Barrels Of Oil Research Articles

Trait-dependent variability of the response of marine phytoplankton to oil and dispersant exposure

The Deepwater Horizon oil spill released millions of barrels of crude oil into the Gulf of Mexico, and saw widespread use of the chemical dispersant Corexit. We assessed the role of traits, such as cell size, cell wall, motility, and mixotrophy on the growth and photosynthetic response of 15 phytoplankton taxa to oil and Corexit. We collected growth and photosynthetic data on five algal cultures. These responses could be separated into resistant (Tetraselmis astigmatica, Ochromonas sp., Heterocapsa pygmaea) and sensitive (Micromonas pusilla, Prorocentrum minimum). We combined this data with 10 species previously studied and found that cell size is most important in determining the biomass response to oil, whereas motility/mixotrophy is more important in the dispersed oil. Our analysis accounted for a third of the variance observed, so further work is needed to identify other factors that contribute to oil resistance.

Effective Treatment and Handling of Produced Water

Editor’s Note: The oil and gas industry is under public scrutiny like never before on a host of health, safety, and environmental issues. These concerns are already affecting how companies operate and interact with the public. This series is intended to shed light on how the industry is actively confronting these challenges or how it should address them going forward. Produced water is an inevitable by-product of oil and gas production. It is estimated that for every barrel of oil produced worldwide there are roughly four to five barrels of water co-produced. As it contains a wide range of contaminants, the discharge of produced water could potentially cause harm to the environment, and therefore should be monitored closely. For the offshore oil and gas industry, approximately 75% of the produced water is treated and then discharged into the ocean, with the rest being reinjected. While onshore, roughly 90% of this water is reinjected, with the rest being treated and reused or discharged. With the rapid development of shale oil and gas, and the demand for water for hydraulic fracturing, there is an increasing emphasis on flowback and produced water reuse. The measurement of oil in produced water is vitally important, for both regulatory compliance monitoring and data collection for the development of future government regulations and operators’ corporate environmental policy. Of course, to calculate the total amount of oil that is discharged via produced water, the volume of that water must also be measured accurately. Measurement of the oil in produced water is also important for the control of the water treatment process itself. Management of produced water varies with operators, geographical locations, and field history. Good produced water management practice should involve different disciplines, including reservoir engineers, production engineers, production chemists, and environmental engineers. It would also require an integrated approach, taking into consideration the different options, as well as production history and profile. Often water production becomes a limiting factor for continuing oil production economically for a specific field. How to best manage produced water in oil and gas production will therefore have a significant impact economically, socially, and environmentally. The key to produced water management is to prevent water getting into the wellbore, and to minimize the water being brought to the surface. Failing this, produced water must then be treated, reinjected, and/or discharged or reused. Using Online Oil-in-Water Monitors The use of online oil-in-water monitors can play an important role in the management of produced water. There are many benefits in using online continuous oil-in-water monitors, but particularly as they provide continuous information on a minute-by-minute basis, if not more frequently. Thus, not only can one spot process upset conditions quickly and take actions to rectify the situation, but such monitors can also be used for process optimization, such as chemical dosing.

Petroleum evolution within the Tarim Basin, northwestern China: Insights from organic geochemistry, fluid inclusions, and rhenium–osmium geochronology of the Halahatang oil field

The newly discovered Halahatang oil field in the northern Tarim Basin has a potential resource of more than 70 billion bbl of oil. Oil organic geochemical data from the Halahatang oil field indicate that the oils are of moderate maturity, biodegraded, and represent one oil family, derived from the same Paleozoic marine source. Modeling of coeval aqueous and hydrocarbon-bearing inclusion data provide fluid trapping temperatures and pressures of 100°C to 110°C and approximately 39 to 59 MPa (∼5656–8557 psi), respectively. The fluid inclusion data coupled with the previous basin model studies suggest a single prolonged oil migration event during the Permian. The Re–Os isotope data of the oil yields an early Permian Re–Os age of 285 ± 48 Ma. The age agrees with the timing of maturation of the Paleozoic source via burial history modeling but is slightly older (∼5–55 m.y.) than the oil migration and accumulation timing implied by the basin modeling coupled with fluid inclusion analysis and the published reservoir illite K–Ar dates. Thus, the oil Re–Os date suggests that oil generation in the Halahatang depression of the Tarim Basin occurred during the early Permian rather than the Silurian as previously proposed, with subsequent oil migration and accumulation occurring during the middle–late Permian as recorded by basin modeling, coupled with fluid inclusion analysis and illite K–Ar dating. In addition to promoting petroleum exploration in the Tarim Basin, this study, which combines crude oil Re–Os isotope dating and traditional analytical methods (organic geochemistry and fluid inclusion analysis) to constrain petroleum evolution, is applicable to hydrocarbon systems worldwide.

