ADAPTIVE COORDINATED VOLTAGE CONTROL ALGORITHM FOR GRID-TIED PHOTOVOLTAIC INTEGRATION IN A RURAL DISTRIBUTION FEEDER USING THE OPEN DISTRIBUTION SYSTEM SIMULATOR (OPENDSS): A CASE STUDY OF MURANG’A DISTRIBUTION FEEDER

Abstract

The increasing penetration of photovoltaic (PV) systems into rural distribution networks presents a critical engineering challenge in maintaining statutory voltage performance and grid compliance. The central problem addressed is that uncoordinated high-penetration PV integration on a long, high resistance-to-reactance (R/X) radial feeder induces substantial reverse power flow and daytime voltage rise that generic, voltage-triggered commercial inverter controls do not detect, because the resulting voltages remain below their default activation thresholds. In radial networks such as the 69 km, 11 kV Murang’a distribution feeder in Kenya, high R/X ratios and a temporal mismatch between peak midday solar generation and minimum daytime consumer demand create significant operational stress. Without active control, uncoordinated PV integration exports surplus active power to the primary substation, raises midday nodal voltages towards the upper statutory boundary, and increases the mechanical duty imposed on the substation on-load tap changer (OLTC). To investigate this, a digital twin of the feeder, comprising 158 medium-voltage buses and 92 distribution transformers, was developed in OpenDSS and validated against utility field measurements at three monitored nodes, yielding a mean absolute percentage error (MAPE) of 0.68 % and a root-mean-square error (RMSE) of 0.0066 p.u. (0.70 %), both within the 2 % acceptance criterion adopted in this study. Quasi-Static Time-Series (QSTS) simulations at a one-minute resolution (1,440 steps per 24 h day) evaluated three standardized scenarios: Scenario A (baseline, no PV), Scenario B (3 MW PV, uncontrolled) and Scenario C (3 MW PV, coordinated control). 2Scenario B produced a peak reverse power flow of 0.93 MW at the substation and a maximum nodal voltage of 1.038 p.u., which represents pronounced voltage rise while remaining below the 1.05 p.u. upper limit adopted in this study; the evening minimum voltage of 0.912 p.u. at the feeder extremity is a pre-existing, load-driven condition that occurs when PV output is essentially zero. A context-specific, coordinated Volt-VAR and Volt-Watt smart inverter control strategy was then designed, in which Volt-VAR acts as the primary reactive-power response and Volt-Watt as the secondary active-power response. In Scenario C the coordinated controller reduced peak reverse power flow by 62.3 % (from 0.93 MW to 0.35 MW), limited the maximum nodal voltage to 1.024 p.u., maintained all monitored buses within the adopted 0.95–1.05 p.u. band throughout the PV generation window, and reduced OLTC operations from 28 to 8 per day (71.4 % fewer than Scenario B and 33.3 % fewer than Scenario A). This operational improvement was obtained at a technical energy trade-off of approximately 1,500 kWh of curtailed solar energy per day, that is, renewable energy sacrificed for grid benefit. The study therefore develops and evaluates a coordinated Volt-VAR/Volt-Watt control framework on a validated model of a real Kenyan rural distribution feeder and demonstrates its potential to mitigate reverse power flow, maintain voltage compliance and reduce OLTC operations under the investigated PV scenarios.