Abstract:
A protection system for a power distribution system includes a bus voltage sensing unit to measure a bus voltage or a load voltage and a demand response module for estimating available demand resources on the distribution system for a period of interest. A distribution system analyzer is provided in the system for analyzing the bus voltage or the load voltage and system parameters to obtain voltage trip points for the available demand resources. A load control circuit controls the available demand resources based on the voltage trip points.

Description:
BACKGROUND 
     Embodiments of the invention relate generally to an electric power grid and more specifically to distribution protection system in the power grid. 
     Distributed generation generates electricity from many small energy sources such as photovoltaic cells and fuel cells. Instead of producing power using remote and large generator units, power is generated using a large number of small distributed generators to meet the local load demand. These small generators are interconnected to the grid at medium or low voltage levels. Solar PV as an example is increasingly being connected at low voltage levels as roof-top installations. 
     Generally, the distribution network topology, control and protection are designed assuming that power is flowing in one direction; from substation to loads. However, the presence of distributed generation may change both the magnitude and direction of power flow in the distribution network or the distribution system. The variability in distributed generation such as the intermittency in renewable generation causes the system operating conditions to vary frequently. For example, a loss or gain of one or more distributed generators may cause the feeder voltage to fluctuate or even violate the desired range. Without coordination, these changes may trigger the false tripping of protective relays including over-current, over-voltage or under-voltage relays. 
     In addition, disturbances in the distribution system may affect the operation of distributed generators. For example, IEEE Standard 1547 stipulates that when any voltage of a distributed generator bus is outside a given range, the distributed generator shall cease to energize the feeder (i.e. shut down by tripping offline) within a specified clearing time. The clearing time is the time between the start of a disturbance condition and the ceasing of the distributed generator to energize the feeder. The tripping of one distributed generator may deteriorate the voltage profile further and potentially result in cascading tripping of other distributed generators. 
     Another issue with connection of distributed generators is that it changes the fault current of the distribution system. In other words, when you connect a distributed generator to the distribution system it will contribute to the fault current based on the power it is generating. This can lead to a failure of protection systems to detect faults when there are high levels of distributed generation. One of the approaches to solve this problem is to adaptively change relay settings in coordination with changes in output power of the distributed generation. However, with this approach, the relay settings may not get updated as fast as the output of the distributed generation changes. A potential problem is that a sudden loss of distributed generator under full load may result in the tripping of the over-current relay when the relay set point is reduced to a very low level. Thus, large scale penetration of distributed generation will reduce the effectiveness of protection schemes either through reducing the detection of faults, of creating false trips in response to the loss of distributed generators. 
     Therefore, there is a need for an improved protection system and method to address one or more aforementioned issues. 
     BRIEF DESCRIPTION 
     In accordance with an embodiment of the present invention, a protection system for a power distribution system is provided. The protection system includes a bus voltage sensing unit for measuring a bus voltage or a load voltage and a demand response module for estimating available demand resources on the distribution system for a period of interest. The protection system further includes a distribution system analyzer for analyzing the bus voltage or the load voltage and system parameters to obtain voltage trip points for the available demand resources and a load control circuit for controlling the available demand resources based on the voltage trip points. 
     In accordance with another embodiment of the present invention, a method of protection a power distribution system is provided. The method includes estimating available demand resources on the distribution system for a period of interest based on demand response programs. The method also includes establishing voltage trip points for the available demand resources based on bus voltages or load voltages and system parameters. The method further includes controlling the available demand resources based on voltage trip points. 
    
    
     
       DRAWINGS 
       These and other features, aspects, and advantages of the present invention will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: 
         FIG. 1  is a diagrammatical representation of typical radial distribution feeder circuit; 
         FIG. 2  is a graphical representation of IEEE standard 1547-2003 for interconnecting distributed resources with electric power system; 
         FIG. 3  is a diagrammatical representation of a distribution system in accordance with an embodiment of the present invention; 
         FIG. 4  is a block diagram of a protection system in accordance with an embodiment of the present invention; 
         FIG. 5  is a graphical representation of voltage profile along a feeder on distribution system; 
         FIG. 6  is another graphical representation of voltage profile along a feeder on a distribution system; 
         FIG. 7  is a graphical representation of a current profile across various branches on a distribution system; and 
         FIG. 8  is a flowchart representing a method of protecting a power distribution system in accordance with an embodiment of the present invention. 
     
