Other waste heat recovery opportunities include the following:
• Steam boiler and process steam generator blowdown systems
• Steam condensate return systems
• Steam trap, trap maintenance and steam leaks
• Venting of excess low-pressure steam
• Compressor horsepower reduction from using chilled waters in compressor suction coolers. (In warmer climates, using 50°F chilled water instead of ambient 80°F water (cooling incoming suction temperatures from 120°F to 80°F), reduces compressor horsepower 7%.)
• Gas Expanders where higher pressure gases are available for energy recovery in dropping to lower pressures.
• Capacity control of rotating equipment by variable speed control of the drivers
• High efficiency motors and steam turbines
• Completely automatic boiler and fired heater combustion control
• Control of Oxygen, draft, and leaks in skins of equipment
• Capacity control of reciprocating compressors by automatic unloader control versus spillback
• Automatic temperature control (on-off, variable speed) of cooling tower and air cooler motor drivers
• Low Temperature Rankine Cycle Waste Heat Recovery versus air or water cooling of process streams
• Vacuum pumps versus steam jet ejectors
• Vacuum deareation versus low pressure steam deareation
• Insulation installation and maintenance
• Hot feed to process units. (An example is that the Hydrocracker feed from the Vacuum Unit could be fed directly to the Isocracker to avoid cooling for intermediate storage, oxidation, and to conserve energy.)
It has long been desired to lower the temperature out of waste heat streams to below the 250°F to 350°F range. With existing technology, this has been considered to be the minimum exhaust temperature range due to the condensation of acid from combustion products.
Condensation heat recovery cools the exhaust gases below the water dewpoint, and can recover a large percentage of the water-vapor latent, and sensible heat. While the Company has done very little of this to date, it is an evolving heat recovery type. In Europe, these systems have been used for several years, in hundreds of applications. There are two approaches, both discussed below.
This brings water directly into contact with the flue gases to remove the heat. The water becomes acidic and a secondary heat exchanger is used to transfer the recovered heat in a recirculating loop to a clean water stream.
Direct contact is also referred to as Non-condensing waste heat recovery. Direct contact usually reduces the waste heat recovery stream temperature to around 150°F. The acid condition prevails at a pH of about two, and there is little water condensation from the flue gases. Therefore, there is little latent heat recovery. This approach saves an additional 3% to 4% of sensible heat from a waste heat recovery stream, (for either an oil or gas fired exhaust stream), when cooling it from around 300°F to 150°F.
In this approach, a corrosion-resistant heat exchanger is placed directly in the flow of the waste heat flue gas. There is no contamination of the fluid receiving the heat.
This fluid can be a process stream or a utility stream that needs the heat. It can also be fluid that is transferring the heat to other users in the plant in a recirculating closed system.
Indirect contact is also referred to as Non-contact or Condensing. Condensing is usually done to a temperature below 100°F. The acid condition prevails and the water in the flue gases condenses, diluting the acid.
For this type of heat recovery, we can use the following guidelines. How many additional efficiency points could be gained if we cooled the hot fluid in the waste heat recovery unit all the way to ambient temperature? For this condition, we are looking at the absolute maximum recovery. By reducing the temperature from 150°F, to ambient, we could save the following additional fired unit efficiency points:
• On gas: 2% of sensible heat and about 10% latent heat
• On oil: 2% of sensible heat and about 5% latent heat
The above variation in efficiency for gas and oil is due to the lower hydrogen content in oil (less water vapor in the gas).
Condensation systems are reported to reduce particulates and sulfur dioxide emissions.
Manufacturers of glass, pyrex, borosilicate, and teflon are actively trying to develop corrosion-resistant heat exchangers for this type of waste heat recovery.
It will be some time before industry adopts this “almost ambient” stack philosophy.
Note that when stack temperatures become cooler, the penalty for firing with excess air is decreased.
A hydraulic turbine can be considered a “waste heat” recovery unit. It actually recovers energy when letting down high-pressure streams to lower pressures.
As an example, in a Hydrocracker there are process pressures that must be dropped from 2500 PSIG to 120 PSIG, and to 40 PSIG. This let-down energy can furnish about one half the power required to pump the incoming feed up to the process pressures.
