Hydrotreating challenges and opportunities with tight oil
Tight oil’s contaminant and cold flow challenges require appropriate catalyst treatment systems
BOB LELIVELD and HIROSHI TOSHIMA
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Until the early 1970s, the United States was the largest oil producer at a peak production of 9.6 million b/d. Production steadily declined to under 5 million b/d in 2008. Since 2008, tight oil production has increased from 0.6 to ~2.5 million b/d due to the production of oil from fracturing of shale deposits combined with horizontal drilling technology. This has changed the face of energy production in the
US with production rising to
7.4 million b/d, and the Energy Information Administration predicts it will return to its 1970 record by 2019. Tight oil has improved profitability in the US refining sector and enabled a robust fuels export market.
Tight oil composition is different to that of traditional crudes. In general, tight oil has a higher API gravity, a larger 700°F (diesel and lighter) fraction, more contamination of Fe, Ca, Na and Pb, lower sulphur, and more paraffinic components. Proper understanding of the mechanism of removing each contaminant is key to effective guard bed catalyst system design to protect the unit from early shutdown due to pressure drop build-up or poisoning of the main catalysts.
The paraffinic nature of tight oils can be limiting in meeting the required cold flow properties of the diesel product. Improvement of distillate cold flow properties can be achieved through a dewaxing catalytic solution. Of critical importance is the understanding of dewaxing catalysis and kinetics in concurrence with desulphurisation, denitrogenation and aromatic saturation for meeting all specifications.
In contrast to these challenges, the lighter and less aromatic feed containing less sulphur and nitrogen will enable decreased hydrotreating severity of the unit to make longer cycles possible. Also, the availability of low cost hydrogen creates new opportunities to be exploited for economic gain in distillate hydrotreaters and hydrocrackers. Adding hydrogen to aromatic distillate feedstocks results in a significant increase in liquid volume as well as improved product qualities, cetane in particular.
Tight oil can be defined as liquid hydrocarbons that are obtained by hydraulic fracturing of shale formations (including Bakken Formation and Eagle Ford Formation), leaving behind the heavy, tar-like fraction in the shale deposit. Globally, reserves of tight oil and shale oil are estimated to be 345 billion bbl. The largest estimated reserves are in Russia (75 billion bbl) and the US (58 billion bbl). China, Argentina and Libya are estimated to have reserves of around 30 billion bbl. Venezuela and Mexico have reserves estimated at 13 billion bbl. As Figure 1 shows, tight oil is in a crude classification even lighter than typical light crudes like West Texas Intermediate (WTI).
Typically, half of a crude originating from the Middle East is in the naphtha and distillates boiling ranges. That implies the heavy fraction, 700°F+, is the other half and needs to be converted to lighter boiling range transportation fuels. The additional processing in conversion units like an FCC, coker or hydrocracker adds additional costs. Unconventional crudes can vary widely in distillates content. Tight oil, compared to these other unconventional crudes, will have an even higher fraction of valuable naphtha and distillates boiling range material (see Figure 2).
Tight oil affects the whole refinery
Most refineries can process some tight oil, but there are limits. Co-processing of tight oil has caused issues with crude tanks, desalters and atmospheric distillation. In crude tanks, the paraffinic tight oil is often incompatible with other crudes and waxy deposits can be observed. In desalters, wax can cause stable emulsions, fouling issues and salt carry-over. Impacts on the atmospheric distillation are due to the increased light ends and decreased bottoms yields. Increased light ends to the fractionator can result in flooding of the overhead section. The segregation of asphaltenes in the bottoms section leads to aggregation of those asphaltenes. As a result these will be built up in the hot tubes and tray surfaces. The decreased amount of atmospheric tower bottoms to the vacuum tower can cause low flow and ‘overdesigned’ vacuum tower heater operation issues.
The tight oil feed to the FCC unit leads to higher conversion and lower slurry. The lower slurry yield may result in plugging due to low pumparound rates in the fractionator bottoms section. Higher LPG yield, lower octane gasoline, lower LCO yield and lower delta coke have been observed. The lower delta coke may result in catalyst circulation limits.
In the hydrotreaters and hydrocracker the tight oil feed is easier to process due to the less aromatic lighter feed and its lower concentration of nitrogen and sulphur species. The hydroprocessing units thus operate at lower severities and with lower reaction exotherms, resulting in longer cycle lengths. Increasing the feed rate to the mechanical maximum will slightly reduce the cycle life but is beneficial for overall refinery economics. In addition, hydrogen consumption declines with the lower concentration of aromatics and contaminants.
In the diesel hydrotreater the waxier feed has worse product cold flow properties that might require catalytic dewaxing or blending of cold flow property improvers.
In all hydroprocessing units, the higher concentrations of iron, lead, calcium and sodium require guard bed designs to manage the pressure drop build-up and to protect the main catalysts.
Tight oil contaminants
For proper management of tight oil feed contaminants such as iron, lead, calcium and sodium, Albemarle offers specialised guard bed catalysts and loading designs.
Iron (Fe) is not a catalyst poison per se, but can cause severe operating problems in hydrotreaters. Iron in feed can be in the form of organic compounds (for instance, iron naphthenates) and as Fe particulates. When both types of iron containing compounds are treated by hydrotreating catalysts, the iron is converted to FeS. Unlike other poisons, FeS is too large to penetrate into the internal pore structure of a normal hydrotreating catalyst; it tends to build up on interstitial surfaces and void spaces between hydrotreating catalysts. To make matters worse, FeS is a catalyst for dehydrogenation – an undesired reaction pathway in a hydrotreater. The filling of interstitial voids with both FeS and coke from dehydrogenation reduces the void fraction and causes pressure drop build-up, resulting in short cycles. The inter-particle deposition of FeS and carbon to fill interstitial voids between catalyst particles is illustrated in Figure 4. Albemarle has special guard catalysts for removal of iron in feed to protect against the detrimental effects of this contaminant.
For instance, KetjenGuard (KG) 1, an Fe trapping guard bed catalyst, is able to remove FeS (see Figure 5) and mitigate the fouling problem. The catalyst has been loaded in more than 230 commercial hydrotreaters. KG 9, a new specialty guard bed catalyst for maximum Fe trapping, has more ultra-large pores and enables more than two times higher Fe capacity.
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