TURBO MACHINERY, GT, MULTI-POLLUTANT CONTROL
ACCEPTING ABSTRACTS ON: Mercury Capture & Control, NG Turbines, CCGT, Startup, Compressors, Reliability Conversion, REACT, Hydrated Lime & Activated Carbon, HG, MACT for HAPS, CO2, NOx and SO2, HG. PM, Medical Waste Incinerator
C1.1 Overview on Mercury Control Options for Coal-Burning Power Plants
(11 am – 11:20 am EST)
C1.1 Overview on Mercury Control Options for Coal-Burning Power Plants
With the USEPA issuing a national regulation requiring high levels of mercury capture, the need exists for low-cost removal techniques that can be applied to coal-burning power plants. The injection of powdered activated carbon into the ductwork upstream of the particulate control device is the most developed technology for mercury capture. Alternative techniques for mercury capture also play a role because of the numerous configurations of air pollution control devices present within the power plants, as well as the many different coals and coal-blends being burned. These methods employ sorbents, catalysts, scrubber liquors, flue gas or coal additives, combustion modification, flue gas cooling, barrier discharges, and ultraviolet radiation for the removal of mercury from flue gas streams. The DOE Mercury Program was an enormous success, spurring continuing development, demonstration, and commercialization of many technologies for the capture of mercury.
An overview of current and alternative technologies for mercury capture from coal-derived flue gas will be provided. In addition, six methods for mercury control within coal-derived flue and fuel gases have been recently developed at NETL and will be discussed. The on-going research needs for mercury control include improved sorbent-flue gas contact, development of poison-resistant sorbents and catalysts, novel sorbent promoters, new scrubber additives for retention of mercury within wet FGD systems, concrete-friendly activated carbons, new continuous measurement methods, benign coal additives, byproducts research, and exploration of international markets.
Co-Authors: Elliot Roth, Ken Ladwig and Ward Burgess, U.S. DOE NETL
C1.2 Amended Silicate Products from Environmental Energy Service
(11:20 am – 11:40 am EST)
C1.2 Amended Silicate Products from Environmental Energy Services
The presentation will cover Amended Silicate products for mercury control in coal-fired power plants and other industrial sources, as well as products for catalytic destruction of organics . Environmental Energy Services (EES) now owns the rights to all Amended Silicate Technologies and products and has the manufacturing capability to produce these products for new customers. This includes four different Amended Silicate products for mercury control, AS-ULTRA for plants without scrubbers, AS-DryScrub for plants with dry scrubbers or CDS systems, and AS-HgOx and HgX-FGD for plants with wet FGD systems. In addition, products AS-DIOX and AS-TOTAL will be described, which are effective at mitigating dioxins, furans, PCBs, and other organics, acid gases, and trace semi-volatile metals, such as SO3, HCl, As, Se, Na, K, Pb, Cd, etc. Both full scale and laboratory performance data will be shown for these products, along with comparison to performance data from competitive products.
C1.3 Solutions, Not Just Sorbents
(11:40 am – 12 pm EST)
C1.3 Solutions, Not Just Sorbents
Choosing and purchasing sorbents is relatively simple; implementing a solution that works over the long term is much less simple. Hydrated lime dry sorbent injection (DSI) offers a means to reduce acid gas emissions; however, a holistic solution that works requires significant expertise and knowledge that goes far beyond sorbent-pollutant chemistry. Today, many utilities and industrial facilities operate with minimal engineering resources. Bringing a solutions-based approach can provide much-needed expertise to plant engineers to effectively operate systems and sorbents, and to have someone to call on when problems arise. Utilizing a sorbent supplier that provides multi-functional expertise can minimize total cost of ownership and alleviate material handling and compliance challenges. Over the past decade, DSI with hydrated lime has become commonplace for acid gas abatement (e.g. SO2, SO3, HCl, H2SO4, HF) and heavy metals abatement (e.g. arsenic, selenium) in industrial processes. Enhanced hydrated lime sorbents that are engineered to have higher pore volumes and surface areas are routinely applied to achieve high degrees (often in excess of 90% reduction) of acid gas and heavy metal removal rates in flue gas exhaust streams. In addition to hydrated lime properties, many other system parameters influence ultimate sorbent performance.
