Feb-2025
Process control and energy management in the 21st century
Key online measurements and technologies for safe and optimal refinery operation, highlighting potential energy savings that can lead to reduced CO2 emissions.
Jochen Geiger
Ametek Process Instruments
Viewed : 112
Article Summary
Refinery working conditions are changing due to the increasing processing of sour crude oil as the availability of sweet crude diminishes. As a result, refiners require more flexibility because, in addition to environmental impact monitoring, sulphur dioxide (SO₂) emissions have to be reduced without expending more energy (as this can increase overall CO₂ emissions). All of this brings significant challenges to the operators of a refinery.
Behind the scenes, there is a growing focus on analyser solutions and the next generation of process instrumentation, which will be reviewed with a specific emphasis on multicomponent/multisensor technologies and their corresponding process control improvements.
The foundation of this methodology is a holistic perspective on analyser design. Rather than adhering to one-size-fits-all solutions, analysers are tailored to each application. This careful customisation enhances accuracy and efficiency, ensuring a seamless fit.
Along with this holistic approach is the integration of tailored sampling systems. Aligning analysers with sampling systems will mitigate potential complexities in sample conditioning systems. Streamlining workflows and boosting operational fluidity, strategic technology selection is a hallmark of this methodology (see Figure 1).
Measuring high sulphur-containing crude samples
The supply of crude oil is becoming more challenging in several geographic regions. Crude compositions can change due to supply methods, which may shift from pipelines with a stable composition to ocean vessels with variable compositions, requiring more refinery flexibility. In addition, it is essential to monitor the environmental impact and reduce emissions to comply with regulatory requirements.
Maximum and minimum sulphur concentrations 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 sulphur concentration. For example, if a refinery is designed to operate at a sulphur level of 3-4% and the incoming crude is at 5.5%, a modified blending control system will be required.
For many refineries, sulphur level measurements in the parts per million (ppm) range are an important part of the final product quality control system. When feedstock sulphur concentrations are changing, it is necessary to measure the sulphur concentration in the crude oil itself. Not only is the incoming crude oil sulphur concentration different, but the viscosity of the crude will also alter, resulting in a change to the final product’s viscosity.
When measuring the percentage level of sulphur in crude oil, the viscosity of the stream being introduced to the process gas analyser 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 analysers. Therefore, selecting the appropriate measurement solution is a critical consideration. Most existing online instruments are based on X-ray or ultraviolet (UV) fluorescence, which are analytical methods designed for low- and mid-level sulphur 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 and 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 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. Sulphur in bunker fuel can eventually be oxidised into SO₂ when burned and must be reduced.
For a long period, bunker fuel was an extremely heavy fuel that only became a flowing liquid at high temperature and was expected to have high levels of sulphur. Since 2020, the International Marine Fuel Specification (ISO 8217:2024) has limited the sulphur 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 FCC inlet, where heavy and light VGO is obtained. For optimal FCC operation, it is essential to control the amount of incoming sulphur to stay within design specifications. Measuring sulphur at the outlet of the FCC unit provides assurance that operations are as intended or helps identify an issue that has developed and should be addressed.
Process analyser solution options for sulphur contaminants include X-ray transmission measurements). These are not the only methods for monitoring sulphur, SO2, and/or 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 emission points. Many plant operational systems are designed based on an expected range of sulphur components and can quickly be damaged or become inefficient if those ranges are exceeded.
Purchasing contracts limit the amount of sulphur 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 and lethal to humans, and SO₂ is known to contribute to acid rain development. Measurements of the amount of each of these compounds are required to ensure that emissions stay below specific limits.
Moisture and corrosion
The measurement of moisture in gases is one of the more complex and difficult applications found in industrial processes. Moisture, or water traces in combination with other components, can easily become a very corrosive mixture, such as moisture in CO₂ or together with H₂S, affecting stationary sections of process equipment such as pipes, reactors, and vessels. Another important factor is that water traces can negatively influence process yields. Water concentrations may lead to line freezing due to cold weather and other factors.
Moisture measurement is different due to the fact that every analyser, especially process analysers, needs to be verified and calibrated. The reading of the instrument can be higher than the concentration expected by the process engineer. The protocol with every other gas analyser is to connect a bottle with a certified calibration gas to the instrument, verify the reading to be correct, or see that an adjustment is needed. However, this cannot be done with a moisture analyser.
Water concentration in the cal (calibrated) gas bottle will vary depending on the pressure and temperature of the bottle. It is possible only under laboratory conditions to have a proven water concentration in a background of nitrogen (N₂) or methane (CH₄). The given concentration in a cal gas bottle is only valid at a very limited pressure window and only true and certified at one temperature. That makes the use of such a bottle in the field impossible.
Add your rating:
Current Rating: 3