    
    
     DETAILED DESCRIPTION 
     When introducing elements of various embodiments of the present invention, the articles “a,” “an,” “the,” and “said” are intended to mean that there are one or more of the elements. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. 
     As discussed in detail herein, embodiments of the invention include a protection system and method for a distribution system. The basic principle is to utilize and manage aggregated demand side resources to prevent unnecessary tripping of traditional protection schemes in power distribution systems. This capability can significantly assist in managing distribution systems with high penetration of variable distributed generation, such as a solar power generation system. 
       FIG. 1  illustrates a single line diagram of a conventional radial distribution feeder circuit  10 . A generating station  11  supplies electric power to transmission and distribution substations  12 . The electric power from substation  12  is then fed to various loads  18  through a power circuit breaker or recloser device installed immediately next to substation  12  or in substation  12  but not shown here (such as an element  14 ) which may be operated by an instantaneous and time overcurrent protection device such as a relay  16  applied for fault detection. As will be appreciated by those skilled in the art, a fault refers to any short circuit condition that occurs between two nodes of an electrical circuit that are at different voltages. The faults that need to be detected may include three-phase, phase-phase, phase-ground, and multiple phases to ground short circuit faults. In certain embodiments, the loading capability of radial distribution feeder circuit  10  may range from 10 to 25 Mega Volts-Amp (MVA) for voltages of 12.5 to 34.5 kilo Volts (kV), for example. In some embodiments, along the radial distribution feeder circuit  10  there may be multiple other overcurrent protection devices which are time coordinated so that the device closest to the fault will trip the fastest. Also the settings of relay  16  are such that for higher fault currents the relay trips the recloser faster compared to the lower fault currents. 
     A distributed generator (DG)  22  may also be connected to the feeder circuit  10  through a recloser device  24 . The recloser device  24  may be operated by an under and over voltage relay  26 . If a fault condition occurs at location  28 , for example, the relay  16  will sense the fault and will trip the breaker  14 . When the distributed generator  22  is connected to the circuit  10 , the fault current at location  28  will increase compared to when the distributed generator  22  is not present. The following equations describe this problem: In absence of DG connection:
 
If=Is=Ir1  (1)
 
Where If is fault current, Is is the current supplied by substation  12  in absence of DG  22  and In is the current sensed by the relay  16 . As discussed earlier, when DG  22  is connected to the circuit  10 , the fault current will increase because of the contribution from DG  22  and can be shown as
 
 If=Is+Idg=Ir 2  (2)
 
Where Idg is the current supplied by DG  22  in absence of the substation power. Further it should be noted the sum Is+Idg is a vector sum i.e., all above terms are complex numbers or vector representations. Thus, it can be seen that the relay current Ir 2  in the presence of DG  22  is higher than the relay current Ir 1  in the absence of DG  22 . So in such cases the settings of the overcurrent relay  16  need to be updated. For example, if the relay  16  was set to operate at a current value of 1.5 pu in absence of DG  22 , then the same may need to be updated to 2 pu in the presence of DG  22 . However, since the power output from DG is fluctuating, there may be a substantial delay in updating the relay settings accurately. In certain cases, this may result in the tripping of recloser  14  even for momentary faults.
 
