Ultrasound applied to crude oil desulfurization

An innovative method for upgrading crude oils will find application across multiple industry sectors.

Following field trials completed late in 2008, Houstonbased SulphCo, Inc. reported it has successfully used a 5,000 b/d mobile “Sonocracking” unit to duplicate on a commercial scale its proprietary process that applies high-energy, high-frequency sound waves, so-called ultrasonics, in conjunction with oxidation chemistry to improve the quality of crude oil and crude oil fractions.

Dr. Florian Schattenmann, SulphCo chief technology officer, said use of high-powered ultrasound can significantly accelerate the sulfur compound oxidation needed to upgrade crude oils and petroleum products into sweeter (i.e., containing less sulfur) crudes and products (e.g., diesel), potentially eliminating or reducing the need for hydrotreating.

The technology works by taking the sulfur, chemically bound to some of the molecules in the oil, and oxidizing it using hydrogen peroxide - a classic oxidant - together with the ultrasound. On a molecular level, the hydrogen peroxide donates one of its two oxygen atoms to the sulfur to form water as the byproduct. The treated oil typically has less sulfur, lower viscosity, and a higher API gravity. In addition, remaining sulfur is thereby converted to a different sulfur species that can be more easily separated.

In operation, the oil, hydrogen peroxide solution, and catalyst are introduced into a reactor, where very intense mixing happens in the cavitation zone generated by the ultrasound. The reaction takes place in half a second or less. The water and oil separate, with the water subsequently being recycled and new hydrogen peroxide added to offset that used in what is “more or less” a closed-loop system.

Applications of SulphCo’s Sonocracking technology are currently being evaluated, the company said, in oil production, transportation, and refining. One reason to assume that multiple uses will be found is that an increasing proportion of the overall market consists of medium, heavy, or sour crudes. In addition, current and expected future industry regulatory requirements will exert pressure to move towards lower sulfur content in most petroleum products.

The traditional method for removing sulfur from oil involves hydrotreating, entailing capital-intensive investments in high-pressure, high-temperature hydro-desulfurization (HDS) units as well as boilers, hydrogen plants, and sulfur recovery units. The deeper the desulfurization required, or the heavier or more sour the crude used for feed, the more expense involved.

At the moment, Schattenmann said, the primary market focus for SulphCo’s technology is the downstream sector of the oil industry, but upstream and midstream applications are already envisioned. “If you can reduce the sulfur content of oil before it goes into the separator or pipeline, there are many benefits. For example, you may be able to meet pipeline specifications without having to add more expensive oil blends to your stream. The upstream and mid-stream guys get really excited at the prospect of having this kind of a simple solution to increase value.”

While the base design and capacity for the technology consists of a 5,000 b/d processing line, successive lines can be added to scale capacity. SulphCo has implemented skid-mounted modular Sonocracking units with 15,000 b/d capacity and currently has 210,000 b/d of capacity constructed.

The cavitation induced as oil and additives stream through the reactor and past the ultrasonic probe leads to the creation of bubbles at the sites of refraction owing to the “tearing” of the liquid caused by the negative pressure of the intense sound waves. The bubbles then oscillate under the effect of positive pressure, growing to an unstable size as the wave fronts pass. The bubbles eventually burst, generating excess heat and pressure in and around every micrometer- and sub micrometer-sized bubble. This happens in a matter of “nanoseconds,” Schattenmann said, and each bubble behaves as a micro-reactor, accelerating the chemical reaction described earlier owing to the heat released and localized pressures obtained.

Subsequent to the completion of the commercial-scale field trials in late 2008, Dr. Larry D. Ryan, SulphCo CEO, said, “Additional technical iterations and analysis will continue as we identify, execute, and evaluate the multiple processes necessary to comply with future customer requirements.”

Read More

Share |

Refinery Feedstocks

The basic raw material for refineries is petroleum or crude oil, even though in some areas synthetic crude oils from other sources (Gilsonite, tar sands, etc.) and natural gas liquids are included in the refinery feedstocks. The chemical compositions of crude oils are surprisingly uniform even though their physical characteristics vary widely. The elementary composition of crude oil usually falls within the following ranges.

