Gasification

Refinery Residues

Over 95% of liquid material gasified consists of refinery residues. Being a high temperature, noncatalytic process, partial oxidation is by and large flexible with

regard to feedstock quality and does not make great demands on the specification of a liquid feed. However, every feedstock needs to be evaluated to ensure that design aspects are correctly selected for its particular requirements. Generally, any feed­stock would need to fulfill the following requirements:

• The fuel per se must be single phase at the reactor burner inlet. Small amounts of gas in a predominantly liquid feed may ignite close to the burner, causing damage at that point. Droplets of liquid in a predominantly gaseous phase feed can lead to erosion and premature wear of equipment. This does not pose a limitation for most feed-

stocks, but must be considered in the design of the preheat train. It is important in this connection, however, to ensure that abrasive solids are kept to a minimum.

• The feedstock must be maintained within certain viscosity limits at critical points in the plant, such as at the burner. Again, this is generally a matter that can be addressed in the design of the feed transport and preheat systems and will not place any limitation on choice of feed.

• Too high a level of certain components in the ash, such as a high sodium content, limits the use of a syngas cooler, since the sodium salts deposit on the exchanger surface. Details are discussed under Sodium below.

The term “refinery residue” covers a wide range of material, some of which is solid at ambient temperatures, and others that are liquid under these conditions. Common to all is their origin in being the product of the distillation and possible subsequent treatment of crude oil. The most common residues are obtained by thermally cracking (visbreaking) vacuum residue or by subjecting it to solvent de-asphalting.

The specifications shown in Table 4-10 show typical gasifier feeds having a high sulfur content, high metal contents, and high viscosities (Posthuma, Vlaswinkel, and Zuideveld 1997). The data for tar sands bitumen, which are discussed in Section 4.2.2, are also included.

C/H Ratio. The C/H ratio of heavy refinery residues can vary between about 7 kg/kg (vacuum residue) and 10 kg/kg (asphalts), depending on the crude source and refining history. There are no specific limitations on the C/H ratio for gasification, but of course it does have an effect on syngas quality.

If all other conditions are maintained equal, the feeds with a higher C/H ratio will produce a synthesis gas with a lower H2/CO ratio. Whether this is an advantage or a disadvantage will depend on the application.

Sulfur Content Typically, the sulfur content of a residue can vary between 1 % and 7%. In exceptional cases (e. g., in parts of China) material with as little sulfur as 0.15% is gasified.

A sulfur content over this range has little effect on the design or operation of a gasifier, but it is an important issue for the design of the subsequent gas treating. A low sulfur content gives rise to a low H2S/C02 ratio in the sour gas from the acid gas removal unit, and this can be decisive for the design of the sulfur recovery unit. Selective physical washes such as Rectisol can be designed to concentrate the H2S in the sour gas, and with a low sulfur feed this would be necessary. Equally, low sulfur feeds can have surprising effects on a raw gas shift catalyst. This catalyst is required to operate in the sulfided state, and if insufficient sulfur is available to maintain this, then the catalyst can lose activity (BASF). Again, it is perfectly possible to design around this by including a sulfur recycle. It is therefore good practice to consider the low sulfur case carefully when specifying the basis of design for a new plant.

Corrosion effects in a residue gasifier, which can be connected with the presence of sulfur, are in most cases independent of the actual content of sulfur, and one needs to look at what other circumstances are contributing to the corrosion. In the event of, for example, high temperature sulfur corrosion, the solution to the problem will generally lie in avoiding the high temperatures rather than trying to lower the sulfur content of the feed.

Nitrogen Content The refining process concentrates the nitrogen present in the crude oil into the residue. Nonetheless, there is seldom more than 0.6 wt% nitrogen in a gasifier feedstock. Much of the nitrogen entering the reactor as part of the feed­stock is bound in organic complexes, and under the gasifier conditions it reacts with the hydrogen to form ammonia and hydrogen cyanide. The more nitrogen there is contained in the feed, the more ammonia and cyanide will be formed. For details see Section 6.9.2.