     It should be noted that although a DG will quickly adjust to fault conditions, some faults may cause the DG to disconnect from the feeder. If the location of the fault is close enough to the DG, this will cause the DG bus voltage to drop below acceptable limits and this will then trigger the voltage relay  26  to trip recloser  24 . The requirements for speed and voltage values of the voltage relay  26  are stated in the IEEE standards for Interconnecting Distributed Resources with Electric Power Systems. 
       FIG. 2  shows a plot  50  of IEEE Standard 1547-2003 for interconnecting distributed resources with electric power systems. In plot  50 , the horizontal Axis  52  represents voltage (in per unit) at a bus or node on the feeder where a DG is connected and the vertical axis  54  represents clearing time in seconds. The clearing time is the time between the start of an abnormal condition such as a fault and the point at which the DG ceases to energize the feeder. As can be seen from plot  50 , when the bus voltage is below 0.5 pu, or above 1.2 pu, the DG should be disconnected from the feeder within 0.16 seconds. Whereas the DG should trip within 2 seconds if the bus voltage is between 0.5 and 0.88 p.u. Similarly, the DG should trip within 1 second when the bus voltage is between 1.1 to 1.2 pu. Also it can be seen that the bus voltage from 0.88 to 1.1 pu represents an acceptable range whereby the DG need not disconnect from the grid during this time. Accordingly, the status of the DG during a fault (i.e., whether it should be connected to the feeder or not) will be determined via the voltage protection relay. However, the bus voltage may fluctuate because of temporary high-impedance faults or faults on a neighboring feeder or even because of significantly higher penetration of power from DGs. Thus, DGs may trip unnecessarily even though there is no fault. The loss of one DG may cause another distributed generator to trip and further trip other DGs without proper mitigation actions. In other words, rapid variations or disturbances in distributed generation or the grid may sometimes result in unnecessary tripping of protective relays for both distributed generators and feeders. These false trips are due mainly to variations in voltage and current that result from rapid changes in power flows. 
       FIG. 3  shows a distribution system  70  in accordance with an embodiment of the present invention. Distribution system  70  includes multiple protection systems  72 . Each protection system  72  determines the voltage at a bus  74  to which it is connected and utilizes demand response in controlling the bus voltages during abnormal conditions by switching on or off the available demand resources or loads. As discussed earlier, the abnormal conditions may include faults and voltage variations beyond the allowable limits as shown in  FIG. 2 . It should be noted that the protection system  72  may also be called a virtual relay since its function is similar to a voltage relay. In one embodiment, protection system  72  may be implemented in a centralized manner as a single controller for all loads on a single bus. For example,  FIG. 3  shows a single controller or a single protection system  72  for a single bus. The arrangement is then repeated for all buses  74 . In another embodiment, the protection system  72  may be implemented in a distributed manner as a single controller for a single load on a particular bus. Other embodiments such as multiple protection systems for multiple subsets of loads are also within the scope of this invention. 
     As an example, to implement protection system  72  in a distributed way, each demand resource or load is given local voltage set points to turn on or off in response to an over or under voltage condition respectively. Thus, the responsive demand resources are controlled by sensing the local voltages (i.e., voltages at the point of demand resources) and comparing them with predetermined time-delayed voltage set points. In other words, if the local voltage exceeds a predetermined value for a predetermined time then the responsive demand resources turns off. Further, the demand resources are set so as to trip faster than existing voltage relays in order to return the distribution system to expected operational profiles in the case of non-fault disturbances. The protection system  72  can respond to the loss of one distributed generator due to minor disturbances without disrupting the feeder operation, whereas traditional protective relays (e.g., 16) would otherwise trip the circuit breakers under real faults despite of the actions of the protection system  72 . This method only reduces outages caused by false trips of existing protection relays. Protection system  70  also prevents unnecessary feeder interruptions when feeder over-current relay settings are not updated fast enough while allowing tighter relay settings to protect against high impedance faults. 
