Power plants in Saudi Arabia burned an average 0.4 million barrels per day (b/d) of crude oil in 2018 directly for power generation, the lowest amount since at least 2009, the earliest year that data are available from the Joint Organizations Data Initiative (JODI, Figure 1). According to the JODI data, compared with all other countries, Saudi Arabia burns by far the largest amount of crude oil directly for power generation. Between 2015 and 2017, Iraq used the second-largest amount of crude oil for power generation (over 150,000 b/d on average), but has significantly reduced its direct crude burn since then.
During the summer months, Saudi Arabia typically experiences an increase in electricity consumption as domestic demand for air conditioning rises. Saudi Arabia relies on crude oil and other fossil fuels, such as petroleum products and natural gas, for power generation. Saudi Arabia’s direct crude burn reached a record high during the summer of 2015, averaging 0.9 million b/d from June to August. In comparison, direct crude burn in the summer of 2018 was 41% lower at 0.5 million b/d.
Despite continued, steady increases in both population and electricity consumption, Saudi Arabia managed to reduce its reliance on crude oil for power generation by increasing the use of other energy sources, such as natural gas and fuel oil. Most of the natural gas that Saudi Arabia produces is associated gas, which is natural gas produced along with crude oil from an oil well. In recent years, however, nonassociated natural gas production has increased. The Wasit gas plant reached its full operating capacity of 2.5 billion cubic feet per day (Bcf/d) in 2016. The plant was built to process nonassociated gas, which it is currently processing from the Hasbah and Arabiyah offshore gas fields, both of which began production in 2016. Saudi Arabia is investing in more natural gas processing capacity, including the construction of the Fadhili gas plant, which will be able to process nonassociated natural gas from both on- and offshore fields. The Fadhili gas plant is expected to be completed by the end of 2019 with a capacity of 2.5 Bcf/d. Consumption of natural gas in Saudi Arabia has steadily increased, averaging 10.6 Bcf/d in 2017, the latest year for which data are available (Figure 2).
In addition to natural gas, Saudi Arabia has also been using fuel oil as a partial replacement of crude oil in power generation. High-sulfur fuel oil is a relatively cheap petroleum product that can be used to fuel marine vessels and can also be used for power generation. However, because of environmental concerns and competition with other fuels, fuel oil consumption has been generally declining in most regions in the world. In Saudi Arabia, however, fuel oil consumption rose 25% between 2015 and 2018 to 0.5 million b/d on average, according to JODI data. Some trade press reports indicate that one potential side effect of the upcoming changes to the sulfur limits in marine fuels in 2020 is that the stranded high-sulfur fuel oil could be sent to Saudi Arabia to further replace crude oil in power generation.
With less crude oil directly being used for power generation, more crude oil is available for domestic refining and exports. For many years, Saudi Arabia has been working to increase its domestic refinery capacity. Saudi Arabia is able to process 2.9 million b/d of crude oil domestically, which will rise further after the startup of the 400,000-b/d Jazan refinery, which may come online in 2019. Because of its refinery additions, Saudi Arabia has been able to process more of its crude oil domestically. Crude oil refinery runs averaged roughly 1.8 million b/d in 2009 and subsequently rose to an average of 2.6 million b/d by 2018, according to JODI data (Figure 3).
As a result of increased refinery runs, Saudi Arabia was also able to increase the amount of petroleum products it could export. Exports of petroleum products more than quadrupled between 2009 and 2018, from 0.4 million b/d to 2.0 million b/d. Saudi Arabia exports more diesel than any other petroleum product, averaging 0.8 million b/d in 2018. Gasoline and fuel oil were the next two most exported petroleum products in 2018 at 0.4 million b/d and 0.3 million b/d, respectively. Saudi Arabia also imports petroleum products; however, over the past several years, Saudi Arabia has generally become a net exporter of most products, according to JODI data.
In addition to refining more crude oil domestically, using less crude oil in power generation can enable Saudi Arabia to increase crude oil exports, if needed. However, in late 2016 and in late 2018, Saudi Arabia, along with other members of the Organization of the Petroleum Exporting Countries (OPEC) and some non-OPEC countries, agreed to voluntarily cut crude oil production in order to prevent further declines in crude oil prices. These agreements resulted in lower production of crude oil in Saudi Arabia, which is a more significant factor in how much crude oil the country has available to export throughout the year (Figure 4).
Furthermore, Saudi Arabia has been cutting production beyond its agreed-upon target, meaning that as Saudi Arabia’s crude oil production falls, production of associated natural gas will also decline. Declines in associated natural gas production could result in an increased need for crude oil used for power generation.
U.S. average regular gasoline and diesel prices increase
The U.S. average regular gasoline retail price rose nearly 5 cents from the previous week to $2.89 per gallon on April 29, 4 cents higher than the same time last year. The Rocky Mountain price rose over 8 cents to $2.84 per gallon, the East Coast and Gulf Coast prices both increased nearly 5 cents to $2.78 per gallon and $2.58 per gallon, respectively, and the Midwest and West Coast prices each rose over 4 cents to $2.77 per gallon and $3.67 per gallon, respectively.
The U.S. average diesel fuel price increased more than 2 cents to $3.17 per gallon on April 29, 1 cent higher than a year ago. The Rocky Mountain price increased 4 cents to $3.18 per gallon, the West Coast price increased more than 3 cents to $3.73 per gallon, the Gulf Coast and East Coast prices increased 2 cents to $2.94 per gallon and $ 3.19 per gallon, respectively, and the Midwest price increased nearly 2 cents to $3.06 per gallon.
