BHBE – G8
System Impact Study
PREPARED ON BEHALF OF THE COMMON USE SYSTEM
BY
BLACK HILLS CORPORATION
TRANSMISSION PLANNING
1. Executive Summary
An Interconnection System Impact Study (SIS) was performed by Black Hills
Corporation under the guidance of the Common Use System (CUS) Joint Open Access
Transmission Tariff Large Generator Interconnection Procedures (LGIP) for the
Interconnection Customer to construct and interconnect an 80.5 MW wind farm in
western South Dakota. The proposed project consists of thirty-five (35) 2.3 MW
Siemens wind turbine generators and will connect to the CUS 230 kV transmission
system at a point along the existing Lange to Lookout 230 kV line near Sturgis, SD.
The purpose of the study was to:
• Analyze the steady state and short circuit conditions for the project
• Evaluate transient stability performance
• Determine any upgrades to the transmission system that would be required to
mitigate any adverse impacts that the proposed project could pose on the
reliability and operating characteristics of the transmission system.
Steady State Analysis
Steady-state voltage and thermal analysis examined system performance without the
proposed project in order to establish a baseline for comparison. System performance was
re-evaluated with the project in place and compared with the baseline performance to
demonstrate the impact of the project on local transmission reliability. The analysis
determined that no steady-state criteria were violated as a result of the interconnection. It
also showed that the reactive requirements have been met for this project.
Stability Analysis
Stability analysis evaluated the impact of the proposed project on transmission system
performance for both heavy summer and light winter load conditions.
The stability analysis identified the project’s impacts on the transmission system
following several different disturbances. Stability analysis results showed that no
transient stability criteria were violated as a result of the proposed interconnection and
verified the project’s Low Voltage Ride-Through (LVRT) capability was in accordance
with current NERC/WECC LVRT requirements.
Short Circuit Analysis
Short circuit analysis was performed in the Feasibility Study (FS) to asses the impact the
proposed project would have on the fault current levels and breaker duty in the area. No
adverse results were found during the FS for the original interconnection request of 120
MW, as such the impacts were assumed to be less for the smaller request of 80.5 MW
and so the short circuit analysis was not performed for the SIS.
Conclusions
The System Impact Study identified no network upgrades, beyond those required to
interconnect the project, to accommodate the 80.5 MW wind project.
Network facilities required to interconnect the project are a new three position ring bus
intersecting the Lange to Lookout 230 kV line at an estimated cost of $2,300,000. Also,
fiber communications would need to be installed on the Lange to Lookout 230 kV line at
an estimated cost of $2,000,000 for a total estimated cost of $4,300,000. Estimated time
of construction for Network Upgrades is approximately eighteen (18) months from
execution of an Interconnection Agreement and receipt of funds. All facilities and
equipment beyond the Point of Interconnection station take-off structure will be the sole
responsibility of the Interconnection Customer. All new facilities and equipment required
to interconnect the project within the substation are considered Network Upgrades and
will be funded by the Interconnection Customer but owned by BHP.
Interconnection Service in and of itself does not convey any right to deliver electricity to
any specific customer or Point of Delivery.
2. Background
2.1. Tariff
Black Hills Power (BHP), Basin Electric Power Cooperative (Basin), and Powder
River Energy Corporation (PRECorp) own and operate 230 kV transmission facilities
in Wyoming and South Dakota which are governed by a FERC approved Joint Open
Access Transmission Tariff (Joint Tariff) and commonly referred to as the Common
Use System (CUS). Black Hills Power acts as the Tariff Administrator of the Joint
Tariff and, as such, is responsible for evaluating and studying all large generator
interconnection requests made on the CUS.
2.2. Study Objective
The primary objective of the study was to determine whether the proposed
interconnection had any adverse impacts on the reliability, stability or operating
characteristics of the Bulk Electric System (BES). Comprehensive steady-state and
“worst-case” stability performance was evaluated.
