Technology for Producing Petrochemical Feedstock from Heavy

Ind. Eng. Chem. Res. 2010, 49, 953–963

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Technology for Producing Petrochemical Feedstock from Heavy Aromatic Oil Fractions Vasily Simanzhenkov,* Michael C. Oballa, and Grace Kim NOVA Chemicals Research and Technology Centre, 2928 - 16 Street N.E., Calgary, Alberta, Canada, T2E 7K7

NOVA Chemicals’ olefins and polyolefins business in Alberta is primarily based on ethane as feed. Historically, Alberta’s competitive advantage in the petrochemical industry has been the plentiful supplies of low cost natural gas and associated ethane feedstock. The growing production of oil from oil sands and the accompanying heavy oil fraction presents a new opportunity for growth and feedstock diversification in the petrochemical industry, provided that these heavy oils can be transformed economically into feed to petrochemical plants. With an estimated quantity of approximately 2.5 trillion barrels of bitumen in the ground, the Alberta oil sands are one of Canada’s major energy resources. At present, this enormous quantity translates into as much as 173 billion barrels of economically viable oil, second only in size to Saudi Arabia. Thus oil sands are a significant hydrocarbon source not only for Canada, but also for the world. Over the past number of years NOVA Chemicals has systematically studied catalytic technologies that can be used to convert heavy oil sands derived fractions into olefins, aromatics-rich products, and other high demand petrochemicals. Work was carried out in collaboration with external academic institutions and with the support of the Alberta government focusing on selection and development of specialized catalysts and process technologies. The work has resulted in the development of two novel, breakthrough processes and a number of catalysts, which not only allow significant feedstock flexibility to the petrochemicals producer but also considerably decrease the amount of emissions produced and energy consumed per ton of produced high demand petrochemicals due to application of catalysis. This paper presents the process configuration and research results from studies undertaken and shows that it is feasible to produce petrochemical feedstock or basic petrochemicals from heavy oil fractions derived from oil sands at competitive costs via two different catalytic processes. Examples of experimental results of catalysts testing are presented for both processes. 1. Introduction NOVA Chemicals’ olefins and polyolefins business in Alberta is primarily based on ethane as feed. Historically, Alberta’s competitive advantage in the petrochemical industry has been the plentiful supplies of low cost natural gas and associated ethane feedstock. Growing production of oil from oil sands and the accompanying heavy oil fraction presents a new opportunity for growth and feedstock diversification in the petrochemical industry, provided that these heavy oils can be transformed economically into feed to petrochemical plants. With an estimated quantity of approximately 2.5 trillion barrels of bitumen in the ground, the Alberta oil sands are one of Canada’s major energy resources. Most of the oil sands in Canada are located in three major deposits: the AthabascaWabasca oil sands of north northeastern Alberta, the Cold Lake deposits of east northeastern Alberta, and the Peace River deposits of northwestern Alberta. Oil sands are mined to extract the oil-like bitumen, which is then converted into synthetic crude oil or refined directly into petroleum products by specialized refineries. The current cost of production of bitumen from oil sands is about $28/bbl.1 Bitumen from oil sands production is now at around 1 million bbl/day.2 Today’s modern petrochemical plants and oil refineries can process hydrocarbon feedstocks from conventional light and heavy crude oils in the following three technically advanced facilities to make substantial volumes of basic petrochemicals as long as the feeds are largely paraffinic. * To whom correspondence should be addressed. E-mail: [email protected].

1. Steam crackers for ethylene or ethylene and propylene or ethylene, propylene, and benzene depending upon the type of feed used. 2. Catalytic crackers for propylene or ethylene and propylene depending upon the specific properties of the catalyst used. 3. Catalytic reformers for benzene. The above processes are mature for which proven technologies are available for purchase. In contrast, the same facilities can produce only inadequate volumes of petrochemicals when the hydrocarbon feedstocks are derived from nonconventional sources such as oil sands bitumen. Most of the reduction arises because these hydrocarbon feeds are largely aromatic rather than largely paraffinic. Proven technologies for processing these feedstocks into petrochemicals are not available for purchase. There is a strong technical and economic incentive therefore to find new low-cost production of petrochemicals from hydrocarbon feedstocks derived from nonconventional sources such as oil sands bitumen. Accordingly, NOVA Chemicals has undertaken a project partly sponsored by the Alberta Energy Research Institute (AERI) in the area of processing of heavy oil fractions from oil sands bitumen to petrochemical feedstock. In the framework of the project, NOVA Chemicals has developed two catalytic technologies: (1) NOVA heavy oil cracking (NHC) technology, which converts heavy bitumen-derived gas oil into olefins, gasoline, and cycle oils (aromatics rich diesel fraction); (2) aromatic ring-opening (ARO) technology, which converts low value cycle oils into valuable petrochemical feedstock containing mainly light paraffins and benzene, toluene, and xylenes (BTX). NHC is a fluid catalytic cracking (FCC) type process, whereby, ARO is carried out in a trickle bed reactor. As a result, both NHC and ARO are based on mature industrial process platforms.

10.1021/ie900609d  2010 American Chemical Society Published on Web 09/17/2009

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Ind. Eng. Chem. Res., Vol. 49, No. 3, 2010

Figure 1. Integration of oil sands upgrader with a petrochemicals plant and the NHC and ARO units.