Co-Authors: Gerald Hunt, Martin Dillon and Greg Filippelli; Lhoist North America
C1.4 Very Green Capture of CO2, NOx and SO2
(12 pm – 12:20 pm EST)
C1.4 Very Green Capture of CO2, NOx and SO2
PRDD has developed and verified through bench scale testing, a process that removes 99% CO2, 90%NOx & 99%SO2 ( target gases) from combustion and chemical process exhaust gas. • This proprietary technology for land and ocean vessel applications requires a small physical “footprint” and creates a very small carbon footprint. All three target gases are sequentially removed in a continuous mist phase reaction vessel not much larger in diameter than conventional duct for a given exhaust gas flow. • The combined CO2, NOx and SO2 abatement processes are collaborative. Chemical use is minimized because reaction products from one process are often reagents in another. • The primary consumable for all three processes is sodium chloride (table salt). The energy required to convert sodium chloride into other consumables is included in the energy balance shown below. • Most of the chemicals used in the CO2, NOx and SO2 capturing processes are recycled. All the reagent recycling only requires waste heat from combustion and nominal electrical power to operate pump etc. • The processes generate commercially viable effluent like sodium bicarbonate (baking soda). • The process is dramatically energy efficient. Because the chemical recycling is done with waste heat from combustion, a system sized for a large ocean-going vessel only requires 98 gallons of HFO/hour.
C1.5 Improving Hg Control While Reducing PAC Injection Rates
(12:20 pm – 12:40 pm EST)
C1.5 Improving Hg Control While Reducing PAC Injection Rates
PAC injection for controlling mercury emissions from combustion processes often has detrimental effects on other aspects of the process. Intelligent, non-traditional methods of performing multi-objective optimization which accounts for varying time constants and situation-specific prioritization of these objectives can realize improvements which traditional control is not capable of. Through the use of an adivarent control concept, mercury emission rate targets are met while also meeting stringent opacity targets and other emission rate limits. This system uses a combination of intelligent prioritization and data analysis and learning systems to achieve improved performance across all process objectives.
Co-Author: Brad Radl, Griffin Open Systems LLC.
QUESTIONS
1. What precludes this control methodology from being developed directly in the DCS?
2. If PAC and opacity are both improved as displayed, where’s the trade-off? There must be some other portion of the system or operations detrimentally affected?
3. How does the system account for other process disturbances (e.g. sootblowing)?
EXHIBIT
12:30 pm to 1:00 pm EST
C2.1 Case Studies of Combustion Turbine Emissions Troubleshooting
(1 pm – 1:20 pm EST)
C2.1 Case Studies of Combustion Turbine Emissions Troubleshooting
Retirement of large coal units and demand for quick-start capabilities has facilities investing in natural gas combined cycle (NGCC) or existing machine upgrades. New NGCC facilities have large turbines, low turndown capabilities, and low permitted emissions. Turbine upgrades could increase power output, improve heat rate and dispatchability, or improve low-load cycling. Emission issues arise from larger combustion turbines requiring higher steam turbine power output. Low turndown and cycling capabilities have strained emissions control systems. This presentation will discuss design considerations for new and existing combustion turbines to meet emissions limits with a case study of actual industry lessons learned.
Co-Author: Emily Kunkel, Sargent & Lundy
QUESTIONS
1. How frequently does SCR/CO catalyst need to be replaced?
2. What kind of emission related guarantees should be requested of the vendors – CT, HRSG or catalyst?
3. What if additional control is needed to meet lower permit limits in the future?
4. What is the right SCR reagent for a specific system?
C2.2 On-Blade Gas Turbine Sensors for Real-Time Health Monitoring
(1:20 pm – 1:40 pm EST)
C2.2 On-Blade Gas Turbine Sensors for Real-Time Health Monitoring
Sensatek’s wireless sensor system provides continuous and real time measurement of temperature in-situ on stationary and rotating gas turbine blades and components used for power generation. This presentation will share how on-blade sensors can help extend running time between outages, increase energy production, predict machine need for maintenance, and extend life of stationary and rotating parts. A low-profile reflective patch antenna behaves as both a resonator (sensor) and an integrated antenna. An interrogation circuit (transceiver) sends out a pulsed wave which contains a wide frequency spectrum surrounding the resonant frequency of the reflective patch sensor. When the temperature in the sensor increases, the resonant frequency reduces which is because the dielectric constant of the substrate material increases over temperature.