2.3. Project Description
The project consists of thirty-five (35) 2.3 MW Siemens wind turbine generators,
producing up to 80.5 MW total. The project was studied as both a network resource
and an energy resource, interconnecting the existing Lange to Lookout 230 kV line.
3. Base Case Development
3.1. Base Case Origin and Year
The proposed interconnection is scheduled for the end of the fourth quarter of 2010.
The base case originated from the Western Electricity Coordinating Council
(WECC). The base case chosen was the 2011 HS1B1P. The case was examined for
accuracy and updated.
3.2. Planned Projects
The case was updated to include committed projects with in-service dates prior to the
facility in-service date which were determined to have an impact on system
performance as well as higher queued LGI requests. These projects included:
•
•
•
•
•
•
Rapid City Voltage Support Project
Wygen 3
The Hughes Transmission Project
Dry Fork Station
Donkey Creek-Pumpkin Butte-DJ area 230 kV line
Teckla Voltage Support Project
Should any one of the projects listed above not be complete prior to the proposed
project in-service date, the interconnection project may be curtailed due to
transmission prior outages or other emergency conditions. These curtailments and/or
operating restrictions, if needed, will be developed and identified through operational
studies as required.
3.3. Resource Assumptions
3.3.1. Network Resource
To dispatch the wind generation as a Network Resource, the generation at Wygen
I, Wygen II, Wygen III, and Neil Simpson II, were scaled down on a pro rata
basis.
3.3.2. Energy Resource
The wind generation was dispatched as an Energy Resource against generating
facilities to the south. Specifically, this was accomplished by lowering the
generation at the Laramie River Station.
3.4. Area Load
3.4.1. 2011 Heavy Summer
The 2011 heavy summer load case was created by updating BHP, CLF&P, and
Basin Electric loads to their 2011 peak forecast values
3.4.2. 2011 Light Winter
The 2011 light winter load case was created by scaling the area load to 55% of
2011 peak summer forecast values.
3.5. Analytical Tools
Power flow simulations were performed using PSS/E simulation software, version
30.3.3. Short-circuit analysis were performed using ASPEN OneLiner, version 10.12.
4. Steady State Analysis Methodology
4.1. Steady State Analysis Methodology
To determine if the proposed project caused any adverse impacts to the reliability and
operating characteristics of the CUS transmission system, it was evaluated using 2011
peak summer and light winter load levels. A baseline for comparison was established
by comparing the voltage and thermal performance of the CUS without and with the
proposed project in-service.
4.1.1. Voltage Limits
Table 1 presents the voltage criteria used in the primary study area for the steadystate voltage assessment.
Table 1: Steady State Voltage Limits
Voltage Class
69 kV and Above
Acceptable Voltage Range
Pre-Contingency
Post-Contingency
0.95 to 1.05 p.u.
0.90 to 1.10 p.u
4.1.2. Thermal Limits
Normal thermal ratings shall not be violated under system intact conditions, and
applicable emergency ratings shall not be exceeded under contingency conditions.
Thermal loading on all transmission lines in the CUS are not allowed to exceed
100% of their normal rating. The CUS transmission lines do not have emergency
ratings. Transformers are allowed to overload as outlined in Table 2.
