REFINERY GASES— Conclusion: Specialty gases assist product quality, emissions compliance

Dec. 14, 2009
This article is the third and final in a series (OGJ, Nov. 23, 2009, p. 50; Dec. 7, 2009, p. 48) on the effects of recent developments on refineries and their use of gases to meet new regulatory and legislative requirements while avoiding major investments.

This article is the third and final in a series (OGJ, Nov. 23, 2009, p. 50; Dec. 7, 2009, p. 48) on the effects of recent developments on refineries and their use of gases to meet new regulatory and legislative requirements while avoiding major investments.

This article addresses refineries' use of specialty gases, which are used in small quantities but are nevertheless of high value for refineries.

These gases especially help the refinery to ensure the correct product quality and meet regulations with respect to emissions into the environment.

Gas production plants are also discussed.

Specialty gases in refineries

Specialty gases are either very pure gases, rare gases, or gas mixtures of very high mixing accuracy used in such demanding applications as quality measurement for products and off-streams in the field and in the labs. Besides calibration purposes, this includes application as utilities for operation of such analytical devices as gas chromatographs.

These gases play an important, though not easily visible part in refineries, contributing to the optimum economy of a refinery.

Major specialty-gas companies can provide the complete range of specialty gases, both standard and tailored products, plus the services and equipment necessary for efficient use. In large companies, specialty gases are based on a long history of expertise and performance. These companies generally know or can determine what refiners need.

Applications

The most commonly known uses for gases in a refinery are in hydrogenating and inerting, possibly also in welding, since these are situations in which the gas is seen in operation. But specialty gases—although unseen—are used somewhere in almost every product chain.

For instance, measuring gasoline quality checks the result with the help of instruments calibrated with specialty gas mixtures. Carrier gases in gas chromatography are high-purity specialty gases. In emission control, specialty gases help to detect hazardous materials. During a turnaround of, for example, a distillation tower, one needs a specialty gas mixture for leak detection.

Following are some examples of application fields in which specialty gases and expertise in refining processes can make a big difference in economy.

Gas chromatography

Prominent among the analytical instruments used in refineries are gas chromatographs. In these devices, carrier gas transports gas components through the separation column and to the detection system. For this purpose, high-purity gases used are typically of a 5.0 purity, that is, more than 99.9990% purity. Especially used are N2, H2, argon, and helium of purity 5.0.

Of primary concern is the absence of specific trace components in these gases. This quality normally can be guaranteed by the gas supplier. Some detection systems call for dedicated supply of gases as utilities. For example, flame ionization detectors in refineries analyze hydrocarbons that are burned in these detectors by addition of fuels, such as H2 and an oxidant, typically artificial air. Even traces of hydrocarbons in this air stream would disturb the readings of the FID.

Controlling the quality of a product, especially concentration, involves comparing it with a specified gas mixture, the calibration gas. Such highly defined gases are needed not only for gas chromatography but also for calibration of other analytical instruments as, for example, ultraviolet or infrared spectrometers. Tailored gas mixtures are provided according to the specifications of the refinery, especially mixtures of hydrocarbons in H2, H2S in N2, hydrocarbons in butane, a specified amount (in parts per million) of CO in helium, mercaptans in helium, hydrocarbon mixtures in CO, and hydrocarbon mixtures in propane.

In addition, gases are provided for measurement during production, as in process control. These include, for example, mixtures of hydrocarbons in methane or in H2, methane in CO2, a specified amount (ppm) of O2 in N2, a specified amount (ppm) of CO in N2, and SO2 in N2.

Leak detection

Many systems in a refinery are checked for leaks with helium or helium mixtures. Tight systems are essential in any refinery section, whether piping in a sulfur-recovery unit or fractionator column of a fluid catalytic cracker. A leak of poisonous gas from a Claus plant or an explosive gas from a FCC unit can be disastrous.

Leak-testing procedures often use a gas mixture of helium in nitrogen. The helium passes through any leaks and is detected on the outside by a "sniffer," a mass spectrometer.

Stack control

Refineries must strictly control their emissions to the atmosphere. Chief among the toxic and hazardous pollutants are SO2, CO2, H2S, and NOx; but also CO must not be neglected.

The concentration of this highly toxic compound is always of concern when hydrocarbons are burnt, as in boilers. For example, when the regenerator of an FCC unit is operated in partial-burn mode and corresponding effluent gas is heavily loaded with CO, the efficiency of its combustion to CO2 is especially important. For incinerator systems generally, a certain surplus of oxidation air is a precondition for proper operation and therefore must be controlled.

