Jerry J. Toman, Robert F. BeckmanFluor Daniel Inc. Irvine, Calif.
Several possible alternate uses for visbreaker equipment are available to refiners who must significantly increase the degree of residue processing to meet future fuel oil sulfur requirements.
In both the U.S. and the European Economic Community (EEC), specifications for the sulfur content of residual fuels will likely be difficult to achieve for refiners who process high-sulfur crudes. Those refiners will have to curtail fuel oil production unless they have a significant fuel oil export market.
To meet the coming specifications, residue streams will have to be either directly desulfurized or partially or totally destroyed in more-severe conversion processes such as coking, fluid-bed hydrocracking, or gasification.
Under this scenario, normal operation of the visbreaker will not serve a useful purpose for the refiner. But revamping the visbreaker furnace and tower-as well as utilizing existing vessels, pumps, heat-exchange equipment, and piping-for alternative uses will require significantly less capital than would building an entirely new facility.
REGULATIONS
Western European refiners collectively operate almost 1.2 million b/d of visbreaker capacity-far greater than the 65,000 b/d operated by U.S. refiners. For this reason, refiners in Western Europe will be much more affected by tightening fuel oil sulfur specs.
A report by Chem Systems Inc. says the amount of unblendable high-sulfur resid could reach 15 million metric tons/year in the region. The report predicts that Western European refiners would be forced to spend about $10 billion to handle the surplus of high-sulfur residue streams resulting from pending legislation (OGJ, Dec. 2, 1991, p. 21).
The study concludes that stricter regulations are likely to all but rule out high-sulfur fuel oil in Western Europe's inland market by 2000. The outlook for bunker fuels is less certain, but the maximum sulfur content could be reduced to 1.5-2% by the end of the decade.
Only five European countries-Denmark, Luxembourg, The Netherlands, Norway, and Sweden-currently have a sulfur specification of 1% or less. By 1995, said Chem Systems, Austria, Finland, Germany, and Switzerland will impose similar limits.
In new, large-combustion plants, EEC rules govern the use of low-sulfur fuel oil and flue gas desulfurization. Reductions in total SO2 emissions as high as 70%, from 1980 levels, will be phased in on a national basis.
The EEC is also studying a proposal from France to reduce the sulfur content of all inland sales in all EEC member countries to 2% by 2000. And the marine environment pollution committee of the International Maritime Organization is considering a 50% reduction in sulfur emissions from shipping by 2000, which would reduce sulfur in bunkers to about 1.5%.
Although it is difficult to predict the rate at which sulfur emissions rules will become tougher, the report estimates that 80-95% of the inland heavy fuel oil market in Western Europe will be low-sulfur by 2000 or shortly thereafter.
ROLE OF VISBREAKER
Because the visbreaker is frequently one of the newer refining units-containing equipment with considerable useful remaining life-alternate uses need to be found for this valuable equipment.
In the past, the visbreaker has been a useful tool to reduce the production volume of residual fuel oil, typically by about 20%. This mild, thermal cracking process decreases the amount of cutter stock needed to meet viscosity specifications for the residual fuel oil pool.
Making the cutter available for higher-value distillate fuels is the main economic benefit derived from the process. But in addition to reducing cutter stock requirements, some small additional benefit may be derived by cracking a small amount of the residue to lighter stocks.
Because very little sulfur is removed from the liquid as a result of visbreaking, the process does not significantly reduce the sulfur content of fuel oil. In some cases, the net result may even be an increase in the sulfur content of heavy fuel oil. This net increase occurs because less low-sulfur cutter stock is required to meet viscosity specifications.
Fluor Daniel Inc. has evaluated a number of possible alternate uses for visbreaker equipment in a refinery where the degree of residue processing must be increased significantly to meet future fuel requirements. The three most likely alternate uses for existing visbreaker equipment are:
- As the fractionation system for a new desulfurization unit
- As a preflash system for light crudes
- As a stand-alone fractionator for heavy, or otherwise unusual, crudes.
From a materials basis, the visbreaker furnace and fractionator have considerable capability to handle relatively high-viscosity, sulfur-bearing compounds at high temperatures. This would be ideal for utilization in a delayed coker application.
Unfortunately, however, the yield structure of a delayed coker is much richer in gas, LPG, and naphtha than that of a visbreaker. This difference means significant derating of the visbreaker column would be required.
Further, in most cases there would be insufficient plot space nearby to accommodate the coke-handling facility and blowdown system. If some space is available, however, the utilization of the high-pressure visbreaker column, as part of a facility to make needle coke, might be a viable option.