This paper provides an overview of a process scheme that integrates the NHC and ARO processing units with an oil sands bitumen upgrader and a steam cracker. Next it reviews briefly some examples of state-of-the-art methods for converting largely paraffinic hydrocarbons from conventional sources to light olefins both by steam cracking and catalytic cracking. Finally, it provides information about the NHC and ARO technologies followed by a conclusion. 2. Process Scheme A few process schemes were considered in the development of business cases before arriving at the preferred scheme reported in this paper. This flow scheme has an oil sands bitumen upgrader, with a NOVA heavy oil cracking (NHC) unit plus an aromatic ring-opening (ARO) unit and an ethylene plant. Figure 1 shows an integration of an oil sands upgrader with a petrochemicals plant and the NHC and ARO units. Whereby, an oil sands upgrader is defined as a bitumen upgrading plant, which can include both atmospheric and vacuum distillation of diluted bitumen as well as thermal and catalytic upgrading units. In Figure 1, bitumen is distilled in an atmospheric distillation unit (ADU) and the distillates are sent to the hydrotreating units (HTU). The atmospheric residue enters the vacuum distillation unit (VDU), where heavy gas oil is produced and the bottoms are sent into an asphaltene separation unit or an alternative vacuum bottoms processing unit. Ethane, ethylene, propane, and propylene from the oil sands upgrader off gases are collected and passed to the separation section of the ethylene plant for processing. Separated ethane and propane are recycled to the heaters (furnaces) of the steam crackers for cracking into

ethylene and propylene, respectively. Heavy oils that have been hydrotreated in the upgrading section are passed on to the NHC unit to produce light olefins, gasoline, cycle oils, and slurry. In this new process, the gas streams from both the NHC unit as well as the upgrader unit containing significant amounts of olefins such as ethylene and propylene are combined. The olefins are separated from the paraffins, and the paraffins are used as feed to the steam cracker. The ethylene plant’s backend separation unit therefore is sized to accommodate this function, and the ethane and propane separated from the ethylene unit are recycled back to the cracking furnace to produce the desired products. The advantage of this scheme is that it combines the gas separation unit in the upgrader with the ethylene back end separation unit, which would result in capital cost savings for the oil sands upgrader. In the ethylene plant, some amounts of olefins already produced from the NHC unit would result in a reduction in the total number of cracking furnaces required in the ethylene plant. Therefore, the total number of cracking furnaces required could turn out to be only half of the number of cracking furnaces that would have been required for a similar capacity stand-alone ethylene unit. This results not only in significant capital savings but also in significant reduction of CO2 emissions per pound of produced ethylene in a cracking reactor. Hydrogen produced from the ethylene plant would be used as feed supplement to the upgrader and/or to ARO unit. Our estimates show that a new hydrogen plant constructed in the upgrader unit would be significantly smaller in size. The cycle oils from the NHC unit are transferred to the new ARO unit. This unit converts the aromatic compounds, (mainly


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Figure 2. Simplified block flow diagram of a steam cracking unit.

two and three ring aromatic compounds) in the C5+ stream from the ethylene unit as well as those in the cycle oil from the NHC unit into paraffins such as ethane, propane, and butane. These paraffins can be used as feedstock for the ethylene plant. As a result, the availability of feedstock for olefins production in an ethylene plant is higher with an ARO unit. 3. Steam Cracking Steam cracking of largely paraffinic hydrocarbon feedstocks from conventional sources provides virtually all of the world’s supply of ethylene and 1,3-butadiene along with substantial volumes of propylene, mixed butylenes, and BTX. Steam cracking is the most energy consuming process in the chemical industry, accounting for about 180 million metric tons per annum (mtpa) of CO2 emissions worldwide.4 The energy cost is estimated at about 70% of production costs in a typical ethane or naphtha based olefin plant. The scale of a plant for ethylene production is huge. The typical size of a world scale ethylene plant is 1-1.5 mtpa. The incentive to build such a big plant is the economy of scale, resulting in the reduction of capital investment and production cost per pound of ethylene produced. The steam cracking method of producing olefins, especially for those who are not familiar with it, is shown below as Figure 2 in the form of a simplified flow diagram. This diagram is self-explanatory. NOVA Chemicals has steam crackers that are based on ethane cracking, with an annual ethylene production capacity of 2.8 million tons/y, plus an additional 0.84 million tons/y from liquid petroleum gas (LPG), naphtha, and gas oil cracking for a total of 3.64 million tons/y, placing it as the fourth largest ethylene producer in North America. The yield of ethylene in these crackers depends mainly on the feedstock used and the operating conditions. A typical yield pattern of steam crackers in relation to the feed used as adapted from Wittcoff and Reuben5 is shown in Table 1. 4. Fluid Catalytic Cracking Technologies for Bitumen and Heavy Oils Upgrading Fluid catalytic cracking (FCC) is a basic process used in the refining industry for converting heavy fuel oil distillates into more valuable lighter components, notably motor gasoline. The first FCC unit was built by Standard Oil Company of New Jersey (Esso) in 1941. The FCC process has continued to evolve, and

