Shale feedstocks fuel ethylene, LNG and petrochemical derivatives expansion
In spite of the variability in shale composition causing operational challenges for refiners, monetisation opportunities are seen throughout the energy value chain
René G Gonzalez
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At a recent seminar
entitled, Overcoming Shale Oil Processing Challenges, George Duggan, Director of Refinery and Petrochemical Technology at Baker Hughes, discussed shale crude variations, even from the same play. The low sulphur and low total acid number (TAN) are good feeds for sweet crude distillation units (CDUs), and their paraffinic characteristics make good FCC and coking feedstock. However, these same shale crudes may contain substantial solids content and their paraffinic characteristic runs the risk of incompatibility with asphaltenic crude oil blends, as has been reported by North American refiners processing blends of Canadian crudes and tight oils. In spite of the variability in shale composition causing operational challenges for refiners, monetisation opportunities are seen throughout the energy value chain, including LNG, ethylene, methanol, olefins, polymers and petrochemical derivatives.
Because of these variability challenges that must be resolved before capturing monetisation opportunities, the case has been made for managing compositional variabilities and fouling and corrosion precursors beginning at the upstream/midstream interface to avoid refinery corrosion and fouling problems originating from the midstream infrastructure, such as remain on board (ROB) material found in transportation systems (barge, rail and so on) before entering the desalter/CDU.
Shale feedstock learning curve
With 2.5 million bpd of shale liquids now being processed, typically blended with a smorgasbord of other conventional and opportunity feedstocks, refiners are reporting formation of emulsions, wax deposits and a host of other problems not previously encountered by even the most experienced refinery operator. These blends require a higher matrix of testing and analyses (for example, crude assay) to select appropriate treatment (such as the use of dispersants) and adjustments to maintenance and operating strategies, primarily at the refinery front end. The ‘front end’ typically takes into account the plant’s tank farm, desalter and CDU.
Emulsions that begin at the tank farm lead to emulsion excursions in the desalter. According to Baker Hughes’ Larry Kremer, Technology Advisor, “A higher dose of emulsion breaker may be needed to resolve a desalter emulsion excursion.” If these types of upsets in the desalter are not dealt with, they can impact key conversion units further downstream in the refinery, such as the FCC unit, where iron (Fe) content can contaminate/deactivate high value FCC unit catalyst.
Another potential problem with waxy shale crudes is their high salt content (for example, Na >136 ppm) as compared to some conventional crudes. High salt content therefore leads to significant fouling and corrosion problems in the overheads and high temperature zones of the CDU and downstream distillation systems and linked furnaces (such as the coker furnace) and heat exchangers, predicating further emphasis on optimal desalter operations.
To be sure, the refinery has become the de facto starting point for the introduction of shale hydrocarbons, including tight oils and other shale liquids, into the downstream value chain. The diesel yields and other high value refinery products are the shortest pathway to shale monetisation, but in many other cases seen with the new shale energy market, the refinery is circumvented altogether.
Refining at the wellhead
Simple, low capacity refineries based on a desalter and CDU provide a direct monetisation link between the oil field and fuel markets. The wave of unprecedented drilling activity in the US has created its own energy market, primarily for diesel, justifying in-the-field diesel production, which is one reason why small refineries located in shale fields of the US as well as in remote inland areas of China continue to operate profitably after projections a generation ago pointed to their inevitable closure.
In the commodity driven fuels business, economies of scale give new refineries in the 400 000 bpd to 1.0 million bpd range a competitive edge, making small refineries obsolete, or so it seemed. These small facilities are known as ‘teapots’ because of their size (typically less than 20 000 bpd) and low complexity. More recently, energy companies have upgraded the capacity of these teapots, some of which have been idle for almost 30 years. The upgrades include amine based treating units, hydrogen production, low severity hydrotreating and desulphurisation capacity (for distillate/diesel production). In some cases, these small facilities may include FCC processing and coking capacity.
Before rapid expansion of the shale industry, teapot refineries historically suffered from poor margins due to lower quality product yields, as well as lack of access to crude oil. In the 1980s, steadily declining sources of conventional crude oil led to the closure and eventual dismantling of most teapot refineries. Their utilisation rates hovered at 35% to 40%, much lower than larger and sophisticated Gulf Coast refineries’ utilisation rates of around 85%.
Teapot refineries, with access to shale tight oil and cheap shale gas (for feeding CDU furnaces and preheaters), allow energy companies to operate competitively in isolated geographies. These small facilities typically integrate well with an energy company’s upstream/midstream operations. Some teapots are also linked by pipeline, rail or truck transportation to larger refineries. In fact, some energy companies have linked these teapot facilities to major refining centres along the Gulf Coast. In China, even though Beijing issued decrees to have these facilities shuddered by the end of 2011, they are still in operation today and provide China with close to 16% of the country’s refined fuel products.
Capturing niche opportunities
How did these small refineries suddenly become important? To begin with, US oil production grew by a record 1.136 million bpd in 2013 year to 8.121 million, according to the US Energy Information Administration (EIA), making any efforts to upgrade tight oils and other shale liquids at or near the wellhead profitable due to capacity bottlenecks at larger facilities designed for processing heavier crudes.
Energy companies like Blue Dolphin, Valero Energy, Kinder Morgan and others are trying to capitalise on the biggest oil boom in US history, erecting on-site modular processing and treating units and superfractionators (separating propane and propylene for direct sale to the petrochemical market). US crude (discounted at about $98 per barrel relative to the Brent global benchmark of about $106) has been a boon to US refiners, including the teapots. The top three performers on the S&P 500 Energy Index since the beginning of 2012 are all refining companies: Valero, Marathon Petroleum and Tesoro.
Before 2011, US refineries invested heavily in heavy crude processing capability before most process engineers had even heard of shale crudes, and were schooled in learning how to process heavy crudes, such as Canadian bitumen based crudes, Venezuelan crudes and Arab Heavy crude. Going forward beyond 2014, in order to mitigate this paradigm shift in the smorgasbord of shale crudes (tight oils) now available, energy companies use the teapots to process tight oils separately from the heavier opportunity crudes that are more efficiently processed at larger and more sophisticated refineries.
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