Providing four megs of power to protect computers.

Fast track design and construction, thorough testing, and adjustments as needed provide power assurance to client's data operations.A strong concern for power reliability at a data site is satisfied by an electrical design that includes installed on-site power, dual primary feeders, and a full UPS with N+1 redundancy of components (no single point of failure causing system shutdown). The on-site power

Fast track design and construction, thorough testing, and adjustments as needed provide power assurance to client's data operations.

A strong concern for power reliability at a data site is satisfied by an electrical design that includes installed on-site power, dual primary feeders, and a full UPS with N+1 redundancy of components (no single point of failure causing system shutdown). The on-site power consists of two engine-generator (EG) sets, with each generator serving as backup to one of the dual primary feeders. These same generators also can operate in parallel with utility service.

How the system works

The peaking/emergency electrical system is designed for five modes of operation. A review of the system one-line diagram shown on page 24 will help you understand these modes.

Normal off-line. In this mode, the generators are not operating. The 13.8kV feeder breakers are closed, energizing the client's step-down transformers from the respective utility feeders. The 13.8kV bus tie breaker is open. The generator systems must be in an automatic switching posture during this mode.

Peaking mode. In this mode, the generators are operating in parallel with the utility's 13.8kV system to provide peak power. The 13.8kV feeder breakers as well as the 480V generator breakers are closed. Alternately, one 13.8kV feeder breaker is open, the other closed, and the 13.8kV bus tie breaker is closed. The generator's controls are operating to provide fixed power output (usually equal to the prime rating) as well as adjusting the power factor (remote controllable, usually set to near unity).

Feeder transferred mode. In this mode, the generators may or may not be operating. The power system configuration calls for one of the 13.8kV feeder breakers to be open, the other closed, and the 13.8kV bus tie breaker closed, thus supplying both the client's transformers from one utility primary feeder.

Emergency stand-by power mode. In this mode, the generators are operating asynchronous to the utility's 13.8kV system, providing power to the client. The 13.8kV feeder breakers and bus tie breaker are open. The 480V generator breakers are closed. This mode is initiated automatically as a result of loss of normal power to the client (loss of both of the utility feeders). The generator controls operate the power output and the power factor. In this mode, the generators are not operating in parallel and the client's tie breaker between Busses MSB-1 and 2 is open.

Manual mode. During this mode, the 13.8kV switchgear may be placed in any configuration desired, and the generators may be run manually, through local control switches. All automatic control aspects of the switchgear system and the engine generator sets are suspended.

Benefits of flexible operation

The option of parallel operation of each of the two generator sets with each of the two primary feeders was a main design objective and meets several operational conditions. First, parallel operation allows both generators to supply power to a single utility feeder in peaking mode. If, while operating in the peaking mode with power flowing into the utility grid, utility power is lost on one of the primary feeders, the engine generator controls switch to an emergency stand-by mode. The affected 13.8kV feeder breaker opens. If an outlet exists through the other utility 13.8kV feeder, the 13.8kV bus tie breaker is synchronized closed, paralleling the two generator sets on the healthy utility feeder. Each primary feeder is sized to handle the entire 4000kVA load. This methodology allows maximum power delivery to the utility grid during a time when the utility may be in great need of power generation.

An emergency 13.8kV loop feeder is provided between the client's two 2000kW transformers in the event one of the primary feeders between the EG set switchgear and client's respective transformer is lost. This loop feeder can be quickly connected between the transformer with the healthy feeder and the other transformer after the dead feeder is disconnected. Both transformers contain loop-feed bushings on the primary with the emergency feeder "parked" in each transformer primary section. The use of this emergency loop feeder allows connection of the client's entire load to the two EG sets in the event of total loss of utility power. When the generators are paralleled, procedures allow for synchronization and equal load sharing of the client's load.

While these abnormal conditions may be very unlikely, the criticality of the data site's load and the utility's need for generated power during peak loads easily justifies the added expenses of providing for parallel operation of the generators.

Electrical design parameters

Several important considerations impacted the electrical design of the peaking/emergency electrical system.

Load factors. The facility was able to shed data processing load down to a required continuous operation limit of 2000kW. As such, 2000kW was the lowest module of power requiring continuous service to the data site. This estimated demand lead to the selection of two 1825kW prime (2000kW standby) rated EGs.

On-site power generation. During discussions with the local utility at the initial design stages, a dispersed generation program (on-site power) was identified. This program provides for the utility company to construct, own, and operate prime rated EG capacity located on a client's property for the dual purpose of providing standby emergency power to the client as well as prime peaking power to the utility. This program is part of an overall demand side management objective of the local utility and one that is carried out with concurrence of the State Utility Commission. A fixed dollar per prime kW is invested by the utility with the remaining costs contributed by the utility's customer. All operational and maintenance costs of the EG sets, including fuel, are borne by the local utility, which has ownership rights to the equipment. The customer has purchase rights after an agreed-upon time, normally 20 to 25 years.

