completed for q0292 - oati · completed for . q0292 . ... substation by replacing an idle...

Large Generator Interconnection System Impact Study Report

Completed for Q0292

Proposed Interconnection Existing Customer 69kV Substation

October 28, 2011

System Impact Study Report

Q0292 Page i October 28, 2011

TABLE OF CONTENTS 1.0 DESCRIPTION OF THE GENERATING FACILITY .................................................................... 12.0 SCOPE OF THE STUDY ................................................................................................................. 13.0 TYPE OF INTERCONNECTION SERVICE .................................................................................. 24.0 DESCRIPTION OF PROPOSED INTERCONNECTION ............................................................... 2

4.1 Other Options Considered (NERC Requirement) ........................................................................ 35.0 STUDY ASSUMPTIONS ................................................................................................................. 3

5.1 Energy Resource (ER) Interconnection Service .......................................................................... 55.1.1 Study Results 65.1.2 Requirements 115.1.3 Cost Estimate 195.1.4 Schedule 195.1.5 Maximum Amount of Power that can be delivered into Network Load, with No Transmission

Modifications (for informational purposes only) 195.1.6 Additional Transmission Modifications Required to Deliver 100% of the Power into Network

Load (for informational purposes only) 195.2 Network Resource (NR) Interconnection Service ..................................................................... 20

5.2.1 Study Results 205.2.2 NR Requirements 205.2.3 Schedule 20

6.0 PARTICIPATION BY AFFECTED SYSTEMS ............................................................................ 217.0 APPENDIX 1: PROPERTY REQUIREMENTS ............................................................................ 22


Q0292 Page 1 October 28, 2011

1.0 DESCRIPTION OF THE GENERATING FACILITY (“Interconnection Customer”) has proposed replacing their existing six interconnected generators at the facility (“Project”), with two new units rated 21 MW each and adding a second step up transformer to 69kV rated for 40 MVA, leaving the existing 20 MVA rated transformer as an alternate normally open interconnection path to PacifiCorp’s (“Transmission Provider”) existing 69kV transmission line located in Douglas County, Oregon. The proposed generation facility will consists of two (2) Hyundai Ideal synchronous generators and will have a maximum combined generating capacity of 42 MW. The Interconnection Customer has agreed to contractually and physically limit the power exchange at the point of interconnection to 35 MW export and 20 MW import. The proposed commercial operation date of the project is 6/1/2012 Transmission Provider has assigned the Project Queue “Q0292.”

2.0 SCOPE OF THE STUDY The interconnection system impact study shall evaluate the impact of the proposed interconnection on the reliability of the transmission system. The interconnection system impact study will consider Base Case as well as all generating facilities (and with respect to (iii) below, any identified network upgrades associated with such higher queued interconnection) that, on the date the interconnection system impact study is commenced:

(i) are directly interconnected to the transmission system; (ii) are interconnected to Affected Systems and may have an impact on the interconnection

request; (iii) have a pending higher queued interconnection request to interconnect to the

transmission system; and (iv) have no Queue Position but have executed an LGIA or requested that an unexecuted

LGIA be filed with FERC. The interconnection system impact study will consist of a short circuit analysis, and a power flow analysis. The interconnection system impact study will state the assumptions upon which it is based; state the results of the analyses; and provide the requirements or potential impediments to providing the requested interconnection service, including preliminary indication of the cost and length of time that would be necessary to correct any problems identified in those analyses and implement the interconnection. The interconnection system impact study will provide a list of facilities that are required as a result of the Interconnection Request and a non-binding good faith estimate of the cost responsibility and a non-binding good faith estimated time to construct.



3.0 TYPE OF INTERCONNECTION SERVICE The Interconnection Customer has selected Network Resource (NR) interconnection service, but has also elected to have the interconnection studied as an Energy Resource (ER). The Interconnection Customer will select NR or ER prior to the facilities study.

