Abbreviations: ID, identification number; kW, connected load; Serv., unit in service (1) or on standby (0); LF, load factor (<1); UF, utilization factor (<1); DF, calculated diversity factor (Serv *LF*UF).
We were all told to size the plant motors to make them operate at not less than 80% of their nominal ratings. This is to save on the cost of motors as well as to operate them at their highest efficiency and thus reducing the cost of energy. My personal feeling is that when all is well and done, the operating load will be around 50–60% of the connected load.
Occasionally, it does happen that a motor is undersized and must be replaced. But, more often, the motors are oversized and operate with a low load factor. That scenario does not seem to concern the owners. Falling short certainly is a bad news.
Here, we go. Let us determine the projected operating load. First, we prepare the complete “Load List.” A partial example of the list is given in Table 2.3 for several plant loads.
Based on the small sample, the operating load is 41.2% of the connected total load. This is just an engineering guess on the paper, for now.
One can create his own tabulation to suit the particular plant and define the load factors for its own reasonable comfort suited to a type of the plant. In this case, we used the factors for the peaking duty: peaking operation for one hour duration. The load in the table is calculated by multiplying the connected load (kW) with the diversity factor (DF).
It was mentioned earlier that the process plant will be operating 24 hours, while the crushers will be working one 12‐hour shift only. Most of the maintenance and admin will be shut down too. Since we are concerned with the maximum plant load over one hour, the crushing plant is included. A welding receptacle or a crane or similar loads, for instance, have low utilization factors as maintenance work is not a continuous work.
Based on the load estimate for the 4.16 kV load, the plant transformers will be 13.2 to 4.16 kV, 12/15 MVA, Dyn1, ONAN/ONAF, BIL 110 kV, 55 °C rise at 30 or 40 °C ambient, depending on the environment. If the plant is in the Northern region, the ambient temperature can be <40 °C.
2.7.3 Voltage Level Selection
In our earlier discussion, we have proposed the voltage levels for the plant. Here, we will confirm the plant voltage levels for the primary and secondary plant distribution and the plant loads. The primary switchgear (Figure 2.8) is located at the main substation several kilometers away from the process plant with convenient routes to feed all the plant buildings with overhead distribution lines.
For the primary distribution, we can apply either 13.8 or 20, or even 33 kV voltages. The switching equipment and cables at 20 and 33 kV are considerably more expensive compared to 13.8 kV equipment. However, higher voltages may be needed if the distances are over 10 km and if there is a need for transfer of larger blocks of power. Since the project requires a large number of short feeders, it does not seem to be cost‐effective to distribute minor load at higher voltages.
The distances to the plant load centers are not large (<6 km) and 13.8 kV can be employed without significant voltage drops (<5%), which is to be verified by system studies.
Therefore, 13.8 kV voltage seems to be the most appropriate for the primary distribution throughout the site for this 40 MVA plant.
Figure 2.8 Plant MV switchgear.
We have already noted that a single transformer must be able to carry the full plant load of 40 MVA for an emergency condition of having one transformer out of service. The maximum incoming current without overloading from a 30/40 MVA transformer is 1675 A at 13.8 kV and 700 A at 33 kV. The standard 13.8 kV switchgear breakers go up to 4000 A. Forced air or water cooled breakers up to 5000 A are also available, but considered less reliable. Since we do not wish to have water complications in the switchgear, we can limit ourselves to lower breaker ampacities.
A good engineering practice dictates that breakers can be loaded to up to 80% of their nominal ratings. For instance 960 A for a 1200 A frame breaker. However, in case of an emergency like having a failure of one incoming transformer, the incoming breaker can be loaded closer to its nameplate rating.
Since the maximum incoming current at 13.8 kV is expected to be 1675 A (40 MVA), we can choose 2000 A incoming breakers. The breaker maximum loading is calculated to be 84% of the expected maximum rated current. The switchgear bus will be of the same rating, as the incoming breakers.
The most common types of breakers at 4.16 and 13.8 kV are vacuum type breakers.
2.7.4 Switchgear Breaker Ratings
The breakers must be selected based on their continuous capability and short‐circuit interrupting duty. The interrupting rating of the switchgear breakers will be based on the short‐circuit fault contributions from the source and the plant motor load to a fault on its bus. For the calculations of fault contributions on the 13.8 kV side of the main transformers, we will use conservative values and ignore the system source impedance, i.e. we will assume it to be zero, as noted earlier.
Let us assume the impedance of the main transformers is 9%.
For the selection of the switchgear breakers it is required to determine the following:
Voltage: It must be the most economical voltage, at which we can transmit power throughout the plant.
BIL level: It goes with the selected voltage and the method of system grounding as a standard. For 13.8 kV switchgear it is 95 kV peak for indoors and 110 kV peak for outdoors.
Breaker