Table 1. Conventional Feeds for Steam Cracking: Dependence of Yields on Feedstock prod (wt %) feed

ethylene

propylene

butadiene

BTX

others

ethane propane butane light naphtha full range naphtha gas oil

82.3 43.7 42.2 29.3 25.0 25.2

1.8 21.2 14.6 14.4 12.8 8.3

2.6 4.1 3.9 4.0 4.5 4.8

0.7 4.8 4.8 13.8 11.3 11.2

12.6 26.2 34.5 38.5 44.2 46.6

its efficiency has greatly improved as a result of many technical innovations and the development of more active catalysts. Of particular importance was the introduction of zeolite catalysts in the late 1960s, which greatly increased the conversion to gasoline. Fluid catalytic cracking of largely paraffinic hydrocarbon feedstocks from conventional sources in oil refineries provides about 35% of the world’s supply of propylene. The proportion of the catalytic cracked feed in the form of propylene however is of the order of 5-9 vol %. Numerous methods are now being employed or investigated for maximizing the yield of propylene or ethylene and propylene by catalytic cracking. Two of these are deep catalytic cracking (DCC) and the catalytic pyrolysis process (CPP) developed by the Research Institute for Petroleum Processing (RIPP) of SINOPEC, Beijing, China.6-9 Deep Catalytic Cracking (DCC). In China, the demand for light olefins, for use as petrochemical feedstock, is rising at a faster rate than the demand for gasoline. As a result, RIPP of SINOPEC, Beijing, China, started a series of studies to develop FCC based technologies for the production of light olefins from heavy largely paraffinic hydrocarbons. Many of these developments have been commercialized. The key to them lies in modifications to different zeolite catalyst formulations coupled with innovations in the FCC hardware and some small changes in the operating parameters. Most widely known among these developments is the DCC process. The DCC process was designed for maximum production of propylene and butylenes.6 The difference between the DCC process and steam cracking is that catalytic reactions predominate in DCC, while thermal reactions predominate in steam cracking. The DCC process scheme is similar to that of a conventional FCC unit, consisting of the heat-up, reaction/catalyst regeneration, fractionation, and gas concentration sections. In comparison with the conventional FCC unit, DCC operates at a higher

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Table 2. Typical Operating Parameters for a DCC Unit7

res. time (sec.) cat/oil (w/w) steam (wt % of feed) rx. temperature (°C) pressure (psig)

DCC

FCC

SC

10-16 9-15 10-30 549-593 10-20

1-30 5-10 1-10 510-549 15-30

0.1-0.2 30-80 760-871 15

reaction temperature, a lower pressure, and a longer residence time with more steam injection. In the DCC process, the primary cracking reaction of heavy hydrocarbons proceeds on the acidic surface of the catalyst via carbenium ion intermediates to produce the primary products. The unstable gasoline range fractions of the primary products undergo substantial secondary reactions in the pores of the shape selective zeolites to produce light olefins. The DCC catalyst was designed to have the following characteristics: high bottom cracking activity, high secondary cracking ability, high olefin selectivity, low hydrogen transfer activity, and excellent thermal and hydrothermal stability. These characteristics were obtained by using a modified zeolite of pentasil structure developed by RIPP. DCC can be operated in maximum propylene mode or maximum iso-olefin mode with some propylene and considerable amounts of naphtha by regulating the operating conditions and catalyst formulations. The typical operating parameters for a DCC unit in comparison with a normal FCC and steam cracking (SC) units are shown in Table 2. Catalytic Pyrolysis Process (CPP). On the basis of an in depth study of both the DCC process and associated technologies, RIPP also developed the CPP process for producing maximum ethylene and propylene at different operating conditions. Some papers8,9 have discussed this process in great detail, and a summary follows. Without a catalyst, hydrocarbons crack according to the free radical mechanism. The free radicals then participate in a series of reactions. The primary free radical decomposes at the beta position to form ethylene. The newly generated free radical continues to decompose at the beta position into a smaller free radical, until the formation of methyl free radicals, which can then obtain a hydrogen atom from paraffin molecules to form methane. The secondary free radical decomposes at the beta position to produce alpha olefin and a primary free radical. Therefore, the hydrocarbon molecule can break up through pyrolysis into many ethylene molecules along with some alpha olefins, propylene, and methane molecules. Other reactions involving olefins and cycloparaffins also take place, such as cyclization, disproportionation, dehydrogenation, and aromatization. In the presence of acidic catalysts, the decomposition of hydrocarbons follows the carbenium ion mechanism. The stability of the carbenium ions decreases in the following order: tertiary > secondary > primary. This trend is much more pronounced than for free radicals, and most of the carbenium ions therefore will be secondary and tertiary with the result that only small amounts of ethylene are formed. The primary and secondary carbenium ions formed can be easily rearranged to form iso-paraffins (through a hydrogen transfer reaction) and iso-olefins (through a hydrogen ion abstraction reaction). The carbenium ions can also be cleaved at the beta position of C+ to form an olefin and a smaller carbenium ion. The smaller carbenium ion continues to break up until either C3H7+ or C4H9+ is formed. The latter are then further transformed into either propylene or iso-butene (through the loss of hydrogen ions) or propane and isobutane (through a hydrogen transfer reaction). For petroleum distillates, the cracking reactions consist of a

