Overcoming the challenges of tight/shale oil refining

The impact tight oil processing can have on a refinery, particularly the considerations that must be given to desalter performance, corrosion and fouling control

Brian Benoit and Jeffrey Zurlo
GE Water & Process Technologies

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Article Summary

Tight or shale oils are considered opportunity crudes because they are typically less expensive than crudes produced by traditional drilling methods. Processing these cheaper crudes offers today’s refiners obvious economic incentives, but they come with their own set of unique challenges. Although tight and shale oils are not technically the same (shale oil is actually a subset of tight oil), for purposes of this discussion the term ‘tight oils’ will be used.

Tight oils have many physical properties in common, but the characteristics that differentiate them from one another are, in many cases, the root cause of a variety of processing challenges.

Figure 1 breaks down about 90% of US oil production over the last six years, as reported by the US Energy Information Association (EIA), and includes major production areas from both conventional and unconventional sources. Tight oils account for much of the growth in US production. This trend is expected to continue for many years, as well as expand globally. The focus of this article will be primarily on tight oils produced from the US Eagle Ford and Bakken fields, two regions with the highest production growth.

The term ‘tight oils’ is derived from the fact that the oil and gas deposits are tightly held within geological formations and are not free flowing, as the rock is very dense and not porous. Horizontal wells are used to greatly increase the well surface area exposed to hydrocarbon-rich deposits, and hydraulic fracturing is used to increase the porosity of the formation and allow the hydrocarbons to flow. Production of tight oils would not be economically viable without these technologies.

The techniques used to extract tight oil supplies often result in the oil containing more production chemicals and increased solids with smaller particle size than conventional crudes. When introduced to the refining process, tight oils can stabilise emulsions in the desalter, increase the potential for system corrosion and fouling, as well as negatively impact waste water treatment.

Common tight oil characteristics:
• Batch to batch variability
• Gravity ranges 20-55°API
• Low sulphur levels, but H2S can be an issue
• Low levels of nitrogen
• High paraffin content
• Heavy metals (Ni & V) are low
• Level of alkaline metals may be high
• Other contaminants (Ba, Pb) may be present
• Filterable solids: greater volume and smaller particle size
• Production chemicals or contaminants.

Eagle Ford and Bakken characteristics
As previously noted, this discussion is primarily focused on Eagle Ford and Bakken crudes, highlighting characteristics they have in common, as well as those that make them unique.

Tight oil characteristics can vary greatly from batch to batch, even within the same type of crude oil supply. For example, Figure 2 is a photo of crude oil samples that were all sold as Eagle Ford crude. In addition, the range of API gravity for tight oils can be quite wide, from 20-55°, with most at 40° gravity and above.

Tight oil crudes, in general, have low nitrogen and high paraffin content. Heavy metals, such as nickel and vanadium, are generally low, but alkaline metals (calcium, sodium and magnesium) may be high. This is highly variable as well. In addition, other contaminants such as barium and lead may be elevated. Filterable solids can be higher than conventional crude oils, with greater volume and smaller particle size.

Select samples of Bakken crude have contained salt concentrations as high as 500 ppm, as well as non-extractable salts. Some samples of Eagle Ford crude have been shown to contain olefins or carbonyls – both fouling precursors that are not typically found in virgin crude oils. As a consequence of these dramatic variations in quality and physical properties, it is increasingly more important for refiners to be able to identify, interpret and respond quickly to changes in crude feed properties.

In general, today’s refiner is continually adapting to increasing variability in crude oil quality. Combine this with the blending of tight oils into the standard crude slate, and normal refinery operations can be difficult to maintain. Processing these difficult blends can have a significant negative impact on overall profitability, affecting product quality, unit reliability and on-stream time. Determining how a new crude oil fits into a refinery operation requires a comprehensive understanding of the physical properties and unique characteristics of that crude and how it will interact with the rest of the typical crude slate.

Figure 3 highlights tight oil distillation cuts compared to several common North American crudes. 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, this can be a negative and limit the amount of tight oil that can be added to the crude blend. In order to balance the mix of products in the crude distillation tower to fit many refinery operations, blending tight oils with heavy asphaltic crude makes sense, as the blend can result in a desirable distillation profile for many refiners. However, this practice can also lead to compatibility issues.

Compatibility tests
Although asphaltene stability has always played a role in crude blending, the high paraffin content of tight oils greatly increases the potential impact of asphaltene precipitation upon blending, and its negative impact on the refinery process. There are several established and developing test methods that can evaluate an oil, or a blend, for asphaltene stability.

The photos in Figure 4 show the progression (from left to right) of a compatibility test performed on incompatible blends of oils that generate agglomerated asphaltenes. The initial mixing of the oils produces a homogeneous mixture. Over time, asphaltenes start to agglomerate such that they form a separate detectable phase in the fluid. Finally, significant agglomeration has occurred and asphaltene particulates are forming larger particles. These precipitated asphaltenes contribute to fouling and can also stabilise desalter emulsions.

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