4.0 DESCRIPTION OF PROPOSED INTERCONNECTION The Interconnection Customer presently owns and operates facility with six generators imbedded in the plant electrical infrastructure, and has an existing interconnection with the Transmission Provider through the Interconnection Customer’s substation. The Interconnection Customer presently purchases and sells power through the existing 69kV point of interconnection. The proposed project will significantly alter the existing interconnection and replace the existing 4.16 and 12.47kV generators with new 13.8kV units operating in a new configuration. The Interconnection Customer proposes to upgrade the existing Interconnection Customer substation by replacing an idle transformer with a new 13.8kV delta to 69kV wye connected transformer rated 40 MVA, reserving the existing 20 MVA 12.47kV impedance grounded wye to 69kV delta load tap changing transformer as an alternate interconnection path. A new power house and boiler will house two 21 MW rated generators connected to the new 13.8kV bus, and a new 13.8kV delta to 12.47kV impedance grounded wye 40 MVA rated transformer and 12.47kV wye connected regulator will supply the facility load. An additional 12.47kV to 4.16kV transformer rated 14 MVA will be added to offset the loss of 4.16kV generation. The point of interconnection with the Transmission Provider’s 69kV line is to remain at the existing customer substation but, the wood pole metering structure will be replaced with a small breaker station owned and operated by the Transmission Provider. The Transmission Provider will require the Interconnection Customer to provide land to this new breaker station. The Transmission Provider’s property requirements are listed on the last two pages of this report. This substation will include total interchange metering, relay protection for the transmission line and transmission ground fault detection equipment made necessary by the delta high side winding on the existing transformer, to be retained as an alternate path. The Interconnection Customer’s substation will be modified for the reconnection of the second transformer and an appropriate interface designed between the two adjacent substations. The Interconnection Customer will be responsible for equipment protecting their transformers, and all internal plant protection and controls. Based on discussions with the Transmission Provider, the Interconnection Customer has agreed to contractually and physically limit the exchange of power through the point of interconnection to 35 MW export and 20 MW import, due to previously identified capacity limitations in the Transmission Provider’s system.



The Interconnection Customer’s facility is normally supplied through the Transmission Provider’s Roberts Creek 115kV to 69kV substation from the Dixonville transmission substation. An alternate supply will be available through the Transmission Provider’s Riddle substation, from the Nickel Mountain transmission substation. The Riddle substation is presently undergoing reconstruction which will add a 115kV to 69kV transformer with voltage regulation. This alternate interconnection path will have capacity restrictions on power flow into the Interconnection Customer’s plant.

4.1 Other Options Considered (NERC Requirement) The Project could interconnect at 115kV which would entail upgrading the existing transmission system between the Q0292 Project and the Dixonville substation. This option would be considerably more costly than the option studied in this report.

5.0 STUDY ASSUMPTIONS • All active higher priority transmission service and/or generator interconnection requests

will be considered in this study and are listed in feasibility Report submitted for this Project. If any of these requests are withdrawn, the Transmission Provider reserves the right to restudy this request, and the results and conclusions could significantly change.

• The Interconnection Customer’s request for energy or network resource interconnection

service in and of itself does not convey transmission service. Only a network customer can make a request to designate a generating resource as a network resource. Since the queue of higher priority transmission service requests may be different when and if a network customer’s requests network resource designation for this generation facility, the available capacity or transmission modifications, if any, necessary to provide network resource interconnection service may be significantly different. Therefore, the Interconnection Customer should regard the results of this study as informational rather than final.

• Tripping of the interconnection breaker may be required for certain outages. It is

assumed that the plant will continue to operate, separated from the Transmission Provider’s system, rather than tripping the individual generator units.

• All facilities will meet or exceed the minimum WECC, NERC, and the Transmission Provider’s performance and design standards.

• Loads used for the study are generally based on the plant loads furnished with the original study, with an estimated adjustment for adding boiler 7 and shutting down boiler 6. The Powerhouse load on Bus 100 was reduced by 1.19 MW. The assumed load for Boiler 7 of 1.25 MW is placed on Bus 300 as per the provided one line diagrams. The total plant load is assumed to be about 30 MW.



