Guidelines for Performing Generator Interconnection
Feasibility and System Impact Studies
1. Purpose
Customers desiring to connect new generation on the Duke Energy Carolinas (DEC)
system are required to make a request through the Contracts Manager. Generator
Interconnection Feasibility and System Impact Studies evaluate the effects the customer’s
new generation will have on DEC’s transmission system. FERC Large Generation
Interconnection procedures (filed as part of DEC’s OATT) govern the interconnection
process. Of primary concern is the creation of newly overloaded lines or transformers
during both normal system operation and contingencies. Evaluation of system stability,
reactive support capability and fault duty are also required. The customer may be
required to pay for correction of any new problems associated with their generation and
will receive transmission credits for the amount they pay. This work practice describes
the method by which this evaluation is accomplished.
The study results are communicated through the contracts manager, who works directly
with the customer. The results will describe what projects will need to be undertaken to
accommodate the new generation.
Study Scope
Generation interconnection application data must be reviewed within 5 business days of
receipt. The customer must correct the data deficiency within 10 business days of
notification. A Scoping Meeting should be scheduled within 30 calendar days of initial
receipt of the request.
Clustering of Interconnection Requests will allow for a rolling six month window in
which Requests will be accepted. The Queue Cluster Window Close Dates will be
January 31st and July 31st. System Impact Studies for each Request within a cluster will
be completed within 90 days of the Cluster Window Close Date. All Feasibility and
System Impact Studies will use the most accurate DEC detailed model available at that
time. It is possible that Feasibility and System Impact Studies may be performed on
different vintage year cases. For example, assume an interconnection request is made in
November and the Feasibility Study is performed using that year’s models. The Cluster
Window Close Date is January 31st of the following year. DEC’s internal models are
annually updated and are usually available near the end of January. Therefore, the
System Impact Study, due 90 days from the Close Date, may use the updated models.
This can lead to significant differences between the Feasibility and System Impact Study
results. The reasons for these differences will be explained in the System Impact Study
Results that are delivered to the customer.
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Transmission expansion plans and model corrections are normally implemented in case
updates throughout the year. Therefore, serially studying Interconnection Requests may
produce differing results for two separate Requests with an equal MW output in the same
location. Clustering avoids this potential confusion by the use of a single basecase model
for all studies within a Cluster Window.
It is unlikely that the number of Requests within a single Queue Cluster Window will
impose constraints on Planning’s ability to deliver the results within 90 days after the
Close Date.
Energy Resource Interconnection Service (ERIS) Study Request
ERIS service will be evaluated by including the new generation with higher queued
projects and associated known upgrades included in the models. The output is used to
serve DEC Load. DEC generation will be re-dispatched economically.
ERIS service is viable using transmission capacity on an “as available” basis.
Transmission capacity is available as long as no transmission element is overloaded under
N-1 conditions and stability & fault duty limits are not exceeded. The thermal evaluation
will only consider the base case under N-1 transmission contingencies to determine the
availability of transmission capacity. Upgrades to maintain the necessary capacity to
allow the full generator output will be identified. Should the customer request it, the
study will also identify the maximum allowable output without requiring additional
Network Upgrades at the time the study is performed.
Network Resource Interconnection Service (NRIS) Study Request
NRIS service will be evaluated by including the new generation with higher queued
projects and associated known upgrades included in the models. The new generator is
studied by fully dispatching its output and economically dispatching DEC generation to
serve balancing authority area load. A variety of severely stressed conditions are modeled
through generation maintenance dispatches and N-1 transmission contingencies to ensure
the generator’s ability to provide network service within the DEC balancing authority
area. The study ensures that the new generation has the same level of reliability as
existing DEC generation. Upgrades to maintain the necessary capacity to allow the full
generator output will be identified.
NOTE 1: A customer can elect to have both an ERIS and NRIS study done
coincidentally to understand the impact of each type of service.
NOTE 2: If studied in a “cluster”, then all ERIS and NRIS requests must be studied
together.
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NOTE 3: Re-study of both the Feasibility and System Impact Studies are allowed, if
required by high queued projects dropping out or making allowed
modifications. Feasibility Re-study must be done in 45 days and System
Impact Re-study in 90 days.