For example gases containing appreciable amounts of so-called "totally reduced sulfur compounds," such as COS, CS2, and especially H2S—typically stemming from Claus units—are not only toxic but also prone to cause odors. Therefore such gases must be incinerated to gain exclusively SO2 as a sulfur-bearing emission component.

Correspondingly, for control of stack-gas quality, not only H2S and SO2 are measured but also oxygen content. Corresponding O2 on line analyzer—often on the basis of a paramagnetic measuring principle—for the sake of precision must be calibrated with a gas mixture of O2 in nitrogen that resembles the expected composition of the required O2 content of the emission stream, that is, only a few percent of O2 per volume.

Sometimes analysis of emissions takes place at the top of a stack requiring calibration at that point. As climbing a stack carrying a bulky and heavy gas bottle is hard and risky, a small and easily portable calibration gas cylinder was developed for that purpose.

One widely used technique for measuring gaseous emissions is gas chromatography with a suitable detector, as the FID described previously.

Another type of detector for monitoring hydrocarbons is the photoionization detector. The PID has the advantage of requiring no fuel gas, such as hydrogen. But the disadvantage is that it is insensitive to C1-C3 saturated hydrocarbons because these are quite stable compounds that are not easily ionized. When looking for traces of sulfur-containing compounds, for example, a flame photometric detector is suitable. The electron-capture detector is particularly sensitive to halogenated compounds, which in general are easily charged by electron addition.

A gas chromatograph plus mass spectrometer as a detection system is frequently used for identifying compounds in exhaust gases because this combination is not only capable of analyzing small traces but also covers a wide range of chemical species to be measured.

Vapor emission control

Also of concern are volatile organic substances (characterized by high vapor pressure and low water solubility) typically emitted from storage tanks. Every refinery has its own tank farm whose tanks contain crude oil and such refined products as gasoline, diesel, and kerosine.

During the filling of these tanks, air or inert gas saturated with hydrocarbon vapors necessarily emanates from the tanks. Furthermore some of these products have a high vapor pressure, which also results in vapors being released. These substances pose potential safety and environmental hazards and must be monitored.

To determine their content, they often are analyzed by a gas chromatograph-FID combination because they are hydrocarbons. The standard against which the offgas is measured is artificial air produced as a specialty gas with a precisely adjusted content of the pollutants in question, often in the parts-per-billion range.

Gas-production plants

Gases used in major quantities in refineries are hydrogen, nitrogen, and oxygen; all three can be produced in refinery-based gas production plants.

Hydrogen can be produced from practically all hydrocarbons, methane up to naphtha, heavy oil, asphalt, or coal. The processes involved may be steam reforming, autothermal reforming, gasification, and prereforming.

Here is an example of a steam reformer, in the Milazzo refinery, Sicily (Fig. 1).

Fig. 1 shows an example steam reformer at the Milazzo refinery in Sicily; Fig. 2 shows the hydrogen pressure-swing adsorption plant at Total's Leuna refinery in Germany.

This PSA hydrogen plant is at the Leuna refinery in Germany (Fig. 2).

A particularly efficient reactor with internal cooling was developed by Linde AG 15 years ago for the CO shift, in which carbon moNOxide and water react to produce hydrogen and carbon dioxide. One such reactor is more efficient and cheaper than a series of conventional, uncooled reactors with heat exchangers in between for temperature control.

This new reactor type has been used many times. The process yields residual carbon moNOxide of less than 0.2% vol/vol even from high concentrations of carbon moNOxide. A downstream PSA plant concentrates the hydrogen from the CO-shift converter.

Such PSA plants can be large. Linde built the largest hydrogen PSA unit in the world, for example, at the Ssang Yong Oil Refinery Corp., Onsan, Korea. It recovers hydrogen from two 175,000-standard cu m/hr streams.

Control of the switching valves in a PSA unit is crucial. Linde PSA units can take individual adsorbers or groups of adsorbers out of service, while the rest of the plant can continue to operate. This permits maintenance during operation, such as repair of valves that are no longer sufficiently gastight. Thus the availability of the PSA plant is practically 100%.

For smaller amounts of hydrogen that may contain impurities, there is the option of membrane units for hydrogen separation.

The quality of the hydrogen produced ranges from only roughly purified crude hydrogen to highly pure hydrogen for the electronics industry, at more than 99.999999% purity.

