June 2021, Vol. 248, No. 6


Sulfur Removal Solutions for Gas Gathering Systems

By Cyndie Fredrick, Senior Vice President & General Manager, Merichem Process Technology  

There are more than 1,300 pipeline operators throughout 120 countries of the world moving gaseous or liquid products across 2,175,000 miles (3,500,000 km) from production or extraction sites to refineries.   

Pipelines are considered one of the safest, most reliable, most efficient and economic means of transporting large quantities of natural gas, crude and refined petroleum products.    

However, sulfur contaminants in the form of hydrogen sulfide (H2S) and mercaptans (RSH) pose significant safety, operational, environmental and compliance problems. They must be removed to meet quality specifications for both pipelines and downstream facilities.   

There are several options available for providing this treatment, including scavengers, homegrown solutions and proprietary equipment offerings.  

H2S is produced as a result of the microbial breakdown of organic materials in the absence of oxygen. It also occurs naturally in crude oil and natural gas.  

RSH, also found in crude oil and natural gas, exhibit a toxicity similar to, but less than that, of H2S. In addition to the danger to humans, they can be corrosive to assets and create chemical reactions with other hydrocarbons or fuel system components.   

The value of the hydrocarbon comes from its ability to be refined and turned into usable end products. Products with increased concentrations of contaminants reduce their value significantly. Measuring and removing undesirable contaminants helps producers meet pipeline requirements and traders meet contract specifications for products sold to end-users.  

Gathering systems often are used to collect oil and gas from wellheads and move it to a processing plant or to a major transmission line. They either use small, individual wellhead compressors or large central units that handle multiple wells or even an entire field.    

Natural gas liquids (NGLs) also are often combined into larger streams to provide improved processing options. As the flows of gases or liquids are gathered, the level of sulfur contaminants in the blended stream could rise above the maximum concentration allowed for the downstream units or larger pipelines. At this point, treating options must be reviewed to remove the higher levels of H2S and/or RSH.  

Treating high levels of contaminants in the field can be quite expensive depending on the method used for treating. To exacerbate the issue, where one pipeline may show no or slight traces of sulfur content, the accumulation of products – whether from hundreds of miles of pipelines from hundreds of wells or a few small pipelines from a handful of wells – will have a propensity to show intolerable levels of H2S and RSH, and potentially traces of carbon dioxide (CO2) or carbonyl sulfide (COS).   

This makes gathering stations the most ideal location for treatment where the combined sulfur additives are compounded, and it becomes more realistic to have capital equipment in place to treat the combined streams. Sulfur content, which is expressed as weight percent of sulfur in oil, typically varies from less than 0.05 wt% to more than 10 wt%, but it generally falls in the range of 1 to 4 wt%. Anything with more than 4 wt ppm sulfur needs to be treated.  

Throughout the history of the oil and gas business, various treatment methods have been used to desulfurize sour streams. Selecting the optimum treatment for removing impurities is a challenging task for any pipeline operator. Hydrogen sulfide scavenger technologies are sometimes considered an option.   

Scavengers are typically a liquid or solid commercial additive that react with H2S, removing it from the stream. When the process is completed, in most cases, the chemical agents cannot be reused, which means the used materials must be replaced constantly. Scavengers can be economical for small amounts of sulfur. For large amounts of H2S, however, they are expensive compared to other large capital equipment investments.    

They can sometimes cause downstream problems in equipment as the scavenger falls out of solution and plugs equipment. Some spent material also can be hazardous and could be pyrophoric.  

There are “homegrown” caustic treating options, but these often come with no guarantees.  The homegrown version often consists of vessels with simple mix valves and some amount of settling time. These may work to some extent, but can still result in poor treating, carryover, corrosion and other problematic results.    

Because the midstream world works as a partnership between upstream and downstream, they require advanced reliable technologies and knowledgeable service providers that are agile and quick to respond to operators’ needs.   

One option is the use of Merichem’s Thiolex units, which can remove RSH, H2S, CO2, COS and elemental sulfur, using a non-dispersive fiber film contactor (FFC) as the mass-transfer device.  

Typical treatments for removal require 14-20 wt% sodium hydroxide (NaOH) (caustic). Caustic will also remove CO2 and some elemental sulfur. For COS removal, the system uses monoethanolamine (MEA)/caustic, which hydrolyzes COS.  

Caustic extraction units specifically designed for gas gathering systems are fully automated and require minimal operator support. They operate efficiently over a wide range of throughputs and operating conditions.   

This process is not limited by hydrocarbon-to-caustic ratios that typically limit counter-current systems. An ideal situation is operation over a wide range of caustic strengths, from 1 wt% to 15 wt%, which achieves a high utilization of the caustic due to the efficiency of the mass transfer.    

Author: Cyndie Fredrick has more than 25 years of experience in downstream, midstream and technology licensing. She is the senior vice president and general manager of Merichem Process Technology. Fredrick holds a bachelor’s degree in chemical engineering from the University of Arkansas and an MBA from Rice University.  

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