Co-Author: Reamonn Soto, Sensatek Propulsion Technology, Inc.
C2.3 Reducing the Cost of Electricity Production: A Case Study
(1:40 pm – 2 pm EST)
C2.3 Reducing the Cost of Electricity Production: A Case Study
Normally when the steam based plants were designed , they have efficiency of 41-42%. However, after few years of operation, the annual efficiencies of some 20-30 year old plants falls in the range of 30-37% depending upon how good the operation and maintenance is done by the asset owners. The drop in efficiency and increase in maintenance cost causes enormous financial burden to the extent that the plants are forced to retire even prematurely. We present here a case study of 2×300 MWe wherein when the assets are managed effectively, the power plant can continue to operate and generate revenue for the asset owners.
C2.4 Reduce Flow Assurance Costs with Low Dose Hydrate Inhibitors
(2 pm – 2:20 pm EST)
C2.4 Reduce Flow Assurance Costs with Low Dose Hydrate Inhibitors
The goals of flow assurance are to prevent oil from cooling and to ensure its fluidity from the reservoir to the surface. One of the biggest issues for upstream production is the formation of hydrates. Hydrates form when light hydrocarbons and water mix under high pressures and low temperatures. Hydrates restrict flow and can form solid plugs that block production and damage equipment. Reliability and maintainability require that hydrates be eliminated in manner that frees space and increases efficiency.
C2.5 Optimizing Operational Benefits of High Reactivity Hydrated Lime
(2:20 pm – 2:40 pm EST)
C2.5 Optimizing Operational Benefits of High Reactivity Hydrated Lime
The presentation will outline how High Reactivity (HR) hydrated limes can benefit dry scrubbing and dry sorbent injection (DSI) systems. Full scale performance examples will be reviewed. We will also discuss how optimization of DSI grids can maximize pollutant removal and hydrated lime utilization, including a novel flue gas traverse process to identify pollutant “hot spots.”
Co-Authors: Cal Lockert, Dan Menniti, Eric Fairbairn and Robert Branning; Mississippi Lime
QUESTIONS
1. What are the key cost benefits of using HR hydrates in dry scrubbers?
2. Why is hydrated lime in-flight capture capability important for neutralizing SO3 prior to the Air Preheater?
3. Can your DSI injection system benefit from a tuning?
EXHIBIT
3:00 pm to 4:00 pm EST
C3.1 Don’t Just Monitor Your PM, Control It!
(4 pm – 4:20 pm EST)
C3.1 Don't Just Monitor Your PM, Control It!
This presentation will attempt to show how concentrating on continuous emission monitoring systems (CEMS) for the last 8 – 10 years has caused us to lose our focus on controlling particulate matter (PM). This presentation will revisit the basics of good baghouse monitoring and particulate control. The presentation will also identify cost savings opportunities in baghouse operations as the PM is being lowered. The presentation will not be how to do emission monitoring, but how to reduce your emissions through diagnostic monitoring.
