Announced in 2015, the West Coast Refining and Petrochemicals Project in India was to have been commissioned in 2022. A joint venture between the three Indian state refiners – IndianOil, HPCL and BPCL – to feed India’s soaring energy demand, land acquisition for the refinery in the Ratnagiri district of Maharashtra state hasn’t even been completed, making that target 2022 date very unlikely. But it will go through, not least because the refinery has now secured the backing of Saudi Aramco and Abu Dhabi’s Adnoc.
Last week, Adnoc signed on to buy a stake in the US$44 billion project, brought in as a strategic partner by Aramco. Together, the two Middle Eastern titans will hold an equal majority stake of 50% in the project, with IndianOil at 25% and BPCL and HPCL at 12.5% each. That’s an unusual move, considering that this is a state project, and some have questioned given the foreign firms such a high stake. But as much as Saudi Aramco and Adnoc need to secure outlets for their crude in an increasingly competitive world, India needs crude far more. And with the latest US moves possibly curbing India’s sourcing from Iran, the project has to fall back on the country’s stalwart providers.
And Ratnagiri will need a lot of crude. When completed – the new target date is a still-optimistic 2025 – it will equal or best the capacity of Jamnagar (also in India), the current largest refinery in the world. The planned capacity is for 1.2 million barrels per day of crude processing while petrochemical capacity is said to be in the 18 million tons per annum region. Currently, India has a refining capacity of about 232 mmtpa, with domestic demand reaching 194.2 mmtpa in fiscal 2017. According to the International Energy Agency, this demand is expected to reach 458 mmtpa by 2040. The country is also now the world's third-biggest oil importer. More than financial certainty and domestic demand, Aramco and Adnoc’s participation guarantees that Ratnagiri will always have enough crude to run. And it fulfils Aramco and Adnoc’s ambitions to move further down the value chain into downstream, with Aramco fulfilling its target of having stakes in key refineries in Asia (India, China, Southeast Asia through Malaysia) and the Americas (Port Arthur). Adnoc, too, has invested in India before – having bought a stake in the country’s strategic petroleum reserve in Mangalore.
With financing and partners in place, it would seem as if Ratnagiri is a done deal. But there is one major stumbling block – land. The state government of Maharashtra has yet to secure the 15,000 acres required for the refinery, facing stiff opposition from local farmers and laws that state that at least 70% of land owners must give consent for land acquisition. With general elections due in India next spring and opposition parties seizing on the issue, it is likely that no on-the-ground moves will be made until the next government is in place. The National Democratic Alliance (NDA) led by Narendra Modi is expected to win, but will be treading cautiously around this contentious issue. The 2025 target seems ambitious, and by the time it starts operations, India’s oil demand may have grown even more.
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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.