System voltage. The serving utility had a standing agreement with a local dealer of EG sets for complete system construction, assembly, and delivery to site of such units. The dealer had successful experience with these installations.

The original intent was to order the generators with 13.8kV output to match the incoming primary feeder voltage for parallel operation. The EG manufacturer, however, didn't offer a 13.8kV set. Because they were available and could be promptly delivered, and because the sets had proven reliability, two 2596-hp turbo-charged diesels were specified through the utility, each connected to a 480V generator. This selection required that the generator output voltage be stepped up to 13.8kV for direct parallel connection to the utility grid. Thus, two 2000kVA step-up transformers were needed to bring the 480V generator power up to the 13.8kV level:These mineral oil-filled pad-mounted transformers were installed simultaneously with the 15kV switchgear. Each transformer is connected in series with it's respective generator set and power breaker in the switchgear.

The 13.SkV primary power is then connected to two facility-owned, 2000kVA, 13.8 kV/480V, pad-mounted transformers located adjacent to the data site.

Meeting site conditions

The two EG sets are each housed in separate weatherproof insulated enclosures, which were constructed by a local specialty switchgear shop. The EG sets were shipped directly to the local shop and fully assembled with controls inside the enclosures. The enclosures contain electric heating for the rugged Minnesota winters and ample ventilation for the hot and humid summers. Each EG set contains a 3000-gal bladder tank located in the sub-base, with double wall containment in the event of a leak. External sound attenuation hoods and oversized internal radiators are included to reduce the running noise while keeping the engines cool in mid-summer. It was determined from previous experience that more ground-level noise is generated by high tip speed of the radiator fan blades than from the muffled exhaust; hence, sound attenuation hoods were provided. All assemblies were delivered to the site on flatbed trailers, hoisted in place with a large crane, and installed within days.

In the mean time, the 15kV class switchgear, which includes utility grade relays and meters, programmable logic controllers, drawout circuit breakers, monitors, gauges, etc., was constructed by a local specialty switchgear shop. It was installed inside a separate weatherproof enclosure, interconnected, and tested before leaving the shop. The entire assembly was delivered to the site and set on a prepoured concrete pad within a matter of hours. To expedite construction, the concrete pads, primary cables, and manholes were constructed just prior to delivery of the switchgear and step-up transformers.

Equipment scheduling

The purchase order for the 13.8kV, twin peaking, 4000kW, generator-transformer system was placed with the local engine generator dealer on March 15. This dealer subcontracted the electrical apparatus (transformers, switchgear, etc.) with various other dealers. The schedule called for switchgear and transformers to be delivered to the site by June 25 and switchgear in service by July 16 of the same year. The EG sets also were to be delivered to the site by July 16. The full system was to be in service by August 27. This schedule provided the client with permanent dual-primary power by mid-July, and gave it additional standby EG-set power by the end of August.

Fortunately, the state's Pollution Control Agency (PCA) (see sidebar on page 30) granted preapproval for concrete pad construction in May, with final permit approval granted June 1.

This was a very aggressive schedule requiring a high degree of coordination among many parties. A rainy spring nearly ruined the underground primary feeder installation and concrete pads construction schedule. However, the team approach to construction paid off to everyone's benefit as the schedule was met and came within budget.

The local utility was especially cooperative and provided specialists from several of its divisions to help assure timely delivery of equipment by working with the engine generator vendor, by assisting with the installation of equipment, and by performing some testing services.

Testing the components

Testing of the switchgear was initiated even before it left the assembly shop. Once in place and connected to the utility primary feeders, load transfer testing was done on each feeder individually. With the client's scheduled relocation date near, the switchgear was permanently connected to the client's step-down transformers before the generators were on site. This way, the client's regular load could be powered up, the data processing equipment connected for a trial run, and internal adjustment procedures carried out.

Shortly after permanent power was established, the EG sets were transferred to the site and hoisted in place. The generators were load bank tested before final connection to the switchgear. Following testing of the EG sets, the next step was to cut over the generator feeders to the switchgear and test the entire system simulating an actual power outage. By this time, the client's data site was up and running. Therefore, any planned outage had to occur between the hours of 12:30 a.m. and 6:00 a.m., one Sunday a month, when the client was performing internal data processing maintenance. And, there had to be advanced notification.

