Selective coordination studies for mission critical environments

Isolating an electrical fault condition to the smallest area possible is essential in providing the most reliable electrical distribution system with maximum uptime for your facility.

08/19/2013


Learning objectives

  • Learn the basics of protective device coordination studies.
  • Know the proper sizing of the transformer primary breaker.
  • Understand selective coordination impacts on arc fault.
  • Understand NEC Article 517 and ground fault coordination studies required for health care facilities. 

Figure 4: This is an aerial shot of the construction of the SABEY Intergate Quincy Data Center Facility. Lane Coburn & Assocs. worked closely with the owner, electrical contractor, and switchgear vendors to ensure proper coordination between all overcurreAn unexpected loss of power can have a significant effect on business, especially in a mission critical environment. Isolating an electrical fault condition to the smallest area possible is essential in providing the most reliable electrical distribution system with maximum uptime for your facility. Expensive electronic distribution protection equipment is not worth the extra cost unless a proper protective device coordination study is provided by an experienced electrical engineer. 

A properly coordinated system will limit an electrical fault to the nearest upstream protective device. After a one-line diagram of an electrical distribution system is completed and the brand and model of the protective devices are selected, an overcurrent protective coordination study can be completed. Protective devices can consist of both fuses and breakers. Evaluating the merits of choosing to use fuses or circuit breakers is beyond the scope of this article. The primary focus of this article is adjustable trip circuit breakers as the protective device. 

Severalparameters can be selected for each protective device. The total number, type, and sensitivity of the settings will depend on the specific device. Adjustment of these parameters allows for what is referred to as “curve shaping.” Curve shaping allows for better coordination between upstream and downstream overcurrent protection devices. Below is a list of the common possible parameters.

Continuous current rating 

Continuous current rating is often called the current sensor or plug. There are several possibilities: 

  • Long-time pickup (long time per unit): This is the long-time trip setting of the overcurrent protective device. This parameter, also known as continuous amps, is a percentage of the breaker’s nominal rating and can typically be set at 20% to 100%. This setting is usually achieved with a thermal overload in a molded case circuit breaker.
  • Long-time delay: This setting allows for inrush from motors to pass without tripping the breaker. This setting effects the position of the I squared T slope just below the continuous current setting.
  • Short-time pickup: This is typically provided with an adjustment of 5 to 10 times. This setting allows downstream overcurrent protection devices to clear faults without tripping upstream devices. It can also be adjusted to allow for transformer inrush current. 
  • Short-time delay and instantaneous override: This setting postpones the short-time pickup. It can be a fixed setting or an I squared T ramp setting. This allows for better coordination between upstream and downstream devices. An instantaneous override can be set at high current to override this function and protect electrical equipment. The I square T function of the short-time delay can provide better coordination when coordinating a breaker with a fuse.
  • Instantaneous: This setting will trip the overcurrent protective device with no intentional delay.
  • Ground fault setting (ground fault per unit): This is the percentage of the rating of the breaker for the ground fault setting. Per the NFPA 70: National Electrical Code, ground fault cannot exceed 1,200 amps, regardless of the size of the breaker.
  • Ground fault delay: This setting allows for a time delay before ground fault pickup, which allows for better selective coordination between multiple levels of ground fault protection. In addition, the time delay cannot exceed 1 second (60 cycles) for ground fault currents of 3,000 amps or more. 

Before beginning a coordination study, the electrical engineer should design a one-line diagram and coordinate with the electrical contractor and/or the equipment provider to determine the actual equipment to be installed. The following are required to provide an accurate protective coordination study:

  • Description, make, and catalog numbers of protective devices
  • Full load current at the protective device
  • Transformer kVA, impedance, and inrush data
  • Available fault current at the protective device
  • Conductor cable information including current carrying capacity and insulation type
  • Protective device design requirements from the serving utility.

It is common to perform complicated electrical protection coordination studies with computer software. These software platforms typically contain libraries that include most of the common overcurrent protective device required settings. Sometimes new device settings have to be developed by the electrical engineer in the software program. 

As noted above, with the review of protective coordination study basics, an electrical system’s reliability can be assured only if proper coordination is implemented between protective devices. The next portion of this article will review instances where the National Electrical Code requires a protective coordination study and where K-rated transformers are employed to deal with electronics and nonlinear loads can reduce reliability if not properly coordinated.

Using K-rated transformers 

On a typical transformer, the current and associated magnetic field is 90 deg out of phase with the voltage. When you close a breaker and turn on a transformer, the instantaneous magnetic field can be twice as high as normal. In an “ideal” transformer, the current required to supply this magnetic field would also be twice as high. However, in a real transformer, the core is saturated and the actual current required to create the field can be 12 times as high as normal. Factors such as the size of the transformers’ cores and the time the voltage is applied play roles in determining the amount of inrush current. 

Figure 1: This indicates a 30 kVA transformer protected by a 45 amp circuit breaker. The “Tx” refers to the transformer inrush. The 45 amp breaker curve is represented by the red hash marks. This breaker curve is to the right of the “Tx” ensuring that theThe actual inrush current mentioned above is different depending on the actual transformer manufacturer. It is critical to contact the specific manufacturer of the transformer supplied in the field. If actual transformer inrush data is not known, common industry standard is to assume the inrush is 12 times for 0.1 seconds and 25 times for 0.01 seconds. Figure 1 illustrates the transformer inrush at 12 times for 0.1 seconds. 

