EMO:Reserves - Revision history

Greg at 02:30, 12 February 2014

2014-02-12T02:30:38Z

Greg at 02:29, 12 February 2014

2014-02-12T02:29:46Z

Sisep at 03:49, 21 January 2013

2013-01-21T03:49:49Z

Sisep: /* The Reserve Management Tool */

2013-01-21T03:14:16Z

The Reserve Management Tool

Sisep at 02:06, 21 January 2013

2013-01-21T02:06:53Z

Sisep: /* The Reserve Management Tool */

2013-01-21T01:49:05Z

The Reserve Management Tool

Sisep: Created page with "{{#hidens:}} === The Reserve Management Tool === The inputs to the SPD solver are shown in the figure and table below (adapted from Transpower's Reserve Management Tool (RMT) ..."

2013-01-21T01:32:35Z

Created page with "{{#hidens:}} === The Reserve Management Tool === The inputs to the SPD solver are shown in the figure and table below (adapted from Transpower's Reserve Management Tool (RMT) ..."

New page

{{#hidens:}}
=== The Reserve Management Tool ===
The inputs to the SPD solver are shown in the figure and table below (adapted from Transpower's Reserve Management Tool (RMT) functional specification). There are two broad categories of input:
#Energy and reserve offers from market participants
#Parameters that define the Reserves requirement are calculated mostly by a software application: the RMT.
[[File:Reserves.PNG]]

← Older revision		Revision as of 02:29, 12 February 2014
Line 258:		Line 258:


−	[[~~EMO:EMarketOffer User Manual~~\|Home~~]] - [[EMO:Forecasting\|Back~~]]	+	[[Main Page\|Home]]

← Older revision		Revision as of 03:49, 21 January 2013
Line 113:		Line 113:
	\|		\|
	:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC halfpoles can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.		:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC halfpoles can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.
		+	\|-
		+	\|
		+	:''Manual Risk''
		+	\|
		+	:Manually Entered Min. A fixed risk that cannot be optimised by the SPD solver.
		+	\|-
		+	\|
		+	:''Clearing Price at Nodes''
		+	\|
		+	:Nodal Price
		+	\|-
		+	\|
		+	:''Cleared Load''
		+	\|
		+	:Load that will be connected at a cleared price
		+	\|-
		+	\|
		+	:''Rampup''
		+	\|
		+	:Internally calculated by SPD. Quantifies the steady state power that the HVDC link can transfer after a Contingent Event, taking Benmore bus constraints into account
		+	\|-
		+	\|
		+	:''BEN P1ANMax''
		+	\|
		+	:The maximum MW north transfer on Benmore Pole 1A
		+	\|-
		+	\|
		+	:''BEN P1BNMax''
		+	\|
		+	:The maximum MW north transfer on Benmore Pole 1B
		+	\|-
		+	\|
		+	:''BEN P1ASMax''
		+	\|
		+	:The maximum MW south transfer on Benmore Pole 1A
		+	\|-
		+	\|
		+	:''BEN P1BSMax''
		+	\|
		+	:The maximum MW south transfer on Benmore Pole 1B
		+	\|-
		+	\|
		+	:''Cleared Reserve''
		+	\|
		+	:Reserves that will be connected at a cleared price
		+	\|-
		+	\|
		+	:''Cleared Generation''
		+	\|
		+	:Generation that will be connected at a cleared price
		+	\|-
		+	\|
		+	:''HVDC Bipole Transfer''
		+	\|
		+	:The MW transfer of the HVDC link
		+	\|-
		+	\|
		+	:''HVDC Branch Limits''
		+	\|
		+	:Limits in the transfer on each HVDC pole and halfpole. May be reduced due to outages of equipment etc
		+	\|}
		+
		+	=== Relationship between ''EMarketOffer'' and RMT ===
		+	''EMarketOffer'' does not reproduce RMT functionality and must be provided with the RMT generated parameters to be used for final dispatch. The inputs required by ''EMarketOffer'' to model reserves appear in the table below.
		+
		+	{\|class="wikitable"
		+	! Input Group !! Item !! Description
		+	\|-
		+	! rowspan="2" \| Energy Offers
		+	\|
		+	:''Price (bands 1-5)''
		+	\|
		+	:Offer Price in bands 1 to 5 for the Units
		+	\|-
		+	\|
		+	:''Quantity (bands 1-5)''
		+	\|
		+	:Offer Quantity in bands 1 to 5 for the Units (always zero for Powerflow Case Data Sources)
		+	\|-
		+	! rowspan="3" \| Reserves Offers
		+	\|
		+	:''Price: PLSR/TWD/ILR (bands 1-3)''
		+	\|
		+	:Price offered by Reserve type for the Unit in bands 1 to 3 for the Unit
		+	\|-
		+	\|
		+	:''Quantity PLSR/TWD/ILR (bands 1-3)''
		+	\|
		+	:Quantity offered by Reserve type for the Unit in bands 1 to 3 for the Unit
		+	\|-
		+	\|
		+	:''Slope: PLSR (bands 1-3)''
		+	\|
		+	:Unit slope to be used for PLSR offers made by the Unit in bands 1 to 3
		+	\|-
		+	! rowspan="9" \| Reserves Settings
		+	\|
		+	:''Reserve Region''
		+	\|
		+	:North/South Island
		+	\|-
		+	\|
		+	:''DC Offset FR''
		+	\|
		+	:HVDC Fast Reserve Risk Offset
		+	\|-
		+	\|
		+	:''DC Offset SR''
		+	\|
		+	:HVDC Sustained Reserve Risk Offset
		+	\|-
		+	\|
		+	:''AC Offset FR''
		+	\|
		+	:AC Fast Reserve Risk Offset
		+	\|-
		+	\|
		+	:''AC Offset SR''
		+	\|
		+	:AC Sustained Reserve Risk Offset
		+	\|-
		+	\|
		+	:''Base Risk FR''
		+	\|
		+	:Fast Reserve Base Risk (Manual Risk)
		+	\|-
		+	\|
		+	:''Base Risk SR''
		+	\|
		+	:Sustained Reserve Base Risk (Manual Risk)
		+	\|-
		+	\|
		+	:''RAF FR''
		+	\|
		+	:Fast Reserve Risk Adjustment Factor
		+	\|-
		+	\|
		+	:''RAF SR''
		+	\|
		+	:Sustained Reserve Risk Adjustment Factor
		+	\|}
		+
		+	NOTE: Some of the Reserve requirement data, particularly the AC Offsets, are not published in the data generally available to market participants. You will need to either estimate the value of these input data or obtain examples on request from the system operator.
		+
		+
		+	[[EMO:EMarketOffer User Manual\|Home]] - [[EMO:Forecasting\|Back]]