The first full system test and cutover occurred on an early Sunday morning in mid August. A detailed time-based schedule of events and testing sequence was prepared, with alternate backup routines established in the event the actual systems test resulted in equipment failure or damage. Temporary site lighting was set up and backup personnel placed on call. As each feeder was cutover, power transfer sequence was tested first using a dummy 120V source of power, then each primary feeder was connected to the system.

In mid October, the generators were run in parallel with the utility for 10 hrs at full load output, including multiple start/stop sequences. Since this operation did not require an outage, the generators were run during normal hours.

On October 31, the generators were again tested early in the morning. A voltage potential of 59V was detected on Phase C to ground at the No. 2 generator output and the test halted. Subsequent investigation suspected the source of the problem to be a C-phase ground detection lamp with incorrect voltage rating, creating a low impedance path to ground. This caused the bulb to burn out, clearing the low impedance path before any protective devices operated. The problem was corrected by using a higher wattage ground detection resistor and matched ground detection lamps having equal voltage and wattage. At this point, the system still had not been tested with the primary feeders actually shut off. Loss of utility power had been simulated by opening the incoming power breaker.

Finally, on the early morning of December 19, the two primary feeders were sequentially interrupted at their respective riser poles, resulting first with total load transfer to the remaining primary feeder and then independent load transfer to respective generators upon startup and stabilization. No. 1 generator started and picked up its respective load of about 600kW within 24 sec. No. 2 generator failed to start right away and was manually restarted after a quick fuel-mixture adjustment was made. It also then picked up its respective load.

Unfortunately, No.2 generator exhibited a load imbalance: 500kW on Phase A, 300kW on Phase B, and 450kW on Phase C. Since the actual load was a balanced 3-phase load, something was wrong within the on-site generation power transfer system. After about 30 min of generator run time, the individual loads were automatically retransferred back to the utility and the generators initiated orderly shutdown. Follow-up investigation revealed that the B-phase fuse connecting the generator to the switchgear bus had become disconnected from its holding clip.

The team learned from this project that, even with thorough systems testing prior to leaving the factory or assembly shop, and with extensive testing on site prior to actual load pickup, small unanticipated problems can still occur when the real load is transferred during an actual loss of utility power. Therefore, you should specify and demand full systems operational testing under all scenarios, including pulling the plug on the incoming utility feeders. Monthly manual exercising of the plant under no load, but with maintenance personnel on site and alert, will also allow timely identification of nuisance problems without risking the loss of power to a critical load.

It was during this same cold December morning testing that the need for sound attenuation hoods on the generator enclosures was fully identified. Previous generator testing in late summer and fall occurred with leaves on the trees and other landscape vegetation helping to absorb the sound. But with all vegetation gone and the air still and cold, sound is transmitted long distances. It's not uncommon for generators to have a loading less than their full ratings, as occurred with this project as well. Under lightly loaded conditions, the engine exhaust noise is lower than at full load. However, the radiator fan blades rotate the same speed regardless of load. It's the noise of the fan blades (high tip speed) that created the need for the sound attenuation hoods. This is the same condition that causes an airplane's propeller to sound so much louder on engine run up and takeoff on a cold, still day.

Monitoring helps client keep track of status of equipment

The facility receives limited operational information directly from the switchgear for each of the two power modules for the following conditions.

* Run in peak mode.

* Run in standby mode.

* Fire detection alarm.

* System abnormal summary alarm.

* Programmable controller failure.

This information is imported directly to the facility monitoring system along with electrical load data, which includes voltage, kW load, kVA load, and power factor for each power module. This allows operating personnel to know what's going on with the power and assist the utility in monitoring local site conditions.

A review of the facility's incoming power monitoring logs showed utility loss on one of the primary feeders 14 times between June of one year and April of the following year. Twelve of these outages occurred during the months of June through August. The other primary feeder experienced eight outages during the same time period, with five of these during the June-through-August summer months.

Recent utility power outage

On a recent Sunday, at 7:42 a.m., another outage occurred. One of the local utility's primary feeder cables faulted inside the utility main circuit breaker cubicle, causing the respective substation feeder breaker to trip. Upon reclosure of the substation breaker, the nearby utility pole cutouts opened due to the faulted cable. As a precaution, the remaining feeder's breaker was opened upon hearing some crackling sounds coming from its cubical.

Unfortunately, the utility had the engine-generator controls on lockout mode, which prevented automatic start of each of the generator sets. The customer started preparing for an orderly shutdown of the datasite because UPS battery power was rapidly being used up and because computer rooms were getting hot due to loss of cooling.