In the United States, crude oils are classified as paraffin base, naphthene base, asphalt base, or mixed base. There are some crude oils in the Far East which have up to 80% aromatic content, and these are known as aromatic-base oils. The U.S. Bureau of Mines has developed a system which classifies the crude according to two key fractions obtained in distillation: No. 1 from 482  to 527°F (250 to 275°C) at atmospheric pressure and No. 2 from 527 to 572°F (275 to 300°C) at 40 mmHg pressure. The gravity of these two fractions is used to classify crude oils into types as shown below.

The paraffinic and asphailic classifications in common use are based on the properties of the residuum left from nondestructive distillation and are more descriptive to the refiner because they convey the nature of the products to be expected and the processing necessary.

CRUDE OIL PROPERTIES

Crude petroleum is very complex and, except for the low-boiling components, no attempt is made by the refiner to analyze for the pure components contained in the crude oil. Relatively simple analytical tests are run on the crude and the results of these are used with empirical correlations to evaluate the crude oils as feedstocks for the particular refinery. Each crude is compared with the other feedstocks available and, based upon the operating cost and product realization, is assigned a value. The more useful properties are discussed.

API Gravity

The density of petroleum oils is expressed in the United States in terms of API gravity rather than specific gravity; it is related to specific gravity in such a fashion that an increase in API gravity corresponds to a decrease in specific gravity. The units of API gravity are °API and can be calculated from specific gravity by the following:

In equation (1), specific gravity and API gravity refer to the weight per unit volume at 60°F as compared to water at 60°F. Crude oil gravity may range from less than 10°API to over 50°API but most crudes fall in the 20 to 45°API range. API gravity always refers to the liquid sample at 60°F (15.6°C). API gravities are not linear and, therefore, cannot be averaged. For example, a gallon of 30°API gravity hydrocarbons when mixed with a gallon of 40°API hydrocarbons will not yield two gallons of 35°API hydrocarbons, but will give two gallons of hydrocarbons with an API gravity different from 35°API. Specific gravities can be averaged.

Sulfur Content, wt%

Sulfur content and API gravity are two properties which have had the greatest influence on the value of crude oil, although nitrogen and metals contents are increasing in importance. The sulfur content is expressed as percent sulfur by weight and varies from less than 0.1% to greater than 5%. Crudes with greater than 0.5% sulfur generally require more extensive processing than those with lower sulfur content. Although the term ‘‘sour’’ crude initially had reference to those crudes containing dissolved hydrogen sulfide independent of total sulfur content, it has come to mean any crude oil with a sulfur content high enough to require special processing. There is no sharp dividing line between sour and sweet crudes, but 0.5% sulfur content is frequently used as the criterion.

Pour Point, °F (°C)

The pour point of the crude oil, in °F or °C, is a rough indicator of the relative paraffinicity and aromaticity of the crude. The lower the pour point, the lower the paraffin content and the greater the content of aromatics.

Carbon Residue, wt%

Carbon residue is determined by distillation to a coke residue in the absence of air. The carbon residue is roughly related to the asphalt content of the crude and to the quantity of the lubricating oil fraction that can be recovered. In most cases =the lower the carbon residue, the more valuable the crude. This is expressed in terms of the weight percent carbon residue by either the Ramsbottom (RCR) or Conradson (CCR) ASTM test procedures (D-524 and D-189).

Salt Content, lb/1000 bbl

If the salt content of the crude, when expressed as NaCl, is greater than 10 lb/1000 bbl, it is generally necessary to desalt the crude before processing. If the salt is not removed, severe corrosion problems may be encountered. If residua are processed catalytically, desalting is desirable at even lower salt contents of the crude. Although it is not possible to have an accurate conversion unit between lb/1000 bbl and ppm by weight because of the different densities of crude oils,1 lb/1000 bbl is approximately 3 ppm.

Characterization Factors

There are several correlations between yield and the aromaticity and paraffinicity of crude oils, but the two most widely used are the UOP or Watson ‘‘characterization factor’’ (KW) and the U.S. Bureau of Mines ‘‘correlation index’’ (CI).

where

TB _ mean average boiling point, °R

G _ specific gravity at 60°F.

The Watson characterization factor ranges from less than 10 for highly aromatic materials to almost 15 for highly paraffinic compounds. Crude oils show a narrower range of KW and vary from 10.5 for a highly naphthenic crude to 12.9 for a paraffinic base crude.