The nature and age of basement host rocks and fissure fills in the Lancaster field fractured reservoir, West of Shetland

Hosting up to 3.3 billion barrels of oil in place, the upfaulted Precambrian crystalline rocks of the Lancaster field, offshore west of Shetland, give key insights into how fractured hydrocarbon reservoirs can form in such old rocks. The Neoarchean ( c. 2700–2740 Ma) charnockitic basement is cut by deeply penetrating oil-, mineral- and sediment-filled fissure systems seen in geophysical and production logs and thin sections of core. Mineral textures and fluid inclusion geothermometry suggest that a low-temperature (<200°C) near-surface hydrothermal system is associated with these fissures. The fills help to permanently prop open fissures in the basement, permitting the ingress of hydrocarbons into extensive well-connected oil-saturated fracture networks. U–Pb dating of calcite mineral fills constrains the onset of mineralization and contemporaneous oil charge to the mid-Cretaceous and later from Jurassic source rocks flanking the upfaulted ridge. Late Cretaceous subsidence and deposition of mudstones sealed the ridge, and was followed by buoyancy-driven migration of oil into the pre-existing propped fracture systems. These new observations provide an explanation for the preservation of intra-reservoir fractures (‘joints’) with effective apertures of 2 m or more, thereby highlighting a new mechanism for generating and preserving fracture permeability in sub-unconformity fractured basement reservoirs worldwide. Supplementary material: Analytical methods and isotopic compositions and ages are available at https://doi.org/10.6084/m9.figshare.c.4763237 Thematic Collection: This article is part of the Geology of Fractured Reservoirs collection available at: https://www.lyellcollection.org/cc/the-geology-of-fractured-reservoirs

Atlanta Field: Producing Heavy and Viscous Oil in Ultradeepwater

SummaryAtlanta Field is a post-salt heavy-oil field located 185 km off the city of Rio de Janeiro, in Santos Basin, Brazil, at a water depth of approximately 1550 m. Atlanta, however, is not just another ultradeepwater heavy-oil field. Several additional challenges had to be overcome for its development, such as low reservoir overburden (800m), highly unconsolidated sandstone reservoir (36% porosity and 5,000 md permeability), heavy and viscous crude flow assurance (14 °API and 228 cp at initial reservoir conditions), high-naphthenic-acidity oil [total acid number (TAN) 10mg KOH/g], high-power artificial-lift pumping-systemrequirement (1,600 hp), and complex-topside crude facilities.The development of Atlanta Field was phased in two stages: an early production system (EPS), which is expected to last from four to five years and comprises three horizontal production wells; and a definitive production system (DPS), which will add nine wells to complete the development plan with 12 horizontal producers. The first two EPS wells were successfully constructed and tested during 2013 and 2014, proving the feasibility of surpassing the great challenges imposed by the field’s unique environment and enabling the beginning of the production phase of the field. The first oil occurred in May 2018 with these two wells producing to the floating production, storage, and offloading unit (FPSO) Petrojarl I. The third and last producer of the EPS was constructed in 2019 and began operation in June of the same year. More than five million barrels of oil were already produced to date.Marsili et al. (2015) described in detail the exploration and development phases of Atlanta Field, focusing on their challenges, the overcoming process, and solutions adopted. This current work intends to present an updated review of the paper, providing the most recent information related to the project with a subsequent focus on the production phase findings and results. Among others, the initial prediction and expectations will be compared with actual field performance. For all milestones achieved, the Atlanta project is considered a great success so far and a benchmark for the industry in this harsh and adverse environment.

