Control Strategies for Distributed Generators ...

Paper accepted for presentation at 2003 IEEE Bologna Power Tech Conference, June 23th-26th, Bologna, Italy

Control Strategies for Distributed Generators operating on Weak Distribution Networks S. J. van Zyl, Member, SAIEE, and C. T. Gaunt, Member, IEEE

Abstract--The application of DG in South Africa is dominated by schemes operating synchronous generators. Reports have indicated the possibility of overvoltage problems that result when operating DG on lightly loaded feeders. It was expected that the "weak" nature of South Africa's distribution networks might exaggerate these effects. A load-flow study was undertaken to investigate the impact of various system parameters on the allowable levels of generation by DG before the onset of network overvoltage conditions. Among the parameters considered are source impedance, feeder load and voltage level. The results of the load-flow simulations were used to develop a composite control strategy for synchronous DG that could be applied when the penetration limits for unity power factor generation are too restrictive. A generalised approach to selecting the control mode for synchronous DG is proposed, and is applied to two South African DG case studies with good results.

Index Terms--Distributed Generation, Generator, Voltage Control, Weak Network.

Synchronous

I. INTRODUCTION HE application of DG in South Africa appears, at first T glance, to be very limited. Novel generation technologies are costly to import and are more so to develop, and must compete with inexpensive power supplied from the country's coal-fired power stations. Current environmental pressures in the country are lenient relative to international standards and as a result there is little drive to adopt more “green” forms of generation. Deeper investigation, however, reveals a number of cogeneration schemes and independently operated generators which either already generate power onto the local distribution networks or which could do so with minor modifications to existing plant, and which fit the commonly accepted definition of Distributed Generators. Synchronous generator technology is used most often in these applications. Synchronous generators can be operated in one of two broad modes of reactive power control: (i) constant reactive power/power factor, or (ii) constant voltage control [1]. This work was supported by Eskom, the national electricity utility in South Africa, in the form of a study bursary and a broader research grant. Financial support is also provided for the project from the National Research Foundation’s THRIP programme. S. J. van Zyl is a student of the University of Cape Town and is employed by Eskom, P.O. Box 1178, Bromhof, 2154, South Africa (e-mail: [email protected]). C. T. Gaunt is with the University of Cape Town, Private Bag, Rondebosch, 7700, South Africa (e-mail: [email protected]).

0-7803-7967-5/03/$17.00 ©2003 IEEE

Tariffs offered to DG operators in South Africa encourage generation at unity power factor (UPF), although no penalties are levied for operation at a leading power factor (i.e. DG absorbing reactive power). DGs are not paid for reactive power supplied to the network and, as a result, none of the country's independently owned generators function in a network voltage supporting role. Documentation from those DG schemes that currently operate in parallel with the Eskom distribution networks indicate that each application was extensively evaluated in terms of generator and intertie protection. To this end, an Eskom protection guideline similar to the United Kingdom's "G59/1" was drafted in 1996. Significantly, no record exists of studies performed to evaluate the effect of power generation by DG on network voltage levels, nor has any guidance been given to DG operators on their choice of generator operating mode. This study was initiated in an attempt to better understand the impact on network voltage levels of operating synchronous DG on the South African distribution systems. This follows a number of recent publications in which concerns were raised regarding overvoltage conditions that can arise from excessive generation onto lightly loaded networks (for example [2], [3], and [4]). It was expected that this phenomenon might be exaggerated for generation onto the high impedance networks that are characteristic of the South African distribution systems. The paper begins with a description of the voltage rise effect that results from DG operation and includes an introduction to salient features of distribution networks in South Africa. A network model is then used to study the impact of various system parameters on the allowable power generation by DG before the onset of overvoltage problems. The results of these studies are used to design a custom control strategy that will allow for increased penetrations of DG in distribution networks. A generalised approach to specifying DG operating modes is developed and is applied to two South African DG case studies in the final section of the paper. II. VOLTAGE RISE EFFECT The voltage rise effect that is seen to occur with the introduction of DG to a passive distribution network is most easily understood by considering a simple two-node network. The network in Fig. 1 includes a conductor of impedance R+jX (Ω/phase) across which a quantity of real-, P1 (kW), and reactive power, Q1 (kVAr), is transferred.