Figure 3200-16 illustrates the principle. A full size motor and a full size spare should be installed. As power recovery takes over, the load on the electric driver is reduced.
A variety of organic fluids are available for use in heating or waste heat recovery systems. These liquids offer the advantage of low-pressure liquid-phase heat transfer at very high temperatures. Therefore, these systems involve small piping and low design pressures.
For specifics on the physical properties and system designs, consult the manufacturer of the specific fluids. The following summarizes organic fluids:
Mineral Oils. They are noncorrosive, low cost, and can be used from -15°F to 600°F. However, they have low heat capacities and are subject to high temperature thermal cracking.
Diphenyl-diphenyl oxide. It is used over a temperature range of 54°F to 750°F. This fluid offers a high specific heat but boils at 496°F. Consequently, a pressurized system may be required. Extreme care must be taken with seals, packing, and fittings. If this fluid leaks out, there are problems of fluid loss, odor, toxicity, and clean up. Dowtherm A is an example of this type fluid which may be used as either a liquid or a vapor heat- transfer fluid.
Glycols. These are used in aqueous solutions for temperatures from -50°F to 350°F. For temperatures over 212°F, some slight pressurization is required. Glycols in water act as a corrosion inhibitor and as an antifreeze.
Polyethylene glycols. These heat transfer fluids have good thermal stability to 555°F. They are easy to pump because of low viscosity. Pressurized systems are not required since these glycols do not boil.
Aromatic based fluids. These fluids may be used over a wide range of operating temperatures and are thermally stable. However, their heat capacities tend to be low and the high temperature versions may require steam tracing.
Heat recovery through steam generation is not commonly used offshore. However, high pressure steam can be generated from turbines or reciprocating engine exhaust gases. Since this type of system does not provide engine cooling, higher pressure steam may be generated ranging from 100 to 450 PSIG.
The most common high-pressure steam system used offshore is the hybrid steam/water waste heat recovery system. This type of system uses forced circulation of water through a waste heat unit, as with the water system shown in Figure 3200-15. The outlet of the waste heat exchanger flows to a steam separator vessel where a portion of the water vaporizes to generate steam. This steam maintains the pressure in the steam separator at a level to preclude the need for a gas blanket system. A pressure controller on the steam outlet of this vessel controls the steam pressure and, consequently, the water temperature. Hot water from this separator can be pumped to nearby users, as with a water system. At the same time, steam may be used to provide heat to nearby users.
Figure 3200-15 shows how a hot pressurized water system, utilizing the unfired exhaust from a combustion gas turbine, can be used economically to recover wasteheat and to transfer the heat to various users. Most hot water systems (treated water) operate at 230°F to 280°F, which requires a minimum system pressure of 60 PSIG. Water can be used at higher temperatures, up to 400°F, but higher pressures are required to prevent boiling. The water is heated by the hot exhaust gases while flowing through the tubes. The water temperature is controlled by diverting a portion of the turbine exhaust. High water temperature or low water flow causes the entire exhaust to be diverted. An expansion tank is included in the water system to allow for the thermal expansion of the water. The pressure in the expansion tank is maintained with nitrogen gas to prevent the formation of steam. The process load shown can be a single user or a combination of many users. A system for using heating oil is similar.
Reciprocating engines convert 20% to 40% of the fuel energy they consume into shaft horsepower. The remainder is removed with the cooling system and rejected in the exhaust. A waste heat recovery system on the engine’s exhaust can increase fuel thermal efficiency to around 55%. If the cooling system energy is recovered as well, the efficiency may be increased to about 75%.
The exhaust temperature of reciprocating engines varies from 800°F to 1350°F depending on the size, efficiency and whether it is supercharged. Because reciprocating engines do not use large amounts of excess air, the combustion products constitute a larger percentage of the exhaust. The specific gravity of reciprocating engine exhaust gases is shown, along with that of air, on Figure 3200-13.
For reciprocating engines, a variety of systems and combinations of systems can be used, depending on the heating medium, and the temperature required by the heat user.
Figure 3200-14 shows a typical hot water system in which the engine jacket cooling water has been replaced by the hot water heating fluid. Additional heat energy is then recovered from the hot exhaust gases.
