Information Document Northwest Area Transmission Constraint Management ID # 2011-004(R)

Information Document
Northwest Area Transmission Constraint Management
ID # 2011-004(R)
Information documents are for information purposes only and are intended to provide guidance. In the event of any
discrepancy between the information document and the related authoritative document(s) in effect, the authoritative
document(s) governs.
1
Purpose
The AESO issues information documents to provide additional information and interpretations regarding
certain subject matter set out in the AESO’s authoritative documents. The purpose of this information
document is to provide additional information regarding the unique operating characteristics and resulting
constraint conditions and limits in two (2) regions in the northwest area. In this information document the
AESO has defined the northwest area as the area illustrated by the maps in Appendix 2 and 3.
2
Related Authoritative Documents
The AESO’s authoritative documents consist of ISO rules, the ISO tariff and the Alberta Reliability
Standards. Authoritative documents contain binding rights, requirements and obligations for market
participants and the AESO. Market participants and the AESO are required to comply with provisions set
out in authoritative documents.
The AESO encourages market participants to review the related authoritative documents which include:
(1) Section 302.1 of the ISO rules, Real Time Transmission Constraint Management.
This section of the ISO rules sets out the general constraint management protocol steps the AESO uses
to manage constraints in real time on the interconnected electric system. These steps are referenced in
Table 1 of this information document as they are applied to the northwest area.
3
General
The northwest area consists of long 144 kV and 240 kV bulk transmission lines, generally with a low
degree of redundancy of transmission paths. The northwest area total generating capacity is
substantially less than the area load, leading to inflows of energy under normal operation. Some of the
144 kV bulk transmission lines are heavily loaded.
The outage of a single bulk transmission line or a generating unit may result in voltage depressions
outside of the acceptable system operating limits set out in Alberta Reliability Standard TPL-002-AB-0 –
System Performance Following the Loss of a Single BES Element. The AESO can partially mitigate this
risk by ensuring a sufficient minimum amount of transmission must-run generating unit capacity is
available under contract with the AESO. The availability of transmission must-run services reduces the
risk of losing firm load due to low voltages and of a voltage collapse for certain critical transmission or
generation contingencies.
Two (2) maps of the northwest area are provided in Appendix 1 and 2. Appendix 1 provides a detailed
geographical map of the northwest area indicating bulk transmission lines, substations and cutplanes.
Appendix 2 provides a detailed view of the northwest area cutplanes including the generating units
effective in managing the regional constraints through transmission must-run dispatch or directive.
A cutplane is a common term used in engineering studies and is a theoretical boundary or plane crossing
two (2) or more bulk transmission lines or electrical paths. The cumulative power flow across the
cutplane is measured and can be utilized to determine flow limits that approximate conditions that would
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Northwest Area Transmission Constraint Management
ID # 2011-004(R)
allow safe, reliable operation of the interconnected system.
4
Constraint Conditions and Limits
When managing a transmission constraint in the northwest area of Alberta which results from the total
generating capacity of the area being substantially less than the area load, the AESO uses regional
cutplane inflow limits to manage area reliability. The AESO calculates the cutplane inflow limits for the
Grande Prairie and Rainbow cutplanes in accordance with voltage requirements and bulk transmission
line transfer limits. A further description of these limits is set out below.
4.1
Studied Constraints and Limits
Cutplane Inflow Limits
There are two (2) cutplanes in the northwest area; one (1) for the Grande Prairie region and one (1)
specific to the Rainbow Lake region. These cutplanes are reflected on the maps in Appendix 2 and 3. As
mentioned above, the northwest area generation capacity is substantially less than the area load, which
leads to inflows of energy into the northwest area under normal circumstances. The specific contingency
conditions and inflow limits are set out in Appendix 4 and 5 of this information document. The limits in
Appendix 4 are not absolute limits as certain generating units operating at or above minimum stable
generation can provide a slight increase to the limits. The scenarios that provide an increase to the limits
are set out in Appendix 5 of this information document.