Propane/propylene inventories rise
U.S. propane/propylene stocks increased by 1.2 million barrels last week to 58.9 million barrels as of April 26, 2019, 10.3 million barrels (21.1%) greater than the five-year (2014-2018) average inventory levels for this same time of year. Midwest, Rocky Mountain/West Coast, and East Coast inventories increased by 0.9 million barrels, 0.2 million barrels, and 0.1 million barrels, respectively, and Gulf Coast inventories increased slightly, remaining virtually unchanged. Propylene non-fuel-use inventories represented 9.6% of total propane/propylene inventories.
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Pioneering technology expert tells ADIPEC Energy Dialogue up to 80 per cent of plant shutdowns could be mitigated through combination of advanced electrification, automation and digitalisation technologies
Greater use of renewables in power management processes offers oil and gas companies opportunities to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects
Abu Dhabi, UAE – XX August 2020 – Leveraging the synergies created by the convergence of electrification, automation and digitalisation, can create significant cost savings for oil and gas companies when making both operational and capital investment decisions, according to Dr Peter Terwiesch, President of Industrial Automation at ABB, a Swiss-Swedish multinational company, operating mainly in robotics, power, heavy electrical equipment, and automation technology areas.
Participating in the latest ADIPEC Energy Dialogue, Dr Terwiesch said up to 80 per cent of energy industry plant shutdowns, caused by human error, or rotating machinery or power outages, could be mitigated through a combination of electrification, automation and digitalisation.
“Savings are clearly possible not only on the operation side but also, using the same synergies between dimensions, you can bring down the cost schedule and risk of capital investment, especially in a time when making projects work economically is harder,” explained Dr Terwiesch.
A pioneering technology leader, who works closely with utility, industry, transportation and infrastructure customers, Dr Terwiesch said despite the increasing investment by oil and gas companies in renewables and the growing use of renewables to generate electricity, both for individual and industrial uses, hydrocarbons will continue to have an important role in creating energy, in the short to medium term.
“If you look at the energy density constraints, clearly electricity is gaining share but electricity is not the source of energy; it is a conduit of energy. The energy has to come from somewhere and that can be hydrocarbons, or nuclear, or renewables.” he said.
Nevertheless, he added, the greater use of renewables to generate electricity offers oil and gas companies the option of integrating a higher share of renewables into power management processes to create efficiencies, sustainability and affordability when modernising equipment, or planning new CAPEX projects.
The ADIPEC Energy Dialogue is a series of online thought leadership events created by dmg events, organisers of the annual Abu Dhabi International Exhibition and Conference. Featuring key stakeholders and decision-makers in the oil and gas industry, the dialogues focus on how the industry is evolving and transforming in response to the rapidly changing energy market.
With this year’s in person ADIPEC exhibition and conference postponed to November 2021, the ADIPEC Energy Dialogue, along with insightful webinars, podcasts and on line panels continue to connect the oil and gas industry, with the challenges and opportunities shaping energy markets in the run up to, and following, a planned three-day live stream virtual ADIPEC conference taking place from November 9-11.
An industry first of its kind, the online conference will bring together energy leaders, ministers and global oil and gas CEOs to assess the collective measures the industry needs to put in place to fast-track recovery, post COVID-19.
To watch the full ADIPEC Energy Dialogue series go to: https://www.youtube.com/watch?v=QZzUd32n3_s&t=6s
Utility-scale battery storage systems are increasingly being installed in the United States. In 2010, the United States had seven operational battery storage systems, which accounted for 59 megawatts (MW) of power capacity (the maximum amount of power output a battery can provide in any instant) and 21 megawatthours (MWh) of energy capacity (the total amount of energy that can be stored or discharged by a battery). By the end of 2018, the United States had 125 operational battery storage systems, providing a total of 869 MW of installed power capacity and 1,236 MWh of energy capacity.
Battery storage systems store electricity produced by generators or pulled directly from the electrical grid, and they redistribute the power later as needed. These systems have a wide variety of applications, including integrating renewables into the grid, peak shaving, frequency regulation, and providing backup power.
Most utility-scale battery storage capacity is installed in regions covered by independent system operators (ISOs) or regional transmission organizations (RTOs). Historically, most battery systems are in the PJM Interconnection (PJM), which manages the power grid in 13 eastern and Midwestern states as well as the District of Columbia, and in the California Independent System Operator (CAISO). Together, PJM and CAISO accounted for 55% of the total battery storage power capacity built between 2010 and 2018. However, in 2018, more than 58% (130 MW) of new storage power capacity additions, representing 69% (337 MWh) of energy capacity additions, were installed in states outside of those areas.
In 2018, many regions outside of CAISO and PJM began adding greater amounts of battery storage capacity to their power grids, including Alaska and Hawaii, the Electric Reliability Council of Texas (ERCOT), and the Midcontinent Independent System Operator (MISO). Many of the additions were the result of procurement requirements, financial incentives, and long-term planning mechanisms that promote the use of energy storage in the respective states. Alaska and Hawaii, which have isolated power grids, are expanding battery storage capacity to increase grid reliability and reduce dependence on expensive fossil fuel imports.
Source: U.S. Energy Information Administration, Form EIA-860, Annual Electric Generator Report
Note: The cost range represents cost data elements from the 25th to 75th percentiles for each year of reported cost data.
Average costs per unit of energy capacity decreased 61% between 2015 and 2017, dropping from $2,153 per kilowatthour (kWh) to $834 per kWh. The large decrease in cost makes battery storage more economical, helping accelerate capacity growth. Affordable battery storage also plays an important role in the continued integration of storage with intermittent renewable electricity sources such as wind and solar.
Additional information on these topics is available in the U.S. Energy Information Administration’s (EIA) recently updated Battery Storage in the United States: An Update on Market Trends. This report explores trends in battery storage capacity additions and describes the current state of the market, including information on applications, cost, market and policy drivers, and future project developments.