Ash Content The ash content of typical feedstocks are summarized in Table 4-10. The evaluation of the feed must be done on the basis of both individual ash compon­ents as well as the total ash content. The most critical and most common components are discussed in the following sections.

Satisfactory experience with ash contents up to 2000mg/kg has been achieved. Individual plants have run with even higher ash contents (Soyez 1988).

Vanadium. Experience of up to 700 mg/kg is available, and in one case of up to 3500mg/kg at the reactor inlet. With the exception of residues from some Central and South American crudes, feedstocks with over about 350 mg/kg are unusual. Many residues from Far East crudes have an order of magnitude less than this.

Vanadium as a feed component has two undesirable properties:

• In an oxidizing atmosphere vanadium is present as V205, which has a melting point of 690°C (Bauer etal. 1989). At temperatures higher than this, V205 diffuses into refractory linings, whether of a reactor or a boiler fired with a high vanadium fuel such as carbon oil (see next bullet), and destroys the refractory binder. In a reducing atmosphere (i. e., in normal operation for a gasification reactor) vanadium is present as V203, which has a melting point of 1977°C and is therefore not critical. For plant operation the lesson is that special care should be taken during heat up and after shutdown, when the reactor could be subject to an oxidizing atmosphere at temperatures above 700°C (Collodi 2001).

• When combusted in a conventional boiler, a fuel with a high vanadium content will cause slagging and fouling on economizer heat-transfer surfaces. Where soot from the gasifier is admixed to oil (carbon oil) for external firing in an auxiliary boiler, this sort of fouling can be a particular problem. With 700 mg/kg vanadium in the boiler feed, cleaning of the surfaces may be required as often as once or more per year.

• Problems with burners and syngas coolers have also been reported when operating with over 6000mg/kg vanadium in the reactor feed (Soyez 1988). This high level of vanadium in the feed is, however, extremely unusual.

Nickel There is no generally recognized upper limit for nickel in gasifier feedstocks. Nickel does, however, have an important influence on the gas treatment. In the presence of carbon monoxide and under pressure, nickel and nickel sulfide both form nickel carbonyl, a gaseous compound that leaves the gasification as a component of the synthesis gas. This topic is handled in more detail in Section 6.9.8.

It is also worth noting that upon air contact nickel sulfide can react to form NiS04 in the water. The NiS04 goes into solution in the water and can then be recycled to the scrubber, where it can increase the amount of carbonyls formed.

Sodium. Sodium can be present in the gasification feedstock either as sodium chloride or as sodium hydroxide. The sodium leaves the reactor as sodium chloride, or as sodium carbonate where the origin is sodium hydroxide, which have melting points of 800°C and 850°C, respectively (Perry and Chilton 1973). In plants where the synthesis gas is cooled by steam raising in a heat exchanger, these salts deposit on the heat-exchange surface. The most serious effect is fouling of a large section of the surface, causing an increase in exchanger outlet temperature. The depositing can, however, also accumulate locally to the extent that there is a significant increase in pressure drop. It is therefore desirable to ensure that the sodium content does not exceed 30 mg/kg, or at the maximum 50 mg/kg. It is our experience that already as much as 80 mg/kg in a feed that had been contaminated with seawater caused the outlet temperature of a syngas cooler to rise at more than 1°C per day.

Fortunately, the sodium chloride fouling is a reversible phenomenon, and operation with a sodium free feed will cause the outlet temperature to reduce again even if not quite to the value prevailing before the sodium ingress. Full recovery requires a steam out.

Sodium compounds—and for that matter other alkali metals—have the additional unpleasant property that they diffuse into the refractory lining of the reactor, where they effect a change in the crystal structure of the alumina from ос-alumina to (3-alumina, which leads in turn to a gradual disintegration and loss of life of the refractory.

For most refinery applications the sodium limitation is not a restriction, since the desalting process in the refinery effectively maintains the sodium level within allowable limits. In cases where a high sodium content is expected on a regular and steady basis, then quench cooling is a preferable choice to a syngas cooler.