Generation Capacity Limits
Due to angular stability and voltage concerns associated with outages of the 7L03, 7L07 or 7L22
transmission lines on the Elmsworth loop, there is a need to limit generation capacity of the generation
pool assets PH1 (Poplar Hill) and NPP1 (Northern Prairie Power Project). Please refer to Appendix 7 of
this information document to review the specific conditions and limits.
Operating Modes and Limits
If the Poplar Hill or Valley View # 1 generating units are either generating MW or operating in
synchronous condenser mode, the AESO increases the Grande Prairie cutplane inflow limits by the
amount specified in Appendix 5 of this information document. The increases contemplated in Appendix 5
are only applicable when there is a net power transfer-out of the northeast area as measured on the
Dover - Ruth Lake cutplane in the northeast area under N-0 and N-1 conditions.
Due to angular stability and voltage concerns, there is a need for the AESO to issue directives or
dispatches for transmission must-run in the northwest area to ensure that the system operating limits and
dynamic reactive reserve requirements for the Rainbow region are met. These reactive reserve
requirements are set out in Appendix 6.
5
Transmission Constraint Management
While the AESO manages transmission constraints in all areas of Alberta in accordance with the
provisions of section 302.1 of the ISO rules, not all of those provisions are effective in the northwest due
to certain unique operating conditions that exist in that area. This information document represents and
clarifies the application of the general provisions of section 302.1 to the northwest area. The Fort Nelson
connection is unique and the curtailment of Fort Nelson load requires additions steps which are set out
below.
The protocol steps which are effective in managing transmission constraints are outlined in Table 1
below, followed by additional steps which may be required.
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Northwest Area Transmission Constraint Management
ID # 2011-004(R)
Table 1 Transmission Constraint Management
Sequential Procedures for the Northwest Area
Section 302.1 of the ISO rules, subsection 2(1)
protocol steps
Applicable to the
Grande Prairie cutplane
inflow?
Applicable to the
Rainbow cutplane
inflow?
(a) Determine effective pool assets
Yes
Yes
(b) Ensure maximum capability not exceeded
No
No
(c) Curtail effective downstream constraint side
export service and upstream constraint side
import service
No
No
(d) Curtail effective demand opportunity
service on the downstream constraint side
No
No
(e)(i) Issue a dispatch for effective contracted
transmission must-run
Yes
Yes
(e)(ii) Issue a directive for effective noncontracted transmission must-run
Yes
Yes
(f) Curtail effective pool assets in reverse
energy market merit order followed by pro-rata
curtailment
No
No
(g) Curtail effective loads with bids in reverse
energy market merit order followed by pro-rata
load curtailment
Yes
Yes
Applicable Protocol Steps
The first step in managing constraints in any area is to identify those generating units effective in
managing the constraint. All generating units and loads operating in the northwest area are indicated in
Appendix 3 (single line diagram), the generating units effective in managing constraints are identified in
Appendix 1.
Step (a) in Table 1
The effective pool assets are as shown in Appendix 1.
Step (b) in Table 1
Ensuring maximum capabilities are not exceeded is not applicable to the northwest due to the deficiency
of generation and inflow scenario.
Step (c) in Table 1
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There is no effective export or import opportunity service to curtail for either the Grande Prairie or
Rainbow cutplane.
Step (d) in Table 1
There is no demand opportunity service load in the area to curtail.
Steps (e)(i) and (ii) in Table 1
Issue dispatches to effective contracted pool assets or directives to effective non-contracted pool assets
for transmission must-run.
Step (f) in Table 1
Reverse merit order curtailment is not effective and therefore not required because the constraint is
caused by not having enough in-merit generation in the downstream constrained area.
Step (g) in Table 1
Curtailing effective loads with bids in reverse energy market merit order followed by pro-rata load
curtailment is available for both Grande Prairie and Rainbow cutplanes.