• The new generators are assumed to have an output of 21 MW each with a reactive capability of +10.2 (supplying) / -2.1 (absorbing) MVAr, and operate at 13.8kV nominal, based on the provided generator data. The generators will be operated in simple voltage control mode regulating to a set voltage under all conditions.

• Partly because of the 30 degree phase shift designed into the interconnection customer’s plant, both of the transformers at the point of interconnection will not be in-service at the same time. The interconnection customer states that transformer T-2 will be de-energized during normal plant operation. In the event transformer T-1 is to be taken out of service, the interconnection customer will disconnect from the transmission providers system, and then reconnect through transformer T-2.

• The maximum power exchange at the point of interconnection, from the Interconnection Customer’s plant toward the transmission provider’s system will be limited to 35 MW, regardless of the actual generator output. While delivering power into the transmission provider’s system, the power factor at the point of interconnection will remain within +/- 95%. The power exchange from the Transmission Provider’s system toward the Interconnection Customers plant will continue to be contractually limited to 20 MVA with a maximum reactive demand of 8 MVAr, pending study results.

• In the event of a trip of all generating units in service, the interconnection customer’s plant will have in place relaying to automatically trip enough load to remain within the 20 MVA interchange limitation.

• The alternate step up transformer’s load tap changer (LTC) will continue to be manually operated so as to maintain approximately 12.47kV nominal voltage on the low side. The existing transformer is on the 63.4kV no load tap.

• The study is based on a maximum delivery of 35 MW into the Transmission Provider’s

system at the 69kV point of interconnection. Internal generation is expected to exceed this value, but the contractual limitation is for the point of interconnection. This is assumed to be addressed in the contractual language included in the final agreements.

• In addition to synchronization equipment at the generators, it is assumed that synchronization between the Interconnection Customer’s internal plant and the Transmission Provider’s system, following a separation event, will occur at the Interconnection Customer’s 69kV breaker, and will be the responsibility of the Interconnection Customer.

• The interconnection will be designed to withstand trip of a single generating unit without requiring load shedding within the interconnection customer’s plant.



• This study is based on the normal feed for the plant via the Roberts Creek substation. System upgrades, if any, will be required only for the normal feed. The alternate feed through the Riddle substation will also be evaluated for the final system configuration with the Transmission Provider’s Line 37 conversion project fully completed. Operational restrictions will be identified for this alternative, but no system upgrades beyond the protection system requirements will be recommended as part of this study.

• Based on real world operating experience, the Interconnection Customer’s facility is

expected to be adequately damped and a stability analysis while connected with the Transmission Provider’s system is not required. There is no fault ride through requirement for this interconnected facility.

• An internal stability analysis for the situation of a sudden separation of the

Interconnection Customer’s internal plant with the Transmission Provider’s system will not be performed as part of this study. The Interconnection Customer is encouraged to independently perform such a study as this transition may introduce considerable internal plant operational complications that need to be addressed.

5.1 Energy Resource (ER) Interconnection Service Energy resource interconnection service allows the interconnection customer to connect its generating facility to the Transmission Provider’s transmission system and to be eligible to deliver electric output using firm or non-firm transmission capacity on an as available basis. Consistent with Section 38.2.2.2 of the Transmission Provider’s Open Access Transmission Tariff, the facility will be studied such that deliverability will be determined to the Transmission Provider’s aggregate network loads assuming some portion of existing network resources are displaced by the output of the Interconnection Customer’s large generating facility. Energy resource interconnection service in and of itself does not convey transmission service.



5.1.1 Study Results The Interconnection Customer’s project required analysis not only of the system impacts due to the generation change, but also, by necessity, included analysis of the internal impacts resulting from the electrical reconfiguration of the plant, and impacts resulting from supplying the 20 to 30 MW of plant load in the context of the generation change. The analysis also included a battery of study cases representing various load level combinations on both the Transmission Provider’s and Interconnection Customer’s systems and the overall system impacts resulting from sudden and unexpected loss of a generating unit or separation of the entire Interconnection Customer’s plant from the Transmission Provider’s system. All cases used for the study include a simplified model of the Interconnection Customer’s internal plant in addition to the new generation configuration. Cases were also ran to assess the interconnected system capabilities with both the planned new interconnection transformer and the existing interconnection transformer. In all, over 40 scenarios were analyzed. Additional cases were analyzed to assess the effectiveness of various proposed solutions to the identified problems.

