Deep catalytic cracking plant produces propylene in Thailand

Jan. 12, 1998
In May 1997, the Thai Petrochemical Industry Public Co. Ltd. (TPI) deep catalytic cracking (DCC) plant in Rayong started producing propylene, exceeding design values. DCC is now a mature, proven technology that can enhance refinery margins and make low-cost propylene available for petrochemicals. Although DCC technology has been practiced in China since 1990 with four commercial units operating in 1997, there was no experience outside China until the TPI unit designed by Stone & Webster
Andrew Fu
Thai Petrochemical Industry Public Co. Ltd.
Rayong, Thailand

David Hunt, Jorge A. Bonilla, Andrew Batachari
Stone & Webster Engineering Corp.

In May 1997, the Thai Petrochemical Industry Public Co. Ltd. (TPI) deep catalytic cracking (DCC) plant in Rayong started producing propylene, exceeding design values.

DCC is now a mature, proven technology that can enhance refinery margins and make low-cost propylene available for petrochemicals.

Although DCC technology has been practiced in China since 1990 with four commercial units operating in 1997, there was no experience outside China until the TPI unit designed by Stone & Webster Engineering Corp. (S&W). Table 1 [9,799 bytes] summarizes DCC commercial applications.

Propylene demand

Currently, the petrochemical industry is experiencing a large increased demand for propylene ( Table 2 [17,026 bytes]), used mainly for the manufacturing of polypropylene products. Demand is expected to increase through the year 2000.

The majority of propylene produced in the U.S. and around the world is obtained from refinery fluid catalytic cracking (FCC) units; the remainder comes from steam cracking (SC) in ethylene plants. Small quantities of propylene are also produced by propane dehydrogenation.

The main product from FCC is gasoline, and the primary product from SC is ethylene. To meet the increasing demand of propylene and yet maintain the ethylene and propylene balance, FCC is the logical choice from which to produce the additional propylene. The FCC also has the advantage of using inexpensive vacuum gas oil (VGO) and heavier feedstocks compared to LPG and naphtha, which are traditional SC feedstocks.

To respond to this challenge, Sinopec International's Research Institute of Petroleum Processing (RIPP) in China, successfully developed a unique catalyst to enhance the FCC olefin yield. The application of the RIPP catalyst to a fluid catalytic cracker is called deep catalytic cracking (DCC), and it is exclusively licensed by S&W outside of China.

The DCC catalyst's yields of olefins, particularly propylene, exceed the levels that can be achieved in traditional FCC units. Table 3 [9,761 bytes] compares DCC and FCC yields. DCC catalyst is available from both U.S. and Chinese suppliers.

ZSM-5 catalyst is becoming a common FCC additive to produce olefins; however, the production of olefins diminishes at higher concentrations (Fig. 1 [31,675 bytes]). Furthermore, while elevated olefin yields are possible with large levels of ZSM-5 additive, such an operation is usually not economically attractive because of the high cost of the ZSM-5 additive.

DCC can increase propylene production and the corresponding refinery margins beyond traditional FCC capabilities. Table 4 [9,803 bytes] shows that the net margins can increase by more than $1/bbl.

DCC technology

DCC uses FCC principles with specific enhancements in order to produce large yields of light olefins and high-octane naphtha. To achieve a high-olefin yield, a high reactor temperature is required. The DCC unit operates at temperatures as high as 570° C., somewhat higher than maximum-olefin FCC and resid FCC operations.

The catalyst developed by RIPP uses a pentasil zeolite that selectively produces propylene, butylene, and a naphtha rich in aromatics.

When the yield slate shifts from a traditional FCC yield distribution to high propylene and other light olefins, an increase in the heat of reaction results. This additional heat must come from additional coke production. Otherwise, the unit heat balance suffers and reaction temperatures cannot be maintained.

DCC design must efficiently produce the additional coke required. To keep the reaction selective, the DCC unit uses a catalyst bed in the reactor. The combination of catalyst, high temperature, and residence time in the reactor promotes catalytic cracking to propylene at the same time that the additional coke is produced. Similarly, decanted oil (DO) may be recycled to produce additional coke.

To minimize hydrogen-transfer reactions, which reduces the olefin yields and increases the saturate hydrocarbon yields (i.e., propylene would become propane), the DCC reactor operates at lower hydrocarbon partial pressure than the FCC reactor. Accordingly, the DCC reactor pressure is slightly lower than the traditional FCC reactor pressure, and the partial pressure is further reduced by injecting steam.