This cryogenic air separation unit at the Leuna refinery produces 1,500 tons/day of gaseous oxygen and 2,700 tons/day of nitrogen, plus 400 tons/day of liquid oxygen, nitrogen, and argon (Fig. 3).

To produce oxygen or nitrogen, air-separation units are employed. Cryogenic air separation, invented 1895 by Carl von Linde, has been developed continually since then. Fig. 3 shows the Leuna air separation unit, which supplies gases to Total's Mitteldeutschland refinery.

The largest air-separation plant for nitrogen production so far was built by Linde. It was shipped to Cantarell, Mexico, for enhanced oil recovery (nitrogen injection). Five plants operate there, each at 500,000 scm/hr air intake, producing 335,000 scm/hr nitrogen at 120 bar. At the small end, standard cryogenic air-separation plants are available on the market with only 1,000 scm/hr air throughput to recover about 700 scm/hr nitrogen or about 200 scm/hr oxygen.

While the cryogenic units serve to produce highly pure oxygen and nitrogen, PSA plants can be used if less purity is required for gas throughputs in the range up to about 5,000 scm/hr.

The accompanying table summarizes the optimal ranges of use for the various gas generation systems for most applications.

On site supply

Refiners have several options to fulfill higher industrial gas needs. Of course, gas production plants can be bought from competent suppliers. That necessarily means that the complete investment shows up in the balance sheet of the refinery. In addition, operation and maintenance costs have to be borne by the refinery.

All this is conventional procedure with advantages and disadvantages. The main disadvantage certainly is that refiners are not specialized in gas plant operation. Therefore reliability of the plants tends to be lower than optimum and the cost higher. But there is an alternative which gains more and more friends among the refining community: "on site supply."

The basic idea behind on site supply is that a gas company builds, owns, and operates the gas production plant for the refinery and the refiner receives the gas as a utility so that it can concentrate on its core business, making fuel.

For on site supply of industrial gases, the gas supplier takes on the investment for the plant and the operating risks. The refineries provide the necessary working materials, such as methane for a steam methane reformer or cooling water for heat exchangers. The result is that the refinery receives the required gases and bears no obligation for the operation of the gas generation facility.

This arrangement affords the refinery several advantages:

• The gas plant is operated by a gas company for which this is core business. The gas companies have experience from operating many such plants. The on site concept secures this experience for the refinery, and as a result the refinery has a reliable gas supply and can concentrate on its own operations.

• The gas supplier takes on the investment in the gas plant. The refinery has less capital tied up for industrial gases.

• The gas company can build the gas plant according to its standards, allowing repeat engineering, which saves money. In addition spare parts can be standardized and stored centrally for specific types of gas plants. This also reduces cost so that gas from an on site plant is usually cheaper compared with a gas plant owned by the refinery.

• With on site supply, the gas operation is usually not part of the refinery balance sheet. Thus the refinery's equity ratio improves and can foster a better rating. In turn the refinery may enjoy improving financial flexibility for this site.

The proper contractual arrangement is critical of course. The accounting practices that apply at the refinery location, such as Generally Accepted Accounting Practices in the US or International Accounting Standards in the EU, have a major influence. This point can only be mentioned here, not discussed in detail, as conditions depend on each location.

The gas company owning the on site plant takes on the risk of a high capital investment. The term of the contract with the refinery will be based on the expected service life of the gas plant, usually 15 years. That time frame can be calculated shorter for small, standardized units, such as containerized nitrogen plants. These units can be reused more easily for other customers after the contract expires.

Because oxygen and nitrogen are usually not required in liquid form, on site plants do not involve expensive liquefaction energy for production. Without truck shipment, costs are lower and the operation is "greener." Hydrogen, too, is used only as a gas in refining applications so that expensive liquefaction is not required in an on site plant.

Beginning in the 1980s, the concept of on site supply began to spread. It succeeded especially in the industrialized countries where it largely displaced the old regional gas distributors in many areas.

Under favorable conditions, conversion to on site supply can reduce gas costs, often by more than 10%.

Correction

Table 1 of "REFINERY GASES—1: Hydrogen, nitrogen assist compliance with new, tougher environmental regs," M. Heisel, B. Schreiner, and W. Bayerl (OGJ, Nov. 23, 2009, p. 50), inadvertently omitted data for 2009 diesel fuel sulfur content: <10 ppm.

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