       FIG. 4  shows a block diagram of a protection system  72  in accordance with an embodiment of the present invention. Protection system  72  includes a bus voltage sensing unit  92 , a distribution system analyzer  93 , a demand response module  94 , and a load control circuit  96 . It should be noted that any of the blocks described herein (e.g.,  92 ,  93 ,  94 , and  96 ), may be a software, or a hardware, or a firmware, or any combination of these, or any system, process, or functionality that performs or facilitates the processes described herein. Bus voltage sensing unit  92  measures a bus voltage and provides it to the distribution system analyzer  93 . In one embodiment, the bus voltage sensing unit  92  may be voltmeter or a potential transformer (PT) with its higher voltage side connected to a bus (e.g.,  74  of  FIG. 3 ) on the feeder and a voltmeter connected to its lower voltage side utilized for measuring a proportionate voltage on the bus. In another embodiment, the bus voltage sensing unit  92  may be a processor that executes a load flow algorithm that provides voltage information on various buses. Demand response module  94  estimates demand response resources or events available in the distribution system at a given time and then provides that information to distribution system analyzer  93 . As will be described in detail in following paragraphs, demand response resources refer to an electrical load of consumers who agree to shed their load in certain cases in exchange for some monetary benefits. The distribution system analyzer  93  then utilizes available demand response resources to alleviate false relay tripping. 
     In general, demand response refers to mechanisms used to encourage/induce utility consumers to curtail or shift their individual demand in order to reduce aggregate utility demand during particular time periods. For example, in the present embodiment, electric utilities employ demand response events when the bus voltage violates a prescribed range in order to alleviate a power imbalance and to avoid unnecessary DG relay tripping. Demand response programs offered by utilities typically offer customers incentives for agreeing to reduce their demand during certain time periods. 
     Demand response programs such as critical peak pricing (CPP), Variable Peak Pricing (VPP), Direct Load Control (DLC), and other various incentive programs are examples of programs wherein a utility specifies contractual obligations on when, how often, and the duration of a demand response event for a participating customer. For example, a contract may specify that the utility can invoke up to 15 events per year, where each event will occur between the hours of 12 pm and 6 pm for up to a maximum of 60 total hours per year. 
     Distribution system analyzer  93  analyzes the bus voltage value determined by the bus voltage sensing unit  92  as well as other system parameters. Such system parameters may include voltage regulator information, capacitor bank information, adaptive relay settings and overall system operating conditions. Distribution system analyzer  93  further determines the circumstances under which false relay trips of distributed generation due to IEEE 1547 specifications might occur. Distribution system analyzer  93  then establishes voltage trip points for each of the participating load resources identified by demand response module  94  for that time. The voltage trip points are voltage values associated with respective clearing times that determines on and off times for the available demand resources. Thus, if the bus voltage exceeds the set points for the specified clearing time, the load control circuit  96  will switch on or off part or all of the responsive load. The load control circuit  96  can return the affected load to normal operation once the voltage returns to the acceptable range. 
     One of the main criterions for distribution system analyzer  93  in establishing voltage trip points for load resources is that the action of switching off or switching on the load should be faster than the existing distribution system voltage or current relays ( 26  or  16  of  FIG. 3 ). Table 1 shows a comparison of clearing time for DG relay tripping as per IEEE 1547 and clearing time for demand response in accordance with an embodiment of the present invention, 
                                                 TABLE 1                   Clearing Time (CT) under different voltage levels            Voltage Range (per   Clearing time for relay   Clearing time for demand       unit)   tripping (seconds)   response (seconds)                      0 &lt; v ≦ 0.50   0.16   0.12       0.50 &lt; v ≦ 0.88   2   1.6       0.88 &lt; v ≦ 0.92   NA   3       0.92 &lt; v &lt; 1.05   NA   NA       1.05 ≦ v &lt; 1.10   NA   3       1.10 ≦ v &lt; 1.20   1   0.8       1.20 ≦ v   0.16   0.12                    
As can be seen from the table, for bus voltages between 0 to 0.5 pu and beyond 1.2 pu, the relay will trip the respective recloser or circuit breaker in 0.16 seconds. However, the demand response event needs to occur even before 0.16 seconds and hence is set to operate within 0.12 seconds. Similarly, for the voltage between 0.5 pu to 0.88 pu, the relay will trip the recloser within 2 seconds, however, the demand response will occur in just 1.6 seconds. Voltages between 0.92 pu and 1.05 pu are considered normal and neither relay nor demand response is activated. It should be noted that the values of clearing time for demand response in table 1 are mere exemplary and in other embodiments the distribution system analyzer might use other values based on overall system conditions with the objective of minimizing the disruption to the consumers and as well as protecting distributed generators.
 
