Short‐Term Stochastic Dispatch With Time‐Domain Dynamic Security Constraints for Low‐Inertia, Inverter‐Based Power Systems: The Galápagos Case Study

ABSTRACT

Short‐term scheduling of islanded microgrids with high renewable penetration must reconcile uncertainty, operating cost and post‐contingency dynamic feasibility. This paper presents a sequential optimisation‐simulation framework that integrates field‐calibrated dynamic‐security assessment with multistage stochastic dispatch. MVMO first identifies the PowerFactory dynamic parameters from synchrophasor records; correlated multivariate chronicles then represent demand and renewable uncertainty; and steady‐state and RMS simulations determine the event‐conditioned capability of the network and the grid‐forming BESS. A security compiler converts the signed BESS trajectories into directional power and stored‐energy margins, while a native Object Pascal extension of the SimSEE BESS actor enforces those margins before each stage cost is evaluated. Consequently, the optimiser searches within a security‐qualified feasible set instead of producing an economic schedule that is screened afterwards. An ex‐post reliability‐worth layer values the selected coverage percentile without assigning an artificial security penalty to the dispatch objective. The Baltra–Santa Cruz study comprises 65,000 audited state—event cases and a separate 30,000‐case fault campaign. The calibrated frequency and voltage RMSEs are 53.5 mHz and  p.u. At , the upward/downward reserve requirements are 3.66/4.07 MW in Baltra and 1.83/2.03 MW in Santa Cruz. Across 100 aligned chronicles, the unconstrained and schedules for the same assets incur mean thermal‐generation costs of $3568 per day and $4777 per day, respectively, while the latter retains an 82.7% renewable share. On the common RMS holdout, the proportion of dynamically insecure states decreases from 42% for the unconstrained schedule and 9% for a static‐SCED reserve to 0% for the RMS‐informed schedule.