Exploration and production companies are being driven by economic and environmental opportunities to stop flaring.
ROBERT HAWLEY, Merichem Technologies
Driven by rising global demand for natural gas and LNG, countries across all oil-producing continents are addressing the longstanding economic and environmental challenges of removing hydrogen sulfide (H2S) from both gas and oil extraction.
Treating H2S adds costs, so operators prioritize sweet formations when all other attributes are equal. However, areas with high concentrations of sour formations, including the Middle East, Kazakhstan, Canada and the U.S., all contain large untapped reserves.
In the past, extraction operators would plug wells, or build expensive plants to treat sour gas and crude. Today, most operators rely on far more effective and economical solutions.
EMISSION INTENSITY
In 2023, Middle East drilling sites were seen flaring across the Gulf from where COP28, the 2023 UN Climate Change Conference, was being held in Dubai. Routine flaring was banned in the UAE 20 years ago, but satellite images show it continues despite the potential impact on inhabitants and those within proximity of the wells. Gases spread hundreds of kilometers across the region.
In 2024, Texas E&P operators disposed of excess natural gas during a time of oversupply and weak prices by flaring. The Railroad Commission of Texas (RRC), the state's oil and natural gas regulatory body, approved 21 exemption requests from operators in one week alone. Most of the requested and granted permits were for the Permian and Eagle Ford shale fields, resulting in more than four times the flaring level approved in 2023.
According to the International Energy Agency (IEA), approximately 140 Bcm of natural gas is flared globally each year, Fig. 1. World Bank's Global Gas Flaring Tracker, the only global and independent indicator of routine gas flaring, publishes estimates of global flaring levels and tracks progress for governments, oil and gas companies, civil society and international organizations to enhance understanding of the global state of gas flaring. The Global Flaring and Methane Reduction Partnership (GFMR), a multi-donor trust fund, is committed to ending routine gas flaring at oil production sites worldwide, to reduce methane emissions from the oil and gas sector to near zero by 2030.
THE EVOLUTION OF H2S TREATMENTS
Early efforts to treat and remove H2S focused only on the odor-using solutions like soda ash. In 1883, advancements led to the Claus process, which converted the H2S into elemental sulfur, making it a commercially viable byproduct. In 1924, significant developments occurred in Canada's Turner Valley region, where the first plant to chemically scrub H2S from sour natural gas was built, marking a critical step in the industry's understanding of H2S management.
The presence of H2S in upstream operations was recognized as early as the 1940s. The liquid redox process was developed during the late 1950s using vanadium, which became the first liquid-phase oxidation process for converting H2S to sulfur to gain widespread commercial acceptance. In the 1980s, iron replaced vanadium in the liquid redox process. Scavengers became widely used in the 1980s, when they became prevalent in hydrocarbon processing facilities to maintain plant worker safety and productivity and eliminate odor emissions.
LEVERAGING TECHNOLOGY, SCIENCE,AND ENGINEERING FOR UPSTREAM EMISSIONS
Throughout the decades, approaches for treating H2S have advanced, as chemistries and technologies have become more sophisticated. Today, they range from microbiological methods to membrane separation, cryogenic distillation, advanced oxidation processes and scavengers, among others, giving producers the option of sweetening sour gas and oil at lower costs.
Several regenerative and non-regenerative scavenger methods are available today, all of which are applicable to upstream operations, creating expectations for the hydrogen sulfide scavenger market to be worth more than $800 million by 2033.
Adsorbents, commonly referred to as H2S scavengers, are one of the most prevalent and effective methods for removing hydrogen sulfide (H2S) in exploration and production. They can manage various H2S concentrations and selectively adsorb specific compounds from process streams. This capability makes them essential for upstream operations for their ability to purify, separate and ensure environmental compliance.
For small amounts of H2S, liquid triazine has been the technology of choice most often. However, recently, operators are moving away from triazine, due to carryover and fouling issues. When triazine carries over from the gas treatment into the liquid oil, it can contaminate the oil to a level that buyers will not accept or will discount the oil. Because of the issues being seen, some liquid triazine suppliers are now offering triazine alternatives.
Solid scavengers are the historical choice for upstream applications, with higher amounts of H2S. Solid scavengers are also beginning to take over some of the smaller triazine applications where operators are running into carryover and fouling issues.
Originally, solid scavengers were known as iron sponges where wood chips were impregnated with iron oxide to increase the surface area. While the sulfur capacity was good, the use of this particular product declined, due to its pyrophoricity. To overcome this problem, wood was later replaced by clay supports. These products were successful in preventing fire incidents while maintaining high sulfur capacity, but they created a new problem—severe media bridging. From the operational point of view, this bridging or caking phenomena causes a sudden and unmanageable high-pressure drop across the bed, expediting gas channeling, which results in shortened bed life.