← Older revision		Revision as of 03:14, 21 January 2013
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	\|		\|
	:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC link can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.		:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC link can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.
		+	\|-
		+	\|
		+	:''Halfpole Rampupmax''
		+	\|
		+	:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC halfpoles can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.

← Older revision		Revision as of 02:06, 21 January 2013
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	\|		\|
	:Reserve available from increasing generation from unused generation capacity		:Reserve available from increasing generation from unused generation capacity
		+	\|-
		+	\|
		+	:''Tailwater Depressed Reserve''
		+	\|
		+	:Reserve available by implementing tail water depression in a hydro generator
		+	\|-
		+	\|
		+	:''Load Bids''
		+	\|
		+	:Bids made by consumers for supply at a GXP
		+	\|-
		+	\|
		+	:''Load Forecast''
		+	\|
		+	:The estimated load forecast given for each trading period
		+	\|-
		+	\|
		+	:''FIR_RISK_MW''
		+	\|
		+	:The risk corresponding to the required FIR. Applies to ACCE, DCCE (CE) and ECE.
		+	\|-
		+	\|
		+	:''SIR_RISK_MW''
		+	\|
		+	:The risk corresponding to the required SIR. Applies to ACCE, DCCE (CE) and ECE.
		+	\|-
		+	\|
		+	:''FIR_MW''
		+	\|
		+	:The required FIR. Applies to ACCE, DCCE (CE) and ECE
		+	\|-
		+	\|
		+	:''SIR_MW''
		+	\|
		+	:The required SIR. Applies to ACCE, DCCE (CE) and ECE
		+	\|-
		+	\|
		+	:''CE''
		+	\|
		+	:Contingent Event
		+	\|-
		+	\|
		+	:''ECE''
		+	\|
		+	:Extended Contingent Event
		+	\|-
		+	\|
		+	:''RAF''
		+	\|
		+	:Risk Adjustment Factor. Four different RAFs exist for each island, for CE and ECE for FIR and SIR respectively. To achieve the required reserve, the RAF is multiplied by the risk after deducting the Net Free Reserve.
		+	\|-
		+	\|
		+	:''NFR''
		+	\|
		+	:Net Free Reserve. The offset from the risk that the RAF is applied to.
		+	\|-
		+	\|
		+	:''ACCE''
		+	\|
		+	:Contingent Event caused by the loss of (usually) one generator unit.
		+	\|-
		+	\|
		+	:''DCCE''
		+	\|
		+	:Contingent Event caused by the loss of (usually) one HVDC pole.
		+	\|-
		+	\|
		+	:''Rampupmax''
		+	\|
		+	:Calculated by RMT. Quantifies the maximum transient overload power that the HVDC link can transfer at the inverter after a Contingent Event, not taking any AC constraints into account.

← Older revision		Revision as of 01:49, 21 January 2013
Line 5:		Line 5:
	#Parameters that define the Reserves requirement are calculated mostly by a software application: the RMT.		#Parameters that define the Reserves requirement are calculated mostly by a software application: the RMT.
	[[File:Reserves.PNG]]		[[File:Reserves.PNG]]
		+
		+	{\|class="wikitable"
		+	! Term !! Explanation
		+	\|-
		+	\|
		+	:''Generation Offer''
		+	\|
		+	:Offer made to supply energy by generator
		+	\|-
		+	\|
		+	:''Reserve Offer''
		+	\|
		+	:Offer made to supply reserve by a Generation Unit
		+	\|-
		+	\|
		+	:''FIR''
		+	\|
		+	:Fast Instantaneous Reserve
		+	\|-
		+	\|
		+	:''SIR''
		+	\|
		+	:Sustained Instantaneous Reserve
		+	\|-
		+	\|
		+	:''Interruptible Load Reserve''
		+	\|
		+	:Reserve available from the reduction of load
		+	\|-
		+	\|
		+	:''Partly Loaded Reserve''
		+	\|
		+	:Reserve available from increasing generation from unused generation capacity

@@ Line 3: / Line 3: @@
 The inputs to the SPD solver are shown in the figure and table below (adapted from Transpower's Reserve Management Tool (RMT) functional specification). There are two broad categories of input:
 #Energy and reserve offers from market participants
-#Parameters that define the Reserves requirement are calculated mostly by a software application: the RMT.
+#Parameters that define the Reserves requirement are calculated mostly by the RMT software application.
 [[File:Reserves.PNG]]