Water treating requirements vary significantly with incoming water quality and the final uses. Water must be treated to economically satisfy the following types of users:
1. Water for cooling in the middle of a superheater: When reducing the temperature in the middle of superheater coils, water of extreme purity (50 parts per billion) must be used. Any dissolved solids in the water will plate out in the superheater.
2. Water for desuperheating at the superheater outlet: This is conventional desuperheating and the water used should be the best quality water in the plant. Typically, this is condensate or demineralized water at 10 to 20 ppm or less.
3. Water for injecting into the gas turbine burner for NOX control: The gas turbine manufacturer should be consulted. Normally, this must be extremely pure water. Frequently steam from the HRSG is condensed for this service. If the steam is injected into the gas turbine, a much larger quantity of steam is required (compared to water) for the same NOX control.
4. Water for boiler feedwater make-up to:
a. Heat Recovery Steam Generators of the dry, superheated type: use the American Boiler Manufacturers Association (ABMA), Guidelines. The more stringent limitations set by the ASME in 1979 are rarely met in industry. As a design guideline, assume that if your existing water treating is adequate for your existing power boilers, it is good enough for the HRSG.
b. Once-through 60% to 80% quality steam generators: Because the tubes are never run dry, the only treatment for this brackish water is softening.
c. High-pressure boilers: Evaluate the merits of operating at the more economic guidelines of the ABMA rather than adopting (and installing the necessary equipment to meet) the more stringent requirements of drum concentration, found in the ASME guidelines.
5. Water to process steam generators, all pressure levels: For all waste heat recovery projects, should be guided by what the plant presently does in this area.
Steam boiler drums and systems should be designed to insure that, with a boiler water total solids content as recommended by the American Boiler Manufacturers Association Standards (ABMA), the boiler carryover will not exceed ½ parts per million (ppm) solids by weight in the steam at design rates. A Larson Lane analyzer should monitor the steam quality.
In waste heat recovery, there are both natural and forced circulation steam generators. The weight ratio of water circulation to steam generation in each heat absorbing circuit is:
• Natural: From 5:1 to 20:1, typically 10:1
• Forced: 5:1 to 8:1
For Heat Recovery Steam Generators at the back end of gas turbines, a few design guides are:
1. Use shock tubes with saturated steam production in them, not superheating tubes, immediately after the supplementary-firing.
2. Use stainless steel liners for the inside hot walls of the convection sections.
3. Use only ceramic fiber between the stainless steel liners and the outer walls. (No mineral wool.)
4. Use a coating on all inner cold surfaces of the outer wall.
5. Economic flow velocities of hot exhaust gases are typically in the range of 30 to 70 feet/second. The higher velocities are through the finned and triangular pitched convection sections; the lower velocities are in the ducts.
6. For water stability, thermal design, and erosion prevention, the velocity on the water/steam side of the tubes should normally have a minimum velocity of
3 feet/second and a maximum velocity of 100 feet/second.
7. The gas velocity through the HRSG should not exceed 100 feet/second, and the HRSG should be designed for horizontal gas flow.
8. Figure 3400-3 is a typical heat release profile, plotting the temperature of the unfired gas turbine exhaust versus the water/steam temperature in the Heat Recovery Steam Generator. It highlights that the “Pinch” point is the difference in temperature between the flue gas and the temperature at which boiling of the water starts.
9. Figure 3400-4 shows the temperature advantage of supplementary firing the turbine exhaust. Over 100% of the heat added in supplementary-firing can be recovered because it can be cooled to a lower exhaust temperature while maintaining the same “pinch” point.
For economizers and air preheaters on boilers and fired heaters, the pressure drop is normally limited to about 4 inches of water. For Heat Recovery Steam Generators at the back end of gas turbines, the pressure drop superimposed on the gas turbine is usually limited to about 15 to 20 inches of water.
The water flow in economizers should be from the bottom up allowing any steam that may be generated to bleed off the top.
Some general considerations are:
1. All waste heat recovery options, if installed, should be done with full consideration of:
– Simplicity of operations
– Ease of maintenance
– Prevention of corrosion
– Proven technology
2. Dewpoint and corrosion of waste heat recovery equipment.
The dewpoint of the flue gas in waste heat recovery is very critical to the efficient operation and maintenance of boilers, fired heaters, gas turbines, and heat recovery steam generators, (HRSG). At temperatures below the dewpoint, sulfuric acid condenses on surfaces and corrodes the metal. At temperatures above the dewpoint, corrosion is not a problem.
Accordingly, each project must select the optimum exit temperature and the appropriate alloys to maximize the efficiency and minimize corrosion.
A guideline showing the temperature at which the acid dewpoint is reached, based on percent weight of the sulfur in the fuel, is shown on Figure 3400-1. It shows the minimum metal temperatures recommended by economizer, air preheater, and boiler manufacturers.
3. Retractable soot-blowing equipment should be installed on all convective heat transfer areas where liquid fuel oils may be fired. Soot-blowing lanes should be appropriately located to be able to clean all tubes in all rows of convective sections.
4. To minimize sulfuric acid corrosion, the temperature of steel surfaces in direct contact with flue gases, should be maintained above the limits referred to in HTR-MS-1350.