Table 2: Transformer Overloads
Maximum Hours @ Overload
½ Hour
1 Hour
2 Hours
Allowable Transformer Overload
153%
135%
120%
4.1.3. Solution Parameters
Pre-contingency solution parameters allowed adjustment of load tap-changing
(LTC) transformers, static VAR devices including switched shunt capacitors and
reactors, and DC taps. Post-contingency solution parameters allowed for
adjustment of DC taps and the Rapid City South capacitor only. Generator VAR
limits were applied immediately and area interchange control was disabled for all
solutions. A fixed-slope decoupled Newton solution method was implemented
for all cases. Table 3 lists all of the prior outages and Table 4 lists all
contingencies
Table 3: Prior Outages List
Prior Outage List
Wyodak-Hughes 230 kV
Lookout-Sturgis Wind 230 kV
Lange-Rapid City South 230 kV
West Hill-Osage 230 kV
Osage-Wyodak 230 kV
Yellow Creek-Lookout 230 kV
Hughes-Lookout 230 kV
Sturgis Wind-Lange 230 kV
Rapid City South-West Hill 230 kV
Osage-Yellow Creek 230 kV
Wyodak-Donkey Creek 230 kV
Table 4: Contingencies List
Contingencies List (Lines are 230 kV unless noted)
Ant Mine-Teckla
Ant Mine-Yellow Cake
Yellow Cake-Dave John
Dave John-Larmie River
Dave John-Stegall
Wyodak-Osage
Osage-Yellow Creek
Wyodak-Hughes
Wyodak-Donkey Creek
Donkey Creek- Pmpkn Bt
Teckla-Pmpkn Bt
Dave John-Pmpkn Bt
Wyodak-Carr Draw
Buffalo-Carr Draw
Buffalo-Sheridan
Buffalo-Kaycee
Dryfork-Carr Draw
Dryfork-Huges
Dryfork-Tongue River
West Hill-Osage
West Hill-Rapid City South
West Hill-Stegall
Larmie River-Stegall
Lange-Rapid City South
Reno-Teckla
Reno-Donkey Creek
Lookout-Yellow Creek
Lookout-Hughes
Dave John-Casper
Casper-Riverton
Dave John-Difficult
Rapid City South-DC Tie
Hughes-Osage 69 kV
Sundance-Lange 69 kV
Yellow Crk-Lange 69 kV
Sundance-Yelow Crk 69 kV
Lookout-Kirk 69 kV
Lookout-Spfsh-YCrk 69 kV
Pactola-YCrk 69 kV
Custer-West Hill 69 kV
Cmbl-4th-BF 69 kV
Cambell-Lng-Tie 69 kV
S Rapid-Cambell 69 kV
BFrench-S Rapid 69 kV
Wyodak Unit
Wygen Unit
Wygen II Unit
NSS2 Unit
BF Unit
NSS1 Unit
Lange Unit
Osage #1 Unit
Wyodak 70 Xfmr
Wyodak 100 Xfmr
Osage Xfmr
Lange #1 Xfmr
Lange #2 Xfmr
Lookout #1 Xfmr
Yellow Creek Xfmr
West Hill Xfmr
Hurghes Xfmr
South Rapid Xfmr
5. Steady State Analysis Results
5.1. Heavy Summer Pre-Wind Results
There were no criteria violations during the heavy summer pre-wind steady state
analysis.
5.2. Heavy Summer Network Resource Results
There were no criteria violations during the heavy summer network resource steady
state analysis.
5.3. Heavy Summer Energy Resource Results
There were no criteria violations during the heavy summer energy resource steady
state analysis.
5.4. Light Winter Pre-Wind Results
There were no criteria results during the light winter pre-wind steady state analysis.
5.5. Light Winter Network Resource Results
There were no criteria violations during the light winter network resource steady state
analysis.
5.6. Light Winter Energy Resource Results
There were no criteria violations during the light winter energy resource steady state
analysis.
5.7. Reactive Requirements
The reactive requirements for this project have been met.
6. Stability Analysis Methodology
6.1. Stability Analysis Methodology
The objective of stability analysis is to analyze the impact of the project on transient
stability performance of the power system for various disturbances. Stability
simulations were conducted with and without the proposed interconnection for both
2011 heavy summer and 2011 light winter load level scenarios to confirm
performance with respect to applicable criteria.
6.1.1. Stability Performance Criteria
The disturbance performance criteria for this study requires that the transient low
voltage swing shall not be lower than 0.70 p.u. at any load or non-load bus and
the system shall exhibit positive damping following any contingency. Table W-1
of the TPL-(001 thru 004)-WECC-1-CR-System Performance Criteria states that
for a NERC Category B contingency, the frequency at a load bus must not dip
below 59.6 HZ for more than 6 cycles, but this requirement was applied to all
contingencies to simplify the presentation of the results.
