Hydrogen Sulfide Remains a Persistent Challenge for Pipeline Operators
R. HAWLEY, Merichem Technologies, Houston, Texas (U.S.)
The U.S. midstream pipeline network spans more than 3.3 million (MM) miles, representing a vital link for safely and efficiently transporting gas from production areas to midstream gas plants, liquid oil to refineries, natural gas liquids (NGLs) to fractionators and then on to individual consumers.¹ Pipeline network assets are designed to ensure the continuous flow of energy sources that support modern economies and infrastructure, and are crucial for energy security by diversifying supply and stabilizing energy markets.
Pipelines that transport natural gas, oil and NGLs can be contaminated by various solids, liquids and gases originating at the wellhead and along the way of the subsequent transportation infrastructure. Extracted gases typically contain varying amounts of hydrogen sulfide (H₂S), a byproduct of the geological decomposition of organic matter and reduction of sulfates by bacterial action. In aggregate, and especially in countries that have historically refined sour crude, feedstocks now contain increasing levels of H₂S, which is of great concern to anyone transporting it through their pipelines.
Extracted natural gas can contain very high concentrations of H₂S, in some cases exceeding 10%. However, even very low levels of H₂S can cause excessive corrosion and degrade equipment in a midstream facility.
SEE MORE: New H₂S Treatment Achieves 99% Removal in Permian Trial
The maximum allowable limit for H₂S in gas pipelines is 4 parts per million (ppm), which is regulated by the U.S. Pipeline and Hazardous Materials Safety Administration (PHMSA). This limit is for both human safety and to prevent corrosive effects on the pipeline, and is part of the regulations for internal corrosion control.
H₂S is heavily regulated in pipelines so corrosion from the gas is not the primary cause of most pipeline failures; however, it can severely damage infrastructure, leading to costly repairs and safety hazards. The economic and environmental impacts of such failures are evident, but the human and environmental factors ultimately present the most severe consequences.
The vital task of removing H₂S across the pipeline network requires fast, proven and cost-effective solutions supported by quick delivery and reliable technical services for the life of the technology solution. Liquid redox technology was developed almost 50 yrs ago and has become a key part of the solution for treating H₂S. There are different types of liquid redox solutions available: the key is finding the one with the longest resume of success at varying sizes, specifications and locations to ensure the best solution for each installation.
The History and Chemical Processes of the Author’s Company’s Liquid Redox Technologyᵃ
The proprietary liquid redox technologyᵃ was first developed in the 1970s as a chelated-iron (Fe) process to provide an isothermal, cost-effective method for conducting the modified Claus reaction, and was first used commercially in 1978. Beginning with the oil and gas industry, the technologyᵃ has been continuously upgraded and modified to enable broader use across other industrial segments and markets, such as petrochemicals, metals, water and wastewater treatment, and carbon dioxide (CO₂)-based products such as food and beverages. More recently, alternative and conventional energy sources such as stranded offshore gas, shale gas, gasification syngas and biogas have also successfully utilized the proprietary technologyᵃ for sulfur recovery. It is also a valuable technology for pipelines that must sweeten sour gas.
The process uses an Fe chelate as a catalyst to promote the overall reaction. In the absorber, the sulfide ions are oxidized by the Fe ions.
The equations H₂S + ½O₂ → H₂O + S and H₂S → 2H⁺ + S⁻² represent the H₂S absorption into the aqueous, chelated Fe solution and its subsequent ionization. The equation Fe⁻³ + S⁻² → 2Fe⁺² + S represents the S⁻² ion oxidation to elemental sulfur and reduction of Fe⁺³ to Fe⁺². In the oxidizer, reduced Fe ions are regenerated by oxidation with dissolved oxygen for reuse, as shown in this equation:
2Fe⁺² + ½O₂ + H₂O → 2Fe⁺³ + 2OH⁻
The function of organic chelating agents is to inhibit the precipitation of ferric hydroxide or ferrous sulfide. The Fe⁺²/Fe⁺³ reactions are very rapid, so minimal excess S⁻² ions are carried over into the oxidizer. The side reaction does not form the unwanted thiosulfate salt byproduct.
Also, excess dissolved O₂ is limited by the presence of Fe⁺² ions in the regenerated solution. The presence of high CO₂ partial pressures in the process gas stream reduces the pH of the proprietary solution. Thus, a buffer solution such as ammonium, sodium or potassium carbonate is added. Since the reaction rate of H₂S absorption is much faster than that of CO₂ absorption, high selectivity for H₂S removal can be achieved.
