SOG-8 – Revision #6 page 4
SYSTEM SECURITY & PERFORMANCE
STANDING OPERATING GUIDELINE
SOG – 8: Saskatchewan / U.S.A Power Transfer
Includes:
Available Transfer Capability
B10T Generator Dumping
BD922T Phase Shifter Tapback Operation
Revision #: 6 Issued by: Dwight Wooley
Effective Date: June 21, 2004 Date: June 21, 2004
Expiry Date: Approved by:
File: S0-24 (SOG-8) Date:
Reasons for Revision:
This SOG has been revised to update information related to power transfer between Saskatchewan (SaskPower: SP) and the U.S.A (Basin Electric: BE). Topics include:
a) A description of available transfer capability (ATC)
b) The Boundary Dam generator dumping scheme (BDGD), in consideration of the addition of the Glenboro-Harvey transmission line G82R on the Manitoba-USA interface.
c) The BD922T phase shift transformer controller (BDPSC) operation.
Recommendations:
A. System intact ATC should be posted as follows:
Limiting Factor Description / TTC / TRM / TRM / Firm / Maxreleased / Flow
For transfer from SP to BE: / 215 / 65 / 50 / 150 / 200
For transfer from BE to SP: / 165 / 15 / 0 / 150 / 150
If system intact conditions do not apply, a review of the existing network must be performed and appropriate ATC values determined. Planned outages causing revised ATC values would typically be implemented through temporary operating guidelines. PNA can be used to confirm secure ATC during forced outages.
B. The Boundary Dam Generator Dumping Scheme should be armed if we have scheduled more than 150 MW export to the U.S. Prior to arming the scheme, the AGC “trip limit” must be set to a megawatt value low enough to suspend AGC operation if B10T trips. A suggested value for the AGC “trip limit” is 100 MW. Otherwise, if B10T trips, the machines under AGC control would be automatically ramped up by the AGC to re-establish the scheduled export, which would then appear on the tie lines between SaskPower and Manitoba, and the tie lines between Manitoba and the U.S.
C. A large generation contingency in SP, or a D602F line contingency in Manitoba, could cause the BDPSC to trip to manual and the tapback to operate until power flow is reduced to 250 MVA. This flow is acceptable for a short period of time. However, the system operator may need to take further action to reduce the power flow to within the 200 MVA continuous rating of the transformer.
If the contingency is a trip of D602F, MH should be contacted to confirm that they are implementing remedial action. Unless absolutely necessary, SP operator action should not reduce load on BD922T by manually initiating tapchanges on BD922T since this would transfer power flow onto the remaining MH to U.S.A tie lines, which may already be overloaded.
If the contingency is a trip of generation within SP, the preferred method of reducing flow through BD922T is to ramp up operating reserve.
Further reduction below 200 MVA may be required to get within the posted ATC values. This situation where high post-contingency flow occurs through BD922T is more likely to occur when we are importing from BE into SP.
References:
Previous revisions of Sog-8.
Report on the Review of the Boundary Dam Generation Rejection Scheme, dated September25, 2003, provided by Manitoba Hydro.
Background & Discussion:
Only one tie line, B10T, exists between Saskatchewan and the U.S.A. The north end of B10T terminates at a phase shift transformer, BD922T, at the SaskPower Boundary Dam Power Station in Saskatchewan. The south end of B10T terminates at the Basin Electric Tioga switchyard, in North Dakota.
A. Available Transfer Capability (ATC)
The maximum secure ATC from BE to SP on B10T is 165 MW. However, the maximum scheduled transfer is 150 MW, to allow a 15 MW margin for typical variations in real-time. The 165 MW limit is determined by post-contingency equipment limitations caused by generation contingencies in SP.
Similarly, the maximum secure ATC from SP to BE is 215 MW. However, the maximum scheduled transfer is 200 MW, to allow a 15 MW margin for typical variations in real-time. The transfer limit is determined by the BD922T transformer continuous rating of 200 MVA.
Seasonal studies of ATC between SP and Manitoba Hydro (MH) have demonstrated an interaction between power transfer on B10T and power transfer between SP and MH. B10T flow into SP reduces the ATC for import from MH into SP. Consequently, the OASIS software used by SP for posting ATC automatically reduces the ATC for import from MH into SP by an amount equal to the scheduled import into SP on B10T. This relationship applies only for import into SP on B10T, not for export from SP on B10T.