The FCC process is modified to create the DCC process by the synergistic integration of the following elements: catalyst, temperature, reaction-residence time, coke make, and hydrocarbon partial pressure. Fig. 2 [32,838 bytes] shows a process diagram of the DCC reactor and regenerator.

TPI DCC decision

TPI is a major polyolefins producer in Thailand. Before start-up of the DCC unit, TPI was importing propylene to feed the polypropylene plant at Rayong, Thailand. To integrate TPI's facility fully, the DCC process was chosen to produce the required propylene, balancing the ethylene and propylene demand.

The feed to the DCC unit is excess VGO, deasphalted oil (DAO), and other byproducts from TPI's lube base-oil plant and other refinery units. DCC was chosen over FCC, mild hydrocracking, and steam cracking.

S&W arranged financing by the U.S. Export-Import Bank. The project was successfully executed on a fast-track schedule achieving commercial production within 31 months after the contract was awarded. TPI was responsible for construction and employed two main subcontractors and 35 local contractors. Commissioning was carried out by a joint TPI and S&W team led by S&W.

Due to the high sulfur level in TPI's VGO, either the VGO would need to be hydrotreated or the regenerator flue gas would need to be treated to control sulfur emissions. Economic evaluations showed that, although the initial investment was higher, hydrotreating the VGO was the most economic route because of other benefits resulting from the hydroprocessing, such as low sulfur in the products and higher olefins yield from the DCC unit.

TPI DCC units

Fig. 3 [36,716 bytes] shows the process flow scheme in the TPI DCC plant:
  • VGO hydrotreater. The raw VGO is contacted with hydrogen at high pressure, producing a sweet oil with less than 0.15 wt % sulfur and ensuring an environmentally clean operation. The hydrotreated VGO is sent directly to the DCC reactor. Diesel is produced by the cracking reactions and from the LCO recycled back from the DCC fractionator. The VGO hydrotreater uses Chevron/S&W technology.

  • DCC unit. The DCC unit consists of a side-by-side reactor/regenerator arranged as shown in Fig. 2. The process uses riser and bed cracking. S&W's advanced feed injection system is employed near the base of the riser. Riser steam is injected above the feed injection to achieve optimal hydrocarbon partial pressure. DO recycle is injected just above the riser steam nozzles if required. The reactor effluent flows from the reactor to the main fractionator.

    S&W's combustion air ring distributors are employed in the regenerator. An external withdrawal well is used to transfer the regenerated catalyst from the regenerator to the reactor.

  • Main fractionator. The reactor vapors are separated into three fractions in the main fractionator: overhead distillate, light cycle oil (LCO), and DO.

    Overhead distillate, containing the light olefins and naphtha, feeds the light-ends recovery unit.

    LCO is recycled to the VGO hydrotreater to increase cetane before blending into diesel.

    DO is recycled to extinction. Any DO not recycled would be used as low-sulfur fuel oil in the complex.

    Light-ends recovery. The light-ends unit includes diethanolamine (DEA) treating for sulfur removal from the sponge gas and LPG. Caustic treatment is used for mercaptan extraction. Light-ends recovery produces ethylene and lighter material, a C3 cut, a C4 cut, and a full-range of naphtha.

    The gas containing the ethylene and lighter material together contains approximately 5% of the propylene produced.

    The C3 cut contains most of the propylene produced plus the propane. This cut flows to purification and the propane-propylene splitter.

    The C4 cut flows to LPG blending. This stream may be used in the future to produce MTBE. The diolefin level in the C4 cut is low and does not require hydrotreating.

    The full-range naphtha (C5 to 221° C.) flows to the naphtha hydrotreater unit.

    The ethylene-rich stream from the DCC sponge absorber gas is processed in the ethylene recovery unit (ERU) section of the complex. The ERU employs S&W's Advanced Recovery System (ARS) technology and a de-ethanizer tower.

  • Naphtha hydrotreating. The DCC naphtha contains a higher aromatic concentration than FCC naphtha (the research octane number clear and motor octane number clear are also much higher) but also contains olefins and traces of diolefins. To conserve the octane when blending in gasoline, either antioxidants must be added or the naphtha must be selectively hydrotreated to saturate the diolefins. By saturating only diolefins, octane value is conserved.

    TPI decided to hydrotreat the naphtha to ensure high quality gasoline. The DCC units in China do not hydrotreat the DCC naphtha. The naphtha hydrotreater unit includes a single hydrotreating stage using a selective diolefins hydrogenation catalyst. The unit was licensed by the Institut Francais du Petrole (IFP).

