October 2016

Process Engineering and Optimization

Remove sulfur and nitrogen from liquid hydrocarbons with absorption process

Adsorption is a well-known and simple separation technique finding application in water treatment, specialty chemicals production, gas separation and removal of trace impurities.

Adsorption is a well-known and simple separation technique finding application in water treatment, specialty chemicals production, gas separation and removal of trace impurities.1–4 Although adsorbents have yet to be broadly adopted in the treatment of refinery liquid hydrocarbon streams, a cursory review of literature reveals that the field is very active. Engineers and scientists have gained remarkable levels of control of the properties of surfaces and interfaces leading to the molecular-level design of new materials. As capacity, adsorption kinetics and selectivity continue to improve, widespread adoption may soon be realized.

In the case where a refiner wants to preserve the aromatic or olefin character of a stream, one promising application of adsorption is the removal or concentration of organo-sulfur or organo-nitrogen compounds. Traditional hydrotreating would saturate olefins and perhaps some aromatic compounds. In the case of zeolites, activated carbons and microporous coordination polymers, these aromatic compounds and olefins tend to compete for adsorption sites, typically leading to a decrease in sulfur (S) compound adsorption capacity. Little information exists on the efficacy of these aromatics and olefins with nitrogen (N2) compounds.5

Fig. 1. Separation process flow scheme.
Fig. 1. Separation process flow scheme.

One company has been working to exploit a molecular feature of its proprietary catalysta that has shown promising results for S and N2 compound separation in a way that does not saturate aromatics and olefins. The catalyst removes S and N2 compounds without the need for hydrogen (H2). Furthermore, with the growing importance of biofuels to the global oil supply, the need for S and N2 removal processes that accommodate a variety of functional groups in oil is clear. Here, the early results of an effort to develop a new separation processb are discussed.

Separation process overview

The proprietary separation process uses two columns for the continuous adsorption processing of contaminated feeds. One column runs in adsorption mode, which removes heteroatom compounds from the liquid hydrocarbon stream. The other operates in regeneration mode, removing the adsorbed heteroatom compounds and regenerating the bed (FIG. 1).

Fig. 2. Breakthrough curves for sulfur adsorption of various feeds using the proprietary desulfurization and upgrading process.
Fig. 2. Breakthrough curves for sulfur adsorption of various feeds using the proprietary desulfurization and upgrading process.

While in adsorption mode, the feed oil flows into the column over the catalyst adsorbent. Heteroatom compounds bind to the adsorbent, and the contaminant-free oil flows out as purified product.

In regeneration mode, oil feed is switched to the fresh column. The spent column is flushed with a solvent to remove residue treated oil, the solvent is recovered and recycled, and the residue oil is recycled back to the operating column. The adsorbed heteroatom compounds are then removed from the spent column by flushing it with a small amount of an inexpensive organic hydroperoxide. The heteroatom-rich stream flushed from the column is then vacuum distilled, and the concentrate is removed from the bottom of the recovery column. The byproducts of the process are an organic alcohol collected overhead and the heteroatom concentrate as column bottoms. Depending on the feed heteroatom content, the enriched concentrate may be burned as fuel, sent to a coker or sent to a fluid catalytic cracking unit (FCCU). As an alternative, the hydrocarbons can be reclaimed using a proprietary desulfurization and upgrading process.c

Desulfurization and upgrading performance

To demonstrate the utility of the proprietary process to remove S from oils without the use of H2, a variety of petroleum oils and intermediates were tested in a plug-flow column. Breakthrough curves (FIG. 2) for four different feeds demonstrate the S-removal capability of the process. TABLE 1 shows the results for the tested feeds. As shown, S compounds can be adsorbed from many different stream types, and the extent of S removal is feed-dependent.

Analysis of the N2 content before and after treatment is shown in TABLE 2. The level of N2 removal in these feeds is unimpressive, with the only exception being the nearly 40% reduction of N2 from dicyclopentadiene (DCPD).

The lack of significant N2 removal results in these feeds was surprising because experience with whole crudes and bitumen using the proprietary process produced 40%–70% N2 removal.

To further investigate this apparent discrepancy, model feeds containing indole, acridine and quinoline were prepared in hexadecane and similarly tested in a plug-flow column at ambient temperature. The model compounds were measured by high-performance liquid chromatography, so detection limits on the basis of elemental N2 were less than 1 ppm. Results are shown in TABLE 3. All of the N2 compounds were completely removed from the model feed through greater than 58 bed volumes. The efficacy for aromatic cyclic N2 compound adsorption appears to be high. Future work will focus on clarifying the generality of N2 compound adsorption by the proprietary separation process.

Separation process economics

Fig. 3. OPEX vs. sulfur removal for various feeds (different sorbent capacities).
Fig. 3. OPEX vs. sulfur removal for various feeds (different sorbent capacities).

Process economic estimates were generated for an 18-Mbpd process treating a 100-ppm feed down to ultra-low-sulfur standards with 40 bed volumes, prior to the required regeneration step. The process equipment includes:

  • Two adsorption columns
  • Standard fractionation column equipment with a feed heat exchanger
  • Pumps.
Fig. 4. Relationship between CAPEX and sulfur removal for various feeds.
Fig. 4. Relationship between CAPEX and sulfur removal for various feeds.

Capital expenditure (CAPEX) is estimated at $3,000,000 (inside battery limits, installed cost), and operational expenditure (OPEX) is estimated at $0.0058/gal (cost of makeups and utilities).

The type of feed being treated influences the economics of the process. Lower S removal and higher sorbent capacity reduce costs, while the opposite conditions raise them. OPEX is more sensitive to S removal than CAPEX and scales almost linearly with it. It is difficult to discern significant differences in OPEX for feeds tested, mainly due to the cost of makeup materials needed to regenerate the sorbent bed.

Conversely, CAPEX shows more sensitivity to changes in sorbent capacity. The sorbent capacity directly influences the size of the fractionation equipment, which is the largest factor for CAPEX. FIGS. 3 and 4 highlight the influence of S removal and sorbent capacity on process economics.

Takeaway

The proprietary separation process provides an alternative for heteroatom removal to meet market needs for feeds where preservation of olefin or aromatic character may be important, or where H2 constraints exist. As the technology continues to mature and additional feeds are treated, improved clarity on which feeds offer the best economic advantages will emerge. HP

NOTE

a The proprietary catalyst is Auterra’s FlexOx.
b The proprietary separation process is Auterra’s FlexULS.
c The proprietary desulfurization and upgrading process Auterra’s FlexUP.

LITERATURE CITED

  1. Worch, E., Adsorption Technology in Water Treatment, Walter de Gruyter, Berlin, Germany, 2012.
  2. Yang, R. T., Adsorbents: Fundamentals and Applications, John Wiley & Sons, Hoboken, New Jersey, 2003.
  3. Wu, L., J. Xiao, Y. Wu, S. Xian, G. Miao, H. Wang and Z. Li, Langmuir, pp. 1080–1088, 2014.
  4. Jia, S. Y., Y. F. Zhang, Y. Liu, F. X. Qin, H. T. Ren and S. H. Wu, Journal of Hazardous Materials, Vol. 262, pp. 589–597, 2013.
  5. Cychosz, K. A., A. G. Wong-Foy and A. J. Matzger, Journal of American Chemical Society, Vol. 131, Iss. 40, 2009.

The Authors

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