants. They are using computer models and corefloods to test their theories and have produced promising numbers that suggest there may be several practical ways to implement EOR strategies for shale.

Enterprise Risk Management In The Oil And Gas Industry: An Analysis Of Selected Fortune 500 Oil And Gas Companies’ Reaction In 2009 And 2010

In 2009, four of the top ten Fortune 500 companies were classified within the oil and gas industry. Organizations of this size typically have an advanced Enterprise Risk Management system in place to mitigate risk and to achieve their corporations’ objectives. The companies and the article utilize the Enterprise Risk Management Integrated Framework developed by the Committee of Sponsoring Organizations (COSO) as a guide to organize their risk management and reporting. The authors used the framework to analyze reporting years 2009 and 2010 for Fortune 500 oil and gas companies. After gathering and examining information from 2009 and 2010 annual reports, 10-K filings, and proxy statements, the article examines how the selected companies are implementing requirements identified in the previously mentioned publications. Each section examines the companies’ Enterprise Risk Management system, risk appetite, and any other notable information regarding risk management. One observation was the existence or non-existence of a Chief Risk Officer or other Senior Level Manager in charge of risk management. Other observations included identified risks, such as changes in economic, regulatory, and political environments in the different countries where the corporations do business. Still others identify risks, such as increases in certain costs that exceed natural inflation, volatility and instability of market conditions. Fortune 500 oil and gas companies included in this analysis are ExxonMobil, Chevron, ConocoPhillips, Baker Hughes, Valero Energy, and Frontier Oil Corporation. An analysis revealed a sophisticated understanding and reporting of many types of risks, including those associated with increasing production capacity. Specific risks identified by companies included start-up timing, operational outages, weather events, regulatory changes, geo-political and cyber security risks, among others. Mitigation efforts included portfolio management and financial strength. There is evidence that companies in later reports (2013) are more comprehensive in their risk management and reports as evidenced by their 10-K and Proxy Statements (Marathon Oil Corporation, 2013).

Microseismic monitoring — Introduction

Most papers the readers find in this special section were presented at the First International Workshop on Microseismic Technology held in Asheville, North Carolina, USA, on 17–22 August 2014. The workshop’s organizing and technical program committee consisted of Werner Heigl (Apache Corporation), Vladimir Grechka (Marathon Oil), Leo Eisner (IRSM Academy of Sciences of the Czech Republic), Christophe Maisons (Magnitude), Serge Shapiro (Freie University, Berlin), Julie Shemeta (MEQ Geo), and Stephen Wilson (Seismogenic). The workshop, designed to facilitate sharing of microseismic expertise and the key observations and findings, was organized with special attention to balancing the needs of industry and academia. To encourage participation from the industry, only brief abstracts of papers were requested and no recording was permitted at the workshop; to attract academic contributions, the special section in Geophysics was offered to authors who would be willing to develop their workshop presentations into full-scale papers. The workshop, attended by 80 geophysicists and engineers from 11 countries, was enthusiastically supported by operating and service companies, with sponsorship from ITASCA, Magnitude, Marathon Oil, Pinnacle, Read, Sigma 3 , and …

E&P Notes (December 2014)

E&P Notes (December 2014)