Additional Steps
Due to the operating characteristics of the northwest area, when managing a transmission constraint on
the Rainbow cutplane, the AESO may utilize the following additional procedures:
(i) curtail applicable load in accordance with the provisions of the contract between the AESO and the
British Columbia Hydro and Power Authority (addressing Fort Nelson operation), after
implementing step (e)(i) in Table 1 set out in subsection 3(1); and
(ii) if necessary to maintain Rainbow area voltage levels, follow the Grande Prairie cutplane
curtailment procedure.
6
Project Updates
As necessary, the AESO intends to provide information in this section about projects underway in the
northwest area that are known to have an impact on the information contained in this information
document.
7
Appendices to this Information Document
Appendix 1 – Effective Pool Assets
Appendix 2 – Geographical Map of the Northwest Area
Appendix 3 – Northwest Area Cutplanes Single Line Diagram
Appendix 4 – Grande Prairie Cutplane Limits
Appendix 5 – Grande Prairie Cutplane Inflow Limits and Operating Mode
Appendix 6 – Rainbow Lake Cutplane Requirements
Appendix 7 – Generation Capacity Limits – Poplar Hill and Northern Prairie Power Project
Revision History
Version
Effective Date
1.0
2011-06-30
2.0
2012-03-03
3.0
2012-06-14
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Description of Changes
Initial Release
Updated to reflect transmission upgrades in the area
Updated to include material content from existing section 302.4 of
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4.0
5.0
6.0
2012-08-31
2013-01-01
2013-02-14
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Effective: 2013-02-14
the ISO rules, Northwest Area Transmission Constraint
Management
Updated to include minor drafting edits
Updated to include Table 4 which reflects changes to the Rainbow
Lake Cutplane limits and Dynamic Reactive Reserve requirements.
Updated Table 4 to reflect changes to the Rainbow Lake Cutplane
limit and Dynamic Reactive Reserve requirements. Minor drafting
edit to geographical map.
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ID # 2011-004(R)
Appendix 1 - Effective Pool Assets
1
The effective generation pool assets for the Grande Prairie cutplane , listed alphabetically by their pool
IDs, are:
BCR2
BRCK
DAI1
GPEC
NPC1
NPP1
PH1
ST1
ST2
VVW1
The effective generation pool assets for the Rainbow cutplane, listed alphabetically by their pool IDs, are:
FNG
RB1
RB2
RB3
RB5
RL1
1
An operational study in this area is being conducted and the effective pool assets will be updated following the
study.
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Appendix 2 – Geographical Map of the Northwest Area
Zama Lake
795S
7L72
Sulphur Point
828S
Rainbow Lake
791S
1L359 7L81
Fort Nelson
852S
High Level
786S
7L133
7L93
Arcenciel
930S
7L122
Blumenort
832S
7L76
7L109
Melito
890S
SVC
Bassett
747S
7L59
SVC
7L64
7L113
Chinchaga
779S
Haig
River
748S
Keg River
789S
Ring Creek
853S
Kemp River
797S
7L58
Rainbow Lake cutplane (RLC)
7L62
7L82
Hamburg
855S
7L63
Hotchkiss
788S
Meikle
905S
7L120
7L138
783S
878S
Kidney Lake
7L63
7L51
7L131
861S
Eureka
River
812S
7L106
839S
7L94
830S
6L16
SVC
827S
Cranberry
Lake
724S
869S
7L12
7L27
6L37
7L75
Lubicon
9L11
7L48