V = V2 DG and/or load location

P1 Q1

Source 1

2

Fig. 1. Simple network used to illustrate the voltage rise effect.

Using the model of Fig. 1 and simple network theory, it is possible to derive an approximate expression for the voltage magnitude at the receiving end busbar, V2(kV), in terms of the sending-end voltage, V1(kV) and the given network parameters: RP + XQ1 (1) V2 = V1 − 1 3V1 In passive distribution networks, P1 and (normally) Q1 flow in the direction as shown in Fig. 1, and give rise to a volt-drop between the sending- and receiving-end busbars as indicated in (1). The introduction of DG to such a feeder reduces the amount of real power, P1, that must be supplied from the source, and hence reduces the volt-drop between busbars 1 and 2 in Fig. 1. If the DG generates at UPF, it will have only a slight impact on the source-supplied reactive power term, Q1, corresponding to a reduction in reactive power losses across the conductor. In the event that the real power generation by the DG exceeds the local demand, it will reverse the direction of the P1 term in Fig. 1. If the reverse flow of real power is of sufficient magnitude, it can overcome the volt-drop caused by the "XQ1" term in (1) and will give rise to a net voltage rise between busbars 1 and 2 in Fig. 1. Masters [2] describes a number of methods by which the DG voltage rise effect can be mitigated. These include (i) operating the generator at a leading power factor (absorbing reactive power), (ii) reducing the sending-end voltage, (iii) installing voltage regulators on the line, (iv) upgrading the network, and (v) constraining the generator. Each of the above mitigation options will have cost implications, and may jeopardise the financial viability of DG projects. This is especially true of DG in South Africa that competes with energy from central power stations using low grade coal. For this reason, it is important that the extent of the voltage rise effect in typical DG applications is understood.

III. DISTRIBUTION NETWORKS IN SOUTH AFRICA A. Characteristics The majority of rural distribution networks in South Africa are constrained by voltage-related issues rather than capacity or waveform quality. These networks can be described as being electrically "weak". The weakness of South Africa's networks can most often be attributed to the sparsity of load. To this end, [5] indicates that rural load density figures of the order of 100kVA/km2 are not uncommon. The distributed nature of network load dictates that rural distribution feeders are long (20-100km), and HV/MV transformer capacities are relatively small (from

750kVA). The feeder backbones are typically strung with ACSR “Hare” (0.32 + j0.38 Ω/phase) or “Mink” conductors (0.52 + j0.39 Ω/phase). This coupled with the long lengths tends to make line impedances high, and small transformer capacities contribute to making busbar source impedances high. The three-phase fault level at a busbar provides a good indication of the source impedance at that location but provides a worst-case estimate as it neglects the impact of upstream load. Accurate loading data is seldom available for use in computer-based network simulation tools, but busbar fault levels are easily and accurately calculated using these packages. Each of Eskom's distribution regions compiles an annual report of calculated fault levels at all MV and HV busbars in their area. These reports were used to compile the cumulative percentage busbar fault level distributions in Fig. 2. 100%

22kV 80%

66kV

60%

132kV

480 MVA

R + jX

Percentage of Sample

V = V1

40%

20%

0% 0

200

400

600

800

1000

1200

1400

Three Phase Fault level (MVA)

Fig. 2. Cumulative percentage distribution of busbar fault levels in South Africa.

