Air Pollution Control Equipment Services, Emissions

Retrofitting Boilers for NOX Control

Issue 9 and Volume 116.

By William Gurski, Director, Power Sales and REX K. Isaacs, Director of Burner Products, Zeeco

The Environmental Protection Agency (EPA) continues to propose tough new standards that require all new coal-fired electricity plants to cut carbon, NOx and other emissions by significant amounts. Doing so can be an expensive proposition and it’s led many power companies to consider backing away from coal and consider natural gas firing.

For decades, coal represented roughly half of the nation’s electricity generation, but in recent years this percentage of coal-fired generation has begun to decline. Power companies are faced with the expensive choice of continuing to burn coal while reducing emissions or potentially switching to largely abundant and inexpensive – at the moment – natural gas. The move from coal to natural gas and the current regulatory environment mean plant owners are seeking to maximize the necessary capital investment into new equipment by retrofitting burners to burn natural gas at the most efficient and lowest overall emission levels possible.

One combustion company with experience in coal-to-gas conversions and retrofits for NOx emission control in power plant operations is Zeeco, Inc. Gathering the right information in advance of a retrofit is critical in order to understand the type of burner needed and the operational parameters of the system. For Zeeco, this process typically includes a site visit performance analysis, full system combustion and ancillary review, and post contract-award reviews such as physical flow modeling and computational fluid dynamic modeling. These steps help quantify the existing system and determine any necessary design and operational changes to the boiler. The combination of engineering and modeling approaches are used to accurately guarantee field performance and meet NOx emission standards after install and commissioning.

Performance Analysis

A thorough performance analysis by qualified combustion experts can identify boiler, burner, and other system issues that may impede achieving the desired operational emissions and performance levels. These analyses are often performed by physically walking the facility, checking operational parameters and controls, evaluating boiler operational and performance data and visually inspecting the boiler, burners, burner components (register, gas/oil tips, pilots, etc.) and ancillaries such as controls and emissions monitoring equipment as completely as possible. It is important that a combustion expert with knowledge and understanding of combustion and boiler operations properly designs the new burner/system to fit the project goals, emissions requirements, and day-to-day operation of the boiler.

If conditions indicate a more efficient operation is possible through replacing parts and optimizing controls, the combustion expert will indicate the recommendation to revamp in a report to the customer. In cases where the existing equipment is simply not sufficient to achieve necessary emissions or efficiencies, the report may recommend a retrofit instead. Plant operators benefit when the person evaluating the boiler thoroughly understands combustion as well as the combustion equipment and can suggest corrections based on visual inspection, current operation, overall condition, flame geometry and boiler performance data, if available.

The analysis phase of an application can include process tools such as Emissions Reviews, Ancillary equipment audits, controls and BMS reviews, etc. Other tools often employed include Physical Flow Modeling and Computational Fluid Dynamics (CFD) Modeling. These tools can reduce application time as well as overall startup time and conditioning of the burner. Companies such as Zeeco use these engineering and modeling practices to know exactly where every pound of air and fuel enter the burner. These tools give engineers insight into a boiler burner’s performance in a variety of situations and scenarios.

Modeling

Physical Flow Modeling (PFM) visually details the combustion airflow. It focuses on the following:

  • 95 percent of the mass flow through a burner is air
  • Solving distribution issues between burners
  • Removing tangential velocities around each burner
  • Proper system pressure drop to ensure optimal performance
  • End goal of proper distribution of air and fuel to meet all project goals and emissions requirements

Physical Modeling visually details the combustion air flow. Burner predictive models are dependent upon equal airflow. Calculations assume each burner receives the same amount of air and fuel and in the same compositions. In reality, boiler burners don’t operate this way unless the system has been properly balanced. The design team builds an accurate, 3-D clear plastic model that contains all internal components, Venturi meters, orifice plates, etc. so engineers can visualize air flow to each burner. Static probes are used to measure the various pressures. After obtaining an accurate picture of existing flow patterns, the design team corrects any air flow imbalances in the model with baffles and turning vanes. In a burner, 95 percent of the mass in the combustion reaction is air, with the remaining 5 percent fuel. Balancing the air is critically important to achieving the designed performance of a boiler burner system, as seen in Figure 1.

fig. 1

Data from the final testing of the burners detailed in Figure 1 show that the mass flow was brought within the acceptable standard of ±2% average of all burners. The peripheral velocity distributions were brought within the acceptable standard of ±10% of all burners. System area pressure drop was increased by less than 0.5″ and brought within Zeeco’s requirements for zero swirl. Physical modeling shows actual mass flow in a system and then shows actual mass flow after corrections are implemented, removing the guesswork.