series of complicated concurrent reactions, and the primary reaction products can still be involved in the secondary reactions, such as rearrangement, hydrogen transfer, dehydrocyclization (to form cyclo-olefin or aromatics), and dehydrogenation to form dienes and other compounds. Among these reactions, the hydrogen transfer reaction is the most important and should be avoided, especially if one desires to produce ethylene and propylene, because it consumes olefin. As just discussed, traditional catalytic cracking is a carbenium ion reaction rather than a free radical reaction as in steam cracking. Both carbenium ions and free radicals resemble each other since they are trivalent reactive species in which two electrons are missing in the former and one in the latter. Moreover the cracking mechanism involving initiation, propagation and termination is formally similar for both. But the two reactions produce significantly different products. In Table 3, the fundamental reasons are summarized. In brief they relate to the relative stabilities of free radicals and carbenium ions. The CPP process produces significant amounts of both ethylene and propylene indicating that both the free radical reaction and the carbenium ion reaction are involved. Greater yields of ethylene and propylene are obtained on a modified H-ZSM-5 zeolite catalyst compared to ultra stable Y (USY) and rare earth ions exchanged Y (REY) zeolite catalysts, since the modified H-ZSM-5 catalyst increases ethylene yield. A higher temperature is favorable to free radical reactions and ethylene and propylene production, and changing the reaction temperature can alter the ratio of ethylene and propylene in the product stream. Increasing the steam to oil ratio produces less coke and more of ethylene and propylene. Lowering the catalyst to oil ratio is favorable to the production of ethylene. The CPP catalyst shows promising performance, such as high bottoms cracking activity, high ethylene and propylene selectivity, good metal tolerance, etc. The CPP catalyst and technology open up a new route for producing light olefins from heavy, largely paraffinic feedstocks. In Table 4 is a comparison of CPP versus steam cracking in terms of yields. The CPP process achieved higher propylene yield and modest ethylene yield even at a much lower reaction temperature. Others are developing or have developed FCC type technologies for cracking heavy, largely paraffinic feedstocks into light paraffins. An example is universal oil product’s (UOP’s) “PetroFCC Unit”. PetroFCC increases olefins while reducing fuel yields. Yields strongly depend on feed and catalyst type. It was published in Japan Chemical Week10 that catalytic cracking for the production of olefins is going to increase in Japan. This will enable them to compete because the competitiveness of their naphtha cracking process is falling amid production increases of ethylene derivatives in the Middle East. Ethane, propane, and butane derived from cheap natural gas are used as feed in this region. Nippon Oil for example is conducting pilot plant tests at its central technical research laboratories to enable commercialization of a high severity fluid catalytic cracking (HS-FCC) process which is being developed jointly with Saudi Aramco of Saudi Arabia. This technology is said to raise the yield of propylene from 5% in a conventional FCC unit to 25%. Asahi Kasei Chemicals has started production of ethylene and propylene in its Mizushima plant in Japan using its proprietary Omega Process. This process, using C4 and C5 raffinates from petrochemical refineries, produces propylene and ethylene at ratios of 4 to 1. All of the above emphasize the emerging importance of FCC technology as a platform for production of olefins, specifically ethylene and propylene.


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Table 3. Behavior of Free Radicals and Carbenium Ion during Hydrocarbon Cracking

rearrangement and fragmentation dominant process tertiary free radicals and carbenium ions more stable than secondary, which are more stable than primary

free radicals

carbenium ions

rearrange and fragment at roughly similar rates fragmentation quite small differences in relative stabilities

rearrange much more rapidly than they fragment rearrangement to branched-chain compounds very large differences in relative stabilities

Table 4. Yields from a CPP Unit versus Steam Cracking (SC)10 process

steam cracking

steam cracking

CPP

feedstock reaction temperature (°C)

AGO atmospheric gas oil 800

LVGO light vacuum gas oil 800

AR atmospheric residuum 640

ethylene acetylene propylene butadiene benzene toluene C8 aromatics

26.60 0.20 13.75 4.39 5.46 3.25 1.93

product yields (wt %) 23.00 0.20 14.50 4.65 5.12 3.46 2.07

20.37 0.002 18.23 0.40 2.05 3.02 2.43

Table 5. Feedstocks Used for Different Catalytic Processes to Convert Petroleum Fractions into Petrochemical Feed feedstock nature

olefinic

paraffinic

naphthenic/aromatic

conventional crude derived light fractions conventional crude derived heavy fractions

Superflex

ACO HS-FCC CPP DCC PetroFCC IndMax

MILOS Maxofin HS-FCC NExCCTM high olefins FCC CPP DCC PetroFCC IndMax PetroRiser high olefins FCC IndMax NHC