The "66kV"curve in Fig. 2 indicates that 80% of all 66kV busbars in the Eskom system have three-phase fault levels below 480MVA. The ratio between the minimum and maximum load on a feeder is termed the "load ratio". Rural feeders in South Africa typically have low load ratios of between 10% and 40%. B. Voltage regulation - application and limits Voltage regulation in MV networks in South Africa is achieved through the predominant application of On-Load Tap Changers (OLTCs) to substation transformers. Given that the distribution networks are often constrained by voltage-related problems, it is common for substation MV busbar voltages to be regulated at 103% of nominal, although settings as high as 104% are applied in extreme circumstances. Tap change bandwidth settings are typically 1.4% or 1.5%. Line Drop Compensation (LDC) and Voltage Compounding OLTC control techniques are seldom applied on South African distribution networks. These methods are beneficial in rural areas where the load density is low, but are better suited to substations where each feeder is fitted with an independent voltage regulator [6]. In any event, as described by Persuad et al [3], the operation of DG on a LDC-enabled feeder introduces error in the controller's voltage predictions and limits the effectiveness of the technique.

In Eskom, the voltage regulation limit for direct supplies to customers at medium and high voltages is normally contracted as a default value of Vnom±7.5%, although [5] stipulates that the actual voltage must fall within +5%, -7.5% under normal network conditions. This range is adopted to limit the overfluxing of MV/LV transformers and the increased losses, winding degradation and harmonic generation that occur as a result of higher voltages. Carter-Brown [5] suggests that the voltage on an MV feeder can be raised as high as 106% under abnormal conditions (not lasting more than 48hrs), but that the voltage should never exceed this threshold. Interestingly, the above discussion is only applicable to selected distribution networks in South Africa. This follows recent research that indicated that the capacity of voltageconstrained networks could be increased by applying a new philosophy to the setting Off-Circuit Tap Switches (OCTSs) of line-installed MV/LV transformers [7]. In the past, all MV/LV transformers on a particular feeder used to be set to the same boost value. The new approach is to apply successively more boost to transformers further away from the source substation, thereby permitting the MV network voltage to drop lower without violating the Vnom -10% statutory lower limit for LV supply points. Using the new approach, OCTS settings are based on the maximum voltage that is experienced at the MV/LV transformer location, and greatest benefit is derived in cases where this is below 100% of nominal. Any generation by DG that will raise the voltage at a point in the network above its previous maximum level will limit the applicability (and hence benefits) of the new OCTS setting approach, and can thus be said to limit the capacity of the network in question. Fortunately for DG operators, the benefits of the new theory are also reduced in networks with direct supply to MV customers, so they may still be permitted to raise the network voltage up to the 105% figure described previously. IV. EFFECT OF NETWORK CHARACTERISTICS ON DG PENETRATION Simulations were performed to determine the impact of various network parameters on the amount of generation at UPF that can be accepted onto typical distribution networks before the onset of overvoltage problems. A. Network model for voltage studies Voltage studies on passive distribution networks have traditionally been completed under the assumption that the voltage of an OLTC-regulated substation busbar remains constant at the OLTC setpoint value. This is equivalent to assuming that the regulated busbar is an infinite source and neglects the effect of the OLTC bandwidth. In reality, the actual voltage of the regulated busbar will vary within the OLTC deadband in accordance with changes in load across the source impedance. This effect is almost impossible to model accurately as it depends on the instantaneous network loading both upstream and downstream of the substation busbar. In the absence of a more detailed model, the assumption of a busbar voltage that is fixed at its most likely value is used as the best alternative. Here, it must be noted that the actual magnitude of the busbar source impedance does not affect the validity of the infinite source assumption, as it will only affect

the rate at which the busbar voltage changes within the OLTC deadband with varied load. Application of the infinite source model for planning purposes gives rise to a window of uncertainty around the predicted voltage values. This window corresponds to the deadband of the OLTC controller. Comment is made in [5] that this effect can be neglected because steady-state voltage limits and those for transformer fluxing, are linked to the average value of the voltage supplied, and that this corresponds to the OLTC setpoint figure. The discussion above indicates that the planning practice of modeling a regulated substation busbar as a fixed-voltage infinite source is adequate for voltage studies even in weak networks (provided that a substation OLTC is installed). This assumption was applied in the network model of Fig. 3 that was used study the impact of DG on voltage levels in distribution networks in South Africa. Feeder length, L Source

Distance of DG from s/s bus, d L1 = d/2

L2 = d/2

L3 = (L-d)/2

Load 1 V = VSetpoint∠0o

L4 = (L-d)/2

Load 2 DG

Where: Load 1 = (d/L) x total DG feeder load Load 2 = (1-d/L) x total DG feeder load Fig. 3. Network model to used in the theoretical analysis.

