Academic literature on the topic 'Efficienza, sala, operatoria'

When a coal-fired power plant is considered for closure, arguments are commonly made about the loss of jobs and unrealized investments. Facing this pressure, governments are reluctant to enact enforceable emission standards, and these plants continue to emit pollutants into the atmosphere. As the equipment ages, the plants may retire, but in their lifetime they will cause irreversible environmental damage. This report presents a method to mediate this damage, create jobs, maintain the efficiency of the turbine, and maintain or increase the capacity factor of the plant. Solar parabolic troughs using molten salt technology are scalable and can meet the steam conditions of a standard Rankine cycle coal-fired power plant. A marriage of these technologies allows the parabolic trough field to be installed without new power generation equipment. The turbine, generator, and transmission equipment are already in place, and when compared to a standalone concentrated solar power (CSP) plant, can be amortized over a greater number of operational hours without the use of very large amounts of thermal storage. That allows for a reduction in capital investment compared to a greenfield CSP plant, and reduces the levelized cost of energy (LCOE) from the solar contribution to well below current US Department of Energy SunShot targets. Coal-fired plant operators note that they typically cannot operate at partial power output without reducing the efficiency of their turbine accordingly. So, while a photovoltaic hybridization can take advantage of existing transmission infrastructure, it will require that the coal-fired system reduces its output and will consequently reduce the efficiency of the coal cycle. If we have to burn coal, we should do it in the most efficient way possible. Hybridizing with a molten salt parabolic trough installation makes use of the same turbine as the coal-fired system, which maintains the overall efficiency of the turbine at its design point and optimal load. With this model, the coal plant can operate at full power, reduce overall usage of coal while maintaining or even increasing employment opportunities, and reduce CO2 emissions.

Communities that own waste-to-energy (WTE) facilities rely heavily on the revenues generated by their facility to help pay for the costs to finance, operate and maintain these facilities. The two primary revenue streams are tipping fees and energy sales, generally in the form of electricity. While communities often retain all of the tipping fee revenue, revenue from the sale of energy is nearly always shared with the contract operator. In some cases the shared energy revenues include both capacity and electricity payments. The basis of this strategy is to offer the contract operator an added incentive to maximize this revenue stream through more efficient operation and, in the case of capacity payments, to meet certain capacity commitment criteria required by the energy purchaser. This strategy recognizes that the contract operator has some degree of control over the factors that affect energy production. Under most existing service agreements, which date back to the 1980s, energy revenues are shared on a 90/10 basis, with 90 percent going to the community. Now that many of these service agreements are coming up for renewal or are expiring, communities will need to revisit how best to share energy revenues with the contract operator in order to maximize the total revenues retained by the community. This paper analyzes several different approaches to sharing energy revenues in light of the operational experience gained over the past 20 plus years and concludes that, while energy revenue sharing is still in the best interest of the community, the widely employed strategy of a 90/10 split may not offer the best incentive, and therefore may not lead to the maximization of energy revenues to the community.

Abstract The Brazilian Pre-Salt has gained importance as an essential world-class province given its prolific production and thanks to its many challenges, it has incentivized the market to look for better ways to faces these technical challenges safely. This article aims to describe the main challenges faced by Shell and Constellation as well as the approach adopted to improve the operations’ safety and reduce drilling time, significantly reducing the drilling costs in an exploratory campaign in the Brazilian Pre-Salt. The campaign was based on the buildup of a partnership between the drilling contractor, operator and the main services provider, Halliburton, creating a transparent and collaborative environment, which improved all parties’ ownership and accountability. The application of many processes and techniques such as Step Seven, Stop Work Authority and Design of Work improved safety and efficiency. A precise equipment selection, detailed planning and careful execution with disciplined application of a learning mindset were also paramount to drilling performance. Four pre-salt wells were drilled in the campaign at Sul de Gato de Mato (2 wells), Alto de Cabo Frio and Saturno prospects with all of them qualifying in terms of drilling time as best in class (BIC), i.e., within the top 5% percentile. In 2019, the GdM3 well was the fastest delivery of a pre-salt well out of the 250+ wells in the region. The well GdM4 drilled in 2020 as part of the same campaign broke the previous record by seven days, being the fastest pre-salt well ever drilled with its 18 dry hole days mark. The main reason associated with the campaign´s success was the utilization of the DID-PDCA methodology, which promoted the integration of all the workforce in a cycle towards continuous improvement by: (i) carefully selecting the equipment and experienced service providers, (ii) generating detailed plans of the drilling activity and engaging all those involved in the delivery, (iii) establishing and applying a HSE strategy for safety culture enhanced and (iv) constantly monitoring of performance and discussing the next steps. Along this article a summary of well layout, the drilling phase duration, some of the key performance improvement initiatives as well as how they were generated will be shared.