conventional crude derived residuum oil sands derived heavy fractions

5. Catalytic Cracking of Hydrocarbon Feedstocks from Oil Sands Bitumen: The NHC Process It will be noted that the DDC, CPP, and other similar technically advanced facilities can produce only inadequate volumes of light olefins when hydrocarbon feedstocks derived from nonconventional sources such as oil sands bitumen are used in place of those from conventional sources. The reduction arises from the high aromatic content of the former. In contrast, the NHC technology starts with heavy, largely aromatic oil fractions, such as vacuum gas oil derived from oil sands bitumen, as feedstock. The process entails FCC technology, which is proven, with a new riser and a specially designed catalyst. The DCC and CPP technologies just summarized are similar but crack atmospheric or vacuum gas oils from largely paraffinic crude oils. The NHC project development has been focused on developing catalysts for cracking largely naphthenic/ aromatic gas oils from oil sands bitumen in well established FCC platforms. Table 5 summarizes some examples of catalytic processes now being used to convert hydrocarbon streams of different origin into petrochemical feedstocks or intermediates for petrochemicals production. This table is not complete with regards to all the available technologies and feed streams; however, it is a very good representation of industrial research trends in the field of converting petroleum fractions into petrochemical feedstock. One can see from the Table 5 that both NHC and ARO technologies are unique technologies, which allow converting heavy, aromatic oil sands derived fractions into valuable petrochemical feedstock. It can be seen from Table 5 that only three technologies are available for conversion of largely aromatic crude oil fractions

MILOS

aromatic ARINO

NHC ARO

into petrochemical feed or intermediates. These are ARINO, ARO, and NHC. It is important to emphasize the difference between ARINO and ARO technologies. ARINO technology is meant for treatment of highly aromatic, light fractions. This feed contains mainly single ring aromatics. Whereby, ARO technology was developed for heavy feeds, which contain polyring aromatics with up to five aromatic rings. Also the significant difference between the origin of hydrocarbon feed has to be stressed at this point in order to understand uniqueness of both ARO and NHC technologies. Typically, oil sands derived feeds are significantly more aromatic compared to conventional oil derived crude fractions, and they also contain higher amounts of sulfur and nitrogen compared to conventional crude. 5.1. Equipment. The reaction unit for the experiments was a confined fluidized bed reactor system, which had five sectionssthe oil and steam feed systems, the reaction zone, the temperature control system, and the product separation and collection system. For each experiment, a set amount of catalyst was loaded into the reactor with an effective volume of about 580 mL. A set amount of distilled water was pumped into the furnace to produce steam for fluidizing the catalyst. The steam was mixed with the feedstock, which was kept in an oven and fed simultaneously by a feed pump. The mixture was heated to approximately 500 °C in a preheater, and then fed into the reactor. In the reactor, the feed was atomized and contacted with fluidized catalysts to cause catalytic pyrolysis to occur. The reaction product from the reactor was cooled and separated into the liquid and gas products, which were collected respectively. After the reaction, the spent catalyst was removed from the reactor by a vacuum pump.

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Ind. Eng. Chem. Res., Vol. 49, No. 3, 2010 Table 7. NHC versus Steam Cracking Yields of Light Olefins steam cracking catalyst C steam cracking catalyst C feed type temp (°C) ethylene propylene butylenes total light olefins (wt %)

Figure 3. Main chemical reactions happening in the NHC process. Table 6. Effect of Feedstock and Catalyst on NHC Yields of Light Olefins base catalyst catalyst A base catalyst catalyst B feed type temp (°C) ethylene (wt %) propylene (wt %) butylenes (wt %) total light olefins (wt %) a

HAGOa 660 12.3 19.4 9.0 40.7

HAGOa 660 11.7 22.3 12.0 46.0

HVGOb 660 6.9 10.7 5.9 23.5

HVGOb 660 9.2 16.1 9.5 34.8

Heavy atmospheric gas oil. b Heavy vacuum gas oil.

The catalytic reaction product consisted of pyrolysis gas, liquid, and coke. An Agilent 6980 gas chromatograph with Chemstation software was used to determine the volume percentages of pyrolysis gas components, which were converted to mass percentages using the ideal gas equation of state. The pyrolysis liquid was analyzed with a simulated distillation gas chromatograph to obtain the mass percentages of gasoline, diesel, and heavy oil. Coke content on the catalyst was determined using a coke analyzer. 5.2. Experimental Results. The main reactions occurring during the NHC process are shown in Figure 3. The key to the success of the project is the ability to invent and produce catalysts capable of cracking the aforementioned feedstocks preferentially to olefins. The significant difference between high severity FCC type catalysts and conventional FCC catalysts is higher acidity of high severity FCC catalysts. High acidity is typically reached by high content of zeolites in the catalyst. The high content of zeolites in FCC catalysts is known to compromise an important property of the catalyst: attrition rate. This is set to be below 3% for the majority of FCC catalysts. Special additives to the NHC catalyst family allowed us to ensure high catalyst acidity and a very low (less than 2%) attrition rate of the catalyst. Our catalyst program is progressing well, and to date, a number of catalysts have been produced and tested in the laboratory and a technical scale FCC type unit. An extensive experimental program was conducted at eight different temperatures, five WHSV (weight hourly space velocity) points, five catalyst-to-oil weight ratio points, and five steam-to-oil weight ratio points. Other process parameters studied were different catalysts and different feedstocks. Results have been very encouraging. Table 6 shows yields of catalysts A and B compared to yields of a base FCC type catalyst, a technically advanced catalyst for cracking paraffinic gas oils to light olefins. Table 6 shows the yields of light olefins from largely aromatic gas oils when catalysts A and B are used in place of a base FCC catalyst, a technically advanced catalyst developed for cracking largely paraffinic gas oils to light olefins. Both catalyst A and catalyst B surpassed the base FCC catalyst in producing light olefins from the largely aromatic gas oils.

