In this series of three blog posts we talk about hydrogen sulfide. Reservoir engineers often talk about H2S as non-hydrocarbon diluents in natural gas, it’s miscibility with crude oils and reservoir management issues. One such reservoir management issue is the possibility of souring reservoirs when inadequate or incorrect bactericides are included in injected fluids. But for these blog posts we will follow this nasty molecule out of the reservoir and consider other important aspects when dealing with it. The primary content of these blog posts is a Baker Hughes white paper available here.
Facilities that process or store hydrocarbons containing H2S often face a number of operational challenges. Two such considerations are contamination of intermediates and finished products with H2S, and the effects of H2S-induced corrosion on terminal facilities.
Contamination of hydrocarbon products with H2S can cause products to be off-specification. Even when there is not an overt limit on H2S, its presence can render the contaminated product off-specification on a number of other product quality checks. Unfortunately, costs associated with demurrage, out-of-service tanks tied up with off-specification product, reprocessing fees, and product downgrades can quickly add up. Product quality issues relative to specific hydrocarbon products are discussed in the next section. In addition to impacting product quality, H2S can have a significant effect on storage tank corrosion. H2S readily dissolves in condensed water to form the bi-sulfide ion, which is corrosive to carbon steel. Storage tanks used to store hydrocarbons with large concentrations of H2S are therefore very susceptible to H2S-induced corrosion. Moreover, the resulting iron sulfide deposits adhere to storage tank walls and can act as cathodic sites that induce severe pitting corrosion. Hydrogen embrittlement and sulfide stress cracking have also been observed. The rates of corrosion are often severe enough to significantly shorten the useful lifespan of a storage tank.
The rate at which H2S corrodes storage tanks is influenced by a number of factors. The concentration of H2S is important, but oxygen, water, locale and turnover frequency should also be considered. For instance, storage tanks that show the highest corrosion rates are those which are loaded and unloaded frequently with crude oil containing H2S and are located in humid coastal regions. Large amounts of oxygen and water (often salt water) are introduced during tank turnovers and during normal tank breathing. The combination of H2S, oxygen, salt and moisture produces a very aggressive corrosive environment.
Hydrocarbon streams and associated H2S issues
Nearly every hydrocarbon product entering or exiting the refinery, from flare gas and liquefied petroleum gas (LPG) to crudes and resids, is subject to H2S contamination and its corresponding problems. Mitigation is critical to ensure the safety of personnel as well as environmental compliance, product quality and equipment integrity.
Flare gas is often limited by government regulations on the amount of H2S it can contain. Refineries produce SOX emissions when H2S-laden gases are flared. The process of flaring converts H2S to SOX. For refineries to reduce SOX emissions and avoid noncompliance issues, it is now more common to treat the flare gas to reduce the amount of H2S it contains.
In these applications, consideration of the injection technique and system operational factors are as important as the selection of the best chemical additive. Residence time, temperatures, pressures and other variables should be considered, as should the separation and disposal of spent scavenger. These applications have the potential to save refiners millions of dollars by maintaining desired throughput, by reducing capital expenditures, and by avoiding unplanned shutdowns, fines and penalties.
LPG may also be contaminated with H2S. Most LPG specifications require a fuel to be noncorrosive to copper because of the copper and copper alloys used in fuel systems. This corrosion is most often caused by H2S remaining in the LPG after a unit upset. In addition to H2S-related copper corrosion in LPG systems, the presence of H2S is also a potential health hazard to consumers. In the case of an LPG leak in a residence or workplace, the hazard is much greater when the LPG is contaminated by H2S than if the leak consisted of LPG alone. Finally, H2S in LPG can corrode ferrous metal surfaces within storage and piping systems, and compromise the integrity of the metal. LPG that contains H2S could be handled by reprocessing or by blending it off; however, these methods can tie up storage and take time. The use of H2S scavengers is usually an economical and reliable way to resolve these issues. Water-soluble scavengers are generally recommended because they will separate completely from the hydrocarbon and prevent contamination of the LPG with materials of lower volatility. The presence of lower-volatility components in LPG is undesirable because these materials do not burn as well and could cause injector plugging and fouling on burner tips.
Other finished fuels
Similar to LPG, finished fuels such as gasoline, kerosene and diesel are required to be noncorrosive to copper. Moreover, gasoline is required to be noncorrosive to silver and to pass ASTM D4952, Qualitative Analysis for Active Sulfur Species in Fuels and Solvents (doctor test). Finished fuels can fail such final specifications when H2S is present. While there are many chemical programs that will readily react with H2S, including caustic, peroxides, nitrites and many types of amines, most of these are neither suitable nor effective for finished products because they will alter important fuel properties such as viscosity, flash point, pour point and ash content. Oil-soluble, nonreversible H2S scavengers are typically the product of choice because they will not adversely affect critical fuel properties and will not add water (and possibly a haze) to a finished fuel.
Crude oil and heavy fuel oil
Crude and heavy residual oils can contain significant concentrations of H2S as a natural component and/or as a result of thermal cracking processes that break apart high molecular weight sulfur-containing compounds to generate H2S. These products often have to be treated with an H2S scavenger before transport to the refinery, when entering storage, or when being transferred between facilities to meet port, terminal, or refinery specifications. Since both of these materials can undergo further processing, the impact of any scavenger or scavenger-H2S reaction byproduct on equipment and processes should be considered. For example, certain amines can distill into crude towers and overhead condensing systems, contributing to salt fouling and related corrosion activity. In these instances, scavengers with noncorrosive reaction products that do not distill overhead are preferred. Because reformer catalysts are typically sensitive to nitrogen content, non-nitrogen or water-soluble scavengers are preferred to minimize the nitrogen content of the hydrocarbon streams processed in the reformer.
Asphalt is the heaviest of the products coming out of the refinery and typically the product in which sulfur compounds concentrate. Because of the high viscosity of asphalt, it must be stored at high temperatures (300 to 400°F). These temperatures promote cracking of sulfur- containing compounds and formation of H2S. For these reasons, asphalt contains extremely high levels of H2S, often exceeding 1% (10,000 ppm). Moreover, asphalt has a high vapor:liquid partition coefficient (400:1), meaning that H2S tends to collect in the vapor phase. The combination of high temperatures, high H2S concentrations, and high viscosity makes asphalt challenging to treat. It is especially critical to lower the H2S content because asphalt is shipped by rail car and tank truck, and exposure of personnel and consumers is a real concern. Because of the elevated temperatures of asphalt applications, water-soluble scavengers generally are not suitable; rather, oil-soluble carriers for scavengers are preferred.