The Hardisty Cavern Facility at Hardisty, Alberta — consists of four underground salt caverns totalling 3.0 million barrels of petroleum products storage — was recently completed. This project is unique in that it integrates existing underground salt caverns into a significant North American crude oil transportation hub. Approximately 400 million barrels of oil move through this hub annually. This project utilizes existing caverns developed in the late 1960’s with significant upgrades and new infrastructure to integrate the Hardisty Cavern Facility into the crude oil transportation hub. This paper discusses the automation related innovations implemented and the challenges encountered during the course of the project. One example of innovation involves utilizing a single variable frequency drive (VFD) to perform multiple functions. Due to process requirements, the VFD was required to operate one or two cavern injection pumps. Electrical power grid constraints dictated that the VFD be used for starting and stopping the 1500 horsepower (1119 kW) pump motors. Process conditions also required that the pump motor loads be automatically transferred from VFD to the utility power grid without interruption to production. Operational flexibility was another key component of the facility automation requirements. Storage requirements for multiple petroleum products necessitated operator-selectable flow paths within the automation system. In addition, flexibility, safety, efficiency and maintainability requirements resulted in a distributed process philosophy across three separate process areas.

Abstract Emerging technologies, stringent permanent well abandonment regulations, and increasing well complexity affect the way we execute well intervention operations. One of the major operators in the Netherlands had an objective to set underbalanced cement plugs in brine across a deviated section using managed-pressure equipment to overcome high reservoir bottomhole pressure. The project involved several challenges: large-diameter production casing with a requirement to maintain high shut-in wellhead pressure, complex wellbore geometry, operations from a workover rig with zero discharge allowance, corrosive salt environment, and small cement slurry volume. These challenges had to be addressed to complete well abandonment to minimize safety risks, maximize efficiency, and achieve compliance with industry standards and regulatory requirements. This paper discusses two case studies involving underbalanced pump-and-pull and conventional balanced plug placement techniques. Thorough analysis and risk assessment, engineering design approach, comprehensive laboratory testing, and fit-for-purpose surface equipment and downhole tools enabled flawless job execution and placement and achievement of long-term zonal isolation. The first well-barrier elements were successfully verified by tagging and pressure testing in both cases. Results of this study include the following observations and conclusions: Managed-pressure cementing was proven to be an ideal solution for a well abandonment in a reservoir environment of high bottomhole pressure.Highly magnesium-resistant cement slurry design should be considered when setting cement plugs across an extremely corrosive salt environment.Successful verification of the first well-barrier element simplifies operations for subsequent cement plugs. Cost-effective solutions for permanent well abandonment under challenging downhole conditions attracts increasing interest from petroleum engineers due to increasing well complexity and low oil prices that challenge the economics of wells, leading to abandonment. The current paper describes the challenging conditions under which the wells had to be abandoned, thorough analysis of the risks involved, and an effective solution. The design strategy, execution, evaluation, and results for these two wells are discussed in detail and will help to guide success and solve problems related to permanent well abandonment under similar challenging conditions.