H. Burton, M. GAURA, J. GEIGER, AMETEK Process Instruments, Newark, Delaware
Whether a refinery process involves the creation of fuels from crude oil or the production of biogas, process analysis can help to address the many challenges involved in operations. These challenges will be different for every application, but central to them all are three key outcomes:
Process analysis provides an effective solution to help keep fuel plants operating efficiently and safely, delivering a clean product while operating within regulatory limits.
Processing different crude qualities in refinery analysis applications. Working conditions for refineries are changing, and these changes are presenting new challenges. In several geographical areas, the supply of crude oil is becoming more difficult. Crude compositions can change—including supply methods, which may shift from pipelines with a stable composition to ocean vessels with variable compositions—requiring more flexibility from refiners.
In addition, it is essential to monitor the environmental impact and reduce emissions to comply with regulatory requirements.
These factors create significant challenges for refinery operators. Efficient and environmentally responsible refinery operations are, in many cases, designed for a specific range of crude oil components. These are particularly focused on maximum and minimum sulfur concentrations, which can vary between 1% and 6%.
Not only are the chemical, catalytic and thermal reactions within refineries dependent on stable crude oil, but piping specifications must also be considered regarding the maximum permitted sulfur concentration.
For example, if a refinery is designed to operate at a sulfur level of 3%–4% and the incoming crude is at 5.5%, a modified blending control system will be required.
For many refineries, sulfur level measurements in the parts per million (ppm) range are an important part of the final product quality control system. When feedstock sulfur concentrations are changing, it is necessary to measure the sulfur concentration in the crude oil itself.
Not only is the incoming crude oil sulfur concentration different, but the viscosity of the crude will also change, resulting in a change to the final product’s viscosity.
When measuring the percentage level of sulfur in crude oil, the viscosity of the stream being introduced to the process gas analyzer is one of the primary hurdles to overcome. In many cases, the fluid only remains liquid at temperatures > 150°C, which is a challenging temperature for many complex process gas analyzers. Therefore, selecting the appropriate measurement solution is a critical consideration.
Most existing online instruments are based on x-ray fluorescence or ultraviolet (UV) fluorescence, which are analytical methods designed for low- and mid-level sulfur measurements in lighter sample streams.
For crude oil, heavy vacuum gasoil (VGO), residuals or heavy bunker fuel, it has long been common practice to use instruments based on a radioactive detector technique. However, this has become increasingly difficult to select and implement, as it presents the system designers and end users with significant safety factors to consider, as well as complicated certification processes.
An alternative method is x-ray transmission, which offers the benefit of no permanent radioactive source, eliminating many of the safety concerns and certification issues. In addition, the entire measuring system is suitable for heavy fuels, as it can be maintained at temperatures up to 250°C. Almost no filtration system is required to protect the measuring system from potential impurities in the stream. All this makes the blending control simpler, with lower maintenance requirements.
Bunker fuel measurements occur quite far downstream in the refinery but have recently become more important as part of the global effort to reduce harmful emissions from points of use. Sulfur present in the bunker fuel can eventually be oxidized into sulfur dioxide (SO2) when burned and must be reduced.
For a long time, this was extremely heavy fuel that only became a flowing liquid at high temperature and was expected to have high levels of sulfur present.
Since 2020, the International Marine Fuel Specification has limited the sulfur concentration of marine bunker fuel to 0.5% (the previous limit was 4.5%). As a result, more accurate and controlled blending is required.
Another critical measurement point is the inlet of the fluid cracker, where heavy and light VGO are obtained. For optimal operation of the fluid cracker, it is essential to control the amount of incoming sulfur to stay within design specifications. Measuring sulfur at the outlet of the cracker provides assurance that operations are as intended or helps to identify an issue that has developed and should be addressed.
Process analyzer solution options for sulfur contaminants. X-ray transmission measurements are not the only methods for monitoring sulfur, SO2 and/or hydrogen sulfide (H2S) measurements in refineries, gas plants, chemical production environments, and even steel mills and coke plants.
UV and infrared (IR) technologies are also used to measure these undesired byproducts along production pathways, in the final product and at emissions points. Many plant operational systems are designed based on an expected range of sulfur components and can quickly be damaged or become inefficient if those ranges are exceeded.
Purchasing contracts limit the amount of sulfur components that may be present in the purchased products, and variances can require additional processing or even create purchasing disputes.
Finally, the release of H2S and SO2 are both highly regulated emissions—H2S is extremely toxic/lethal to humans and SO2 is known to contribute to the development of acid rain. Measurements of the amount of each of these compounds are required to ensure that emissions stay below specific limits.
Modern gas/liquid measuring instrumentation helps keep plants operating in an efficient, clean and safe manner, and should be maintained and updated to the best-available technology, when possible.
Analysis in biogas production. Biogas and bio-methane production have grown in prominence over recent decades. Sales of biogas reached nearly $68 B in 2022, and this figure is expected to increase by 4.7% between 2023 and 2028.1 As the sector continues to thrive, producers will find it imperative to maximize the amount of usable product (i.e., methane gas). However, meeting the escalating energy demands of a worldwide economy brings with it the added challenges of abiding by environmental regulations.
