Desalter chemical programmes for opportunity crudes
Opportunity crude processing can present many challenges including incompatibility, high calcium and tramp amines.
MIKE DION and PETER PEREZ
SUEZ — Water Technologies & Solutions
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Opportunity crudes can be categorised by their prevalent downstream processing challenges. High calcium-containing crudes such as Doba (Cameroon) and Kraken (North Sea) pose emulsification challenges and downstream fouling potential. High amines in crudes may be due to upstream additives or naturally occurring in the crude oil. Oil shale crudes, such as Bakken (US and Canada), Eagle Ford (US) and Niobrara (US), can be blended with other crudes, which may precipitate asphaltenes, stabilising emulsions that result in oily effluent brine or increase fouling risk in crude unit hot trains and furnaces. This article will describe desalter chemical programmes to mitigate processing challenges from these opportunity crudes and reduce customer carbon footprint.
Incompatible crude blends
Crude oil is a complex mixture of hydrocarbons with varying molecular weights, bond structures, and heteroatom functional groups. Asphaltenes are the most polar fraction in crude oil, typically consisting of aromatic structures with five to seven rings at the core of the asphaltene molecule with peripheral alkane substituents.1 At low concentrations, asphaltenes are predicted to exist as a solution of dispersed molecules but, as concentration increases, they have a strong tendency to self-associate into nanoaggregates. These nanoaggregates can also form bigger clusters that would have limited solubility in crude oil.1 The entire crude mixture, along with temperature and pressure, impacts the solubility of the asphaltenes in solution. Asphaltene precipitation can hinder emulsion resolution in desalters and foul downstream heat exchangers and furnaces.
There are several methods to measure crude compatibility. The colloidal instability index1 (CII) is one such method that uses a measurement of a crude blend’s saturate (S), aromatic (A), asphaltene (As), and paraffin (P) content. This defines as CII = (As + S) / (R + A). When the index is less than 0.7, the crude is deemed incompatible. Above 0.9 is considered compatible, and 0.7 to 0.9 is deemed a region of uncertainty. However, most refinery laboratories do not have the ability to measure SARA. For the few who have the equipment, it still takes a considerable amount of time.
SUEZ — Water Technologies & Solutions has developed CrudePLUS, a model using spectroscopy, measured crude stability, toluene insoluble solids, and toluene soluble solids to predict crude compatibility. The output generated is a relative instability index (RIX — a measure of instability), a crude precipitation index (CPI — a measure of the amount of mass that may precipitate), and a fouling potential index (FPX — tendency to foul downstream heat exchanger and furnaces). An interpretation guide is shown in Figure 1. RIX values between 1.5 and 5.0 have the potential to stabilise desalter emulsions. In less than 30 minutes, with less than 200 ml of sample, the stability and fouling potential of the crude can be measured along with the approximate location of occurrence: the desalter, the hot train preheat, or the crude furnace. Due to differences in unit configurations, the data should be correlated to the actual unit; this takes only about two to three weeks. For instance, a desalter with large residence times and transformers may not have issues until RIX is greater than 2, whereas a smaller vessel or smaller transformers may have stable emulsions with a RIX of 1.5.
The CrudePLUS model can also predict instability and fouling potential from crude names. For new crude oils not previously analysed, predictions are estimated based on data from crudes with similar characteristics. The ability to predict potential processing issues in advance of crude sampling can provide crude purchasers with data to make more informed decisions to enhance refinery profits from opportunity crudes.
Precipitation of asphaltenes when processing incompatible opportunity crude blends may manifest as a growing emulsion band that may eventually result in oil in the effluent brine. Chemical additives can be successfully utilised to disperse asphaltenes in solution when processing incompatible crude blends. For example, a North American refinery was experiencing emulsion issues when processing lower cost Western Canadian crudes. The mix valve pressure drop was reduced to minimise oily effluent brine when the emulsion band would expand to exit the bottom of the desalter vessel. SUEZ’s crude stabiliser was employed to resolve emulsion stability issues from incompatible crude blends. It is ashless, containing no metals or phosphorous. Figure 2 depicts the emulsion height in the vessel before and after the crude stabiliser programme. With mitigation of emulsions from incompatible crude blends, the mix valve was increased to enhance salt and solids removal to reduce overhead corrosion risk and downstream fouling potential. Best practice is to inject the crude stabiliser into the most asphaltenic crude prior to crude blending.
Calcium naphthenate crudes
Some specific opportunity crudes, such as Doba and Kraken, contain calcium naphthenates. The calcium is ionically bonded to an organic molecule with a carboxylic functional group. Under typical desalter operations, ionically bound calcium is not extracted from crude oil. Calcium naphthenate, depending on the number of carbons in the molecule, can be a surfactant which stabilises emulsions in desalters. Calcium carried through the desalter may catalyse fouling or poison catalyst in residual processing.
An acidic effluent brine pH will extract calcium, exchanging a calcium ion with a hydrogen ion. Figure 3 is a conceptual graphic of the exchange mechanism. Typically, a desalter brine’s pH is basic and an acid is required to drive the pH down to extract calcium. Mineral acids such as sulphuric acid are strong and difficult to control a consistent pH. Several organic acids are easier to maintain pH control, such as glycolic, acetic, and citric. Citric acid is contained in orange juice, lemonade, used as a food preservative, and is more environmentally friendly than other types of acids. Due to high calcium concentrations, there is a high calcium scale risk. SUEZ has patented the use of citric acid with a scale inhibitor.
SUEZ’s patented Predator MR series has proven effective in field applications processing calcium naphthenate crudes. One refiner evaluated SUEZ and another specialty chemical supplier when processing Doba crude. The Doba was blended to achieve ~20 ppm calcium in the crude charge. SUEZ treated the first parcel of Doba with an average extraction efficiency of 84%. The competitor treated the second parcel and only achieved 57% removal efficiency while also scaling the effluent brine heat exchanger. The customer shut down the competitive programme and SUEZ treated the remainder of the parcel. The heat exchanger was cleaned prior to the third parcel with 92% extraction efficiency with no scale formation. Figure 4 is a representation of extraction efficiency during the trials.
Crudes with tramp amines
Some opportunity crudes contain amines, either naturally occurring in the crude, as byproducts from the use of an H2S scavenger, or as additives used upstream during production, such as some biocides or corrosion inhibitors. The amines will partition between the bulk oil and water phase in a desalter. Partitioning will depend on several factors including temperature, the structure of the amine, and the salinity of the brine. Small amines such as monoethanolamine (MEA) readily partition to the brine. Amines that remain in crude or are carried over in desalted crude residual water will vaporise in the crude unit fractionator. In the overhead system, amine chloride salts that precipitate before the water condenses increase the risk of corrosion in the overhead system.
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