The correlation index is useful in evaluating individual fractions from crude  oils. The CI scale is based upon straight-chain paraffins having a CI value of 0 and benzene having a CI value of 100. The CI values are not quantitative, but the lower the CI value, the greater the concentrations of paraffin hydrocarbons in the fraction; and the higher the CI value, the greater the concentrations of naphthenes and aromatics.

Nitrogen Content, wt%

A high nitrogen content is undesirable in crude oils because organic nitrogen compounds cause severe poisoning of catalysts used in processing and cause corrosion problems such as hydrogen blistering. Crudes containing nitrogen in amounts above 0.25% by weight require special processing to remove the nitrogen.

Distillation Range

The boiling range of the crude gives an indication of the quantities of the various products present. The most useful type of distillation is known as a true boiling point (TBP) distillation and generally refers to a distillation performed in equipment that accomplishes a reasonable degree of fractionation. There is no specific test procedure called a TBP distillation, but the U.S. Bureau of Mines Hempel and ASTM D-285 distillations are the tests most commonly used. Neither of these specify either the number of theoretical plates or the reflux ratio used and, as a result, there is a trend toward using the results of a 15:5 distillation (D-2892) rather than the TBP. The 15:5 distillation is carried out using 15 theoretical plates at a reflux ratio of 5:1. The crude distillation range also has to be correlated with ASTM distillations because product specifications are generally based on the simple ASTM distillation tests D-86 and D-1160. The TBP cut point for various fractions can be approximated by use of Figure bellow. A more detailed procedure for correlation of ASTM and TBP distillations is given in the API Technical Data Book—Petroleum Refining published by the American Petroleum Institute, Washington, DC.

Metals Content, ppm

The metals content of crude oils can vary from a few parts per million to more than 1000 ppm and, in spite of their relatively low concentrations, are of considerable importance. Minute quantities of some of these metals (nickel, vanadium, and copper) can severely affect the activities of catalysts and result in a lowervalue product distribution. Vanadium concentrations above 2 ppm in fuel oils can lead to severe corrosion to turbine blades and deterioration of refractory furnace linings and stacks.

Distillation concentrates the metallic constituents of crude in the residues, but some of the organometallic compounds are actually volatilized at refinery distillation temperatures and appear in the higher-boiling distillates.

The metallic content may be reduced by solvent extraction with propane or similar solvents as the organometallic compounds are precipitated with the asphaltenes and resins.

Read More

Share |

API Oil-Water Separator

An API oil-water separator is a device designed to separate gross amounts of oil and suspended solids from the wastewater effluents of petroleum refineries, petrochemical and chemical plants, natural gas processing plants and other industrial sources.

The name is derived from the fact that such separators are designed according to standards published by the American Petroleum Institute (API).

Description of the design and operation

The API separator is a gravity separation device designed by using Stokes' Law to define the rise velocity of oil droplets based on their density and size. The design of the separator is based on the density difference between the oil and the wastewater because that difference is much smaller than the specific gravity difference between the suspended solids and water. Based on that design criterion: most of the suspended solids will settle to the bottom of the separator as a sediment layer, the oil will rise to top of the separator and the wastewater will be the middle layer between the water on top and the solids on the bottom.

Typically, the oil layer is skimmed off and subsequently re-processed or disposed of, and the bottom sediment layer is removed by a chain and flight scraper (or similar device) and a sludge pump. The water layer is sent to further treatment consisting usually of a dissolved air flotation (DAF) unit for further removal of any residual oil and then to some type of biological treatment unit for removal of undesirable dissolved chemical compounds.

Parallel plate separators are similar to API separators but they include tilted parallel plate assemblies (also known as parallel packs). The underside of each parallel plate provides more surface for suspended oil droplets to coalesce into larger globules. Any sediment slides down the topside of each parallel plate. Such separators still depend upon the specific gravity between the suspended oil and the water. However, the parallel plates enhance the degree of oil-water separation. The result is that a parallel plate separator requires significantly less space than a conventional API separator to achieve the same degree of separation.

History

The API separator was developed about 75 years ago by the API and the Rex Chain Belt Company. The first API separator was installed in 1933 at the Atlantic Refining Company (ARCO) refinery in Philadelphia. Since that time, virtually all of the refineries worldwide have installed API separators in their wastewater treatment plants. The majority of those refineries installed the API separators using the original design based on the specific gravity difference between oil and water. However, many refineries now use plastic parallel plate packing to enhance the gravity separation.