HAGO 18.8 11.6 6.0 36.4

HAGO 660 11.9 24.2 11.7 47.8

HVGO 15.6 11.9 6.0 33.5

HVGO 660 8.9 17.4 8.5 34.8

Table 7 shows the advantage of NHC technology over steam cracking for the production of light olefins. It compares the yields of light olefins from steam cracking and from the NHC process. The catalytic process produced more light olefins in total from heavier, largely aromatic feedstocks although it produced less ethylene than steam cracking. Noncatalytic steam cracking is based on a free radical reaction mechanism favored by higher reaction temperatures. Catalytic cracking is based on the carbenium-ion mechanism, which preferentially produces more propylene than ethylene.8 The results shown in Tables 6 and 7 indicate that new engineered catalyst variations, such as catalysts A, B, and C together with a specially designed FCC unit allow substantial volumes of light olefins to be produced from largely aromatic gas oils derived from oil sands bitumen. Depending upon market conditions, heavy cycle oil (HCO) and light cycle oil (LCO) formed during catalytic cracking in the NHC process can be hydrotreated by the ARO process to transform multiring aromatics to paraffins for feed to a steam cracker. A possibility is that alternate feedstocks for the NHC process could include a wider range of light and heavy gas oils, deasphalted oil, or oil from waste plastics. 6. Hydroprocessing of Cycle Oils from NHC Using ARO Technology Today the refining industry is required to process increasingly heavy feedstocks and refiners have to look for routes to improve economic margins. One of those routes is increasing the processing of middle distillates, such as gas oils (GO) and light cycle oils (LCO), so that the processed products can be blended into various product streams as desired. LCO is one of the streams from the FCC type unit that is normally disposed of as low-value heating oil. It is characterized by a high content of aromatics (>70 wt %) and relatively high amounts of heavy aromatic sulfur compounds and nitrogen compounds (3 and 0.08 wt %, respectively).11 GO may contain more than 50 wt % aromatics as well as relatively high amounts of sulfur and nitrogen (more than 2.5 and 0.08 wt %, respectively). In the ARO process, LCO and GO upgrading may be achieved by a two-step process involving catalytic hydroprocessing, as a first step, followed by ring cleavage of naphthenic structures formed in the first step to produce light paraffins (C1-C4) and a BTX rich stream. In the first step, hydrotreating

Figure 4. Two-step ARO process. Table 8. Heteroatom Reduction in the Product of the First Stage Reactor heteroatoms

feed

product

sulfur [wppm] nitrogen [wppm]

2800 867.1

50 13.6


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Figure 5. Effect of pressure (a and d), temperature (b and e), and LHSV (c and f) on the conversion of aromatic compounds and heteroatom removal during GO hydrotreating.

removes heteroatoms such as sulfur and nitrogen and selectively hydrogenates polyring aromatics with little or no saturation of single ring aromatic compounds. This has been achieved by using a combination of commercial NiMo/alumina and NiW/ alumina based catalysts on staged beds. The selectivity of the saturation of poly ring aromatics is governed by two major factors:

(a) The kinetic factorswhere the hydrogenation reactions of single ring aromatics are very slow compared to the hydrogenation of poly ring aromatics.12 (b) The adsorptive hindrance factorswhere polyring aromatics have higher adsorption strengths on the catalyst active centers compared to single ring aromatics, which makes active catalytic centers less accessible for single ring aromatics.13,14 In the

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Figure 6. Effect of pressure (a), temperature (b), and LHSV (c) on product composition for the ring cleavage step.

Figure 7. Sulfur and nitrogen content effect on the content of unconverted C11+ fraction during the ring cleavage step of the ARO technology.

second step, the naphthenic ring cleavage is affected via a noble metal modified zeolite catalyst. This kind of catalyst has been shown to be effective for naphthenic and aromatic ring cleavage by some authors.15,16 The main reaction occurring at this step is hydrocracking of naphthenic and paraffinic compounds in the feed, resulting in the formation of light paraffins. The side chains of the single ring aromatics and condensed naphthenic rings on single aromatic rings are also hydrocracked during this step, resulting in the formation of light paraffins and C6-C9

aromatics, which is the BTX rich stream. A diagram of the twostep process that we term the ARO process is shown below as Figure 4. Results from research on both steps of the technology as described above are shown in the next sections. The feed is VGO, (which is readily available) derived from Alberta’s Athabasca Oil Sands Upgrader. However, LCO, pyrolysis gasoline, refinery fuel oil or waste plastics oil can be alternate feeds for this process.


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Figure 8. Ring cleavage product composition and conversion over the time on stream.

Figure 9. Content of total hydrocarbons in reactor exhaust gas over regeneration time.

Figure 10. Ring cleavage product composition and conversion over the time on stream after regeneration.