The model in Fig. 3 includes the following additional features: - DG represented as a negative load a distance, d, from the source substation on a radial feeder of total length, L. - Load uniformly distributed down the feeder length. Loads 1 and 2 represent load upstream and downstream of the generator and follow the assumption that uniform load on a feeder can be modeled as a lumped value at the centre of the line segment. The magnitudes of Loads 1 and 2 are derived as shown in Fig. 3. The model of Fig. 3 was implemented using a 4-bus GaussSeidel load flow program. B. Simulation results 1) Impact of feeder load The amount of power generation that is permissible at a particular location on a distribution feeder is dependent on the feeder load. The absence of feeder load dictates that most of the DGs output power must be exported back towards the source substation, and this gives rise to high network voltages in the vicinity of the DG. A sensitivity analysis was performed to determine the extent to which different levels of feeder loading impact on the DG penetration limit at a particular location. The penetration limit in each case is defined as that quantity of generation that causes the local voltage to rise to 105% of nominal. The model network of Fig. 3 was used to represent a typical 22kV feeder strung with ACSR “Hare” conductor and with its OLTC setpoint at 103%xVnom. Simulations were

performed with different levels of feeder loading at a power factor of 0.95 lagging. The results are illustrated in Fig. 4. No load

1MVA load

2MVA load

No load (104%)

8 6 4

V. CHOICE OF DG OPERATING MODE 2 0 0

5

10 15 20 25 Distance of DG from source (km)

30

Fig. 4. Impact of feeder load on DG penetration limits.

The "No Load" curve in Fig. 4 indicates that even under no-load conditions, a DG that is installed close to the source substation can export significant amounts of real power without giving rise to local overvoltage problems. Specifically, a DG installed within the first 15km of the line (50% of the line length) can generate in excess of 2MW. As expected, the addition of load to the feeder increases the DG penetration limits for all possible generator locations on the line. The penetration limits for DGs on the first 15km of the line actually increase by more than 1MW with the addition of 1MVA of load. This is a result of the increased reactive power load that tends to a cause a volt drop between the source and DG, hence permitting more generation before the 105% voltage limit is reached at the DG installation. A corollary of the assumption that the substation busbar is an infinite source, is that the presence of load on feeders adjacent to the DG-installed feeder has no impact on the allowable generation limits. 2) Impact of OLTC setpoint It is seen from Fig. 4 that increased loading on a distribution feeder is beneficial for DG. In the absence of DG, however, heavy network loading is likely to give rise to excessive volt drops along the feeder. This effect might be countered by increasing the OLTC setpoint at the source substation. The impact on the DG penetration limits of raising the OLTC setpoint to 104%xVnom is indicated as the dashed curve in Fig.4. It is seen in Fig. 4 that the DG penetration limit drops to 50% of the previous limits at no-load for a setpoint of 103%xVnom. The same effect is noted with the penetration curves for the 1MVA and 2MVA cases, although these are not indicated in Fig. 4. 3) Impact of voltage level The results in Fig. 4 can be scaled to indicate the amount of power generation by DG that can be accepted onto an 11kV feeder. Eleven and 22kV lines in South Africa are designed using the same pole-top configurations (and thus have identical phase spacings) so, for a particular conductor type, have identical ohmic impedances per kilometre. In the per-unit system, however, the impedance of the 11kV line is four times

The results from the previous section indicate that even at no-load, 22kV feeders can accept a significant amount of DG close to the source substation before experiencing overvoltage problems. The allowable generation is seen to decrease quickly as the DG is moved farther from the substation, however, and is greatly reduced for DG connected at lower voltage levels. In the latter case, even the presence of feeder load is not sufficient to raise the DG penetration limits significantly. As a result of the above findings, an alternative control strategy was developed for synchronous DGs that will allow increased levels of generation. The new strategy is based on the results of simulations with the DG operating at a leading power factor. A. Operation of synchronous DG at a leading power factor The no-load simulations from Fig. 4 were repeated, but with the DG operating at 0.95 leading power factor instead of at UPF. The results are included in Fig. 5. Three of the curves from Fig. 4 are included as dashed lines in Fig. 5 for the purposes of comparison. 0.95 lead