Computational Fluid Dynamics (CFD) is used to visualize temperature, velocity, emissions, particle sizes and their interactions within the combustion process. CFD is a proven modeling tool that aids in the design process to ensure optimal boiler performance. When CFD is used in conjunction with physical flow modeling during a retrofit or performance analysis, combustion engineers can accurately anticipate boiler performance taking into account fuel and air distribution after any solutions indicated by the physical modeling are implemented.

CFD modeling focuses on:

  • Flame fit within the required boiler confines
  • Flame behavior and interactions between fuels and respective burners
  • Emissions predictions
  • Firing system temperature profiles for the boiler and downstream heat transfer surfaces

Because physical and CFD modeling each provide different but important predictions of field performance, using both approaches in every burner design makes sense. Using both methods improves startup and commissioning time as well since potential problems or emissions issues can be discovered and corrected in the engineering and design phase rather than having to be field-corrected on site. Overall boiler performance is more efficient from the beginning since the system has been thoroughly tested and evaluated prior to install. In retrofit applications, a tandem approach to modeling allows for more cost-effective and predictable results in shorter timeframes. The cost of physical modeling is typically less than 10 percent of the overall project cost, but using it effectively can reduce startup costs by 50 percent or more.

Why Retrofit Now?

Recent EPA and Boiler MACT rules will require industrial plant and power plant owners to reduce their overall plant emissions. According to the EPA,1 “Boilers and process heaters, used within a wide range of applications such as industrial process heating, petroleum refining, and chemical manufacturing, consume approximately 37 percent of all gas used in the industry and contribute a significant percentage to overall NOx emissions.”

When power plants use gaseous fuels without fuel-bound nitrogen, the primary contributor to overall NOx production is the formation of thermal NOx. Thermal NOx is produced when flame temperatures reach a high enough level to “break” the covalent N2 bond apart, allowing the “free” nitrogen atoms to bond with oxygen to form NOx. See Figure 2.

fig. 2

Burner and complete firing system retrofits in boilers are an economical solution to achieving lower NOx levels while utilizing the existing boiler. Retrofits for ultra-low-NOx emissions can be challenging in some cases and many facilities are concerned about the retrofit impacting steam generation.

Case Study in Low NOx Emissions Control

One example of a retrofit application from a recent Zeeco boiler burner case study involves a pair of marine boilers that were originally designed for service on a ship more than 70 years ago. The boilers were removed and land based at a Gulf Coast Refinery. Each boiler was originally equipped with two conventional burners with corresponding firebox dimensions of 14 feet deep (this dimension was not apparent during the application development phase. It was left as “to be determined”), 20 feet tall, and 10.8 feet wide. Information on the boilers was limited due to age of the installation, as many of the details important to properly engineer next generation burner retrofits were not relevant 70 years ago and were therefore not clearly documented. Additionally, some original design documentation was missing. Zeeco replaced each of the existing conventional burners with a Zeeco GLSF Ultra Low NOx Free-Jet burner. The heat release design of the new burners was set at 77.4 MM Btu/hr per burner and the combustion air pressure drop was set at 3.25″ W.C. at 15 percent excess air with an ambient air temperature of 100°F.

Zeeco and the facility operators probed the boiler, sampled the flue gas and conducted air and flue gas system pressure surveys. The following challenges and solutions were identified:

1. Boiler Leakage

Challenge: Boilers had air leakage issues, causing air to enter the boiler through locations other than through the burner throat. Not all of the air was being used to help mix the gas and air together, resulting in longer flames.

Solution: Boilers were thoroughly sealed. Combustion air entered through the burner and not through the leakage in the boiler.