858S
720S
865S
9L56
7L68
7L07
811S
Clairmont
728S
749S
7L03
823S
734S
7L32
798S
6L57
7L57
794S
808S
845S
Big Mountain
6L73 7L162
844S
745S
729S 7L49 732S
727S
23 Valleyview
862S
722S
758S
6L99
6L91
787S
6L68
7L22
739S
7L45/7L46
736S
Little Smoky
813S
854S
809S
9L02, 9L05
733S
7L80
HR
Milner
740S
7L199
741S
Fox
Creek
9L938
234S
69S
9L939
72kV
199L
720L
236S 77S
397S
854L
To Bickerdike
39S
Page 7
7L230
824S
347S
24 Fox Creek
857S
9L913
743S
851S
738S
26 Swan Hills
810S
Dome
9L40
7L56
7L40
7L90
735S
744S
742S
725S
SVC
7L20
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Grande
Prairie
cutplane
7L23
784S
730S
Rycroft
790S
Poplar Hill
731S
Elmworth
9L15
7L61
882S
815S
Goodfare
To Britnell 876S
796S
7L73
7L10
Wesley Creek
834S
793S
West
Peace
800S
Fredenstal
829S
754S
Ksituan
780S
To Whitecourt
323S
144kV
240kV
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Northwest Area Transmission Constraint Management
ID # 2011-004(R)
Appendix 3 – Northwest Area Cutplane Single Line Diagram
FNG1
RB1, RB2, RB3, RL#1, RB5
7L81
Rainbow Lake
791S
7L122
7L109
NPP1
Arcenciel
930S
7L113
PH1
Ring Creek
853S
Poplar Hill
790S
DAI1
Keg River
789S
7L82
Rainbow Lake Cutplane (RLC)
M
BRCK
BCR2
Hotchkiss
788S
7L38 7L120
ST1
ST2
7L58 7L62
M
M
Meikle
905S
NPC1
7L106
7L131
GPEC
Wesley Creek
834S
GOC1
M
9L11
HRM1
VVW1
VVW2
Kinuso
727S
M
9L15
M
M
Little Smoky
813S
M
M
6L57
Mitsue
732S
M
M
M
Grande Prairie Cutplane
876S
9L56
7L56
7L90
Louise Creek
809S
9L02
9L913
720S
69S
9L05
9L40
725S
240 kV
144 kV
741S
72 kV
Electrical Path
Rainbow Lake Cutplane
Grande Prairie Cutplane
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Appendix 4 – Grande Prairie Cutplane Limits
Table 1 Grande Prairie Cutplane Limit for a Northeast area Export
Grande Prairie Cutplane Limit for a Northeast area Export
Contingency
Conditions
Maximum Grande Prairie area load studied 860 MW
To increase the Grande Prairie import limit add the synchronous condenser
mode effect (Table 3)
HR Milner = 70MW 70 MW < HR Milner < 140 MW HR Milner ≥140 MW
X = HR Milner output – 70 MW
No contingencies
585
585 – (0.71 * X)
535
GPEC or
BCR2 steam
590
590 – (0.79 * X)
535
9L11
610
610 – (0.93 * X)
545
9L15
585
585 – (0.57 * X)
545
9L02 or 9L05
485
485
485
919L or 989L
470
470 – (0.21 * X)
455
9L938 or 9L939
485
485
485
9L40
570
570 – (0.93 * X)
505
9L56
600
600 – (0.79 * X)
545
9L913
545
545 – (0.79 * X)
490
7L56
600
600 – (0.57 * X)
560
7L90
600
600 – (0.57 * X)
560
7L23
575
575 – (0.71 * X)
525
7L61
595
595 – (0.57 * X)
555
6L57
610
610 - (0.79 * X)
555
590
590
590
565
565 – (1.29 * X)
475
595
595 – (1 * X)
525
HR Milner < 70
MW
Little Smoky static
VAr compensator
Cranberry
static
VAr compensator
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Examples to assist with interpretation of Table 1:
1. If HR Milner is generating at 70 MW and transmission line 9L15 is out of service then the
power flow limit into the northwest is 585 MW.
2. If HR Milner is generating at 100 MW and the region load is less than 860 MW, and
transmission line 9L15 out of service then the power flow limit into the northwest is
calculated as 585 – (0.57*(100 – 70)) = 567.9 MW.
3. If HR Milner is generating at 140 MW and transmission line 9L15 is out of service then the
power flow limit into the northwest is 545.