6.1. Experimental Equipment. All the experimental runs were carried out in a laboratory scale fixed bed reactor in the up-flow mode. This type of reactor has been shown to closely represent the behavior of an industrial gas oil hydrotreatment

trickle-bed unit.17 Because the unit contains only one reactor, all the experiments were carried out in such a way that the ring saturation step was carried out first. Thereafter, a zeolite-based noble metal catalyst was reloaded for the second step reaction

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to take place. The catalyst used for the first step was a stacked catalyst bed. The catalyst volume was chosen accordingly to meet the required liquid hourly space velocity (LHSV) for each stage. The runs for both the hydrogenation and the ring cleavage steps showed very good repeatability before the final runs were carried out. To minimize the effect of deactivation of the catalyst, the experimental runs were carried out during the day and the catalyst was regenerated during the night. This allowed catalyst activity to be the same for each of the runs. 6.2. Effect of Process Parameters on the Aromatic Rings Saturation Step. This first stage of the ARO process is the heteroatom removal and ring saturation step. It is a conditioning stage for the next step, which is the ring cleavage step. In particular, poly- and diaromatics are saturated to single ring aromatics. Only a small change of a total amount of aromatics has been observed in the first stage. Sulfur and nitrogen containing compounds in the feed have been reduced to levels that can be tolerated by the noble metal/zeolite catalyst in the next stage. Table 8 below shows that the sulfur level was decreased from 2800 wppm in the original feed to only 50 wppm in the feed to the second stage reactor. The nitrogen level was also considerably reduced. Sulfur level in the feed to the second stage reactor should be kept to below 100 wppm. Thirty runs were carried out in order to study the influence of process parametersspressure, temperature, and liquid hourly space velocity (LHSV)son the hydrogenation of VGO. Some of the results are shown. It can be seen from Figure 5 that higher pressure, higher temperature, and lower LHSV lead to both more extensive aromatics saturation and to higher heteroatom reduction. 6.3. Effect of Process Parameters on the Ring Cleavage Step. An extensive experimental program was carried out to study the influence of process parameters on the ring cleavage step of hydrotreated GO (HTGO). Figure 6 shows the results obtained. It is obvious from Figure 6 that lower pressure, higher temperature, and lower LHSV promote higher production of light paraffins indicating that the desired product composition can be adjusted by changing the process parameters. For example, if a higher yield of BTX is required, changing LHSV from 0.2 to 1 h-1 triples the BTX yield (see Figure 6c)), from 4 to 11 wt %. More detailed information on yields, selectivity, and nature of the ARO catalyst can be obtained from US7,513,988B2.19 Additional runs, under the same experimental conditions, but with different feedstocks were carried out for a period of 100 h each to study the effect of sulfur and nitrogen on product yields of the ring cleavage step. The conditions for these runs were the following: temperature ) 410 °C, pressure ) 900 psig, and LHSV ) 0.5 h-1. These runs were necessary to assess heteroatom poisoning of the noble metal catalysts in the second reactor. Figure 7 shows the unconverted C11+ during 100 h trials with four different feedstocks. The results in Figure 7 show the level of tolerance of the (Pd/zeolite) catalyst to the presence of sulfur and nitrogen in the feed. The feedstock with 200 wppm S and 165 wppm N was successfully converted within the interval studied. However, feedstock with 633 wppm S and 522 wppm N exhibited deactivation after 20 h. No significant deactivation was observed for feedstocks with total heteroatom contents of 130 and 64 wppm. A more rigorous catalyst deactivation study was conducted at 868 h of a long-term run. The gas oil, containing 50 wppm sulfur and 13.64 wppm nitrogen, was used as feedstock for this

run. The catalyst was chosen based on a comparative study of a number of different ring cleavage catalysts, which revealed that the chosen catalyst for the ring cleavage step resulted in the highest yields of light paraffins as well as of BTX. Figure 8 shows a graphic representation of the results of this study. Generally, one can see four main areas in Figure 8: 1. 0-70 h on stream. The catalyst activity increased to the stable level. 2. 70-400 h on stream. The catalyst activity was at its highest level. 3. 400-850 h on stream. The amount of light paraffins was slowly decreasing. However, the total conversion did not change. 4. 850-868 h on stream. Severe and fast deactivation of the catalyst occurred within this time. Changes in process parameters could not compensate for the decreased catalyst activity. The run was interrupted at this point in time, and catalyst regeneration with hydrogen, according to the procedure described in the literature,18 was started. Since the extent of catalyst poisoning was not known, it was decided that it would be reasonable to stop catalyst regeneration and to restart the run at the point in time when the amount of hydrocarbons in the regenerator output gas had reached its minimum. Figure 9 shows the change of amount of hydrocarbons in reactor exhaust gas depended on regeneration time. The regeneration of the catalyst was stopped after 209 h of regeneration. One can see from Figure 9 that no significant changes in the amount of total hydrocarbons in the reactor exhaust gas occurred after 100 h. This means that the catalyst was sufficiently regenerated after 100 h of regeneration. After regeneration of the catalyst was completed, the experimental run was resumed. Figure 10 shows the results of this run and the run on the catalyst with original activity. It is obvious from Figure 10 that despite the fact that the catalyst could not be regenerated completely to its original activity, its activity after the regeneration was still very high and also stable for over 200 h on stream. This work demonstrates that simultaneous production of light paraffins and BTX from highly aromatic gas oil is feasible. 7. Conclusion Technical advances are being made in linking Alberta’s oil sands and petrochemical industries. Some olefins and aromatics byproduct are currently being produced and used as petrochemical feedstocks and intermediates. However, little work has been done to date on using heavy bitumen-derived gas oil as a sustainable alternative, competitively priced feedstock for Alberta’s petrochemical industry. The potential expansions of oil sands production and upgrading capacity create opportunities for phased development of new and improved technologies that can further improve economic returns. This work provides a method for processing largely aromatic oil sands derived bitumen in Alberta to produce basic olefins for the petrochemical industry. No commercially proven technologies are available on the market for converting this feedstock into petrochemicals. Acknowledgment This work is being carried out with the financial support and strategic input from the Alberta Energy Research Institute (AERI) as part of its Hydrocarbon Upgrading Demonstration Program. This program is aimed at developing and demonstrating commercially viable advanced technologies that convert bitumen-derived products into high value products and petro-


