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Natural gas is the fastest growing primary energy source. Its use is projected to double between 1999 and 2020.[1] The mix of fossil fuels used to provide energy and petrochemicals is shifting toward natural gas (or just "gas") and away from coal. Natural gas is the more hydrogen-rich fuel. The worldwide increase in demand for natural gas is driven by the abundance of natural gas reserves, continued technological advances in exploration and production, and the desire for low-carbon fuels and cleaner air. The global demand for gas is increasing at more than twice the rate of oil demand. In the near future, one can envision an economy powered by gas. There are approximately 150 trillion m3 of proven natural gas reserves available worldwide as of the year 2000.[2] Table 8.1 compares the worldwide fossil fuel reserves. At current consumption rates, the worldwide reserves-to-production ratio for gas is approximately 65 years, compared with 38 years for crude oil.
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- Asia (1.00)
- Africa (0.68)
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- Materials > Chemicals > Commodity Chemicals > Petrochemicals (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Oil & Gas > Downstream (1.00)
- Information Technology > Knowledge Management (0.40)
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Abstract This paper will discuss the feasibility of transmitting grid-supplied power to offshore platforms at long step-outs using high-voltage AC (HVAC) transmission systems. In recent years, in an effort to reduce their environmental footprint, an increasing number of operators have considered supplying offshore installations with power from mainland electrical grids using high-voltage subsea cables. This is particularly the case in places like The North Sea, where there is a widespread push for O&G producers to ditch on-platform generators in favor of cleaner sources of electricity (hydro, wind, etc). On account of their low electrical losses and high transmission capacity over long distances, subsea DC transmission lines have traditionally been utilized to supply power to offshore platforms โ especially for structures at long step-outs from shore (>50 km). However, because these systems require the installation of a DC to AC power converter on the platform (along with other ancillary equipment), they pose significant challenges with regards to space, weight, and cost. This paper will examine how flexible AC transmission systems can be used to eliminate this problem by supplying offshore installations long distances from shore with reliable and eco-friendly grid-supplied power. It will outline the advantages of deploying an AC transmission system over conventional on-platform gas turbine generators โ some of which include reduced CO2 and NOx emissions, increased availability, and less maintenance. A case study will be presented on Total's Martin Linge platform in the North Sea, which currently employs the longest subsea AC power link in the world at 163 km (Power Martin Linge, 2015). The AC transmission system helps reduce Martin Linge's CO2 emissions by two million metric tons through elimination of on-platform generators. The paper will focus on the technologies and methodologies that were used on Martin Linge and will discuss the role that power grid simulation and modeling played in lowering the cost for critical power infrastructure, ensuring onshore grid stability, and minimizing overall project risk. The paper will conclude by discussing how producers can use flexible AC transmission systems in other regions of the world to reduce the environmental impact of their offshore installations by capitalizing on clean, reliable grid-supplied power.
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Tarbert Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Ness Formation (0.99)
- Europe > Norway > North Sea > Northern North Sea > North Viking Graben > PL 043 > Block 30/7 > Martin Linge Field > Lunde Formation (0.99)
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- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems > Subsea processing (1.00)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (0.94)
- Health, Safety, Environment & Sustainability > Environment > Air emissions (0.89)
Abstract Natural gas has the potential to play an important role as a "bridge" fuel in the transition from fossil fuels towards a cleaner energy mix and a low-carbon future, due to its better environmental credentials (lower emissions of CO2 and other pollutants per MWh) and higher efficiency in power generation, compared to oil and coal. Natural gas is also suitable as a back-up fuel for complying with renewables and could turn in to a "final destination" fuel if Carbon Capture & Storage (CCS) technology would be competitive and conveniently located. Natural gas with CCS could be a cheap and reliable low-carbon energy source in the long term and a critical technology for climate change mitigation, while delivering sustainable power. Currently, the destination of most of the transported gas is as fuel for power generation, but the electricity can be generated anywhere, even at or near the reservoir source. Gas-to-Wire (GtW) is the process of generating electricity from natural gas at or in proximity of the field, a different approach than producing electricity at a centralized power plant. In the Gas-to-Wire process a gas motor (usually a gas turbine) is placed close to the field and the gas is directly converted into electricity for own use or for sale to the local market (eventually transported by cables to the destination). For a more sustainable process, the CO2 produced by the power plant could be captured and injected underground (in a water layer or a depleted reservoir, if available in the area). Thus, the costs for CO2 transport and storage are reduced and NIMBY (Not In My Back Yard) reactions are limited, as everything remains confined inside the field and the only output is electricity. Following this approach, the paper reports the results of a pre-feasibility study carried out applying the integrated GtW-CCS scheme to a gas production field. Economic sensitivities were performed determining the Levelized Cost Of Electricity (LCOE) and the CO2 captured cost as a function of: gas flow rate, power transmission distance and feedstock valorization. Our analysis evidenced that the GtW-CCS scheme can be competitive in some circumstances, for instance: in remote assets (for own power), when associated gas is present and when wire transmission lines are located nearby the field. LCOE increases when capture plant is present and is particularly sensitive to location and feedstock cost.