Because of its small size, a visbreaker fractionator would be even less well-suited to separate the cracked product from a fluid catalytic cracking (FCC) unit, the principal products of which are in the gasoline and lighter boiling range. Some consideration might be given to using it as an auxiliary unit to unload the main FCC fractionator, if an FCC reactor were to be debottlenecked.
Because of its large size, the visbreaker furnace would be of relatively little use in an FCC preheat application. The materials of construction of a typical visbreaker provide more resistance to corrosive attack than normally would be required for products from a desulfurization unit.
The furnace materials are, however, suitable for a crude preflash application, or to make rough cuts on crude stocks. The process advantages of the preflash application would be to unload an existing crude unit.
Making crude rough cuts would provide the ability to fractionate certain crudes separately, perhaps at a higher severity than would be optimal for other crudes in the mix. Another useful opportunity is where segregation of residua having different sulfur or metals contents might promote optimal refinery operation.
The configuration of a typical visbreaking unit is shown in Fig. 1. Generally, the unit contains a feed-surge drum with feed pump, extensive feed/product heat exchange, and a large furnace, tubed for multiple passes through radiation and convection sections.
It may also contain a soaker drum, where additional reaction occurs before the stream is quenched and introduced into the flash zone of the main fractionator. (In some early designs, this flash zone is actually contained in a separate vessel, referred to as an evaporator, with the overhead flowing to a separate fractionator for naphtha and gas oil recovery.)
Significant heat recovery is possible via exchangers on the recycle quench streams and the main fractionator pumparound. A sidestripper is usually provided to control the flash point of the distillate cut. The overhead system is typical of most distillation units, and it may have a naphtha stabilizer or splitter to produce light and heavy naphtha fractions.
Table 1 gives typical rates of overhead product streams resulting from the visbreaking process in the first column, expressed as a percentage of the visbreaker feed stream. These values correspond to the processing of vacuum residua in the visbreaker under moderately severe conditions.
Somewhere between 6 and 10 vol % of 350 F.-endpoint naphtha is usually produced, together with about 15 vol % of a 650 F.-cutpoint distillate side draw. To meet viscosity specifications, the bottoms-having almost 5 wt % sulfur when a typical Middle Eastern crude mix is used-are generally diluted with as much as 30 vol % cutter stock.
Even if the cutter contained no sulfur, this would not be sufficient to reduce the final sulfur content of the fuel oil to the required levels. And if the visbroken residue were to be flashed into a vacuum tower to recover as much as 20 vol % (on feed) of additional vacuum gas oil for desulfurization, and this were recombined with the residue, fuel oil with less than about 2.5 wt % sulfur could not be produced.
HYDROTREATER FRACTIONATOR
Fig. 2 depicts the integration of the equipment from a visbreaker to form the fractionation section of a new hydrotreating unit.
The equipment shown in purple corresponds to new equipment, whereas existing equipment appears with normal outline.
The surge drum, pump, and existing low-pressure exchangers can be reutilized, but a new high-pressure exchanger and reactor feed pump will be needed. The furnace will have to be retubed with appropriate thickness and metallurgy to handle the higher overall pressures, as well as the high hydrogen and hydrogen sulfide partial pressures.
The reaction section, high and low-pressure separators, and recycle gas-treating systems will also be new. After the low-pressure separator, the liquid can be introduced into the existing visbreaker fractionation section.
In the configuration shown, the soaker drum has been converted into a side-stripper to produce an additional distillate cut. This may not be possible if the number of trays in the existing tower is insufficient.
The soaker could alternatively be used as a vapor/liquid separator or as a stabilizer. The fractionator bottoms would be suitable as residue catalytic cracker feed in the case of an atmospheric resid desulfurization (ARDS) unit, or as FCC feed in the case of a gas oil hydrotreater. The light ends stabilizer and naphtha splitter would function as before.
In Table 1, hydrodesulfurization (HDS) product yield structures are given for process severities ranging from that of a mild vacuum gas oil (VGO) hydrotreater, consuming 500 scf//bbl chemical hydrogen, to that of a deep desulfurizing ARDS unit, consuming 1,000 scf/bbl hydrogen. An intermediate case with a severity corresponding to a mild hydrocracker or coker gas oil hydrotreater (800 scf/bbl) is also included.
For the two cases of greater severity shown in the third and fourth columns, it is evident that their total distillate yields are very similar to that of a visbreaker, although somewhat less naphtha is produced. This is favorable when rating the tower for feed capacity because fewer total moles are produced, which reduces vapor traffic in the upper section of the tower.
The tower may therefore be expected to handle a somewhat greater throughput as an HDS product fractionator than as a visbreaker fractionator, assuming adequate gas oil pumping capacity is available. If adequate capacity is not available, the endpoint of the naphtha can be increased into the kerosine range, creating a product distribution in closer agreement with that of a visbreaker.
