You might have a look at Markets for Reactive Power and Reliability: A White Paper <http://e3rg.pserc.cornell.edu/node/100>.
Ray > On Sep 24, 2015, at 7:36 AM, Mirish Thakur <mirishtha...@gmail.com> wrote: > > 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 > <mailto: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 > <mailto: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 >> <mailto: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. > >