chemicals with a reduced environmental footprint. We acknowledge the joint development effort with Alberta Energy Research Institute (AERI) and the intellectual contributions of the University of Stuttgart and China University of Petroleum, together with members of our Research and Technology Centre at NOVA Chemicals who also work on this project. Literature Cited (1) UPI Energy watch report: Oil sands costs up 55%, March 6, 2007. (2) Canadian Association of Petroleum Producers June report: Crude Oil Forecasts, Markets and Pipelines Expansions, 2007. (3) Hou, D.; Wang, X.; Xie Ch., Shi Zh. Studies on the Reaction Mechanism of CPP and the Factors Affecting the Yields of Ethylene and Propylene. China Pet. Process. Petrochem. Technol. 2002, 4, 51. (4) Ren T., Patel M., Blok K., Energy efficiency and innovative emerging technologies for olefin production. European Conference on Energy Efficiency in IPPC-Installations, Vienna, Austria, October 21-22, 2004. (5) Wittcoff, H. A.; Reuben, G. B. Industrial Organic Chemicals; John Wiley & Sons Inc.: New York, 1996, pp 58. (6) Zai-Ting, L.; Fu-Kang, J. Chao-Gang, X.; You-Hao, X. DCC technology and its Commercial Experience. 16th World Petroleum Congress, Calgary, Canada, June 11-15, 2000. (7) Chapin, L.; Zai-Ting, L. Deep Catalytic Cracking for light olefins. Paper at the 5th World Chemical Engineering Congress, San Diego, CA, July 14-18, 1996; paper 4, p 299. (8) Shi, W.; Xie, C.; Huo, Y.; Zhong, X. FCC Family Technology for Producing Light Olefins from Heavy Oils. China Pet. Process. Petrochem. Technol. 2001, 2, 15. (9) Hou, D.; Wang, X.; Xie Ch., Shi Zh. Studies on the Reaction Mechanism of CPP and the Factors affecting the Yields of Ethylene and Propylene. China Pet. Process. Petrochem. Technol. 2002, 4, 51. (10) Catalytic cracking for olefins gaining importance in Japan. Japan Chemical Week, 3/10 Aug 2006, 47 (2378), 8.

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(11) Laredo, G. C.; Leyva, S.; Alvarez, R.; Mares, M. T.; Castillo, J.; Cano, J. L. Nitrogen compounds characterization in atmospheric gas oil and light cycle oil from a blend of Mexican crudes. Fuel 2002, 81, 1341– 1350. (12) Stanislaus, A.; Cooper, B. H. Organic nitrogen compounds in gas oil blends, their hydrotreated products and the importance to hydrotreatment. Catal. ReV-Sci. Eng. 1994, 36/1, 75. (13) Korre, S. C.; Klein, R. J. Polynuclear aromatic hydrocarbons hydrogenation. 1. Experimental reaction pathways and kinetics. Ind. Eng. Chem. Res. 1995, 34, 101. (14) Lylykangas, M. S. Kinetic Modelling of liquid phase hydrogenation reactors. PhD Thesis, Helsinki University of Technology, 2004. (15) Ringelhan, C.; Burgfels, G.; Neumayr, J. G.; Seuffert, W.; Klose, J.; Kurth, V. Conversion of naphthenes into a valuable steamcracker feed using H-ZSM-5 based catalysts. DGMKsTagungsber. 2001, 4, 57. (16) Ringelhan, C.; Burgfels, G.; Neumayr, J. G.; Seuffert, W.; Klose, J.; Kurth, V. Conversion of naphthenes to a high value steamcracker feedstock using H-ZSM-5 based catalysts in the second step of the ARINOprocess. Catal. Today 2004, 97, 277. (17) Myrstad, R.; Rosvoll, J. S.; Grande, K.; Blekkan, E. A. Hydrotreating of gas-oils: A comparison of trickle-bed and upflow fixed bed lab scale reactors. Stud. Surf. Sci. Catal. 1997, 106, 437. (18) Josl, R. Regenerierung desaktivierter Zeolith - Katalysatoren durch Hydrocracken der Koksdeposite. PhD thesis, Institut fu¨r Technische Chemie der Universita¨t Stuttgart, 2005. (19) Oballa, M. C.; Simanzhenkov, V.; Weitkamp, J.; Gläser, R.; Traa, Y.; Demir, F. Aromatic saturation and ring opening process. U. S. Patent 7,513,988, April 7, 2009.

ReceiVed for reView April 16, 2009 ReVised manuscript receiVed August 23, 2009 Accepted August 28, 2009 IE900609D

Technology for Producing Petrochemical Feedstock from Heavy

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