Preparing wet scrubbing systems for a future with NOx emission requirements

This paper examines what refiners may want to consider today in preparation for a future that may have more stringent NOx emission requirements for major process units and combustion sources.

Scott T Eagleson and Nick Confuorto
Belco Technologies Corporation

Viewed : 2943

Article Summary

Many of the world’s refiners already must limit NOx emissions to very low levels that are many times lower than those Indian refiners face today. Achieving very low NOx emissions requires specialised technologies and some forward planning to work well with refining processes and other emissions control technologies. Indian refiners may want to consider this when modifying processes and adding new technologies to meet today’s stringent emission requirements for particulate, metals, CO and SOx emissions. Care can be taken now so today’s work enhances and does not inhibit tomorrow’s NOx control. Using the fluid catalytic cracking unit (FCCU) as a basis for discussion, the paper looks at both how NOx emissions are produced and the proven options for controlling them. Synergies with the FCCU process and with technologies used for controlling other emissions are considered.

Emissions, Regulations and Controls
Nitrogen oxides (NOx) emissions to the atmosphere from stationary and mobile sources contribute significantly to a variety of environmental problems. These include ground level ozone formation (photochemical smog), acid rain and elevated fine particulate levels. In many countries, there are regulations addressing the control of NOx emissions from many stationary and mobile sources.

For large stationary combustion sources, regulatory requirements to reduce NOx emissions have generally lagged behind regulatory requirements to reduce atmospheric emissions of particulate matter (PM), metals, sulphur oxides (SOx), and carbon monoxide (CO).  Regulatory requirements have also generally targeted the largest point source emissions first. In time moving on to require control for increasing smaller emission sources. Refineries, not being the largest emission sources and having many smaller point sources within a single facility, were not typically the first of the large stationary combustion sources to face emission reduction requirements.

Now, however, refiners in many countries are seeing that they now need to control and reduce emissions. A fluid catalytic cracking unit (FCCU), when present, is generally the single largest point source of emission in a refinery. The FCCU also contributes greatly to a refinery’s product yields and profitability. Although this discussion focuses on the refinery FCCU, the LoTOx process can be applied to many other refinery emission sources such as, for example, fired heaters and boilers.

Refineries in the USA face some of the most stringent emission requirements in the world. Table 1 reflects the typical FCCU emission requirements faced by many refineries in the USA. These refiners use many different technologies to meet these requirements.

Up until about 2005, most USA refineries were required to control CO, PM and SOx emissions (not NOx) from their FCCUs to very low levels.  Combustion techniques, combustion equipment and FCCU catalyst additives were commonly used to minimise CO emissions. PM and SOx emissions were controlled with many different technologies. These included electrostatic precipitators (ESPs) for PM control, Thirds Stage Separators (TSS) for PM control, wet scrubbers for combined PM and SOx control, feed/process changes for SOx control, and FCCU catalyst additives for SOx control. Many of these were used in combination to achieve the required results for CO, PM and SOx emissions.

As requirements for controlling NOx emission to very low levels evolved around 2005, refiners needed to find how to best meet the new NOx emission requirements while minimising impacts on FCCU run life, minimising installed/operating costs and how to best fit in with existing emission control systems. Generally these NOx control solutions involved process modifications and/or the use of add-on control technologies. The process modifications are not discussed as part of this paper, but include changes in feeds, temperatures, reactions, catalysts and/or catalyst additives.

Three add-on NOx control technologies were mainly used to meet these more stringent NOx emission requirements. These are Selective Non Catalytic Reduction (SNCR), Selective Catalytic Reductions (SCR) and Low Temperature Oxidation (LoTOx). Each is discussed below.  A brief comparison of these approaches is provided in Table 2.

NOx Emissions from FCCUs
FCCU NOx emissions result both from nitrogen in the FCCU feed stocks (feed NOx) and from nitrogen in the combustion air (thermal NOx). The main contribution comes from the oxidation of feed stock nitrogen during coke combustion in regeneration. The temperatures and excess oxygen levels in regeneration are generally too low to support thermal NOx formation. On partial burn units, additional NOx can be produced downstream of regeneration during carbon monoxide (CO) combustion (in a CO boiler or CO incinerator). This typically results from thermal NOx formation. NOx emission from an FCCU regenerator are typically 90% NO/90% NO2 and is expressed on a 100% NO2 basis. High levels of NO2 can produce a visible yellow/brown plume.

Selective Non-Catalytic Reduction (SNCR)
The use of SNCR technology is generally limited to only partial burn FCCUs that have CO combustion furnaces/boilers and provide about 20% to 60% reduction in NOx emissions. Where these limitations are acceptable, using an SNCR may provide a very cost effective solution. SNCR may be used ahead of and in combination with SCR and Wet Scrubbing (with LoTOx process).

SNCR is typically available as an option from boiler suppliers. A number of technology suppliers/licensors offer SNCR technologies for installation on existing CO-boilers.

SNCR systems have been used for years on boilers and on many FCCU applications. On an FCCU, an SNCR system is used in conjunction with secondary combustion device (CO-boiler or fired boiler) located downstream of the FCCU regenerator. Ammonia (NH3) is injected into the boiler under proper conditions so that NOx is reduced to nitrogen and water. Some systems use urea injection instead of ammonia injection for SNCR and ammonia for reactions is formed within the boiler.

It is very simple process and requires a minimal amount of additional capital equipment. Operating costs are typically very low. The process is also very robust and can operate for years in FCCU service. An SNCR system is generally as robust and reliable as a CO-boiler.

Add your rating:

Current Rating: 2

Your rate:

  • Responsive image Advanced sulphur analysis in hydrocarbons
  • Responsive image Capture more value from every barrel
  • Responsive image Designing deepcut vacuum units that work
  • Responsive image Get the right answer faster
  • Responsive image Extensive tray portfolio
  • Responsive image FCC catalysts & additives
  • Responsive image Axens on Linkedin
  • Responsive image Download Tracerco level system data sheet
  • Responsive image BASF Refinery Solutions on LinkedIn
  • Responsive image Galexia™ hydroprocessing platform