More importantly, the cleaning of bridged media replacement creates a safety challenge for operators. Hardened material is extremely demanding to remove, often requiring a jackhammer or hydro-blasting to chisel it away. In many cases, operators are exposed to confined spaces, as they need to enter the vessels to mechanically remove the bridged media to the walls. Bridged media may also contain pockets of H2S, thus creating an additional safety hazard.
In the past decade, an innovative, iron-based solid adsorbent, SULFURTRAP® was developed, patented and proven to work in numerous upstream, midstream and downstream facilities. This new technology overcame the issues with the previous products’ pyrophoricity and severe bridging. The SULFURTRAP solid adsorbent (Fig. 2) was designed to completely remove H2S from any gas stream while imparting low and stable pressure drop throughout the entire bed life.
SULFURTRAP’s proprietary composition and manufacturing process assures free-flowing material at the end of life, making the turnarounds easier and safer for operators and maintenance crews. SULFURTRAP purity allows for a sulfur loading capacity two-to-three times higher than conventional products at a lower cost, offering the lowest OPEX available on the market. SULFURTRAP can be used to remove H2S from any gas stream and from light liquid hydrocarbon streams, with an add-on bonus of removing small quantities of light mercaptans and oxygen, further preventing corrosion issues.
Merichem Technologies supplies the SULFURTRAP media, as well as Skid-Mounted Equipment Packages available for sale or lease. Operators can choose from standardized systems with very short lead times to fully customized systems that meet specific site specifications for a wide range of operating conditions.
NOT ALL LIQUID REDOX IS CREATED EQUAL
Larger gas streams with increased H2S content can also have recovered value, if they can be treated efficiently in a cost-effective manner. This benefits clients in multiple ways. First, they gain the economics of the recovered gas stream that can then be used as a sellable product instead of being flared. That same stream can also be used to power their own operations, thus saving additional costs. Second, they become better economic stewards, as they help prevent the formation of sulfur dioxide (SO2), acid rain and other environmental hazards.
For the even larger gas applications with 1.5 to 20 LTPD of sulfur removed, the iron-based liquid redox technology has been deployed, developed and optimized over the past 45 years. Liquid redox removes H2S from sour natural gas and other gas streams, converting it to elemental sulfur via an iron catalyst reduction-oxidation reaction in an aqueous solution. As with any technology or solution, not all liquid redox technologies are equal.
Merichem Technologies’ LO-CAT® was developed in the late 1970s, Fig. 3. Early iron-based units deployed in the 1980s had technical issues with sulfur sticking to surfaces. These issues have been reduced significantly with major engineering improvements through the turn of the century and further improvements over the past 25 years in the art and experience of keeping sulfur moving with system internals.
LO-CAT uses a chelated iron solution to convert H2S to innocuous, elemental sulfur. It does not use any toxic chemicals and does not produce any hazardous waste byproducts. Its environmentally safe catalyst is continuously regenerated, so operating costs are low, and its aqueous-based ambient temperature process applies to any gas stream. Even with its high removal efficiency, the technology's design has a small carbon footprint. There are no liquid waste streams, so it does not require treatment and disposal, and it's far less costly than alternative liquid redox technologies. Its unique design allows for 100% turndown in gas flow and H2S concentrations.
The process chemistry of the LO-CAT technology is embedded in its name: Liquid Oxidation CATalyst. The overall system oxidation reaction is as follows:
The well-known oxidation reaction is sub-divided into two parts:
(i) REDUCTION: H2S gas absorption, ionization and reaction to make solid sulfur in the liquid solution; and then
(ii) OXIDATION: The liquid solution is oxidized, using air and regenerated for re-use.
For more than 45 years, the LO-CAT technology has been continuously evaluated and refined and has been the favored solution for large upstream, midstream and renewable applications.
VENDOR SELECTION PROCESS
With increasing global demand for LNG, operators have more incentive than ever to capture gas and stop flaring. In addition to the enhanced economics of selling gas, operators can also help reduce emissions and pollutants that cause acid rain. Deciding to invest in an H2S gas removal technology can be onerous, as operators analyze what questions to ask potential vendors to determine their best path forward.
The selection process should take essential capabilities into consideration, rather than simply a product purchase. Often, vendors will only compare their cost to triazine, and it’s up to clients to understand what other offerings are available to them, often at significant cost savings. The selected vendor must have the capacity to become a strategic partner, considering factors such as platform maturity, service and support capabilities and company track record, as well as specific use cases that call out pounds of sulfur and sulfur dioxide produced annually, and the daily amount of gas avoided. By arming themselves with as much knowledge as possible, clients can make the best, most informed decision to solve their H2S treatment problems. WO
ROBERT HAWLEY brings more than 40 years of chemical engineering strategy, sales, marketing, and engineering design experience to his role as Senior Technology Licensing Director for Merichem Technologies. During his 11 years with Merichem, his focus has been on selling and designing sulfur plants. Mr. Hawley has a BS degree in chemical engineering from Cornell University and an MBA from Duke University.