Hydrogen Sulfide Management: Part I of III
Posted by D Nathan Meehan June 13, 2012

In this and the following two blog posts we talk about hydrogen sulfide. Reservoir engineers often talk about H2S as a 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.

Hydrogen sulfide (H2S) is a naturally occurring gas contained in many of the world’s crude oils. It is also formed in the refining process by the degradation of sulfur-containing compounds in crude at high temperatures. New global market demands are expanding hydrocarbon processing and the distribution infrastructure. At the same time, the average sulfur content of crude oils being processed in the world’s petroleum refineries continues to increase (Fig. 1).

The expansion of hydrocarbon volumes is matched by real problems that relate to higher concentrations of reactive sulfur compounds such as H2S. Although many of the challenges posed by high levels of reactive sulfur in crude oil and refinery products are known, the growth of processing, transportation and storage infrastructure can result in hazards and operational concerns. A review of the significant dangers and operating problems posed by H2S creates a better understanding of available mitigation options as well as how those options can be tailored to meet particular needs. Proper treatment of H2S with an appropriate H2S scavenger will improve safety, environmental compliance, product quality and process integrity management.

Hydrogen sulfide concerns

Increasing world demand for crude oil coupled with the increasing concentration of H2S in the oil and products formed from processing hydrocarbon is placing greater emphasis on the safety, environmental and operational concerns associated with hydrocarbon management. Refineries and storage facilities, such as tank farms, are likely to encounter problems specific to the handling of crude oils, intermediates and refined products that contain or generate H2S. Heavy oils, including crude oil, residual fuel and gas oil, tend to have large concentrations of H2S. This becomes a concern if these products are to be stored for an extended time or transported. Lighter products leaving the refinery may also be contaminated with H2S that distills into them during the refining process. While safety remains the primary concern when dealing with H2S, other H2S-related issues can create additional challenges for these facilities.

In addition to the risk of direct harm to exposed personnel, products and equipment, environmental considerations such as odor and emissions control must also be addressed. Changing demographics mean that more communities may be susceptible to nuisance odors from nearby facilities. Depending on specific local and national regulations, penalties and fines can result from exceeding either H2S or sulfur oxide (SOX) emissions standards.

From an operational standpoint, off-spec products can lead to difficulties in meeting customer commitments and in accumulation of unsalable inventory. Moreover, H2S is highly corrosive and can degrade both process and storage equipment, potentially reducing throughput and increasing the difficulty and cost of integrity management programs.


Safety for personnel and for the community is the foremost consideration when dealing with crudes or other hydrocarbons containing large amounts of H2S.

H2S is especially insidious because it deadens the sense of smell at concentrations as low as 30 parts per million (ppm). Death can occur within a few breaths at low concentrations of 700 ppm. Hydrocarbons containing even a few ppms of H2S can produce headspace concentrations in excess of these levels.

H2S is a gas at typical storage temperatures and equilibrates between liquid and vapor phases. Distressed cargoes containing high H2S levels can easily generate percent levels (parts per hundred) of H2S in storage tank and transport vessel headspaces. Certain tank conditions (increased liquid volume, agitation and high temperatures) cause deterioration of this already hazardous situation by changing the partition coefficients (the ratio of H2S in the liquid and vapor phases of the hydrocarbon). For example, as a tank fills with H2S-laden oil, the volume of headspace decreases, increasing the relative concentration of H2S in the headspace. Fig. 2 shows the effect of tank level on headspace H2S content for one hydrocarbon storage tank.

Fig. 3 illustrates the measured effects of temperature on tank headspace H2S levels. A crude oil tank with 450 ppm of H2S in the vapor phase at 120°F (49°C) can have nearly 1,500 ppm at 300°F (149°C). In fact, H2S can be generated by thermal cracking of higher molecular weight sulfur compounds at temperatures as low as 200°F (93°C).

In summary, small concentrations of H2S can be deadly to exposed personnel. Other factors such as temperature and tank-filling practices affect H2S concentrations and can create a more hazardous situation.

Environmental and regulatory concerns

In recent years, residential communities and hydrocarbon storage facilities have become closer in proximity. At the same time, fugitive emission/environmental regulations in many areas have become more prevalent. These factors result in an increase in the number of complaints about odors issued to terminals by residents. An increase in the use of higher-sulfur crudes will compound this problem. Nuisance odors are caused by many types of sulfur- and nitrogen-containing volatile compounds that are present in these crudes stored at terminals. These compounds can be present in very small quantities or within the safety level for the particular compound and still be unpleasant to workers and neighbors.

Government agencies have implemented many regulations on terminals, refineries and ports that cap the amount of H2S a product or a storage vessel headspace may contain. These rules may stem from emissions concerns or may be driven by air pollution legislation. Of recent interest, many U.S. refinery flare gas systems are affected by environmental regulations that limit H2S content in fuel gases sent to combustion devices. For example, the New Source Performance Standards (NSPS) for Petroleum Refineries, Subparts J and Ja, 40 C.F.R. 60.100 limits the permissible H2S in gas burned in a flare to 160 ppm H2S on a rolling three-hour average.

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D Nathan Meehan