In the European Union (EU), a directive has been implemented to target a 40% reduction in greenhouse gas (GHG) emissions by 2030.2 The biogas industry is likely to shoulder some of that burden.
With biogas producers seeking to recapture two of the most common GHG emissions—methane (CH4) and carbon dioxide (CO2)—carbon capture and process control will be instrumental in cementing the industry’s place as a mainstay renewable energy source.
To ensure they can maximize product output while also meeting environmental standards, producers will find opportunities in the deployment of process analyzers that work in tandem with their biogas treatment units. Not only do process analyzers provide a method of monitoring gas composition, thereby ensuring that unwanted chemical species are removed, but they also help to protect treatment equipment from harmful corrosive components.
Biogas production uses anaerobic digestion (AD), which is the degradation and stabilization of organic substances in an oxygen-less environment. This biogasification technique is useful because its inherent operation helps in the recovery of GHG molecules (CO2 and CH4) and reduces the abundance of waste products and pathogens.
Waste collection serves as the starting point in the process, with food and plant matter, manure, wastewater and sewage being separated into usable biogas feedstock. Size reduction or contaminant removal may also take place during this time depending on the type of digestion (solid or liquid). Afterwards, feedstock is then mixed and stored before digestion.
AD encompasses several forms, such as lagoons that utilize a cover to trap CH4 emissions. More commonly, complete mixers are used, implementing hydraulic mixing systems to blend manure with water and allowing microorganisms (such as methanogens) to break down this material and respirate the desired biogas.
Bacterial hydrolysis is central to digestion, as it allows feedstock monomers—such as glucose—to be broken down into simple sugars and amino and fatty acids. The subsequent processes of acidogenesis, acetogenesis and methanogenesis all culminate in the production of CO2 and CH4 (Eq. 1):
C6H12O6 --> 3CO2 + 3CH4 (1)
Biogas captured from this digestion is transported from the digestor to a gas treatment system to remove any remaining moisture, siloxanes, ammonia, oxygen, carbon monoxide and nitrogen. During treatment, it is also critical that H2S is removed—or mitigated—prior to the gas entering the grid. At this point in the biogas process, a process analyzer can be a critical tool in the monitoring of sulfur species.
Environmental regulations determine the concentration limits of any chemical species deemed harmful to the public, energy grid and environment. These standards will, of course, differ depending on the respective country or territory. In the U.S., the American Biogas Council states that it is ideal—before biogas natural gas grid injection—that CO2 be maintained at less than 2 mol%, H2S at 9 ppm and total sulfur at 35 ppm.3
European biogas markets follow similar guidelines, with H2S being limited to 0 ppm–10 ppm. Producers will also want to monitor the chemical composition of their biogas during compression for efficiency purposes. As the goal is to maximize storage of natural gas or CH4, an analytical instrument can ensure that both the compression and treatment units are adequately providing a serviceable product.
The role of process analysis in the biogas market. Process analyzers are useful to address both the high- and low-pressure sides of biogas analysis. Electrochemical sensors are widely used measurement tools within the biogas industry and use porous membranes that allow the chemical of interest to permeate an electrode situated in the sensor, oxidizing the gas and generating a charge (current).
The concentration of the detected gas can be observed by this current output, with high linearity at low concentrations. More importantly, these sensors can operate within high-pressure environments commonly seen during biogas compression.
Users may also want an analyzer capable of detecting upsets during biogas upgrading. Options available to meet that requirement include UV process analyzers and gas chromatographs (GCs) that can measure at the low-pressure side of biogas operation (typically before exiting to the natural gas grid). As electrochemical sensors can be damaged by sulfur chemicals (e.g., H2S), having an alternative for gas measurement can provide additional assurance of operation.
GCs work by using a carrier gas to transport the biogas through an elution column. The gas is vaporized within this column, and each subsequent chemical component is separated throughout the column at different times. The GC then measures each resulting chemical against a database, where it characterizes the chemical and its concentration. GCs are effective measurement tools and can measure with both high specificity and sensitivity (even at low concentrations).
With UV analyzers, when a sulfur species is excited with UV radiation (UV light), it will produce an absorbance response that is detectable in the deep UV (< 280 nm). These analyzers, if calibrated accordingly, have the capacity to measure several sulfur-bearing species at once, and at a faster response time than typical GCs.
Analyzer options also exist that blend the two methodologies together, using the separation approach of the GCs elution column, while implementing the UV irradiation method of a UV analyzer. This combination allows for faster response times than that of a GC, while still affording the low-concentration specificity of a GC.
If required, CO2 can also be monitored with IR-capable analyzers, such as those using IR emitters or Fourier transform IR (FTIR). Should producers in the industry need assurance, process analyzers can be an extremely worthwhile investment.
Takeaway. Process analyzers are an essential tool for both the crude oil and biogas industries. By monitoring fuel composition, process analyzers can help to ensure that unwanted contaminants are removed and help protect treatment equipment from harmful corrosive components.
With the continuing growth of the biogas industry, in particular, the use of process analyzers is likely to become increasingly important. By using the wide range of process analyzers available, fuel producers can improve the efficiency and environmental impact of their operations and help to ensure that their products meet the requirements of environmental regulations. HP
LITERATURE CITED