The Transmission Provider’s system was found to be adequate to support the proposed 35 MW of generation delivered at the point of interconnection without system upgrades outside the protection, metering and communications items necessary for the revised interconnection. The Interconnection Customer’s facility will require modifications in the form of adding enough shunt capacitors throughout the plant to bring the plant power factor to near unity at the point of interconnection with no generation on line to avoid a voltage collapse condition following a generator trip event. It was also found that with this modification, the Interconnection Customers project can operate at full load with both generators on line when connected to the alternate Riddle/Nickel Mountain source and can operate with restricted load and generation when connected through the alternate (existing) interconnection transformer. Special restrictions and operating details for these alternatives are discussed below.

Summary of Study Results

The interconnected system was initially studied to verify the steady state performance of the newly developed power flow model, and to analyze the system integrity following the removal of the 4.16kV and 12.47kV connected generators. Several correctable problems were found with the proposed equipment and configuration. It was observed that removing the support of the generation on the 4kV portion of the plant would result in low 4kV system voltages. For study purposes, the regulated voltage for the 12.47kV bus was raised to 1.045 PU, and BUS 10 was transferred from transformer T-X to transformer XFMR 1. These corrections allowed for acceptable system voltages during steady state operation. The generators were found to operate best with the terminal voltage regulated to about 1.012 PU on a 13.8kV base. The 69kV to 13.8kV 601 T-1 transformer was found to operate well on a no load tap of 69kV.

Steady State Analysis and Recommend Changes



Analysis Discussion Following the base model analysis, a series of cases were created to represent the Transmission Provider’s system operating at heavy summer, heavy winter, and light load conditions. Scenarios were set up to represent the Interconnection Customer’s system under full 30 MW plant load, 20 MW plant load, and an assumed 6 MW minimum plant load to simulate delivery of 35 MW at the point of interconnection. Plant load reductions were achieved by switching off select loads at both the 4kV and 12kV levels, leaving the boiler and generator auxiliary loads fully operational. Then a series of plant states and trip events were simulated for each system load condition for the normal Roberts Creek/Dixonville source, and for the alternate Riddle/Nickel Mountain source. Simulations were also ran for use of the alternate interconnection transformer connected through the normal Roberts Creek/Dixonville source. Multiple system contingencies were not studied. The study simulations quickly revealed that the proposed 13.8kV generators do not have adequate reactive capability to maintain voltage with the plant at full load of about 30 MW and only one generator in operation. With both generators in operation, and the plant at full load, trip of the first generator resulted in a plant wide voltage collapse condition. Further study verified prior findings that the point of interconnection voltage is very sensitive to reactive power flow. This makes control of the voltage relatively easy through reactive power control, but can result in wide voltage excursions during system state transitions. With the present operating power factor of the Interconnection Customers plant, it is not possible to operate the plant with no generation on line, even with the load reduced to 20 MW and a 5.4 MVAr capacitor added at the 13.8kV bus. The reactive demand of the facility exceeds the capability of the Transmission Provider’s system to support the transmission system voltage to an acceptable level. After considerable trial and error, it was found that reactive support distributed throughout the plant to improve load power factor provides adequate support allowing the generators to operate near unity power factor, and for the system to survive the trip of a generator without adverse voltage impacts. With this reactive support added, a single generating unit trip does not result in adverse voltage impacts to the Transmission Provider’s or the Interconnection Customer’s systems, and steady state conditions with one generator in service are satisfactory. Under steady state conditions and with the added reactive support, the Interconnection Customer’s plant operates satisfactorily with one generator in operation and the plant load at a full 30 MW. However, loss of the remaining generator results in an instantaneous overload and under voltage condition on the Transmission Provider’s system, and voltage collapse internal to the Interconnection Customer’s plant. The proposed remedial action scheme to shed load could avoid the problem, but it must act instantaneously to avoid other complications.