No Evidence for Long-term Impacts of Oil Spill Contamination on Salt Marsh Soil Nitrogen Cycling Processes

Salt marshes are important sites of nitrogen cycling and removal that straddle the land/ocean interface, allowing them to intercept human-derived nitrogen before it reaches coastal waters where it causes problems like hypoxia and harmful algal blooms. In 2010, the Deepwater Horizon oil spill released an estimated five million barrels of crude oil into the Gulf of Mexico, significantly contaminating coastal wetlands over approximately 800 km of shoreline. We investigated microbial nitrogen cycling processes in soil from four salt marshes in Terrebonne Bay, Louisiana, USA that were either exposed or not exposed to Deepwater Horizon oil over the course of 1 year (2013–2014), 2.5–3.5 years post-spill. Specifically, we measured nitrification and denitrification potentials, nitrogen cycling functional gene abundances (nirS, bacterial and archaeal amoA), and soil physical and chemical properties. We show that variation in nitrification and denitrification potentials was independent of site oil exposure. Large year-to-year differences in springtime nitrification potentials were inversely related to plant live belowground biomass, indicating that competition for nitrogen is likely an important control on nitrification. There were positive correlations between nitrification potentials and both soil extractable nitrate concentrations and denitrification potentials, supporting the idea that denitrification is coupled with nitrification. We found no evidence that there was a long-term impact of oil exposure on salt marsh soil microbial nitrogen cycling processes and the nitrogen removal ecosystem service they provide. It is important to note, however, that these impacts could have been masked by high background variability in process rates or loss of oil exposed soil to coastal erosion.

Legislación Ambiental, Regionalización y Presupuesto. Ley Orgánica de Planificación Integral de Circunscripción Territorial Especial Amazónica

El presente artículo analiza la Ley Orgánica para la Planificación Integral de la Circunscripción Territorial Especial Amazónica publicada en el Suplemento 245 del Registro Oficial, de fecha 21 de mayo del 2018, y además su relación y vinculación con la Constitución de la República del Ecuador, Código Orgánico de Organización Territorial Autonomía y Descentralización, y Código Orgánico del Ambiente. Los resultados demuestran la importancia de esta Ley, pero también las necesidades de reforma sobre todo en lo referente a que el ejecutivo nacional sea el que designe o delegue directamente al Presidente del Consejo de Planificación y Desarrollo de la Circunscripción Territorial Especial Amazónica, y otro aspecto que debe mejorar es en lo referente a el Fondo para el Desarrollo Sostenible Amazónico, donde solamente se establece una asignación equivalente al cuatro por ciento (4%) del precio de barril de petróleo que se extraiga en la Circunscripción Territorial Especial Amazónica.

On the sustainability of CO2 storage through CO2 – Enhanced oil recovery

This work uses pilot examples of CO2 enhanced oil recovery to analyze whether and under which circumstances it is exergetically favorable to sequester CO2 through enhanced oil recovery. We find that the net storage efficiency (ratio between the stored and captured CO2) of the carbon capture and storage (CCS)-only projects is maximally 6–56% depending on the fuel used in the power plants. With the current state of technology, the CCS process will re-emit a minimum of 0.43–0.94 kg of CO2 per kg of CO2 stored. From thermodynamics point of view, CO2 enhanced oil recovery (EOR) with CCS option is not sustainable, i.e., during the life cycle of the process more energy is consumed than the energy produced from oil. For the CCS to be efficient in reducing CO2 levels (1) the exergetic cost of CO2 separation from flue gas should be reduced, and/or (2) the capture process should not lead to additional carbon emission. Furthermore, we find that the exergy recovery factor of CO2-EOR depends on the CO2 utilization factor, which is currently in the low range of 2–4 bbl/tCO2 based on the field data. Exergetically, CO2 EOR with storage option produces 30–40% less exergy compared to conventional CO2 enhanced oil recovery projects with CO2 supplied from natural sources; however, this leads to storage of >400 kg of extra CO2 per barrel of oil produced.

