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Latin American shale oil: 
promise or pipedream?

The challenges faced by Latin American refiners in processing fast emerging sources of shale oil in a low price environment.

GE Water & Process Technologies
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Article Summary
As a crude oil importer for over 30 years, the North American refinery market focused on heavy gravity, high sulphur crude oil processing to take advantage of the lower purchase prices and abundant volumes offered on these crude oils. Over the last decade, the proliferation of shale gas and shale oil (also known as tight oil) production in North America has literally changed the region’s refinery landscape – seemingly overnight. Shale gas has reduced the cost of natural gas significantly, and some predict low gas prices will continue through at least 2020.1 Shale oil has very different characteristics to what was considered opportunity or price advantaged crude oils in the past; this relatively new oil is light in gravity, low in sulphur, and contains very little heavy residuum. As a result of developing the production of these raw materials, the US is on the road to energy independence, possibly within the next 5-15 years.2 North American refineries have significantly changed operating conditions, are reconfiguring their equipment, expanding production, and new facilities are being built specifically to handle shale oils. Despite the recent drop in global oil prices, shale oil appears to remain an important part of the North American refinery landscape.

In Latin America, and specifically Argentina, the conditions are ripe for a similar shale revolution. In a 2014 study, the US Energy Information Administration ranked the country as having the third largest technically recoverable shale gas resource in the world, with 11% of the world’s total, and the fourth largest technically recoverable shale oil resource, with 8% of the world’s total.3 In addition, Venezuela has the seventh largest technically recoverable shale oil resource, with 4% of the world’s total.4 Geologically, the shale formations discovered in Argentina’s Neuquén province have been deemed an excellent thickness and pressure for favourable oil and gas production, using the one-two punch of horizontal drilling and hydraulic fracturing.5 Much of the shale play resides in the area of the province known as Vaca Muerta. The terrain of this region is fairly flat, which helps optimise well pad placement and simplify equipment movements. The province also has a relatively low water-stress level – key for the large quantities of water needed to conduct hydraulic fracturing. Since the Neuquén province already has significant conventional hydrocarbon production, there is an established gathering and transportation infrastructure in place, which gives this region an advantage over what the North American shale plays had at the start of ramping up shale production.

Argentina is one of only four countries in the world so far to produce commercial quantities of shale oil or gas – the others are the United States, Canada, and China – and Argentina is the only shale producer in Latin America (see Figure 1).6 Several joint ventures between Argentina’s national oil company, YPF, and international producers have been ramping up production. Also, the introduction of newer technologies is reducing the cost of drilling and producing from shale oil and gas reserves. From the author’s experience, a number of Argentina refineries are already processing some level of tight oil produced in the country, or are considering what changes may be needed in their operations to start processing this local resource. Indications are that Latin American shale oil and gas production shows more promise than pipe dream, assuming that it can weather the current low-price oil environment.

With a low density, low sulphur, and lack of a large residuum cut, shale oil certainly breaks the mould of historic characteristics of opportunity crude oils. Normal refinery operations can be difficult to maintain in the face of today’s refining environment of increasing crude oil variability combined with the blending of shale oils into the standard crude slate. Processing these potentially problematic blends can have a significant negative impact on overall profitability, affecting product quality, unit reliability, and on-stream time. Some aspects of refining have not changed, such as determining how a new crude oil fits into a refinery operation by acquiring comprehensive understanding of the physical properties and unique characteristics of that crude and how it will interact with the rest of the crude oils in the refinery crude diet. Today’s environment does, however, make obtaining this knowledge quickly and efficiently more important than ever to be able to adapt to changing conditions. Several companies have developed, or are working to develop, more rapid evaluation methods that improve upon analytic models to help understand the impacts of adding a particular crude oil to a refinery blend before the blend is processed at the plant, moving from experience based reaction to prediction of potential challenges.

Using the learning experiences of North America and Argentina, which are processing shale oil, the main approaches to processing additional shale oil crudes successfully can be described in a few points. Those approaches include:
• Enabling better blending strategies to identify and respond to compatibility issues
• Defining new operating envelopes for unit operations and challenging the markets to test production volume changes
• Adopting different treatment approaches – from tank farms to waste treatment – since the traditional chemical treatment approach does not always work with this new crude, so a paradigm shift is often required
• Identifying capital expenditures needed to remove the bottlenecks of bringing shale oils into the refinery crude oil diet.

Blending and compatibility

Figure 2 highlights the distillation cuts of several types of crude oil: Argentina shale oil, the US shale oils, and several conventional crude oils. For the shale oils (two left bars), note that residuum production is low, compared to high volumes of gasoline and distillates. For refineries that are configured for bottom of the barrel upgrading (such as the typical US and Latin American refinery), this can actually be a limiting factor for the quantity of shale oil that can be added to the crude blend. Blending shale oils with heavy asphaltenic crudes makes sense to balance the mix of products produced from the crude distillation tower since the resultant blend can produce a desirable distillation profile for many refiners based on their current configuration and product mix. However, this practice is likely to produce blend compatibility issues that can negatively affect refinery operations.

Although asphaltene stability has always played a role in crude blending, the high paraffin content of shale oils greatly increases the potential negative impact on the refinery process from asphaltene agglomeration and precipitation out of the bulk crude oil. To illustrate, Figure 3 shows the saturate and asphaltene component content of several crude oils. While the asphaltene content of commercially produced shale oils is low, the saturated hydrocarbon components are markedly higher than in most other crude oils. As mentioned earlier, the typical refinery configured to process heavier feeds will need to blend shale oils with other, heavier, and likely more asphaltenic crude oils. Since asphaltenes are, by definition, insoluble in paraffinic hydrocarbons, blending shale oils into heavy crudes can often upset the natural stability of the asphaltenes in the blended mixture.

Another method to show the impact a crude oil may have on blending is to use the Asphaltene Phase Separation Index. This is a measure of a crude oil or blend to cause an upset in asphaltene stability when mixed with other crudes. As compared to the other benchmarks shown in Figure 4, it can be seen that the Argentina shale oils analysed are very high on this scale, exceeded only by the US Eagle Ford shale oil.

There are several established and developing test methods that can evaluate an individual crude oil, or a blend of two or more crude oils, for asphaltene stability. The photos in Figure 5 show the progression (from left to right) of a compatibility test performed on an incompatible blend that generates agglomerated asphaltenes. The initial mixing of the oils produces a homogenous mixture (left photo). Over time, asphaltenes start to agglomerate such that they form a separate detectable phase in the fluid (middle photo). Finally, significant agglomeration has occurred and asphaltene particulates are forming larger particles (right photo).
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