Feasibility Study
Following the scoping meeting with the interconnection customer, a Feasibility Study is
performed. The Feasibility Study will involve assessment of the following:
a. thermal impact of probable contingencies (power-flow)
b. fault duty local to the new generation (short-circuit)
c. reactive power capability
Higher queued projects and associated known upgrades must be included in the thermal,
stability and fault duty models. Lower queued projects in the same Queue Cluster
Window with a Commercial Operation Date that precede the facility under study should
also be included in the model for evaluation. However, Network Upgrades identified
under these scenarios cannot be charged to the customer.
A summer peak powerflow model for the year under study will be modified by inclusion
of the new generator. Designation of ERIS or NRIS service will dictate how the new
generation is modeled. Application of probable transmission and generation
contingencies (depending on type of service requested) and faults will identify necessary
Network Upgrades. A non-binding good faith estimate of the time and cost to perform
upgrades will also be provided. 45 days are allotted for completing the Feasibility Study.
System Impact Study
Following the Queue Cluster Window Close dates, a System Impact Study is performed.
The System Impact Study will involve assessment of the following
a.
b.
c.
d.
thermal impact of probable contingencies (power-flow)
fault duty local to the new generation (short-circuit)
generator angular stability (angular stability)
reactive power capability
Higher queued projects and associated known upgrades must be included in the thermal,
stability and fault duty models. Lower queued projects in the same Queue Cluster
Window with a Commercial Operation Date that precede the facility under study should
also be included in the model for evaluation. However, Network Upgrades identified
under these scenarios cannot be charged to the customer.
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A summer peak powerflow model for the year under study will be modified by inclusion
of the new generator. Designation of ERIS or NRIS service will dictate how the new
generation is modeled. Application of probable transmission and generation
contingencies and faults will identify required Network Upgrades. A non-binding good
faith estimate of the time and cost to perform upgrades will also be provided. 90 days
from the Queue Cluster Window Close Date are allotted for completing all System
Impact Studies for requests made within that Queue Cluster Window.
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Load Flow Cost Assignments
I. Prior to need for system upgrade or capacity increase:
The first customer that drives the need for a transmission upgrade or capacity increase
will in all cases have some cost allocation. The cost allocation for this Interconnection
Customer is based upon the following set of criteria:
Criteria Set 1 (Both must apply to charge Network Upgrade cost to the customer):
a. The difference in the percent loading on a facility increases by 5% or more due to
the presence of the new generation,
b. The required Network Upgrade project completion date moves from outside
DEC’s 5 year Planning Horizon to within Duke Energy’s 5 year Planning
Horizon. If the Commercial Operation date of the facility is within 5 years of the
Queue Request Date, DEC’s Near-Term Planning Horizon (years 1-5) applies. If
the Commercial Operation Date of the facility is beyond 5 years of the Queue
Request Date, DEC’s Longer-Term Planning Horizon (years 6-10) applies.
Criteria Set 2 (Both must apply to charge Network Upgrade cost to the customer)
a. The presence of new generation causes the required Network Upgrade project
completion date to move up 5 years or more.
b. The required Network Upgrade project completion date is within 5 years of the
customers Commercial Operation Date.
In the event the need for a Network Upgrade is accelerated as a result of the generation
facility, the cost allocation for this Interconnection Customer is based upon the following
set of criteria:
Criteria Set 3 (a&b or a&c must apply to charge Network Upgrade cost to the customer):
a. The difference in the percent loading on a facility increases by 5% or more due to
the presence of the new generation
b. The required Network Upgrade project completion date moves up more than 1
year within DEC’s 5 year Planning Horizon. The customer is charged the time
value of money associated with accelerating the project.
c. The solution identified by DEC to address the overloaded facility requires
modification that adds cost to the Network Upgrade project. The customer is
charged for this increase in cost.
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II.
Interconnection Customers will be assigned costs in proportion to their
contributing MW impacts.
III.
No depreciation of the as built System Upgrade cost will be used when allocating
costs between Interconnection Customers.
IV.
Cost allocation for the engineering design of system upgrades will terminate based
on the completion of the applicable Interconnection Facility Study.
V.
In general, the solution to a thermally overloaded facility should be sufficient for
at least 30 years.