6.1.2. Low Voltage Ride-Through Criteria
The current NERC/WECC Low Voltage Ride-Through (LVRT) Standard requires
generators to remain in-service for 3-phase faults with normal clearing (4-9
cycles) and single line-to-ground faults with delayed clearing that result in a GSU
high side voltage of 0.15 per unit or greater
6.2. Stability Fault Descriptions
Each dispatch scenario for the 2011 heavy summer and 2011 light winter load cases
were simulated with various 3-phase faults applied. Table 5 lists the faults that were
simulated. In addition to system intact fault analysis, the prior outages listed in Table
3 were also simulated with the various 3-phase faults.
Table 5: Stability Analysis Fault Description
Fault Description
3 PH Bus Fault
Cleared Element
New Tap 230
New Tap-Lookout 230 Line
New Tap 230
New Tap-Lange 230 Line
Lookout 230
Lookout-Hughes 230 Line
Lookout 230
Lookout-Yellow Creek 230 Line
Lange 230
Lange-South Rapid 230 Line
South Rapid 230
South Rapid-West Hill 230 Line
Teckla 230
Teckla-Wind Star 230 Line
West Hill 230
West Hill-Osage 230 Line
West Hill 230
West Hill-Stegall 230 Line
Wyodak 230
Wyodak-Carr Draw 230 Line
Wyodak 230
Wyodak-Donkey Creek 230 Line
Wyodak 230
Wyodak-Hughes 230 Line
Wyodak 230
Wyodak-Osage 230 Line
Fault Duration
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
4.25 Cycles
7. Stability Analysis Results
There were no stability performance criteria violations observed on the transmission
system as a result of the interconnection of the proposed project. All post-contingent
voltage dips remained well above the established limit and rotor angle oscillations were
positively damped. Additionally, there were no frequency excursions below the 59.6 HZ
limit for a period of 6 cycles or more at any of the monitored buses. The faults simulated
at the New Tap 230 kV bus confirmed the LVRT capability of the Siemens 2.3 MW and
exhibited performance that met NERC/WECC LVRT requirements.
8. Short Circuit Analysis
A short circuit analysis was performed as part of the Feasibility Study for the 120 MW
project, which exhibited no adverse impacts on the BES. The size of the project has since
been reduced to 80.5 MW and the impacts are assumed to be reduced as well. Therefore
the short circuit analysis was not performed as part of the SIS.
9. Conclusions
This report describes the power flow and stability studies performed to determine the
impacts of interconnecting a new 80.5 MW wind plant which intersects the existing
Lange to Lookout 230 kV line. The interconnection project as studied is comprised of
thirty-five (35) 2.3 MW Siemens wind turbine generators.
There were no negative impacts to the transmission system as a result of the proposed
interconnection and the reactive requirements have been met for this project. Customerfunded Network Upgrades required for interconnection to the existing Lange to Lookout
230 kV line are listed in Table 6.
Table 6: POI Estimated Costs
Customer-funded Network Upgrades
3 Position Ring Bus
Construct a new 3 position ring bus
to interconnect with BHP’s
transmission system
OPGW
Install OPGW between Lange and
Lookout 230 kV substations
(estimate includes outage costs)
Estimated Total Cost
Estimated Time Frame
$2,300,000
$2,000,000
$4,300,000
18 Months
Estimated time of construction for Network Upgrades is approximately eighteen (18)
months from execution of an Interconnection Agreement and receipt of funds. All
facilities and equipment beyond the Point of Interconnection station take-off structure
will be the sole responsibility of the Interconnection Customer. All new facilities and
equipment required to interconnect the project within the substation are considered
Network Upgrades and will be funded by the Interconnection Customer but owned by
BHP.
Interconnection Service in and of itself does not convey any right to deliver electricity to
any specific customer or Point of Delivery.