B. Boundary Dam Generator Dumping Scheme (BDGD)
The addition of the Glenboro-Harvey transmission line G82R has prompted a review of the BDGD.
If B10T trips, the flow on B10T immediately prior to the disturbance is distributed among the remaining lines in the network. The grid is operated so that there is sufficient capacity on the other lines to accommodate a swing up to 165 MW. This applies for both import and export.
Export from SP to BE can be as high as 215 MW. When SaskPower is exporting to the U.S., a trip of B10T would reroute the export power flow through Manitoba and into the U.S. This shift in power flow could cause overload of any of the intervening lines, and is a particular concern for the tie lines between Manitoba and the U.S., since coincident transfer from Manitoba to the U.S. may also exist. The purpose of this Sog-8 is to provide a method of preventing this potential overload by limiting the magnitude of the power swing to 165 MW.
SaskPower has installed the BDGD to trip either Boundary Dam #3 or #4 if B10T trips. BD3 and BD4 are usually base loaded at 150 MW. The shock to the system would be the net difference between the export on B10T and the net generation tripped. The optimum approach is to arm the BDGD only if SP schedules more than 150 MW to BE. It is not necessary to arm the BDGD if SP schedules 150 MW or less.
The BDGD is not required if SaskPower is importing from Basin Electric and should not be armed. If the BDGD were armed during import, system security would be reduced since a trip of import would then cause additional loss of generation, with a much greater subsequent shock to the grid.
Note that a trip of any of the tie lines from Manitoba to the U.S. would reroute power through Saskatchewan onto B10T. If pre-disturbance flow is import into MH from the U.S.A., then MH remedial action would likely be to increase northern generation. If pre-disturbance flow is export from MH to the U.S.A., a HVDC reduction scheme quickly reduces power flow on the DC lines out of northern Manitoba.
C. BD922T Phase Shift Controller (BDPSC)
The BD922T transformer includes three tap changers as follows:
a) off-load phase shift tap changer
b) on-load voltage tap changer
c) on-load phase shift tap changer
The BDPSC controls only the on-load phase shift tap changer. The main features of the BDPSC are as follows:
· A maximum short term overload limit is active continuously, and will reduce the transformer MVA loading to 250 MVA whenever actual loading exceeds this limit. This control is active whether the BDPSC is in either automatic or manual control mode. When the short term overload operation occurs, loading will be reduced at a rate determined by the physical capability of the tap changer itself. Operation of the short term overload feature does not depend on the direction of power flow. A load of 250 MVA is acceptable for at least 30 minutes. The transformer is rated for a continuous load of 200 MVA. A large generation contingency in SP would be the most probable cause of a BDPSC tapback until power flow was reduced to below 250MVA. This is more likely to occur when we are importing from BE into SP.
· Either of two control modes, automatic or manual, may be selected for operation. The BDPSC is normally expected to be in the automatic mode. The controller will trip to manual operation if a power swing occurs that exceeds a pre-defined setting (e.g. 40 MW). The philosophy behind this feature is to ensure that for a 300 MW generation contingency in SP, or a D602F line contingency in MH, the controller would not automatically reduce flows more than necessary (i.e. less than 250 MVA as described above) that could otherwise cause overloading elsewhere on the U.SCanada interface.
· In automatic mode, the controller incorporates maximum flow limits for both import and export. Pre-defined time delays are associated with each maximum flow limit. If the MW power flow exceeds a maximum flow limit for more than the specified time delay, the BDPSC will initiate a tap change action in the appropriate direction to reduce the MW power flow to within the maximum limit. As an example, if import exceeds 165 MW for more than 5 seconds, this feature will reduce the import.
· In automatic mode, the controller incorporates a deadband relative to the scheduled power transfer with a pre-defined time delay. If the actual MW power flow exceeds the setpoint by more than the deadband for more than the specified time delay, then the BDPSC will initiate a tap change action in the appropriate direction to restore the actual power transfer to the setpoint. As an example, consider a scheduled power flow of 100 MW export, deadband setting of 30 MW, and a deadband time delay of four minutes. If actual export drops to 60 MW for longer than four minutes, this feature will increase the export.
· In automatic mode, the controller incorporates an error reduction feature. The MW error from setpoint is accumulated at one second intervals (MW-sec). If the error count exceeds the setting (i.e. 8100 MW-sec) for a predetermined time setting (i.e. 30 sec), the controller will move a tap in the appropriate direction to reduce the error. The count is reset following a tap change operation. Error is not integrated out completely since the count is reset subsequent to a tap change operation.