2. Boiler Forced Draft Blower Control

Challenge: The existing Forced Draft (FD) blower control mechanism contained older technology and lacked fine adjustments. Therefore, it was difficult to maintain the desired airflow rate through the burner. The Induced Draft (ID) fan was instead used to control the airflow, affecting the draft within the boiler, which increased tramp air leakage.

Solution: Mechanism on the Forced Draft blower was adjusted to allow for better excess air control. This allowed the boiler to be operated in a more traditional balanced draft configuration, reducing tramp air and NOx.

3. Change Gas Port Sizing

The size of the ports was altered to operate at a maximum fuel gas pressure of 32 psig as opposed to the original 25 psig. The high gas pressure provided more energy to mix the fuel and air together, resulting in a shorter flame and reduced emissions. The burner was also redesigned to mix the steam directly with the air stream prior to entering the boiler. The new rate for the steam was revised to 0.5 lb.

4. Increase Air Pressure Drop and Add Air Spin

Original GLSF design was based upon maximum combustion air pressure drop of 3.25″ W.C. with no air spin. Field testing confirmed there was a slightly higher air pressure drop available to help with the mixing of the air and gas. A spin diffuser in the throat of the burner was employed to improve mixing of the air and fuel and change the flame shape from long and narrow to shorter and bushy. Airside pressure drop increased to 3.5″ W.C.

Field Results

After the burners and boilers were modified as described in the Challenges and Solutions section of this paper, the following emissions were achieved:

NOx emissions 0.03 lb/MM Btu (HHV Basis)

CO emissions, corrected to 3 percent dry O2 50 ppmv

After initial startup, evaluation and redesign, the burners were able to operate from low firing rates with good flame characteristics. The burners utilize approximately 0.3 to 0.4 lb steam injected into the combustion air stream and are currently operating at or below the target NOx emissions requirements.

During the process of this retrofit, Zeeco identified the following areas that should be of consideration when retrofitting a boiler burner:

Burner Design Conditions: It is necessary to receive all of the design information at the beginning of the project. This task was challenging due to the age of the boilers and the limited amount of information that was available. Small changes in conditions can have a large effect on performance.

Gas Port Sizing: With the Free Jet Design, it is crucial to maximize the mixing energy of the near-field flue gas and the air stream, especially at low rates to increase flame quality and allow for the sometimes shorter fireboxes in older boilers.

Air Pressure Drop: It is critical to optimize the design for introduction of the gas and the air streams, especially at low rates to keep flame lengths short.

Boiler Forced Draft Blower Control: It is very important to be able to control the combustion air with both the Forced Draft blower (FD) and the Induced Draft (ID) blower to mitigate/eliminate tramp air, which affects performance.

Placement of Steam Injection: To maximize the mixing energy of the gas and the air when not using steam injection, a steam lance inserted into the air steam was used. With the steam lance, the addition or subtraction of steam will not affect gas pressure or the mixing energy of the fuel and air.

Zeeco installed burners that were designed to use 0.3 lb steam/lb fuel gas injected into the fuel gas stream for increased NOx reduction if needed since External Flue Gas Recirculation (EFGR) was not planned for this application. The use of a small amount of steam was less expensive than reworking the boiler to add approximately 14 percent EFGR to achieve the required NOx emissions level of 0.03 lb/MM Btu (HHV). The new burners were installed in the existing burner wind-box configuration. The new burner footprint was approximately the same size as the existing burners, so boiler modifications for burner installation were minimized to reduce the overall installation cost of the retrofit.

Conclusion

With a continued increase in power companies considering the switch from coal to natural gas and continued pressure to achieve ultra-low NOx emissions levels, plant owners are faced with the expense of retrofitting boiler burners to burn natural gas at the most efficient and lowest emission levels possible. Performance reviews and accurate modeling gives engineers insight into a boiler burner’s performance and helps maximize efficiency from the earliest engineering and design steps all the way through startup and commissioning. Emissions levels can be accurately predicted, fuel and air mixing and the combustion process can be properly planned, and plant owners can realize reduced costs long term. With today’s operational parameters, dependable field results based on accurate modeling protect the facility, the environment and the equipment manufacturer.