The utility was immediately contacted upon loss of power and they quickly switched the generator sets into automatic operation. Within 15 min of initial loss of power, both sets were running, delivering full power to the datasite, with the faulted feeder disconnected. The faulted feeder was repaired and the circuit breaker line-side bussing replaced within a week. Full utility operation commenced five days later.


Demand side management: A process for reducing the demand on the power generation facility (usually the local utility) by the power user (utility customer). Various strategies can be used such as synchronizing the operation of large motors so that they do not operate concurrently.

Peak shaving: Reducing electrical power usage by a facility during a period when the serving utility is experiencing a heavy demand for its power, and/or, by providing on-site power to help the utility meet its power requirements.

Prime power: This is the rating for continuous operation of an engine-generator set (often, in lieu of purchased power from a utility) and represents the highest electrical power output available for unlimited hours per year, less time for maintenance.

Standby power: This is the rating of an engine-generator set when used as a secondary source of electrical power. This rating is based on the set operating 24 hours per day for the duration of the outage of the primary power source. Because there is only limited operating service of the set, the rating of the electrical output is higher than for the rating of the set when operating in prime power mode. Operation at the standby rating results in greater mechanical wear rates and greater stress on the mechanical and electrical components.


Its enlightening to see a complex project come together at breakneck speed, one that includes installation of on-site power with microprocessor control of the power, for the mutual benefit of both the client and the serving utility. The client, a Fortune 100 company, decided early in December 1992 to build a major computer datasite and office support facility that would accommodate nearly 1200 employees, consolidating its local work force. The company was growing very rapidly and needed to obtain the facility quickly. Therefore the client decided to lease an existing building in lieu of building a new one.

A vacant 340,000 sq ft manufacturing and storage building was found in a nearby community and remodel plans were immediately initiated. The schedule required a new 80,000 sq ft computer site, part of the overall project, to be completely operational within 8 months, with design professionals and contractors quickly selected for the team. Our firm was chosen to carry out the electrical and mechanical engineering, other than the engineering associated with the computer room systems. Fast track construction techniques were used to provide "hypertrack" construction.

Schematic design plans were started in early January 1993 with long lead equipment identified first. Tentative orders were placed with escape cancellation clauses in the event the lease of the building wasn't resolved in time to meet the client's schedule. Since the computer datasite was the driving force behind the project, the total project power needs were assembled and reliability of local utility power was analyzed. It was determined that two primary feeders, each from a different substation, were desired. However, the costs and construction time needed to obtain power from two separate substations was prohibitive. Therefore power from two separate feeders served by a single nearby substation was agreed upon. Analysis of existing utility power in the immediate area revealed that there had been multiple outages within the past 5 years, one caused by an auto collision with a utility pole at the corner of the project site.

A voluminous contract covering the engine-generators sets and the utility service being offered was worked out between the lawyers representing the utility company and our client. The whole project had a very tight time frame and the contract was resolved at a critical time that just avoided a time delay while the project permit was being reviewed by the state's PCA. The state legislators had recently enacted a requirement for all new pollution contributors, such as engine-generator sets, boilers, etc., to have the owner, or his or her agent, submit a highly detailed plan for review by the local PCA. Approval of the plan was required before any construction could begin, with stiff monetary penalties levied for early construction without a PCA permit. Therefore the utility constitution was extra cautious not to start any construction until the permit was approved, even though the project deadline was fast approaching.

Both the client and the serving utility benefited from this joint project. With new power generation plants costing upward of $2000 per kW to build, and a number of years for regulatory approval and construction, procuring 4MW of peaking power for $250 per kW is a bargain and a savings to the utility. Likewise, the client has 4MW of available standby power on site with an up-front contribution of about $188 per kW, but without the costs and headaches of maintaining, operating, or replacing the system. Even 100% of the preventative maintenance and fuel costs are borne by the utility. This allows the client to concentrate on it's core business with the peace of mind that highly reliable power will always be available to maintain its datasite operations.


Architect: Ankeny, Kell, Richter & Walsh Electrical Contractor: Electric Repair & Construction Co. Engine-Generator Vendor: Ziegler Power Systems Co. Utility Company: Northern States Power Co. Computer Room System Engineering: Hypertect, Inc.


EC&M Articles

"Mobile Generators Power Up Newark Airport," February '95 issue. "When Standby Systems Are Emergency Systems," May '94 issue. Cost: $9.95 for articles. Order No. 2248. Orders are taken via facsimile machines only. To order by fax dial 800-234-5709. (Have a credit card and your fax number ready when you call.)

Gayland J. Bender, P.E. is Chief Electrical Engineer for Lundquist, Wilmar, Potvin & Bender, Inc., Consulting Engineers, St. Paul, Minn.

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