Fe was chosen for this proprietary technologyᵃ solution because it is inexpensive and safe to operate. The Fe chelate catalytic solution does not participate in the reaction. Its role is to retain Fe ions in solution, as both Fe⁺² and Fe⁺³ are not very stable or soluble in aqueous solutions. Usually, at low concentrations, Fe will form precipitates as either ferrous sulfide (FeS) or ferric hydroxide [Fe(OH)₃]. Chelating agents are organic compounds that bind to Fe ions, preventing precipitation and keeping them in solution throughout the operation.
The advantages of the author’s company’s liquid redox technologyᵃ include its use of inexpensive catalysts, stability at any pH, low catalyst consumption and tolerance of CO₂, ammonia and other gas contaminants. The process ensures almost complete H₂S removal from H₂S-containing acid gas streams. The process operates under mild reaction conditions and does not require high temperatures or pressures, resulting in lower energy consumption compared to other processes.²
Case Example 1
With the recent surge in global demand for natural gas, especially liquified natural gas (LNG), the Haynesville, Permian and Eagle Ford basins in the U.S. are all expanding drilling operations for gas. These basins all contain significant pockets of H₂S contamination that must be removed from the gas in midstream plants before it is sent to the LNG plants on the Gulf Coast.
The liquid redox technologyᵃ has operated in each of these basins for decades. Recently, a unit was started up in Haynesville for a 70-million standard cubic feet per day (MMft³d) amine acid gas stream with 0.4% H₂S removing up to 10.5 long tons per day (ltpd) of sulfur. This client purchased new sour gas production to capture market space knowing that the gas would have to be treated.
They used triazine treatment as an intermediate solution and experienced typical issues like plugging and carryover. They also incurred significant expenses with triazine due to its high cost for larger quantities of H₂S treatment. With these units up and running, the unit performance was greatly improved and expenses were reduced significantly. The operation became a model for future operators shipping treated gas through pipelines.
Case Example 2
A client in the central U.S. is producing a CO₂-rich natural gas stream containing significant H₂S in the feed. Previously, the gas was sent to flare without recovering any value or reducing sulfur emissions. To make the gas stream viable for pipeline transport, the processer needed to remove only the corrosive H₂S constituent without removing the CO₂.
The H₂S that was previously being burned was subsequently creating sulfur dioxide (SO₂) emissions harmful to the atmosphere. With energy-efficiency, environmental sustainability and cost all being major considerations, the liquid redox technologyᵃ was the only appropriate choice over other alternatives for selectively removing H₂S.
Five identical trains have been deployed, thereby reducing the unwanted H₂S contaminant to minimal levels. The treated gas from three of the trains was compressed and sent to commercial supply pipelines for consumers in that area. Following this successful implementation, the other two H₂S removal trains are expected to follow a similar path in the near future.
Takeaways
H₂S is the most specified contaminant by transportation operators and downstream users. The capture and conversion of H₂S has been one of the long-standing economic and environmental challenges of the past century, as evidenced in the wide breadth of techniques and materials developed to capture H₂S from various streams.
When gas emerges from wells that are tainted by H₂S, the suitability for sulfur removal solutions depends on numerous factors, such as operating conditions, cost, space and weight restrictions, gas volume, inlet H₂S content, outlet specifications and technological maturity. Many of the technologies and solutions are often expensive and complex.
The author’s company’s liquid redox technologyᵃ offers a well-developed and economic solution that has been in commercial use for almost 45 yrs. It provides 100% turndown capability with respect to H₂S concentration, flowrate and sulfur loading, achieves single-stage removal efficiencies greater than 99.9% and can process any type of gas stream.
NOTE
ᵃ Merichem Technologies’ LO-CAT® process
LITERATURE CITED
- U.S. Department of Transportation, “Fueling America’s economy: Legislation to improve safety and expand U.S. pipeline infrastructure,” January 2024, online: https://www.transportation.gov/fueling-americas-economy-legislation-improve-safety-and-expand-us-pipeline-infrastructure
- Royal Society of Chemistry, “Latest technological advances and insights into capture and removal of hydrogen sulfide: A critical review,” March 2024, online: https://pubs.rsc.org/en/content/articlehtml/2024/su/d3su00484h#cit276
About the Author
ROBERT HAWLEY is the Senior Technology Licensing Director for Merichem Technologies and has more than 40 yrs of experience in chemical engineering strategy, sales, marketing and engineering design. During his 11 yrs with Merichem, his focus has been on selling and designing sulfur plants. Hawley earned a BS degree in chemical engineering from Cornell University and an MBA from Duke University.