Detailed Energy Accounting of Electrical Submersible Pumping Systems

The concept of energy return on investment (EROI) is applied to a set of electrical submersible pumps (ESPs) installed on a small offshore platform by conducting a detailed energy accounting of each ESP. This information is used to quantify the energy losses and efficiencies of each ESP system as well as the EROI of the lifting process (EROILifting), which is derived by dividing the energy out of each well, which is the chemical energy of the crude oil produced, by the energy consumed by each ESP system and by the surface equipment used to dispose of the well’s produced water. The resulting EROILifting values range from 93 to 565, with a corresponding energy intensity range of 18.3 to 3.0 kWh/barrel of crude. The energy consumed by each well is also is used to calculate the lifting costs, which is the incremental cost of producing an additional barrel of crude oil, which range from 0.64 to 3.90 USD/barrel of crude. The lifting costs are entirely comprised of procured diesel fuel, since there is no natural gas available on the platform to be used as fuel. Electrical efficiencies range from 0.60 to 0.80, while Hydraulic efficiencies range from 0.12 to 0.56. The overall ESP efficiencies range from 0.09 to 0.39, with the largest losses occurring in the hydraulic system, particularly within the ESP pump itself. Improvement of pump efficiencies is the only practical option to improve the overall ESP system efficiencies. Other losses within the electrical and hydraulic systems present few opportunities for improvement.

External Economic Shocks and Vulnerability of the West African Economic and Monetary Union

Background: The regional integration, may it be economic integration or monetary union, is considered, since the success of the European Union, as a mean to development and to mitigate the consequences of exposure to globalization. However, in the African context, the capacity of resilience and the vulnerability of these economies against external shocks remain questionable. Objective: This paper aims to analyze the effects of external economic shocks on the economies of West African Economic and Monetary Union (WAEMU) which is comprised of West African francophone countries (Benin, Cote d’Ivoire, Mali, Niger, Senegal and Togo) and lusophone countries (Bissau Guinea). Method: To achieve this, the Vector Auto Regression technique has been used. We examine the impact of Organization for Economic Cooperation and Development (OECD)’s GDP the price of agricultural commodities, the price of the crude oil barrel, and aid and development assistance shocks on the economies of the union. Due to the lack of data, Bissau Guinea has been removal from the analysis. The data ar primarily sourced from the World Development Indicators and World Economic Outlook databases respectively from the World Bank and the International Monetary Fund and cover the period 1980 – 2018. Results: The results show that the WAEMU countries are highly sensitive to the variations of these different variables with the exception of the price of the crude oil barrel. In addition, the impulse responses show that the WAEMU’s economies are permanently affected by these shocks. Conclusion: In terms of economic policy implications, it is essential to strengthen the insurance mechanisms such as intra-trade through the deepening of the regional integration process, responsible budgetary policy, flexibility of the economies, and the economic convergence for the viability of the union.

An Unconventional Challenge Can Casing Failures During Hydraulic Fracturing Be Stopped?

Shale producers around the world have learned in recent years that they cannot take wellbore integrity for granted. During pressure-pumping treatments, the interplay of hydraulic fracturing and formation geomechanics is deforming and even shearing steel casing. In the worst of cases, this means that some operators have lost access to long sections of a wellbore before it produces a single barrel of oil. This is largely not viewed as an inter-well challenge similar to frac hits. Rather, it is considered to be intrawell phenomena. The problem can take several forms and has no universal driver. George King, an independent consultant and leading technical voice on hydraulic fracturing, points out that not every unconventional asset is affected—indicating that geology and understanding of the rock fabric matter. However, information he has collected from client operators shows that in certain US shale and tight oil fields, between 20%–30% of horizontal wells are impacted to some degree. “Sometimes it is with the cement support, and sometimes it is with the casing itself,” said King, listing two of the problem’s general root causes. He added that the casing deformation is “an artifact of some damage that we are seeing right now in the realm of fracturing, and [during] the time period of fracturing.” A commonly reported version of the problem emerges after just a few stages at the toe-end of a horizontal well have been fractured. As another plug is pumped downhole to continue the completion, it suddenly stops 1,000 ft to 5,000 ft short of its target. This could happen in the bend, or it could be somewhere deep in the lateral. Often the deformation is described as ovalling. If a restriction consumes much more than a tenth of an inch of the pipe’s original internal diameter, there is the potential that unstimulated stages beyond the stopping point are lost to conventional plug-and-perf methods. This fate can sometimes be avoided by running slim-profile perforating guns, but then other isolation technologies are still needed to replace conventional plugs. Unconventional operators in China, Argentina, Canada, and the US have all faced the issue. In response, the technical community has recently stepped up collaboration efforts at industry conferences to find answers. In China, the issue appears to be more widespread on a per-well basis. National oil companies working the Sichuan Basin, the country’s most active unconventional area, have reported that more than 40% of gas wells have experienced casing deformation or failures. Like their US counterparts, Chinese operators typically realize the problem during a post-fracturing tool run. Argentina’s Vaca Muerta is not immune either. A 2015 technical paper coauthored by researchers at Chevron and YPF (URTeC 178620) casts casing shear and restrictions as common and “extremely detrimental to the performance of the well.” When explaining why the issue is cropping up today, more than a decade into the shale revolution, experts are quick to point out that a lot has changed since the first horizontally drilled and hydraulically fractured wells.