Summary Electricity is one of the single largest costs associated with oil and gas production. This cost, however, tends to be overlooked relative to other production costs because of utilities regulation combined with its specialized and noncore technical requirements. In spite of this, several studies and strategies over the years have looked at ways of reducing this cost component with meaningful results. Many of these strategies consist of structuring loads and designing equipment to take advantage of the utilities' regulated rate structure. As the electricity industry in the United States moves toward deregulation, these rate structures will no longer exist; in their place, contracts will be negotiated on a free-market basis between the user and supplier(s) of electricity. In the upcoming deregulated electricity market, three key strategies are available to effectively manage oilfield power costs.Real-time monitoring and control of the electrical load. In-field electricity generation. Negotiation of an integrated power-supply agreement. Because electricity is the ultimate just-in-time product, prices vary greatly depending upon when the power is consumed. The strategies listed previously allow users to proactively structure power supply systems to address the fundamental volatility of the real price of electricity. The effect is to strip out the historic premium paid to the utility to handle the natural volatility of electricity prices by blending load shifting, internal generation, and market purchases. This paper examines different scenarios in which the previous strategies are proposed and makes estimates for potential savings. These solutions use existing technology applied to the changing market environment and, therefore, focus on economic justification as opposed to technology verification. In one such case, the pumping intervals for a collection of wells is adjusted with real time power prices combined with remote operations. This reduces the total cost of electricity consumed per barrel of production while only marginally reducing the actual number of barrels produced. Introduction The cost of electricity has historically been one of the largest operating costs in the production of oil and gas. Additionally, this cost tends to increase over time as the typical oil field ages. Artificial lift, gas compression, water treating, water injection, etc. are installed as the fields age, and all these functions consume an ever-increasing amount of electricity. This increasing electric load trends in the opposite direction from the net oil recovered. The result is that electricity costs tend to make up a larger and larger percentage of the field's lifting costs. It is not uncommon to see power costs representing 40 to 50% of total production costs. Although power costs are a major cost component of field profitability, they tend to be overlooked relative to other production costs for the following reasons.The technical skills needed are specialized and not core to the production company. Unlike other suppliers, the utility that provides electricity is a regulated monopoly. The skills necessary to optimize power costs in this kind of environment are not the same as optimizing other, more conventional costs, such as well servicing, treating chemicals, and artificial lift. As a direct consequence of this, most oil operators do not manage their power costs but endure them without taking proactive measures to change undesirable situations. In spite of this, several studies have looked at ways of reducing the cost of power with meaningful results. The recommendations from these studies can be divided into three groups.Optimizing mechanical systems.2,3 Optimizing electrical systems.3โ5 Working with the utility to optimize usage against a regulated rate structure.3โ6 Examples of Item 1 include balancing pump units, installing pump-off controllers, and modifying the pumping unit's stroke length and speed. Examples of Item 2 include correctly sizing electric motors, correcting power-factor penalties and resultant line losses with capacitor banks, meter consolidation, distribution system optimization and retrofit, and using high-voltage substations. Examples of Item 3 include moving to interruptible or curtailable rate structures, bill verification, demand management, and regulatory intervention. All the approaches mentioned in Items 1 and 2 should be thoroughly researched and implemented to begin any electricity cost-reduction initiative. The approaches examined in Item 3, however, work within a defined and rigid rate and business structure. Operators were encouraged to examine how they were being charged for electricity and to change their behavior to optimize their positions within these relatively rigid price and rate structures. With the advent of deregulation, this area will change radically. Operators must understand how deregulation works in their area and how to best position their company to take advantage of these changes. Deregulation. Electric power generation in the United States is changing from a regulated industry to a competitive one. Where power generation was once dominated by vertically integrated, investor-owned utilities (IOUs) that held most of the generation capacity, transmission, and distribution facilities, the electric power industry now has many new companies that produce and market wholesale and retail electric power. These new companies are in direct competition with traditional electric utilities. Today, vertically integrated IOUs still produce most of the country's electrical power, but that is changing. The long-standing traditional structure of the industry was based, in part, on the economic theory that electric power production and delivery were natural monopolies and that large, centralized power plants were the most efficient and inexpensive means for producing electric power and delivering it to customers. Large power-generating plants, integrated with transmission and distribution systems, achieved economies of scale and, consequently, lower operating costs than relatively smaller plants could realize. Because of the monopoly structure, federal and state government regulations were developed to control operating procedures, prices, and entry to the industry to protect consumers from potential monopolistic abuses.
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Power Industry (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
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Abstract Combustion in gas turbines or diesel gensets typically represents one of the largest sources of carbon emissions on offshore production and drilling installations, second only to flaring. Significant potential exists to decarbonize these assets via electrification. Many regions of the world where large-scale wind developments are planned or currently being built are also centers for oil and gas production (e.g., North Sea, Gulf of Mexico, etc). It is logical to expect that in the coming years opportunities will arise for operators to directly utilize the electricity generated by these wind farms to reduce their carbon footprint. This paper explores possibilities for supplementing conventional power generation on offshore production installations with clean electricity from offshore wind farms. It discusses the feasibility of powering large production assests in deepwater and smaller assets in shallow water. The paper focuses primarily on curtailement utilization (i.e., taking power from the wind farm during times of overproduction) and the inherent commercial capacity of such a scenario. Additionally, it addresses steps/measures operators will potentially have to take in relation to the inherent intermittency and unpredictability of wind generation. Electrical power continuity, stability, and magnitude are crucial to production, as well as meeting required process heat requirements on the topsides. Thus, a discussion on the utilization of combined cycle for deepwater large assets is also discussed.
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- North America > United States > Texas (0.46)