Sonar Metering Optimizes Production in Liquid-Loading-Prone Gas Wells

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166652, ’Use of Sonar Metering To Optimize Production in Liquid-Loading-Prone Gas Wells,’ by C.A. Shields and M. Dollard, Marathon Oil UK, and S. Sridhar, G. Dragnea, and M. Illingsworth, Expro Meters, prepared for the 2013 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed. This paper discusses the use of clamp-on sonar flowmeters to minimize losses associated with well testing and to gain the subsequent benefits seen with respect to production optimization and well deliquefication. Clamp-on sonar flowmetering is a nonintrusive technology that measures the flow velocity of the fluid stream. This intensive well-management strategy has assisted in reducing the production decline of the East Brae field in the North Sea. Introduction The East Brae platform (Fig. 1) is located 275 km northeast of Aberdeen in Block 16/3a in a water depth of 110 m. The reservoir comprises high- permeability sands deposited by turbidity currents. The reservoir has an average porosity of 17% and an average permeability of 558. md. The platform initially started producing condensate, while reinjecting the gas, in December 1993. Exporting of the gas began in 1994, and reinjection was phased out. The current topside holds a low- pressure (LP) separator (test separator) operated at 217 psig, a high-pressure (HP) separator (first-stage separator) currently operated at 406 psig, and second- and third-stage separators. It also includes a gas-processing and - dehydration plant, three gas-compression trains, and produced-water-processing facilities for discharge into the sea. There are currently 12 producing monobore wells on the East Brae platform. Former gas-injection wells have now been converted to producing wells. The wells are inclined up to a maximum deviation of 45°. The reservoir fluid is a retrograde gas condensate that exhibits compositional variation with depth. The reservoir has an active aquifer that has encroached into the producing layers as reservoir pressure has depleted through production. Background: Allocation and Well Testing On the East Brae platform, production allocation for the wells has typically been carried out by individual well tests of each well in the test separator on a monthly basis. The well test records the amount of oil and gas produced from a well during the first stage of separation. The oil and gas are then processed further in the plant. Some of the oil is vaporized into the gas phase as it is stabilized in lower-pressure separators, and some of the gas is liquefied as it is cooled and compressed. As a result of these equilibrium changes, the oil and gas rates exported from the platform (known as its “potentials”) that are attributable to a single well are not directly comparable with the oil and gas rates measured at the test separator for that well.

A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 169010, ’A Novel Completion Method for Sequenced Fracturing in the Eagle Ford Shale,’ by C. Kraemer, SPE, B. Lecerf, J. Torres, SPE, H. Gomez, and D. Usoltsev, SPE, Schlumberger, and J. Rutledge, SPE, D. Donovan, SPE, and C. Philips, SPE, Marathon Oil, prepared for the 2014 SPE Unconventional Resources Conference—USA, The Woodlands, Texas, USA, 1-3 April. The paper has not been peer reviewed. Evenly fracturing all clusters in heterogeneous zones is challenging in long horizontal sections penetrating heterogeneous reservoirs, as is often the case in the Eagle Ford shale. Furthermore, efforts to improve well economics result in reducing completion time by extending the length of each stage even farther to decrease the number of interventions required for completing the well. To address this challenge, a new sequenced-fracturing technique has been developed on the basis of a novel composite fluid comprising degradable fibers and multisized particles. Introduction In Eagle Ford shale completions, which typically rely on limited-entry principles, the distribution of fluid flow is a function of fracture initiation and propagation pressure, differential pressure on perforations, and net pressure of the stimulation treatment. New injection-evaluation and logging techniques demonstrated the possibility of significant variations in fracture-gradient anisotropy and formation fluid-flow distribution over the intervals of horizontal wells. Recently, several operators in the Eagle Ford play revised their completion strategy and decided to increase differential pressure on perforations by reducing the number of perforation clusters per stimulation stage. This approach requires a larger number of wireline interventions to place the additional necessary bridge plugs and is accompanied by longer subsequent coiled-tubing milling operations. A solution was needed to increase the number of perforations being stimulated without increasing the complexity of operations, the associated time, and the costs. Increasing Contact, Not Operational Complexity Chemical diversion has been proposed as a cost-effective and faster alternative to mechanical techniques for isolating perforations and forcing fluids into previously unstimulated portions of the reservoir. Numerous materials (e.g., benzoic acid flakes, rock salt, fracturing balls, and rubber-coated neoprene balls) are commercially available for this purpose, but none was found to provide reliable diversion. The sequenced fracturing technique described here introduces a composite fluid that temporarily plugs zones that were previously stimulated and diverts fluids to understimulated regions. The composite fluid overcomes the limitations of traditional chemical diverters by coupling degradable particles of a wide size distribution.