The Challenge of Oil Spill Monitoring and Control in Nigeria

Oil has been a fundamental enabler of development. Be this as it may, the emergence of the green environment movement, catalyzed by the challenge of climate change, has called into question the significance of crude oil as a source of energy. This has necessitated the need to manage the environmental impact of oil. One area needing attention is oil spill monitoring and control. Several technological systems have been developed in order to monitor and subsequently control oil spills. These include acoustic emission sensoring, infrared sensoring, fibre optic sensoring, satellite remote sensoring and remotely-piloted aircrafts. Nigeria, where oil spill is a major challenge, requires an effective management of oil spills. In realization of this, regulatory agencies such as National Oil Spill Detection and Response Agency and detailed guidelines for effective oil spill monitoring and control have emerged. Be this as it may, weak regulation by government agencies has been exploited by oil companies and communities; resulting in frequent oil spills, large quantities of spilled oil, extensiveness of polluted areas and persistence of the impact of spilled oil. Oil spills occur frequently. For instance, there were 5,848 incidents resulting in the spillage of about 169,691 barrels of oil between 2010 and 2018. Spills occur in all parts of the oil producing region, the Niger Delta; resulting in its being commonly described as the most polluted area of the planet. The impact of spills is usually enduring because many spill sites are either not cleaned or cleaned ineffectively. Effective regulation and a more environment-friendly oil spill monitoring and control through technological applications are necessary.

Smart Solutions for Oil and Gas industry Challenges

Crude oil is the most attractive source of energy. It is formed at high temperatures and pressures deep down in the earth. Extraction of this energy resource involves expensive drilling and extraction processes. The composition and physical characteristics of the oil depend on the source of the organic material, temperature, and heat. The greater the viscosity of the oil the more difficult it is to extract. Heavy oil, is the name given to oil with API gravity between 10 and 20, and high viscosity <10,000 cP. It is technologically challenging and expensive to extract. Many solutions have been explored owing to the high financial returns in this business. In this study, we propose new smart solutions, utilizing unique properties of nanoparticles of different shapes and sizes to reduce the viscosity of heavy oil to make it easier to extract. Nanoparticles are 1- 100nm in size, have a high surface-to-volume ratio, high heat capacity, excellent heat conductivity, low thermal expansion, and high melting temperatures. A combination of some of these properties was utilized to explore solutions for drilling and heavy oil viscosity problems. In drilling, problems like pipe sticking lost fluid circulation, formation damage, erosion of the borehole, thermal instability of drilling fluids, and their insufficient gel properties, lie in controlling and optimizing the rheology of the drilling fluid. Therefore, to advance the performance of water-based drilling fluids in such harsh reservoir conditions, a simple treatment based on nanotechnology was utilized by synthesizing in-house nano-additives. 1-3 wt% of nano-additives increases fluid density by~5% and dynamic viscosity by-20% and reduces fluid loss by 50%. In addition to this, it forms a thin smooth Mud Cake with the surroundings of the formation. At ambient temperatures, crude oil and bitumen are resistant to flow through reservoir rock because of their high viscosities. Consequently, the energy expended to produce and upgrade a barrel of oil can be as high as 40% of the total energy available from the crude oil resource. Thermally enhanced oil recovery techniques such as steam-assisted recovery and also in situ combustions are employed to upgrade and save the physicochemical properties of the oil. All these recovery techniques are expensive, complicated, and need periodic maintenance; therefore, direct and cheap solutions are the main targets for high in situ upgrading. Our study provides an alternative method that can help in the production and upgrading of such heavy oil by cracking it. For the heavy oil cracking process, iron oxide Nano-Rods (IONRs) were synthesized by an environmentally friendly method. These rods were embedded and well mixed with 1 L of heavy oil (12 API) and subjected to direct microwave radiation. The radiation causes a reduction in the dynamic viscosity of crude oil due to the presence of dipole water molecules. This reduction increased up to 50% when a controlled amount of IONRs additives were added at the same temperature.