UPF

UPF+1MVA ld

UPF+2MVA ld

10 DG penetration limit (MW)

DG penetration limit (MW)

10

as high as that for the 22kV line because the impedance base is proportional to the square of the voltage base. From (1), we thus deduce that the penetration limits in Fig. 4 should be divided by four to represent the limits of DG penetration on a typical 11kV feeder. This indicates that for a DG installed 5km from the source substation, instead of allowing 6.4MW as at 22kV, only 1.6MW would be allowed at 11kV. The effect of voltage level is similar to that on the MW-km capacity of lines, as used in distribution planning.

8 6 4 2 0 0

5

10 15 20 25 Distance of DG from source (km)

30

Fig. 5. Penetration limits for DG operating at 0.95 leading power factor.

In Fig. 5, it is seen that a DG located 15km from the source substation, operating at a power factor of 0.95 leading can generate 3.6MW onto the distribution network before the local voltage will rise to 105% of nominal. This is in comparison to the UPF generation case where the penetration limit at no-load is 2.1MW. Notice also in Fig. 4 that the same level of power generation is allowed with the DG operating at 0.95 leading power factor, as with the DG operating in UPF control mode, but with 2.4MVA of feeder load. Generation of 3.6MW at a power factor of 0.95 leading gives rise to a 1.2MVAr drain of reactive power from the

network. This is unlikely to be a problem during periods of light network loading as there is an excess of reactive power capacity available at this time (from lightly loaded lines and capacitor banks). Generation in this way during periods of peak loading could, however, require the addition of reactive power capacity to the network, the costs of which would most probably be reflected in a reactive power tariff to the DG operator. The above discussion indicates a requirement for a composite control strategy for DG: one that allows for unity power factor operation during periods of heavy feeder loading, and operation at a leading power factor when the feeder is lightly loaded. B. Composite control strategy for DG The composite control strategy outlined above can be implemented using off-the-shelf (microprocessor-based) control relays as follows:

1.

2. 3.

4.

Set the DG output power limit to the value given in a study similar to that in Fig. 5. Case specific variables include: voltage level, conductor type, and distance of DG from the substation. Operate the DG at UPF until the local voltage rises to 105% (i.e. feeder load drops). Switch to Voltage Control mode. In this mode, the generator power factor will decrease as the feeder load drops. In the worst case, with no feeder load, the power factor will not drop below 0.95 leading. Use a reactive power sensing relay to alarm when the DG begins to supply reactive power to the network (indicating that it is supporting the network voltage). Switch back to UPF generation.

C. Generalised approach to DG control mode selection The discussion of the previous sections indicate that a generalised approach can be applied in evaluating the control strategy for DGs on radial distribution feeders. The approach to be followed is illustrated in Fig. 6 below.

In Fig. 6, decision 1 requires only basic information regarding the DG proposal: maximum planned power output, location, and voltage level and conductor type. This information is used to determine the worst case DG penetration limit via a simple load flow study. Decision 2 requires that statistical metering data is available for the DG feeder, and the simple study is repeated but with load information included. Implementation of the composite control algorithm (in the final output block of Fig. 6) may require that the DG's control instrumentation be upgraded. Failure to do this will restrict the allowable generation to the limit value determined in decision 2. VI. CASE STUDIES The generalised approach to DG control mode selection was applied to two South African DG case studies. CASE 1: Sugar Mill A Co-generation A sugar mill in the Mpumalanga Province applied for cogeneration rights in April 2002. The mill planned to generate up to 4MW onto the local 22kV network using one of its 8MVA (6.4MW) synchronous generators (refer to Fig. 7). In Fig. 7, the maximum load on the mill feeder under normal operating conditions is 2MVA (at a power factor of 0.87 lagging) although this is increased by up to 4MW when back-feeding an adjacent feeder. The transformers at the source and mill substations are all fitted with OLTC functionality. Source substation

132kV 2 x 20MVA 132/22kV 22kV

Load on adjacent feeders 16MVA

5.6km "Hare"

2-6MVA

Utility Sugar Mill A

Proposed max. DG output 1 More than maximum limit in Fig. 4 (no load)?