To obtain the separate naphtha and kerosine cuts, the overhead stream can be rerun in the existing crude unit or in other distillation equipment that might become available, such as a naphtha splitter. The split can then be adjusted to meet reformulated gasoline trends toward lower endpoints.
In the case of the typical VGO hydrotreater-the yield structure of which is shown in the second column of Table 1-it is evident that the product stream contains significantly less total distillates, especially naphtha. As in the above cases, the total throughput can be increased, and the endpoints of the distillate cuts can be changed to optimize capacity.
CRUDE PREFLASH
In some refineries it may be more economical to simply spike the gas oil feed to the hydrotreater with miscellaneous refinery streams in need of hydrotreating (heavy naphthas, kerosines, slop oils, cycle oils, etc.). This scheme will allow the recovery of those streams in the fractionation section, before the gas oil undergoes further conversion in an FCC unit or hydrocracker.
Other strategies to reduce the production of high-sulfur fuel oil may range from something as simple as the processing of a lighter crude slate, to significant investment in desulfurization and/or conversion capacity, coupled with the processing of a greater volume of an even heavier, higher- sulfur crude slate.
In either case, the use of the visbreaker preheat train, furnace, and fractionator as a preflash system, or as a stand-alone crude unit, would help unload the existing fractionation section. A schematic of this application is shown in Fig. 3.
Note that the visbreaker fractionation section is designed to produce fewer cuts than the typical crude unit. This means that subsequent atmospheric distillation to recover gas oils will be required for most light crudes.
Because a visbreaker fractionator is usually designed to operate at a higher pressure than are crude units, it should be possible to obtain an additional cut by flashing the bottoms into another column, operating at or below atmospheric pressure, before the bottoms stream is sent to the existing crude/vacuum unit.
For some heavier crudes this additional step may be sufficient to avoid intermediate atmospheric distillation altogether, allowing the introduction of the bottoms directly into a vacuum flasher. The existing soaker drum may be converted into a column appropriate for carrying out this additional separation step by equipping it with trays or packing, the usual overhead equipment, and a nozzle for the introduction of stripping steam at the bottom.
Table 2 compares the characteristics of the streams obtained from the distillation of various crudes with those streams obtained by distillation of a typical visbreaker product. The recoveries are expressed as volume percentages of feed, and the stream characteristics are expressed in terms of the estimated boiling range of the cuts.
For example, the distillation of an Arabian Light crude at the normal rated visbreaker capacity would only result in the production of a light naphtha in the overhead stream, and a heavy naphtha stream, removed from the bottom of the side stripper. An additional kerosine cut might be removed by flashing the bottoms into a new separator, as described previously.
The bottoms would, in most cases, still require additional atmospheric distillation to recover light gas oils before vacuum flashing.
If Arabian Heavy were to be processed, a light naphtha and an extended-range heavy naphtha could be withdrawn from the tower. The additional flashing could produce a stream suitable for kerosine or diesel blending after hydrotreating.
More importantly, should the crude unit be operating near capacity, the bottoms stream might be sufficiently stripped of light ends to allow the introduction of at least a portion of it directly into the vacuum tower.
The match is even more favorable for a heavy 19 API crude of Venezuelan origin, for which a whole naphtha cut can be taken overhead, a kerosine cut taken from the side draw, and an atmospheric gas oil cut obtained in the new flasher.
Of course, crudes even lighter than Arabian Light could be processed in the preflash system if sufficient capacity were available in the pumparounds and side strippers of the existing crude units to handle the additional volumes of light distillates present in the underflow from the preflash.
Another option that might take greatest advantage of the capacity of the visbreaker furnace, as well as the ability of the fractionation system to handle high temperatures with cracking, would be to affect deep, high-temperature distillation of an atmospheric residue in the visbreaker unit. This would be equivalent to "shallow" vacuum distillation.
The fractionator underflow could be further flashed in an existing vacuum unit.
As indicated, a visbreaker fractionator is usually designed to produce only a few rough-cut fractions. If desired, however, the quality of the separations can be improved by increasing the number of theoretical stages between draw-off points.
This can be achieved, in some cases, by decreasing the tray spacing, employing trays of greater efficiency, or installing packed sections using high-efficiency dumped or structured packings. The latter option can sometimes effect considerable reductions in the height equivalent of a theoretical plate (HETP), especially when compared to older bubble trays.
There are therefore three viable options for using visbreaker equipment, when upgrading a refinery to reduce or eliminate high-sulfur fuel oil production.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