Integrated reservoir management in a Niger Delta oil rim field

Several hundred million barrels of oil and trillions standard cubic feet of gas are enclosed within the oil rim reservoirs in the Niger Delta. The low recovery from these reservoirs can be attribut...

The Forties Field, Blocks 21/10 and 22/6a, UK North Sea

Abstract The Forties Field, discovered by BP in 1970, is the largest oilfield on the UK Continental Shelf. It is trapped in a simple four-way dip closure, with a Paleocene turbidite sandstone reservoir. The Forties Field originally contained between 4.2 and 5 billion bbl of oil, with 2.75 billion bbl produced to June 2017. Production has been supported by water injection and the influx of a regional aquifer. The original development contained equally spaced producers with peripheral injectors. As the field matured, production was concentrated in the crestal parts of the field with injectors tending to be moved upflank. With the development of seismic lithology prediction and fluid detection, together with 4D seismic technology, it became possible in the late 1990s to target bypassed oil in unexpected locations throughout the field. In 2003, BP sold the field to Apache who were able to rejuvenate production, adding over 170 MMbbl oil reserves, with an extended drilling campaign targeting bypassed pay identified using seismic technologies. Production at the Forties facility has been further enhanced by the development of four satellite oilfields, Bacchus (Jurassic reservoir), Brimmond, Maule and Tonto (Eocene reservoirs), together with Aviat (Pleistocene reservoir) produced for fuel gas supply.

E&amp;P Notes (January 2020)

E&amp;P Notes (January 2020)

What Strategies And Policies Can Save Nigeria in the Energy Transition?

The world is fast changing and so is the energy mix. A clarion call by scientists worldwide calls for immediate action to prevent the impact of climate change or face the consequences in the coming few years. Scientists and environmental activists are lobbying against the use of fossil-based fuel and mounting pressure on financial institutions and government to stop the financing of fossil fuel projects all over the world. The strategy is to dry-up investment from fossil fuel energy, then more investment will flow towards the greener alternatives in the next two decades to support the development of new technologies and other earth-friendly energy sources. Also, by clamouring for change, the cleaner technologies and alternative (greener) energy will create a substantial fall in the demand of fossil fuel, particularly crude oil. However, this move poses existential threat to third-world countries like Nigeria which is largely dependent on sales royalties and tax revenues from crude oil and natural gas reserves respectively. The future trends warn of a looming dooms day approaching when the remaining oil may not be able to attract foreign money for its development. Nigeria must therefore hasten in the effort to recover its reserves timeously and make the most of what it has before the green era. Since joining Organization of Petroleum Exporting Countries (OPEC) in 1971, Nigeria has established is membership status by steadily growing its reserves to now over 41 billion barrels of crude oil that is yet untapped mainly attributed to the Niger Delta basin. This means that Nigeria’s crude oil export is controlled by OPEC but this restriction does not apply to the export of Nigerian petroleum products. Hence, with investment into refineries and downstream value chain, Nigeria can afford to increase its production to maximize its resources and grow enormous wealth. Most of the other Nigerian petroleum basins in Nigeria are still under-explored and as such not accounted for in the nation’s wealth of resources. It is believed the nation can also benefit from significant amount of oil discoveries that are either invisible to conventional technologies or bypassed by natural recovery mechanisms. These presents an opportunity to uplift the nation’s reserves without risky investment in deep water exploration. Nigeria should aim to ramp up its production rapidly in the next couple of years to harness its available resources while there is still time to do so. To take advantage of Nigeria’s vast oil resources, the government must explore strategic policies that will enhance its exploration and development interests through the expansion of value chain and promote alternative energy. It must also exploit the remaining reserves quickly. Therefore, Nigeria must take advantage of its crude oil resources by exploring various fiscal incentives and take key regulatory steps to ensure that production is maximized to drain the technically recoverable reserves as quickly as possible. The wind fall from this can then be ploughed into the economy to develop value chain and also promote transition to greener energy alternative. To achieve this, a radical policy change is necessary such as incentivizing oil production and encouraging oil companies to change their direction. This paper presents some thought-provoking ideas of how this can be achieved in the near term.