No

Allow generation at UPF

6.6kV

Yes Determine min. fdr load during periods of proposed DG 2 More than maximum limit in Fig. 4 (min load)?

2 x 5MVA 22/6.6kV

Mill load

Turbo Generator No

Yes Determine generation limit at 0.95 leading pf (min load). Allow generation up to limit value. Use composite control algorithm. Fig. 6. Decision tree for DG control mode selection.

Allow generation at UPF

8MVA

2MVA

Fig. 7. Electrical network for Case 1: Sugar Mill A co-generation.

From Fig. 4, it is clear that generation of up to 6.3MW can be accepted onto an unloaded 22kV "Hare" line without exceeding the 105% voltage limit near the mill's Point of Common Coupling (PCC). The decision chart of Fig. 6 thus indicates that the mill's generator should operate at unity power factor, although a leading power factor will be seen at the PCC (mill absorbing reactive power) owing to the embedded load at the mill.

The electrical network in Fig. 7 differs from that used in the model of Fig. 3 in its inclusion of a "generator transformer". If the transformer impedance is included with the series line impedance in the no-load volt drop simulations, it is seen that for generation of 6.3MW, the mill's 6.6kV busbar voltage will rise to 105.28% of nominal. This effect would be countered by OLTC action on the mill transformers. The transformers, however, are capable of a maximum 5% voltage buck and it is expected that the OLTCs tap limits would be reached in maintaining the MV busbar voltage near the mill's 100% setpoint during periods of peak generation. In the worst case considered above, the 6.6kV busbar voltage would reach a maximum value of 100.28% on tap 1 (with peak 6.35MW generation and no feeder/mill load). Note from the above discussion that the approach described in this document in assigning generator penetration limits based on MV network voltage limits is also valid in cases where the DG is connected through an OLTC-installed generator transformer. This is because a 5% overvoltage at the PCC will be compensated by the 5% voltage buck of the generator transformer, and the most onerous overvoltage condition will exist at the PCC (rather than at the generator bushings). CASE 2: Sugar Mill B Co-generation A second sugar mill has been co-generating up to 2MW onto the utility's 22kV network since 1996. Mill B is supplied via a 10.3km line section that tee's off the backbone 5.1km outside the source substation (refer to Fig. 8). As in Case 1, the source substation and mill transformers are fitted with OLTCs. Source substation

66kV 3 x 10MVA 66/22kV 22kV 5.1km "Wolf"

15MVA

Load on adjacent feeders 10.3km "Wolf"

6MVA

Utility Sugar Mill B

7.5MVA 22/11kV 11kV Turbo Generator 10MVA

Mill load

6MVA

Fig. 8. Electrical network for Case 2: Sugar Mill B co-generation.

The no-load study for a DG located 15km from the source substation on a "Wolf" line (not shown) indicates that up to 3.6MW of generation can be tolerated at UPF before the voltage at the PCC rises to 105% of nominal. The decision tree in Fig. 6 thus indicates that Mill B's generator can operate