Calcium. Typically, there may be some 6-20 mg/kg calcium in a refinery residue. Calcium can react with the C02 in the synthesis gas to form carbonates. This does not normally present any problems. Where significantly more calcium is present, these carbonates can precipitate out of the quench or wash water depositing in the level indicators, possibly with disastrous results if not recognized in time. A certain degree of depositing on the surface of syngas coolers is also possible (Soyez 1988).

Iron. The iron content of the feed can be as high as 50 mg/kg, but is generally lower. The behavior of iron is similar to that of nickel. Carbonyl formation in the synthesis gas takes place at a lower temperature than for nickel. This is discussed in more detail in Section 6.9.8.

Silica. Silica can find its way into refinery residues from a number of sources, as sand, catalyst fines from a fluid catalytic cracker (FCC), or from abraded refractory. Typically, there may be between 20 and 50 mg/kg in the residue, which can be tolerated. Larger quantities can cause two types of problem.

On the one hand, silica is an abrasive material that largely passes into the water system, where it settles out to some extent. In recycle systems, it is partly mixed with the feedstock, increasing the quantity being fed to the reactor. Abrasion has been reported on the feedstock charge pumps as a result (Soyez 1988).

Silica entering the system as FCC catalyst fines can also deposit close to the burner area of the reactor, with the risk of disturbing the flame pattern in the reactor.

Additionally, there is the problem that under the reducing conditions in the reactor, silica is reduced to volatile SiO according to the reaction

Si02+H2=Si0t + H20

The SiO condenses at about 800°C while cooling in the syngas cooler and deposits on the exchanger surface. This is one reason why all oil gasifiers use a low-silica high-alumina refractory lining (Crowley 1967).

Chloride. Chloride in the feedstock is mostly present as NaCl. Smaller quantities may also be present as K-, Fe-, Cr-, Ca-, and Mg - compounds.

Although large quantities of chlorides will damage the plant, the limitation of the main source, NaCl to 30ppmw Na, is usually sufficient to limit the overall chloride intake.

The potential problems of fouling or corrosion associated with chlorides are described in Section 4.1.

Naphthenic Acids. Naphthenic acids can be present in residues to a greater (e. g., those derived from Russian crudes) or lesser extent. While this is not of importance for the gasification process itself, it can be an important evaluation criterion, since it would need to be considered in the selection of metallurgy for the feedstock transport system.

Viscosity. Many refinery residues have an extremely high viscosity and are (subject­ively) solid, having the consistency of street bitumen at ambient temperatures. Since the viscosity decreases considerably with increased temperature, it is often desirable to transport and store this material in a heated condition.

The temperature dependency of viscosity takes the form of the Walther equation (GroBeetal. 1962, L4):

log (log (v + c))=m*(log(T0) - log(T)) + log (log(v0+c)) where v (cSt) is the kinematic viscosity at absolute temperature T (K), m is a constant for any given oil characterizing the temperature dependency of the viscosity, and c is a constant. This equation can be plotted as a straight line in a log(log(v)) versus log(7) diagram such as Figure 4-3. Ideally, m can determined from two reference temperatures for which the viscosity is known, since it is the gradient of the straight line joining the two points on the diagram. From this it is possible to use the value of m to determine the viscosity at any other desired temperature.

For cases where the viscosity at only one temperature is known, a correlation for m is required. Singh, Miadonye, and Puttagunta (1993) have developed such a correlation. A short program to calculate the viscosities of the feed on the basis of both one and two reference temperatures is included on the companion website.

The viscosity is an important parameter in the design of a gasification system, since the effectiveness of atomization at the burner is dependent on viscosity limits. Values of 20cSt-300cSt can be found in the literature (Supp 1990; Weigner etal. 2002.). The exact values depend on the individual burners, so licensors must be consulted for any specific project. In general, the desired tem­peratures required to achieve the prescribed temperature range can be achieved by steam heating, which is in most cases preferable to a fired heater, since the metal temperatures are lower and there is less tendency for the feed material to crack in the preheater.

