Guidelines for Performing Generator Interconnection Feasibility and SystemImpact 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 InterconnectionFeasibility and System Impact Studies evaluate the effectsthe 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.

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 DECbalancing 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.

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:

  1. thermal impact of probable contingencies (power-flow)
  2. 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

  1. thermal impact of probable contingencies (power-flow)
  2. fault duty local to the new generation (short-circuit)
  3. generator angular stability (angular stability)
  4. 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 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.

Load Flow Cost Assignments

  1. Prior to need for system upgrade or capacity increase:

The first customer that drives the need for a transmission upgrade or capacityincrease will in all cases havesome 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):

  1. The difference in the percent loading on a facility increases by 5% or more due to the presence of the new generation,
  2. 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)

  1. The presence of new generation causes the required Network Upgrade project completion date to move up 5 years or more.
  2. 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):

  1. The difference in the percent loading on a facility increases by 5% or more due to the presence of the new generation
  2. 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.
  3. 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.

  1. Interconnection Customers will be assigned costs in proportion to their contributingMW impacts.
  1. No depreciation of the as built System Upgrade cost will be used when allocating costs between Interconnection Customers.
  1. Cost allocation for the engineering design of system upgrades will terminate based on the completion of the applicable Interconnection Facility Study.
  1. In general, the solution to a thermally overloaded facility should be sufficient for at least 30 years.

Fault Duty Cost Assignments

  1. All Interconnection Customers are studied in queue order.
  1. 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.
  1. 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.

  1. An Interconnection Customer will be assigned costs in proportion to its fault level contribution.
  1. No depreciation of the as built System Upgrade cost will be used when allocating costs between Interconnection Customers
  1. Cost allocation for the engineering design of system upgrades will terminate based on the completion of the applicable Interconnection Facility Study.

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 filesused 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. Evaluationof 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.

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

  1. FERC Standardization of Generator Interconnection Agreements and Procedures – Final Rule (issued July 24, 2003)
  2. DEC Open Access Transmission Tariff (OATT)
  3. DEC Work Practice on Generator Reactive Power Support
  4. DEC Facility Connection Requirements
  5. Voltage & Thermal Screening to Reliability Guidelines

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