in UPF control mode up to (and beyond) its proposed 2MW output limit. The "absolute" generation limit at UPF was found to be 4.15MW when 1.2MVA of load (corresponding to a 20% load ratio) was added 5.1km from the source substation in the simulation model. Interestingly, in the event that the composite control algorithm was implemented (on the mill's 22kV busbar), the generation limit is extended beyond 20MW without the generator power factor dropping below 0.95 leading. This is well above the full load rating of both the DG and the generator transformer. The composite control algorithm is especially effective in this application on account of the fact that "Wolf" conductor has a high X/R ratio, and hence DG operation at a leading power factor very effectively compensates for the voltage rise effect caused by real power transfer towards the source. The composite control algorithm must be applied so as to regulate the voltage of the 22kV busbar and not that of the 6.6kV busbar. This is because, as in Case 1, OLTC action of the generator transformer dictates that overvoltages will always be reflected most severely at the PCC. VII. CONCLUSION Load flow simulations using a simple network model indicate that DG location, feeder load, OLTC setpoint and voltage level are important factors in determining the generation limits in DG applications. Generation limits are chosen so as to limit the network voltage rise in the vicinity of the DG to below 105% of nominal. DG penetration was found to be most restricted under light loading conditions on lower voltage networks. The source impedance seen from the distribution substation was found to have no impact on the allowable DG penetration limits on account of OLTC action on the substation transformer. Further simulations indicated that significantly greater penetrations of DG could be accepted onto distribution networks in the event that the generator operates at a leading power factor. This mode of control is, however, not recommended during periods of heavy loading on the DG feeder as it requires that extra reactive power capacity be installed. A composite control strategy is proposed that will allow generation at UPF during most DG operating conditions, but will automatically switch to operation at a leading power factor during periods of light feeder loading. The composite control strategy can be implemented using off-the-shelf control relays. The composite control strategy is integrated into a generalised approach to selecting the control mode in DG projects. The generalised approach was applied to two South African DG case studies. The approach provides a simple method to evaluate proposed DG projects and is applicable even in the event that the DG is connected to the utility network via a generator transformer. VIII. ACKNOWLEDGEMENT The authors gratefully acknowledge the contributions of C.

Carter-Brown for his guidance on aspects of distribution planning, and C. Vermeulen for his insight into the operation the DG case studies presented herein. IX. REFERENCES [1]

[2]

[3]

[4]

[5]

[6]

[7]

N. Jenkins, R. Allan, P. Crossley, D. Kirschen and G. Strbac, Embedded Generation, IEE Power and Energy Series 31. London: Institute of Electrical Engineers, 2000, p.100-109. C. L. Masters, “Voltage rise: the big issue when connecting embedded generation to long 11kV overhead lines,” IEE Power Engineering Journal, vol. 16, no. 1, pp. 5-12, February 2002. B. Persaud, B. Fox and D. Flynn, “The Effects of Embedded Wind Generation on Automatic Voltage Control in Radial Distribution Networks,” in Proc 1999 34th Universities Power Engineering Conf., pp. 365-8. S. K. Salman, F. Jiang and W. J. S. Rogers, “Investigation of the operating strategies of remotely connected Embedded Generators to help regulating local Network Voltage,” in Proc. 1996 Opportunities and Advances in International Power Generation Conf., pp. 180-5, IEE conf publ. no. 419. C.G. Carter-Brown, “Voltage drop apportionment in Eskom’s distribution network,” MSc. Dissertation, Dept. Elec. Eng., Univ. Cape Town, South Africa, 2002. C.G. Carter-Brown, “Optimal Voltage Regulation Limits and Voltage Drop Apportionment in Distribution Systems”, in Proc. 2002 11th Southern African Universities Power Engineering Conf. (SAUPEC), Vaal Triangle Technikon, pp.318-322. C.G. Carter-Brown and C.T. Gaunt, “Increasing Network Capacity by Optimising Voltage Regulation on Medium and Low Voltage Feeders,” in Proc. 2003 17th International Conf. on Electricity Distribution (CIRED), Paper No. 5-27.

X. BIOGRAPHIES Stuart van Zyl graduated with a B.Sc degree with distinction in Physics in 1996, and with a B.Sc (Elec. Eng) degree Cum Laude in 1998, both from the University of Cape Town, South Africa. He joined Eskom Distribution in 1999, and is currently working in the protection settings environment. Stuart has been involved with the technical evaluation and implementation of a number of co-generation and stand-by generator projects in South Africa, and is currently reading for a MSc. degree in Electrical Engineering with the University of Cape Town. C. T. Gaunt is an Associate Professor in the Department of Electrical Engineering at the University of Cape Town. He has 30 years experience in equipment manufacture, consulting engineering and research.