Other oil-water separation applications

There are other applications requiring oil-water separation. For example:

·    Oily water separators (OWS) for separating oil from the bilge water accumulated in ships as required by the international MARPOL Convention.

·     Oil and water separators are commonly used in electrical substations. The transformers found in substations use a large amount of oil for cooling purposes. Moats are constructed surrounding unenclosed substations to catch any leaked oil, but these will also catch rainwater. Oil and water separators provide a quick and easy cleanup of an oil leak

Read More

Share |

Capacity Loss due to Cubcooled Reflux Use

Sometimes feeds going to a distillation column are subcooled. One reason a feed may be subcooled is because during energy optimization of the plant the feed stream going to the column was identified as a source of heat that could be cross-exchanged with colder stream. Another reason is it may be advantageous to subcool the overhead product of a column at the condenser instead of using an additional product cooler. The biggest problem is that these factors are often not taken into account when sizing column internals. This may lead to a premature flooding, loss of column efficiency, and reduced capacity.

Excessive sub-cooling of a reflux feed to a distillation column can lead to a variety of operational problems. Excessive subcooling of a reflux feed condenses some of the internal vapor traffic. This, in turn, increases the liquid traffic in the affected area of the column (Figure 1). Often, the operations department will try to counter this by cutting back on the amount of reflux being introduced into the column or by adjusting the condenser duty. Reductions in reflux being introduced will have an effect on the effectiveness of the column.

Sub-cooling also reduces overall column efficiency. The subcooled reflux or feed shifts some of the internal equipment from a mass-transfer service to a heat-transfer service.

Subcooled Liquid Feed Mechanism

Sub-cooled liquid feed is at a temperature below its column-pressure bubble point. The effect of a subcooled feed or reflux can be estimated by:

LF        change in liquid flow at the feed stage

F          total moles of feed (reflux)

H          molar enthalpy of liquid feed at conditions to the column

h*         molar enthalpy of liquid feed at the column pressure boiling point

H_eq        molar enthalpy of vapor which would exist in equilibrium with the feed if the liquid

feed were at the column pressure boiling point.

Referring to Figure 1, we see that LF equals L2-L1. When a sub-cooled liquid feed is used, the increase in liquid molar flow at the feed stage is greater than the liquid molar feed rate alone. Vapor rising to the feed stage is condensed in order to raise the feed conditions to the bubble point temperature. The condensing vapor increases the liquid flow leaving the feed stage, flooding the column (Figure 2.)

Operational Example

After a revamp of a commercial petrochemical column the column was started up and lined out. Operations brought the column up to the new design-operating rate. Before the column reached the new design-operating rate the column started to experience a loss of efficiency. The capacity of the column fell five to ten percent short of the design capacity. The column was gamma scanned and the scan revealed that the top five to six trays had an extremely high liquid level on the tray active area. The down comer also had an extremely high clear liquid back up. All of these conditions were consistent with a premature flooding condition.

A test run was performed to evaluate the column’s performance and to verify the design. The data collected from the test run was used to evaluate the model.

While reevaluating the model, it was discovered that 100°F (55ºC) subcooled reflux was being introduced into the column. The use of sub cooled reflux was missed during the design phase of the column revamp project. The simulation was rerun using the subcooled reflux conditions.

The results of the simulation indicated that the liquid traffic in the rectification section of the column was dramatically higher than previously used in the design. The internals were re-rated with the loadings from the simulation. It was determined that the column would get about five percent less capacity than planned. This was consistent with the results seen from the simulation and the gamma scan.

Sub-cooling the reflux was a normal part of the operation of the plant. The reflux was subcooled to make the plant more energy efficient. This practice could be abandoned if necessary. The operations group agreed to increase the temperature of the reflux in order to determine if this was the problem with the column. Once the reflux was introduced to the column at bubble point temperature, the capacity and efficiency of the column increased. The column was able to handle the new design-operating rate and the efficiency of the column was within design specifications.

Conclusions

The introduction of subcooled feed into a column may cause operational problems and lead to premature flooding. If a subcooled reflux feed is going to be used, the effects of this stream must be accounted for in the design of the column.

Read More

Share |