Electrical engineers were running into trouble some years back when the K13-rated transformer was becoming more prolific in regular office and mission critical facilities. A K13-rated transformer is often just a larger transformer with a smaller rating to compensate for harmonics. The same 110 amp breaker typically on the primary side of a regular 75 kVA transformer may trip when protecting a 75 kVA, K13 transformer. For sizing of the primary side overcurrent protective device for K13 or higher rated transformers, I recommend multiplying the input full load amps of a transformer by 125% and going to the next common size up. In addition, a breaker with the instantaneous setting is often required to allow for the transformer current inrush. As a final step, I recommend a coordination study to ensure the system will work before it is too late, after construction is complete and the engineer is stuck with an angry owner.


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Eddy , Brittish Columbia, Singapore, 12/16/13 12:37 AM:

Dear Sir,
I would like to share on SPOF (Single Point of Failure)

Single Point Of Failure (SPOF) And Resiliency Report

Background

In engineering, redundancy is the duplication of critical components or functions of a system with the intention of increasing reliability of the system, usually in the case of a backup or fail-safe. Global Switch are contractually obliged to provide at least N (full duty capacity) + 1 but in many instances we actually exceed these requirements with N + N

This level of redundancy can sometimes, by virtue of design or construction deficiencies have single control or other functions which in the event of failure will cause the system in which they are installed to fail despite having redundancy in terms of base units. These are called “single points of failure” or SPOFs.

It is important that to maintain the required 100% uptime that these SPOFs are identified and that an educated decision be made as to whether it is acceptable to live with these SPOFs or whether it is required to maintain acceptable levels of reliability or an acceptable limitation of risk necessary to engineer these SPOFs out.

Systems can be made more robust by adding redundancy or duplicating the plant or device in all potential SPOFs thus removing the single point of failure.

General Objective

The assessment of a potential SPOF involves identifying the critical components of a complex system that would result in a total systems failure in should it malfunction. Highly reliable systems should not rely on any such individual component failure. Clearly it is not sufficient to identify the weakness on its own; a decision has to be made as to whether the risk as acceptable or not and to establish the cost and feasibility of engineering out this single point of failure by adding additional redundant services. Providing master/slave controllers is a typical example of this.

Approach

This process would entail an initial highly detailed desktop analysis covering both electrical and mechanical schematics’. Any single items of critical plant should be noted these should be at least double fed or be duplicated in terms of function elsewhere such that their failure would not impact the service delivery of the site. BMS systems, Pressurisation units and water filtration units on a sealed system plus monitoring systems of most types are just a few examples of such plant. Careful consideration would have to be made of each of the systems such as DRUPS, Chiller, Generators, UPS, CRAC units to ensure that they did not have any single shared function that could cause the environment to go out of control.

A physical survey would have to be carried out to identify such weaknesses of generator cables running over transformers. If the transformer explodes the resultant fire would damage the cables. Whilst this is not a true single point of failure it is a potential risk which affects the site resilience. The operating regime for each system will need to be considered to ensure there is nothing within the system that would pose a total system risk. A good example of this is an N + X redundant system where the modules feed through a single static switch or output board. These two items are then the single points of failure.




Potential area for SPOF:

1. HV distribution:
a. Locations of HV switch room.
b. Main incoming power feed cables routes to HV switch gear.
c. Locations of the HV transformers & supplying cables routes.
d. Radial or ring feed for the incomer within the building
e. Radial or ring feed for the incomer from utility provider.

2. LV distribution:
a. LV main switch board location
b. LV distribution routes from HT transformer

3. DC system:
a. Location of DC system
b. DC system supply cable routes

4. Stand-by power:
a. Gen-set location
b. Gen-set switch room location
c. Cable routes from gen-set to gen-set switch board
d. Generator outgoing cable routes to main LV boards
e. Gen-set starting devices (Electrical / pneumatic starter)
f. Location of Compressors & air dryer with air reservoir if pneumatic starter
g. Power supply for Compressors & ait dryer
h. Routes of air pipe to the pneumatic starter for gen-set from air reservoir.
i. Location of diesel storage tanks
j. Location of diesel transfer pumps
k. Power supply for diesel transfer pumps
l. Single or multiple pipe line for the following:

i. Suction pipe from diesel storage tanks
ii. Discharge pipes from pumps to gen-set day tank
iii. Return pipes to the diesel storage tanks from gen-set day tank
iv. Over flow pipes to the diesel storage tanks from gen-set day tank
m. Diesel pipes routes to the gen-set day tanks

5. UPS supply to IT loads:
a. Location of UPS room
b. UPS topology (Single or modular)
c. Static by-pass module topology for UPS
d. Cables routes to UPS from MSB
e. Cables routes to Static by-pass module from UPS
f. Cables routes to Static by-pass module from MSB
g. Location of Battery rooms
h. Battery configurations, No. of strings etc
j. Cable routes to UPS from Battery isolator (if the battery far away from the UPS)
k. UMSB locations
l. Cables routes to UMSB from UPS
m. Cables routes to UMSB from MSB (Maintenance by-pass feed)

6. STS
a. Location of STS
b. Cables routes to STS from UMSB (A feed)
c. Cables routes to STS from UMSB (B feed)


7. PDU
a. Location of PDU
b. Cables routes to PDU from STS (main feed)
c. Cables routes to PDU from UMSB (Maintenance by-pass feed)

8. RDU
a. Location of RDU
b. Cables routes to RDU from PDU

9. Final circuits
a. Location of cee-forms / industrial socket for Racks from A feed RDU
b. Location of cee-forms / industrial socket for Racks from B feed RDU
c. Cables routes for cee-forms / industrial socket from RDU A feed
d. Cables routes for cee-forms / industrial socket from RDU B feed

13. Other critical services:
a. Power supply Water detection
b. Power supply fire alarm panel
c. Power supply for VESDA
d. Power supply for security equipment’s (CCTV, CAC, PA system, AV system)
e. Security systems topology (single or hot-stand by)
f. Location of security system server
g. Lighting & small power DBs with ATS or MTS
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