Fault Duty Cost Assignments
I.
All Interconnection Customers are studied in queue order.
II.
An Interconnection Customer will have some cost allocation if it results in a
greater than 3% increase in fault duty at the substation where the system upgrade
is required.
III.
Prior to the need for Network Upgrade:
The first customer that drives the need for a transmission upgrade or capacity
increase will in all cases have some cost allocation. The cost allocation for this
Interconnection Customer will only consider the loading above the equipment’s
capability.
IV.
An Interconnection Customer will be assigned costs in proportion to its fault level
contribution.
V.
No depreciation of the as built System Upgrade cost will be used when allocating
costs between Interconnection Customers
VI.
Cost allocation for the engineering design of system upgrades will terminate based
on the completion of the applicable Interconnection Facility Study.
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Optional Studies
The interconnection customer can request optional studies involving only their project,
but with their assumptions involving status of earlier queued generators. This is in
addition to the Feasibility and System Impact Studies.
Analysis of Study Results
The Customer’s request to connect a power plant on the DEC system requires
performance of both Feasibility and System Impact Studies. The existence of a request
will be communicated through the contracts manager. The manager will provide the
information on year of implementation, total generation, location of connection, and
configuration contained in the customer application.
Powerflow Study (Thermal and Voltage Screening)
The interconnection study should use the same files used in the annual Voltage &
Thermal Screening to Reliability Guidelines process.
Screening process
The new generation will be incorporated into the appropriate internal model, accounting
for its queue position. The model will be screened following the same methods applied
during the annual screening process used for transmission system upgrade and expansion
planning. ERIS only involves screening base case conditions and comparing the results
with and without the new generation.
Results Analysis
Analysis is performed utilizing the system impact study analysis spreadsheet and
importing the data into the appropriate areas of the spreadsheet. These spreadsheets
allow easy comparison of base and customer case screenings to determine if there are any
negative impacts that the new generation will have on line loadings. Evaluation of the
impact of the new generation and determination of the system upgrades required to
accommodate it is performed.
Short-Circuit Study (Fault Duty/Breaker Study)
Aspen software is used to evaluate the impact of a fault given the new system
configuration, including upgrades, and additional generating capacity. Applicable
transformer and generator impedances, and the circuit configuration are needed to model
for the study. The new generation buses and those local to it are faulted to allow
comparison with fault conditions prior to the new equipment’s installation. The study
results are reviewed to ensure that no equipment ratings will be exceeded.
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Stability Study (Generator Rotor/Angular Stability Study)
PSSE dynamics software should be used to evaluate the impact of the new system
configuration and additional generating capacity on system stability. In addition to the
normal steady state model data, generator/ turbine governor and voltage regulator data are
needed to create a model for the study. The new generation buses and those local to it are
faulted to allow comparison to evaluate system stability. Study results are evaluated to
ensure system stability will be maintained and that any necessary changes to relaying or
controls are identified.
Reactive Capability Study
Reactive capability is evaluated by modeling a facility’s generators and step-up
transformers (GSU’s) at various taps and system voltage conditions. The reactive
capability of the facility can be affected by many factors including generator capability
limits, excitation limits, and bus voltage limits. The evaluation determines whether
sufficient reactive support will be available at the Connection Point. The basis for
reactive power capability requirements is outlined in DEC’s work practice document
entitled Generator Reactive Power Support.
Communication of Results
The study results are communicated to the customer through the contracts manager. A
cover page should be prepared that specifies the details of the impact study - what levels
of generation, the model year, season, balancing authority area receiving the new
generation. The cover page should also summarize the results and the overall impact to
the customer.
The study results should be included in an attachment that explains (as appropriate for the
type of study) the assumptions, study methodology, direct assign facilities requirements,
thermal screening, fault study and stability study results. Any necessary tables should be
attached to provide details of required upgrades and their costs.
.
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References
a. FERC Standardization of Generator Interconnection Agreements and Procedures
– Final Rule (issued July 24, 2003)
b. DEC Open Access Transmission Tariff (OATT)
c. DEC Work Practice on Generator Reactive Power Support
d. DEC Facility Connection Requirements
e. Voltage & Thermal Screening to Reliability Guidelines
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