Instead of relying solely on the remedial action scheme to avoid equipment damage, it is recommended (not required) that the plant loads be manually reduced to below the 20 MVA limit after a generator trip, or at any time that only one generator is in service. Distributed Reactive Support - Recommended Solution The Interconnection Customer’s plant operates at a rather low power factor which, adversely impacts the interconnected system. This must be corrected to make the interconnected system function acceptably. The recommendation is to install distributed shunt capacitors throughout the plant to achieve a near unity power factor at the point of interconnection with no generation on-line. Results of a trial and error placement of shunt capacitors found that a combination of 5.4 MVAr on the 13.8kV 700 or 601 bus, 5.4 MVAr on the 12.47kV 300 bus, 3.6 MVAr on the 4.16kV 400 bus, and 1.2 MVAr on the 4.16kV 200 bus worked best. It should be noted that placing distributed shunt capacitors in a plant with harmonic sources like variable speed drives can result in harmonic resonance conditions and that careful harmonic analysis and filtering may be needed to comply with this requirement. The location and placement of capacitors recommended in this study is only a recommendation based on the simplified model of the Interconnection customer’s plant. Further analysis by the Interconnection Customer may indicate a better reactive support allocation among the plant busses. Alternative Reactive Support at 13.8kV Only The Interconnection Customer’s application included installing a 5.4 MVAr capacitor on the 13.8kV bus. Upon detailed simulation, it was found that this device is required, but not adequate to mitigate excessive voltage excursions for a variety of simulated states and transitions. As one possible solution, increasing the size of this capacitor was studied. It was found that a 21.6 MVAr four stage 13.8kV capacitor could be made to work for nearly all situations. Controlling and selecting the number of stages to be on for a given operating state was found to be difficult with little correlation to the present operating state. The capacitor staging would need to be based on anticipated state transitions; hence this alternative is not being recommended. Alternative Generators As an alternative to distributed reactive support, a test was ran to determine if selecting a different generator with a wider and more typical reactive capability range of 80% lagging and 95% leading would reduce or eliminate the capacitor requirement. It was found that under the summer heavy loading condition with the Interconnection Customer’s plant operating at 30 MW load and both 21 MW generators on-line, the trip of one unit results in a tolerable voltage dip on the Transmission Provider’s system but, likely unacceptable voltages within the Interconnection Customers plant. A single generator was found to lack adequate VAR capability to support internal plant voltages without additional reactive support.



Interconnecting Through the Existing Transformer The Interconnection Customer requested that use of the existing interconnection transformer be studied as a backup to the proposed new transformer. It should be noted that there is a 30 degree phase shift between the Interconnection Customer’s plant and the Transmission Provider’s system, between the two transformers due to differences in winding configuration. This would require that the systems first be separated and then resynchronized through the other transformer when making a transition. Another limitation is that the power exchange in either direction at the point of interconnection cannot exceed the 20 MVA rated capacity of the interconnection transformer. The Interconnection Customer’s plant was found to be operable under steady state conditions while using the existing 20 MVA rated interconnection transformer, with the total generation limited to 39 MW and the plant load up to full operation. However, the voltages within the facility are very unstable partly due to having the generator voltage as a reference, using the automatic voltage regulation between the 13.8kV and 12.47kV busses then, finally interconnecting to the Transmission Provider’s system through a transformer with a manually controlled load tap changer. It is highly recommended that the plant load be restricted to less than 20 MVA while using this configuration especially if only one generator is on line. There is also a high risk of excessive voltage excursions, up to 30% high or low within the plant following a sudden change in generation output or load and the overall system voltage is excessively sensitive to reactive power flow at the point of interconnection. When operating through the alternate transformer, careful management of the plant power factor and the load tap changer position on the interconnection transformer is critical, regardless of whether or not any generation is active. The Interconnection Customer must accept responsibility for regulating the Transmission Provider’s transmission voltage at the point of interconnection when operating in this configuration. It was also found that with the recommended reactive support solution implemented and while operating through the alternate transformer, up to 20 MVA of plant load can be served with the 13.8kV portion of the facility de-energized. Alternate Supply Through the Riddle / Nickel Mountain Source The Transmission Provider is currently rebuilding its Riddle substation which will then provide an alternate transmission path from the Interconnection Customer’s project to Nickel Mountain substation instead of Dixonville substation. This will allow the Transmission Provider to perform maintenance on the lines and substation equipment between the Interconnection Customer’s project and Dixonville substation without fully curtailing the Interconnection Customer. This alternate path was studied for the related operating restrictions it may place on the Interconnection Customer. No system upgrades are proposed for this path as part of this study.