5. On all waste heat recovery systems, baffles and bypasses can be used to control temperatures.
6. In all waste heat recovery systems, extended tubes are commonly used on gasside flows to increase the heat absorption.
7. Problems of reduced draft, increased pressure drop, and added pumping or blowing requirements on each of the waste heat recovery streams must be fully evaluated.
8. Year-round availability of the waste heat stream and the cold stream must be evaluated if they are in different plants. How does the second stream get cooled or heated while the other stream is in turnaround or shut down for some unforeseen event? Is there an operating plan that will permit this? Figure 3400-2 illustrates this situation. The heat source is in one plant and the stream receiving the heat is in another. Very few inter-plant exchanges are installed because of the complications caused by outage of one of the streams.
9. Along these lines, there are significant options of integrating process plants and the direct flow of hot feeds between units. This eliminates some intermediate tankage. However, it adds to the complexity and reduces operating
flexibility. For example, there is surplus heat in Isocrackers (exothermic heat of reaction) and Rheniformers (high process fluid heater exit temperatures). This surplus heat would be most useful in the Crude Unit which requires much crude feed heating.
For both the waste heat stream, and the stream receiving the heat, the data (in addition to ambient conditions) needed to evaluate waste heat recovery are:
• The flow rate
• The specific gravity of the fluid
• Chemical composition
• Corrosive capabilities
• Depositing characteristics
• Any temperature limitations or control requirements
Use average conditions for economic considerations, but evaluate variations for critical design conditions.
Review data on the stream receiving the heat to make sure that it is a valid use. The amount of heat that can be recovered from any heat source is meaningless unless valid uses exist. As a prime example, there is no benefit from producing more low pressure steam from waste heat when the plant is already venting low pressure steam most of the time.
Figure 3300-6 illustrates the principle of power recovery in a Hydrocracker. The 2500 PSIG process streams would have to be let-down through a control valve to lower pressure at three locations. The 3300 kW recovered from the three units shown represents about 7% of the total electric load for the complex. At 8.6 cents/kWH, it is valued at $2,300,000/year. Also shown are the investments, annual savings, and before-tax payouts.
Figure 3300-7 shows how air preheaters can be used in a plant to recover waste heat after all the economic steam production has been accomplished. The three fired heaters in this graphic reduce the stack temperatures to the 350°F to 500°F range while preheating ambient combustion air to the 400°F to 800°F range. Shown are the investments, annual savings, and before-tax payouts, in years, for air preheaters on the three fired heaters.
Figure 3300-4 shows several alternative waste heat recovery systems available to a Crude Unit.
Along with showing the process steam generated on E-68 and E-24, it highlights that:
1. The Crude Fired Heaters, (F10), instead of generating 40,500 pound/hour of 150 PSIG steam, could have:
a. Generated 23,900 pound/hour of 625 PSIG steam
b. Added an air preheater to save 73.5 MMBH
c. Combined with the exhaust from a gas turbine to make 13,000 kW of electric power and produce 53,000 pound/hour of 150 PSIG steam in the fired heaters economizer. (See Figure 3300-5.)
2. The Vacuum Fired Heaters F20, fired heaters, instead of generating 24,500 pound/hour of 625 PSIG steam, could have:
a. Generated 40,000 pound/hour of 150 PSIG steam
b. Added an air preheater to save 59.7 MMBH
c. Combined with the exhaust from a gas turbine to make 8,000 kW of electric power and produce 46,000 pound/hour of 150 PSIG steam in the fired heater economizer. (See Figure 3300-5.)
Figure 3300-5 depicts electric generators, and the turbines exhausting to the Crude-Unit fired heaters. It also details investments, annual savings, and before-tax payout.
Figure 3300-3 shows the stack temperature, after a steam generating economizer, being reduced from 700°F to 300°F while heating the combustion air from 60°F to 600°F. Fired Heater efficiency is improved from 79.7% to 89.3%. This is an example of utilizing both an economizer and an air preheater on a fired heater to optimize the amount of energy recovered by making steam and preheating combustion air.
Figure 3300-2 shows the stack temperature being reduced from 850°F to 300°F while heating combustion air from 60°F to 750°F. Fired Heater efficiency is improved from 76% to 89.3%.
Figure 3300-1 shows several items:
1. When 150 PSIG steam is generated (F10), the stack temperature is reduced to 450°F.
2. When 600 PSIG steam is generated (F20), the stack temperature is reduced to 600°F.
3. The higher the pressure of the steam generated, the more energy or work can be recovered in steam turbines.
4. The Atmospheric Fired Heater makes 40,500 pound/hour of 150 PSIG saturated steam while reducing the stack temperature from 758°F to 450°F. Fired Heater efficiency is improved from 78.2% to 85.8%.
5. The Vacuum Fired Heater could make either:
a. 24,500 pound/hour of 600 PSIG saturated steam while reducing the stack temperature from 900°F to 600°F. Fired Heater efficiency is improved from 74% to 82.2%.
b. An alternative not shown, 40,000 pound/hour of 150 PSIG steam, while reducing the stack temperature from 900°F to 450°F. Fired Heater efficiency is increased from 74% to 85.8%.
6. The investments, annual savings, and payout in years (before taxes) for making steam in the Crude and Vacuum Fired Heaters.