  • Propylene purification. Sulfur and mercaptans are removed by DEA and caustic treating of the C3 and C4 LPG cut in the light-ends recovery unit. Other contaminants that need to be removed to meet polymer-grade propylene specification are carbonyl sulfide (COS), arsine, and water. Hydrotreating the C3 cut is not required. The purification processing steps include a contaminant-removal step, a refrigerated de-ethanizer, and a propane/propylene splitter.

  • Ethylene recovery unit. In TPI's case, the amount of ethylene produced is enough to justify its recovery and further processing in TPI's adjacent ethylene plant. The ethylene recovery unit removes remaining contaminants that are not allowed in the ethylene-rich stream: mainly acetylene, oxygen, arsine, traces of COS, and water.

The treated gas is processed into an ethylene-rich stream and fuel gas, containing mainly hydrogen, methane, and ethane. A heavy fraction is produced, containing the propylene losses from the light-ends unit, together with some propane and very small amounts of butane and butylenes. This heavy fraction is recycled to the light-ends unit resulting in essentially 100% propylene recovery.

The gas is processed using S&W's Advanced Recovery System (ARS), including a dephlegmator and expansion/compression.

TPI DCC operation results

Properties of the DCC feed blend (including the hydrotreated VGO and wax) are shown in Table 5 [6,743 bytes]. This feed blend is slightly heavier than that of the original design. Operating conditions at design rates of the DCC are listed in Table 6 [4,604 bytes].

The DCC yield slate reported in Table 7 [8,802 bytes] is the average of three runs carried under stable conditions. Both propylene and naphtha yields exceeded design. Propylene was measured at over 17 wt %. Naphtha yield (C5 to 221° C. true boiling point) was 31.9 wt % or 35.6 vol %. Ethylene was very near design quantities at 5.1 wt %. Both coke and LCO were lower than design values.

The comparison of the commercial light olefins yields to the pilot plant (design-based) work shows an excellent agreement.

The butylene isomer breakdown is shown in Table 8 [4,977 bytes] and approaches equilibrium values. The high yield of isobutylene, 4.8 wt %, could result in future high production rates of MTBE.

When the data were taken, the catalyst inventory contained 80% start-up catalyst (CRP-S), and the VGO hydrotreater was not operating at maximum severity. As the VGO hydrotreater increases in severity and the CRP-1 catalyst (conventional DCC catalyst) is added to the unit, the olefin yield and the olefin-to-paraffin ratio will increase. Recent propylene yields from the TPI DCC unit are approaching 20 wt %.

Properties of the full-range DCC naphtha, prior to selective hydrotreating, are shown in Table 9 [4,023 bytes].

Octane of the DCC naphtha is high as a result of high aromatic content and the conversion of olefins to iso-olefins over the DCC catalyst. While not measured here, the aromatic content of DCC naphtha is nominally 55%. (This percentage will be higher when calculated on a C6+ basis.) The high specific gravity of the naphtha indicates high aromaticity. The diene content and the bromine number of the DCC naphtha were lower than anticipated, considering the high reactor temperatures.

The gravity of the light cycle oil indicates high aromatic content and a high conversion operation. The API gravity was 12.6° API, the sulfur content was 0.64 wt %, and the cetane number was 19.0. All material heavier than LCO was recycled to extinction.

The Authors

Andrew Fu is the complex manager at Thai Petrochemical Industry Public Co. Ltd.'s Rayong refinery. He has more than 20 years of experience in the petrochemical and refining industries. Fu holds a BS degree in chemical engineering from Chun Yung University in Taiwan and an MS degree in management from Chulalongkorn University, Bangkok.
David Hunt is a process engineer for Stone & Webster's process engineering refining division. For the past 7 years, he has been responsible for FCC process designs, yield prediction, and technology enhancement. He was involved with the TPI DCC project from the early proposal stage through start-up. Hunt holds a BS degree from the University of Wyoming and an MS degree from the University of Houston, both in chemical engineering.
Jorge A. Bonilla is a senior vice-president of Stone & Webster Technology Corp., Houston. He is responsible for petroleum processing technologies. Bonilla has 27 years of experience in the petroleum industry and has been responsible for the design of large petroleum refining facilities in Europe, Canada, the U.S., South America, and Thailand. He holds a doctorate in chemical engineering from the University of Paris.
Andrew Batachari is project director at Stone & Webster. He has been in charge of the TPI DCC project. Currently, he resides in Bangkok and is responsible for business development in Southeast Asia. Batachari has been involved in engineering and management of petrochemical, refining, and gas projects during his 25 years at Stone & Webster. He holds an MS degree from Columbia University, New York City.

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