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Table 2 Grande Prairie Cutplane Limit for a Northeast area Import
Grande Prairie Cutplane Limit for a Northeast area Import
Maximum Grande Prairie area load studied 860 MW
Contingency
Conditions
HR Milner=70 MW
70 MW < HR Milner < 140 MW
HR Milner ≥140 MW
X = HR Milner output – 70 MW
No contingencies
565
565 – (0.36 * X)
540
GPEC or
BCR2 steam
555
555 – (0.21 * X)
540
9L11
590
590 – (0.64 * X)
545
9L15
545
545
545
9L02 or 9L05
440
440
440
919L or 989L
405
405
405
9L938 or 9L939
460
460
460
9L40
530
530 – (0.71 * X)
480
9L56
575
575 – (0.29 * X)
555
9L913
550
550 – (1.43 * X)
450
7L56
570
570
570
7L90
570
570
570
7L23
550
550 – (0.36 * X0
525
7L61
560
560
560
6L57
580
580 – (0.29 * X)
560
HR Milner < 70 MW
560
560
560
Little Smoky static
VAr compensator
540
540 – (1.14 * X)
460
Cranberry
static
VAr compensator
570
570 – (0.86 * X)
510
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Examples to assist with interpretation of the Table 2:
1. If HR Milner is generating at 70 MW and transmission line 9L11 is out of service then the
power flow limit into the northeast is 590 MW.
2. If HR Milner is generating at 100 MW and the region load is less than 860 MW, and
transmission line 9L11 out of service then the power flow limit into the northeast is
calculated as 590 – (0.64*(100 – 70)) = 570.8 MW.
3. If HR Milner is generating at 140 MW and transmission line 9L11 is out of service then the
power flow limit into the northeast is 545 MW.
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Appendix 5 –Grande Prairie Cutplane Inflow Limits and Operating Mode
Table 3 below sets out the power flow limits if the Poplar Hill or Valley View (VVW1) generating units are
operating in either synchronous condenser mode or MW generation mode:
Table 3
Increase to Grande Prairie Transfer Limit IF the Northeast area is Exporting
System Conditions
PH1
in
synchronous
condenser
mode
or
1
generating
MW
VVW1
in
synchronous
condenser mode or
either
VVW
generating unit is
1
generating MW
Both PH1 and VVW1 in
synchronous
condenser
mode or both generating
2
stations are generating
MW
System normal
+30
+20
+45
HR Milner contingency
+10
+0
+20
Note:
1. Generating units are considered in generating mode if they are above their minimum stable
generation.
2. It is accepted that any combination of the following meets this requirement:
a. PH1 is on synchronous condenser mode/generating MW; or
b. VVW1 is on synchronous condenser mode or either VVW1 or Valley View 2 generating
units are generating power.
Examples to assist with interpretation of Table 3:
1. For any limit calculated in Appendix 4 and when VVW1 is in synchronous condenser mode
or is generating MW, for system normal conditions, the limit calculated from Appendix 4 is
increased by 20 MW.
2. For any limit calculated in Appendix 4, if PH1 is generating at some level or in synchronous
condenser mode, and HR Milner is out of service, the cutplane limit is increased by 10 MW.
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Appendix 6 – Rainbow Lake Cutplane and Dynamic Reactive Reserve Requirements
Table 4 sets out the Rainbow Lake cutplane and the dynamic reactive reserve requirements.