     Another criterion for distribution system analyzer  93  in establishing voltage trip points for load resources is the location of demand response resource. In one embodiment, demand resources that are close to distributed generators may have the greatest impact on improving the voltage profile of the system in response to a loss of that particular distributed generator. Thus, the responsive demand resources are activated based upon local setpoints and clearing times which may vary according to circuit characteristics or voltage profiles. It may also happen that multiple demand response resources may be required to participate in the protection scheme. For example, if the demand resources at a particular DG location are not sufficient, the resources at adjacent nodes may come into play, since there may be some correlation between the voltages at adjacent nodes. The set points for a particular demand resource can be adjusted both to maximize the impact for protection, and to also equitably or economically distribute the number of times a particular load is called upon to respond. It may happen, as an example, that the demand resource at the end of the line would get picked all the time because it has the greatest impact on improvement on voltage profiles. Adjusting set points or random selection of available demand resources may be an option to solve this problem. 
     Yet another criterion for distribution system analyzer  93  in establishing voltage set points for load resources is the amount of responsive load. The distribution system analyzer  93  needs to determine the amount of responsive load necessary for given conditions. For example, insufficient load reductions will not restore voltage to levels that will prevent tripping of distributed generators. On the other hand, excessive load reductions will result in unnecessary disruption of the service to some customers. In one embodiment, a theoretical analysis of the sensitivity of node voltage changes to power flow variations may be conducted to determine how much load reduction is appropriate. In another embodiment, a sampling approach in a distributed way is utilized to phase in load reductions as needed. Typically, the household load is not continuous. When an appliance or a piece of electronic equipment is turned on or off, the load consumption changes discretely. So in the sampling approach, parts of the household loads are shed selectively in an increasing order instead of shedding all loads at once. The timing of individual pieces of load can be slightly different, and neighboring households may have random timing. This allows appropriate amount of load reduction to return voltage to desired levels. 
       FIG. 5  shows voltage profile plot  120  for an example distribution system  130 . The distribution system  130  is a five bus system with a DG  22  on bus  3 . Protection systems  72  are located on each of the buses  3 ,  4 , and  5 . Plot  120  shows a voltage profile along the feeder on the distribution system  130 . Horizontal axis  122  on plot  120  represents bus number and vertical axis  124  on plot  120  represents bus voltage in pu. Plot  120  shows three different curves  126 ,  128 , and  129 . Curve  126  is a voltage profile when DG  22  is supplying power to distribution system  130 . Curve  126  shows that voltage on bus  1  is approximately 1 pu and because of the voltage drop on feeder between bus  1  and bus  2  the voltage on bus  2  falls to around 0.99 pu. At bus  3 , since the DG is connected, the voltage goes up to around 1 pu whereas on bus  4  and  5  the voltage drops to around 0.97 and 0.96 pu respectively. 
     Curve  129  shows voltages on various buses in absence of protection system  72  and when DG  22  is disconnected from distribution system  130 . Since there is no DG on bus  3 , the voltages from bus  1  to bus  5  keep dropping from 1 pu to approximately 0.86 pu. However, when protection system  72  is employed the loads on distribution system  130  are controlled such that half of the load on bus  4  and bus  5  are shed or turned off. This results in improvement in voltages profile  128  on buses  1  to  5  with voltages now varying from 1 pu to 0.91 pu instead of 1 pu to 0.86 pu as in curve  129 . The improvement in voltage profile occurs because when the loads are reduced the current in the feeder reduces which reduces voltage drop across the feeder and increases bus voltages. 
       FIG. 6  shows another voltage profile plot  150  for an example distribution system  170 . The distribution system  170  is a five bus system with a first DG  22  having a higher power rating on bus  3  and another DG  22  with a lower power rating on bus  5 . Plot  150  shows four different curves  152 ,  154 ,  156  and  158 . Curve  152  is a voltage profile when both DGs  22  are supplying power to distribution system  170 . Curve  154  represents a voltage profile when first DG  22  is disconnected from the system  170 . The first DG may be disconnected because of several reasons. For example for a wind generation plant there may not be sufficient wind in the particular area. It can be seen that with the first DG, disconnection voltage on bus  5  drops to almost 0.87 pu. This voltage value exceeds the prescribed limit by IEEE standards and will result in tripping of the second DG  22  which further pulls down the overall system voltages as shown in curve  156 . However, when the protection system  72  is employed into system  170 , voltage at bus  5  increases above 0.92 pu as shown in curve  158  which ensures that second DG  22  need not be disconnected from the system. 