If during operation the feed preheaters should fail, leading to an increase in viscosity, the tendency will be that the atomization deteriorates and an increase in the soot make can result.

Pour Point. The pour point is the second important property for the feedstock trans­port system. It provides an indication of the lowest temperature to ensure pumpabil - ity and avoid solidification of the feed in the line.

Since the transition from solid to liquid is gradual, there are a number of different defined points in the transition, which are shown in the diagram in Figure 4-4. The pour point is defined as the lowest temperature at which the oil will pour or flow under defined standard conditions (ASTM D 97).

When evaluating the transport properties of a feed, it is insufficient to look at the pour point in isolation. Two sample feeds illustrate this:

In the case of feed A, with only a slight increase of temperature above the pour point, the feed flowed sufficiently easily that no problems ever occurred on loss of steam tracing. Bringing the steam tracing back on line was sufficient to unblock the pipe. This would have been a considerable problem in the case of feed B, so a flushing system was included as part of the original design. The reason is that feed A is a feed­stock with a high percentage of paraffins that once they are molten have a low viscos­ity. Feedstock В has a so-called viscosity pour point where heat must just be applied until the required low viscosity is reached, and no use can be made of a state transition.

Density. Densities of typical gasifier feedstocks lie between 970 and 1250 kg/m3. There are no limitations imposed by gasifier performance or design.

Figure 4-5 shows the relationship between temperature and density for different oils. This correlation is also included in the companion website.

Flash and Ignition Temperatures. The flash point is the temperature at which sufficient hydrocarbons have evaporated that an explosive mixture is formed that can be ignited by an external ignition source.

There are two methods commonly used for determination of the flash point: the Cleveland open cup method (ASTM D 92) and the Pensky-Martin closed cup method (ASTM D 93). Using the open cup method a certain amount of the evaporating hydrocarbons is lost to the surroundings, which leads to a relatively high value for the measured flash point. The closed cup method uses a closed vessel with a narrow neck so that all the hydrocarbons that evaporate remain part of the potentially ignitable mixture. The difference between the two methods is about 30°C, that is, the closed cup method will provide a value about 25-30°C lower than the open cup method.

In contrast to the flash point for which an external ignition source is used, the ignition point (ASTM D 874) is that temperature at which the hydrocarbon begins to burn without any external ignition source.

The flash point places an upper limit to the preheat temperature of a gasifier feed­stock. If material is preheated to its flash point, then there is a danger that it will ignite immediately on exiting the burner and damage it. A damaged burner can in turn change the design flame pattern, causing local stoichiometric combustion with associated high temperatures and the potential for reactor containment failure. A suitable safety precau­tion is to maintain the preheat temperature 50-100°C lower than the flash point.

Generally, there is no need to preheat to anything like the flash point of normal residues, since the viscosity is already sufficiently low for good atomization at substantially lower temperatures. Problems can arise, however, with blended feedstocks. If, for instance, FCC light cycle oil is added to a heavy asphalt to reduce its viscosity, then the light material might have a flash point at a temperature required to achieve an acceptable viscosity of the blend at the burner.

Conradson Carbon. The Conradson carbon (ASTM D 189) is determined by placing a feed sample into a container and heating it to a given temperature so that it cracks. The Conradson carbon value is given by the amount of cracked residue expressed as a percentage of the original sample.

The Conradson carbon value is not used expressly in gasifier installation design. It does, however, provide an indication of the propensity for coke formation by the residue during preheat. It can also, in connection with the C/H ratio, provide a guide to the moderating steam requirement. Additionally, it can be of use when consider­ing the consistency of other data received for a particular feed.

Typical values for the Conradson carbon are:

Propane asphalt 35%

Vacuum residue 20%

Atmospheric residue 10%

The Ramsbottom method (ASTM D 254) provides an alternative determination of the carbon residue. A conversion chart between the two methods can be found in Speight (1998, p. 335).