Table 4
Rainbow Lake
1
Cutplane Limit
Operating State
3
Minimum
Dynamic
Reactive
2
Reserve
(MVAr)
Rainbow Lake
1
Cutplane Limit
Minimum
Dynamic
Reactive
2
Reserve
(MVAr)
No
Either
Synchronous Condenser or
Rainbow unit on line
A Synchronous Condenser or a
Rainbow unit is on line
Summer
130
“N-0” System Normal
103 MW
30 MVAr
Summer
103 MW
30 MVAr
Summer
103 MW
30 MVAr
N-1: 7L131 or 7L106 Out
83 MW
20 MVAr
Winter
/ 155
30 MVAr
(See Note 1)
130
N-1: High Level SVC Out
30 MVAr
(See Note 1)
130
N-1: Arcenciel SVC Out
Winter
/ 155
Winter
/ 155
(See Note 1)
30 MVAr
128 MW
Summer
71
N-1: 7L82 or 7L113 Out
Summer
N-1: 7L58 or 7L62 Out
71
20 MVAr
83 MW
75
Summer
/ 80
(See Note 1)
N-1: 7L64 Out
N-1: 7L59 or 7L93 Out
Winter
Winter
(See Note 1)
83 MW
Summer
75
20 MVAr
38 MVAr
Winter
/ 80
30 MVAr
30 MVAr
(See Note 1)
20 MVAr
/ 86
83 MW
(See Note 1)
20 MVAr
Winter
/ 86
(See Note 1)
83 MW
20 MVAr
38 MVAr
Notes:
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1. The Rainbow Lake cutplane operating limits are based on voltage stability and thermal
limits. Thermal limits are illustrated when summer and winter limits have been identified.
2. The dynamic reactive reserve units are: Arcenciel Static Var Contoller (desired range: 0 to
-5), Arcenciel Synchronous Condenser, High Level Static Var Contoller (desired range: 0 to
-5), Rainbow generators.
3. An unstudied state occurs when two elements in the above table are out of service. Real
time limits are determined using the energy management system advanced applications
contingency analysis or voltage stability application.
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Appendix 7 – Generation Capacity Limits – Poplar Hill and Northern Prairie Power Project
Tables 5.1 and 5.2 below set out the generation limits for Poplar Hill and Northern Prairie Power Project
generating units under certain conditions. When reading the tables:
(1)
(2)
(3)
(4)
HRM refers to the HR Milner generating unit.
NPP1 refers to the Northern Prairie Power Project generating unit.
PH1 refers to the Poplar Hill generating unit.
Generation limit refers to the sum of the MW generation plus any operating reserves for which the
AESO issued a dispatch.
Table 5.1 Poplar Hill Unit Generation Capacity Limits
PH1 Generation Limit (MW) = the sum of
energy and operating reserve for which the
AESO has issued dispatches for the
generating unit
NPP1 and HR Milner Generator Status
A.
HR Milner on-line and ≥ 70 MW, and
A.1. NPP1 is on-line when the sum of energy and operating reserves for which
the AESO has issued dispatches > 1MW
42
A.2. NPP1is off-line and not issued dispatches for operating reserves
48
B.
HR Milner off-line or generating < 70 MW, and
B.1. NPP1 is on-line when the sum of energy and operating reserves for which
the AESO has issued dispatches > 1 MW
41
B.2. NPP1 is off-line and not issued dispatches for operating reserves
48
An example to assist with interpretation of the table directly above:
If the HRM generating unit is on-line and generating seventy (70) MW or more; and the NPP1 generating
unit is on-line; then the generation limit for the PH1 generating unit is forty two (42) MW.
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Table 5.2 Northern Prairie Power Project Generation Capacity Limits
NPP1 Generation Limit (MW) = the sum of
energy and operating reserve for which
the AESO has issued dispatches for the
generating unit
PH1 and HR Milner Generator Status
A.
HR Milner on-line and ≥ 70 MW, and
A.1. PH1 is on-line when the sum of energy and operating reserves for which the
AESO has issued dispatches > 1 MW
81
A.2. PH1 is off-line and not issued dispatches for operating reserves, or
82
A.3. PH1 is operating in synchronous condenser mode and not issued dispatches
for operating reserves
93
B.
HR Milner off-line or generating less than 70 MW, and
B.1. PH1 is on-line when issued dispatches for energy > 1 MW.
79
B.2. PH1 is off-line, or
76
B.3. PH1 is operating in synchronous condenser mode and not issued dispatches
for operating reserves
93
An example to assist with interpretation of the table directly above:
If the HRM generating unit is on-line and generating more than seventy (70) MW or more; and the PH1
generating unit is on-line; then the generation limit for the NPP1 generating unit is eighty one (81) MW.
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