       FIG. 7  shows a current profile plot  180  for an example distribution system  200 . The distribution system  200  is similar to distribution system  170  of  FIG. 6  with an adaptive overcurrent relayl 6 . In the illustrated embodiment, adaptive overcurrent relay settings are such that in absence of any DG the overcurrent relayl  6  trips recloser  14  within 0.2 seconds when the overcurrent relay senses the current of 2 pu. The adaptive overcurrent relay settings are changed to 0.85 pu in presence of DGs. Plot  180  shows 6 current profile curves  186 ,  188 ,  190 ,  192 ,  194  and  196  across various branches. Horizontal axis  182  of plot  180  represents branch number whereas vertical axis  184  represents current supplied from that particular branch. Curve  196  merely represents a setpoint of adaptive overcurrent relay  16  in absence of DG, where the setpoint refers to a current value at which the relay should trip. Curve  194  shows a current profile when the first DG  22  is connected into the system  200  with full load. When the first DG  22  is disconnected with full load still being present, the current from branch  1  increases to around 0.9 pu as shown in curve  190 . Since this current exceeds the setpoint of adaptive overcurrent relay  16 , relay  16  trips the circuit breaker or recloser  14 . Thus, disconnection of one DG from the distribution system  200  results in disconnection of the complete circuit  200  from a power grid. However, when protection system  72  is employed, the protection system disconnects some of the loads on bus  4  and  5  improving the current profile along the branches as shown in curve  192 . Now since the current from branch  1  (0.8 pu) is lower than adaptive relay setting (0.85 pu) it doesn&#39;t trip the circuit breaker  14  thereby keeping the circuit  200  energized. Thus, protection system  72  prevents complete breakdown of system  200 . 
     Further, curve  186  shows a current profile when there is a short circuit fault on bus  4  in the absence of DGs, whereas curve  188  shows similar current profile in the presence of DGs. As can be seen from curve  188 , when there is fault in presence of DGs, the fault current at bus  1  goes to around 1.4 pu exceeding the adaptive relay settings of 0.85 pu and thus tripping recloser  14  and protecting circuit  200 . Thus, protection system  72  does not affect overcurrent relay operation in the presence of faults. 
       FIG. 8  shows a method  220  of protecting a power distribution system in accordance with an embodiment of the present invention. At step  22  of method  220  available demand resources for the demand response are determined As discussed earlier, the demand response programs include critical peak pricing (CPP), Variable Peak Pricing (VPP), Direct Load Control (DLC), and other various incentive programs. In step  224 , voltage trip points are established for the available demand resources. In one embodiment, the voltage trip points may be determined based on bus voltages when the control is centralized or based on local load voltages when the control is distributed. Other factors that help in identifying voltage trip points include system parameters such as voltage regulator information, capacitor bank information, and adaptive relay settings. In step  226 , the available demand resources are controlled as per the voltage trip points. Controlling available demand resources may include switching on or switching off part or all of the loads either at once or in steps. 
     One of the advantages of the proposed system is that it allows for tighter settings for protection relays in the distribution system to detect high impedance faults. High impedance faults are those which have lesser fault currents due to high impedance such as tree or sod between the power line and the ground. Generally, the protection relays are unable to distinguish between these high impedance faults and common load imbalances. In one embodiment of the present invention, this problem is solved by reducing the settings of the protection relay. For example, reducing the current settings of the relay from 1.5 pu to 1.3 pu gives a detection capability of high impedance fault of 1.3 pu. This is possible because the contribution of the DG to the fault can now be diverted to a certain amount of load. 
     While only certain features of the invention have been illustrated and described herein, many modifications and changes will occur to those skilled in the art. It is, therefore, to be understood that the appended claims are intended to cover all such modifications and changes as fall within the true spirit of the invention.