Steam system pressure optimization

The efficiency of the Rankine cycle itself can be increased by higher motive steam pressures and superheat temperatures, and lower surface condenser pressures in addition to rotating equipment selection. These parameters are generally optimized on the basis of materials of constmction as well as equipment sizes. Typical high pressure steam system conditions are in excess of 10,350 kPa (1500 psi) and 510 °C. 

Once the highest steam level is set, then intermediate levels must be established. This involves having certain turbines exhaust at intermediate pressures required of lower pressure steam users. These decisions and balances should be done by in-house or contractor personnel having extensive utility experience. People experienced in this work can perform the balances more expeditiously than people with primarily process experience. Utility specialists are experienced in working with boiler manufacturers on the one hand and turbine manufacturers on the other. They have the contacts as well as knowledge of standard procedures and equipment size plateaus to provide commercially workable and optimum systems. At least one company uses a linear program as an aid in steam system optimization. 

Nuclear reformer tube heating with a high-temperature reactor is performed with helium, typically at 950 °C, as the heat source. A counterflow scheme allows the use of internal return pipes for the product gas. Experience in construction and operation was gained with the EVA-I and EVA-II facilities at the Research Center Jiilich. The perceived disadvantages of a nuclear steam reformer with its comparatively low heat transfer and its high system pressure can be overcome by design optimization to increase heat input into the process gas and its conversion rate. 

Constraints Optimizing the steam system is to know what knobs to turn, which can change operating costs. First, the steam system should avoid any foreseeable losses such as steam trap losses, leaks, and poor insulation. This issue has been discussed in detail in Chapter 18. Second, the pressure of steam headers eould be optimized. This is usually done onee within a time period and they are maintained to the optimized values after optimization. 

The only way to reconcile the true cost implications of a reduction in steam demand created by an energy reduction project is to use the optimization techniques described in the previous section. An optimization model of the existing utility system must first be set up. Starting with the steam load on the main with the most expensive steam (generally the highest pressure), this is gradually reduced and the utility system reoptimized at each setting of the steam load. The steam load can only be reduced to the point where the flowrate constraints are not violated. 

Extraction of potable water from saline waters by means of immiscible solvents has been shown to be theoretically possible, experimentally feasible, and economically attractive. Data presented show the process to be especially adaptable to the conversion of feed water in the range of 5000 to 10,000 p.p.m. It is adaptable to use of low-quality heat such as hot water from cooling towers or low pressure waste steam. By use of mixed solvent systems, the process can be optimized to take advantage of seasonal changes in temperature and sources of cold feed water and low-level heat sources. The process, in general, is somewhat more economical when a cold source of feed water is available. 

Back-pressure turbine control system for the generation of LP steam, provided with valve position-based optimizer. 

In the secondary reformer, process air is admitted to the syngas via a special nozzle system that provides a perfect mixture of air and gas. Subsequent high-pressure steam generation and superheating guarantee maximum process heat usage to achieve an optimized energy efficient process. 

The detailed optimal results for each stream are shown in the Fig. 2, Table 3 and Table 4. It is showed that this process condensate reusing system need three mass exchange units, one for natural gas stripping, two for medium pressure stripping. The process condensate first is divided into two streams, dealing with the natural gas and medium pressure steam respectively, and then the effluents are united and stripped with medium pressure steam again. 

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