Pipeline Capacity Rationing and Crude Oil Price Differentials: The Case of Western Canada

This paper examines the impact of pipeline capacity constraints on the discount of Canadian oil prices relative to U.S. benchmark oil prices. Using a panel of monthly data for Canadian oil exporting pipelines, we estimate that price differentials between U.S. markets and Western Canada would increase by 3.6% for 1% increase in pipeline capacity constraints. Pipeline capacity constraints in Canada have resulted in an average loss of $5.53 for every barrel of crude oil exported to the U.S. between 2009 and 2017. In 2015 and 2016, the losses due to insufficient pipeline capacity were equivalent to 3%-5% of the Canadian oil and gas industry’s sales revenue and 69%-102% of its royalty payments to provincial governments. Western Canadian oil refiners and refined products’ consumers benefit from the depressed crude oil prices. However, the total gains captured by local refiners and consumers are much smaller than the losses of the upstream sector.

Sustainability in higher education schools in México

The increase of gases in the ozone layer is an important issue nowadays in the Universities of Higher Education in Mexico; there is a great interest in contributing to the reduction of the carbon footprint, therefore, a study was carried out to calculate the footprint generated by the students of the Polytechnic University of Guanajuato through the use of software. The participants were 27 students of the Automotive Engineering degree of the sixth semester, which during this period kept a record of the consumption of PET bottles in their various presentations. The main findings were that the total CO2 they produce is 131.7 Kg, which would be equivalent to 0.176 barrels of oil and 1.19 m3 of space saved in landfills. Now, taking into consideration the entire student population (3,899), the calculation was projected annually and estimating the same consumption patterns, would save 76.3 barrels of oil against 515.55 m3 of space in sanitary landfills.

“Green Fingerprint” Project: Evaluation of the Power Consumption of Reporting Stations in a Radiology Department

To quantify the power or energy consumption of reporting stations in a radiology department and to consider a hypothetical scenario to reduce energy waste. We measured the energy consumption of 36 radiology reporting stations over a mean time frame of about 194 days and then extrapolated results to 1 year. Reporting stations were configured (by default) to enter a stand-by mode after 4 hours of inactivity. A hypothetical scenario was calculated in which stand-by was skipped and the reporting stations were shut down after 1 hour of inactivity. Data from four stations was corrupted. The overall power consumption of the 32 remaining reporting stations was 53,170 kWh/a, equivalent to 12 family households (4500 kWh/a per household in Switzerland in 2014) or 97.2 barrels of oil. We identified three main power consumption patterns of the reporting stations: mainly off, mainly on, and always off. The on-mode consumption per year was 40,763 kWh/a, the stand-by consumption was 10,010 kWh/a, and the off-mode consumption was 2397 kWh/a. The reporting stations spent half of their on-mode time awaiting the initiation of stand-by, resulting in a wait-time consumption of 18,243 kWh/a. With the hypothetical scenario, we achieved an energy consumption saving of 23,692 kWh/a, a reduction of about 45% of the initial energy consumption, equivalent to 5 households or 40.8 barrels of oil consumed. The power consumption of the reporting stations is not negligible. Reducing energy waste in the radiology department can be established through simple changes in device configuration which will simultaneously promote energywise habits. Minor changes to the settings of the reporting stations in a radiology department can result in significant long-term energy savings and promote energy-wise habits.