The two main sources of waste-heat on offshore platforms are combustion gas turbines and reciprocating engines. These engines provide power for compression, pumping, and/or electrical power. A portion of the fuel consumed by these engines is rejected as heat in their exhaust or cooling system. This waste-heat can be recovered and put to use in a variety of ways to improve the platform’s overall efficiency, such as heating process fluids or glycol regeneration.
These units are required, and must operate whether the waste-heat is recovered or not. From a safety aspect, waste heat recovery units can be used in place of fired heaters to provide platform heating requirements. This eliminates fire hazards associated with fired heaters.
Waste heat recovery systems may need some backup heat source if the main heat source is to be shut down while the users of the heat are still operating. The backup system may be an independent heating system or duplicate heat recovery systems if enough heat sources are present. A detailed study of the platform operations and heat balances under various operating schemes must be made to provide an adequate system.
The heat energy from either a combustion gas turbine or, reciprocating engine is usually recovered by an intermediate heating medium such as water, steam, or heating oil.
Oil field cogeneration projects are identical to refinery projects, as far as the CGTgenerator is concerned. Where they differ is in what they do with the supplementally fired gas turbine exhausts. In the refinery type, (HRSG) normally dry (saturated) and superheated steam are required.
In the oil field, (HRSG), 60% to 80% quality steam is required for injecting into wells at pressures in the 1000 PSIG range to assist in enhanced oil recovery.
Figure 3200-11 is an isometric of a proposed six-parallel-pass, steam generation for enhanced oil recovery. The design for this project is 220,000 pound/hour of 60% quality steam at 775 PSIG, (from 180°F boiler feedwater), by supplementary-firing the gas turbine exhaust to 1394°F. Flow in the preheater is counter-current; flow in the boiler is co-current. Description of finning, size of tubes, number of tubes in height and in depth, and the heat balance equations for both boxes are shown. A sketch on the top summarizes the heat transfer conditions for the preheater and the once-thru boiler.
Figure 3200-12 is an isometric of the rough outline dimensions for a waste heat recovery type behind a General Electric LM-2500 gas turbine for a producing field. This unit is also rated as a 220,000 pound/hour, 775 SIG outlet, once-through, 60% steam generator for enhanced oil recovery. Units of this type have multipass parallel flow. This unit has four passes. There are no steam drums or mud drums. The passes are heated as in any economizer.
Another significant area of waste heat recovery is the Combustion Gas Turbine (CGT), used either as:
• A direct mechanical drive for process equipment. In some instances, the hot turbine exhaust is used as combustion air for a fire heater in the plant where the mechanical drive machine is located.
• Part of a “Cogeneration” System. In these plants, the gas turbine shaft produces electricity, and steam to operate the plant is produced from the hot CGT exhaust.
For both situations, the CGT produces hot exhaust gases, typically in the 950°F to 1000°F range. This exhaust is used as:
• Preheated combustion gas for fired heaters, or
• Hot gases to a Steam Generator. The exhaust is almost always supplementary fired, up to 1600°F and 1700°F, to normally produce both dry (saturated) and superheated steam at different pressures for the operating center, or in the case of producing, a 60% to 80% quality steam for downhole injection.
Production of electricity and steam from one fuel source is called Cogeneration, which cuts the amount of energy necessary to make electric power to nearly onehalf. This is based on an economic amount of steam and electrical power being required at the plant.
Public Utilities typically furnish electric power to our operating centers at an efficiency of 32% to 35%.
Steam is typically generated in most of our plants at efficiencies of 70% to 75% without waste heat recovery, and 85% to 90% with it (all on a HHV basis).
The overall weighted efficiency for power purchased from a public utility power plant and steam produced at a Company facility is in the 60% to 70% range. This results from averaging the electric power at its low efficiency (from the power plant) with the higher efficiency for steam produced (in the Company facility).
By using an on-site gas turbine to simultaneously generate both electric power and steam, the overall “weighted” efficiency can be improved to the 75% to 85% range.
Figure 3200-6 compares the efficiency of Cogeneration with the conventional way of making steam at the plant and purchasing electric power from the utility.