Thank you Dr. Ray and Vida. I think there might be mismatch between generation and demand which I need to check out through database and may be unvalid standard position of taps which may cause the problem. So my approach is to minimize reactance values of transformers (at distribution side which are connected to lower voltage 110 KV bus) and set tap position default as 1 at input side in modeling which I hope will give better results. Another thing I want to ask you Vida can you suggest me any literature for reactive power pricing methods. Right now I'm focusing on 1) Triangular relationship between active and reactive power approach 2) opportunity cost method. Thanks for your time.
Mirish Thakur KIT University. On Tue, Sep 22, 2015 at 3:20 AM, vids <vidaj...@gmail.com> wrote: > Hi Mirish, > > I just finished my work that is somewhat related to yours. I did a > reactive power dispatch where the Pg of all generators are already known > since it is cleared separately in the electricity market. > What i did was i set one generator to be a "slack" generator to take > up/absorb the changes in losses due to the redispacth of reactive power. I > set the Pmin and Pmax of this gen to its true values while the rest of the > generators i set to Pg=Pmin=Pmax. It converged for the cases that i worked > on. > > Vida > On Sep 21, 2015 10:57 PM, "Ray Zimmerman" <r...@cornell.edu> wrote: > >> *First of all, when asking a new unrelated question, please don’t just >> reply to a previous message. Start a new thread with a new subject.* >> >> So, are you saying your are attempting to run an AC OPF problem where Pg >> is fixed and Qg are the only free variables? If so, the only way it really >> has a chance of working is if the loads and active power generation are >> feasible for the AC OPF problem (e.g. you got them from an AC OPF >> solution). In that case, the original Qg solution should also be feasible. >> However, this is a very constrained problem that may only have a single >> feasible solution point (corresponding to the original AC OPF values of >> voltage and reactive injection). >> >> If however, the Pg values and the loads are not guaranteed to be feasible >> (i.e. coming from an AC OPF solution), then branch flows may violate their >> limits and it may not be possible to dispatch reactive power in a way that >> results in system losses exactly matching the difference between specified >> load and specified generation. I.e. the problem may be over-specified and >> therefore infeasible. >> >> Ray >> >> >> >> On Sep 21, 2015, at 7:45 AM, Mirish Thakur <mirishtha...@gmail.com> >> wrote: >> >> Hello MatPower community, >> >> >> I want to analyze monetary consequences of reactive power dispatch on >> energy market which is already considering real power prices only. For this >> I have data of conventional power plants dispatch for every hour in whole >> year and respective variable cost of generation. I’ve active and reactive >> power demand for each hour as well. For this case I want to keep generator >> dispatch Pg=Pmin=Pmax (no change in active power generation) and Pd and Qd >> (real and reactive demand) as per given for whole year. Also I want to keep >> RATE_A value constant in opf. But I’m facing convergence problem in runopf. >> runopf >> doesn’t converge until and unless I make Rate_A value 1.5 times and some >> changes in Pmax and Pmin values at input side. Is there any alternate way >> to get convergence without making any changes in Pg, Pmax, Pmin and Rate_A >> value? (For example any changes in line parameters or something else). >> Thank you for your time. >> >> >> Regards >> >> Mirish Thakur >> >> KIT University. >> >> >>