QUESTIONS
1. What’s the payback period of a diagnostic system?
2. How will it affect my current controls?
3. Can it work on baghouses other than pulse-jets?
C3.2 Cope Baghouse Retrofit Project
(4:20 pm – 4:40 pm EST)
C3.2 Cope Baghouse Retrofit Project
After 20 years of Dry FGD service on Eastern Bituminous coal, the reverse gas baghouse at the 410 MW Cope coal fired generating station had become severely corroded. The generation plan for Dominion called for this unit to be reliably operational for another 20 years. Extensive repair or replacement to correct air leakage and structural weakness in the baghouse casing would have required a long unit outage. Various alternatives were considered for cost, schedule, and technical risk. An innovative solution was to install a full flow bypass while the baghouse was still in service, and then fire natural gas in the boiler while the baghouse was being replaced. This minimized the outage time and enabled the unit generating capacity to be available for dispatch. Numerous design challenges were overcome in designing and installing the bypass while minimizing the impact on the existing equipment.
Alternatives considered for replacement of the baghouse were:
1. New epoxy coated carbon steel pulsejet filter located alongside the existing unit.
2. New epoxy coated carbon steel reverse gas baghouse located alongside the existing unit.
3. Demolition and replacement of the existing baghouse with an identical epoxy coated carbon steel duplicate in the original location.
4. Demolition and replacement of the original baghouse with an identical new 2205 alloy steel unit, in the original location.
The alloy steel alternative was chosen as the lowest risk solution long-term solution
Co-Author: Jack A. Robinson Jr., Dominion Energy
C3.3 It’s All In The Dust Cake Revisited
(4:40 pm – 5 pm EST)
C3.3 It's All in The Dust Cake Revisited
The most successful dry FGD plants are associated with optimized bag houses. After the FGD reaction in the main scrubber, a secondary SO2 neutralisation reaction takes place in the dust cake formed on the filter bags in the BH (bag house). An engineered dust cake improves the effectiveness of the neutralization reaction.
Test results performed on specific reference filter bags in large BHs substantiate the importance of a high-quality dust cake. The presentation will provide an update of our presentation to EUEC in 2018 with additional case studies demonstrating the influence of the filter media design on the SO2 removal.
Co-Author: Florin Popovici, Emission Control Engineering Consulting
C3.4 Diesel vs Natural Gas
(5 pm – 5:20 pm EST)
C3.4 Diesel vs Natural Gas
Diesel Fuel vs Natural Gas for on-site power generation. This presentation explores the customer challenges with storing diesel fuel at the facilities as well as it explores the growing natural gas market segment. This presentation has a very strong focus on reliability, be it either diesel or natural gas.
C3.5 Unit Flexibility for Coal Fired Units
(5:20 pm – 5:40 pm EST)
C3.5 Unit Flexibility for Coal Fired Plants
Do to an abundance of cheap natural gas and an increase in renewable power generation, large coal fired power plants must adapt to this new market. To survive and thrive the coal fired units need to become much more flexible. This presentation covers the challenges involved within industry to adapt and operate the units to match today’s market. This will include results from on-site Unit Flexibility Testing at large coal fired units (750 MW Net) where minimum load was decreased from 50% down to 20-25% of rated full load, and unit ramp rates were increased from the normal 3-4 MW/min up to 12-15 MW/min. We will discuss potential issues like SCR inlet temperature, Steam Temperatures, Controls Tuning. Unit Flexibility allows the coal fired unit to turn down without shutting down. This avoids short term and long term issues related to cycling the unit on and off. It also provides a greater degree off power grid/system reliability on very short notice.
C3.6 Meeting Increasingly Stringent Medical Waste Incinerator Standards
(5:40 pm – 6 pm EST)
C3.6 Meeting Increasingly Stringent Medical Waste Incinerator Standards
Curtis Bay Medical Waste Services operates a dedicated medical waste incinerator permitted to process up to 150 tpd. Each of two incinerators has a dry injection scrubber/catalytic fabric filter (DI/FF), activated carbon injection (ACI) and selective non-catalytic reduction (SNCR). EPA regulates solid waste combustion emissions with limits for both criteria and hazardous air pollutants. The applicable federal regulations, first promulgated in 1997, were again revised in 2009. The facility has managed to comply with two generations of NOX, acid gas, heavy metal, and dioxin/furan limits, as well as stringent state air toxics rules, largely by upgrading existing emissions control systems.
Co-Authors: Kenneth Jackson and Tracy Fearson, Curtis Bay Medical Waste Services