Results of the study indicate that when the Interconnection Customer’s plant is supplied from the alternate Riddle / Nickel Mountain source, the plant can operate at a full 30 MW load with both generators at full output with the recommended reactive support installed. Trip of one generating unit does not result in adverse system impacts. However, it was found that even with the plant load reduced to 20 MVA as proposed for the remedial action scheme, trip of the second generator would result in unacceptable line loading and under voltage conditions. When supplied from the Riddle source with only one generator operating, the plant load needs to be reduced to about 13 MW and the plant load internal power factor managed to approximately unity to survive an unexpected trip of the remaining generator. With these restrictions met, no adverse line loading or unacceptable post transient voltages occur. Plant load can be operated at about 13 MW with near unity power factor when no generation available and the plant is supplied from the Riddle / Nickel Mountain source. The primary limiting element is the transmission conductor between Myrtle Creek and Riddle substations. Recommended Equipment Settings Selection of equipment settings internal to the Interconnection Customer’s facility are the responsibility of the customer. However, this study required some trial and error analysis to develop tap positions and regulated voltage settings for select major equipment in order to model a realistic interconnected system. The following settings are those developed for the model and are shared as a courtesy, not as a requirement.

• Transformer 601 T-1 was set to a ratio of 69kV to 13.8kV.

• Transformer T3 was set to a ratio of 13.8kV to 12.47kV with a regulation range of +/- 10%.

• Transformer XFMR1 was presented as having a high side nominal voltage of 13.2kV,

and was set in the model at a ratio of 12.54kV to 4.16kV.

• The 13.8kV 21 MW generators were found to operate best throughout the range of generation and load conditions when set to regulate to 1.012 PU at the generator terminals. A modern solid state voltage control is required, and assumed for the model.

• The regulator associated with transformer T3 was found to operate best with a band

center set to regulate to 1.045 PU on the 12.47kV bus. This was set above nominal to compensate for loss of the generation support on the 4.16kV portion of the plant.



WECC Requirements The plant has a total capacity less than 75 MW and all units are smaller than 30 MW thus, there is no requirement for power system stabilizer equipment. The new 21 MW generators are large enough to be required to operate in automatic voltage control mode.

5.1.2 Requirements

5.1.2.1 Generating Facility Modifications The Interconnection Customer is required to operate its generating facility in voltage control mode. Power factor at the point of interconnection is to be maintained within a +/- 95% range, based on peak real power flow, for each direction. Ideally, the facility should be operated to manage near unity power factor at the point of interconnection for all flow conditions to minimize transmission voltage variation resulting from state transitions. The Interconnection Customer needs to design and implement an automatic and instantaneous load shedding remedial action scheme to reduce the total plant load to 20 MVA (at near unity power factor) in the event the second generator trips off line. With this scheme, the plant can be allowed to operate at a full 30 MW level with a single generator on line. The Interconnection Customer is required to add a 5.4 MVAr switched capacitor to the 13.8kV generator bus (or at Interconnection Customer substation). Additionally, the customer is to add distributed capacitors throughout the plant to bring the power factor at the point of interconnection to within 3 MVAr of unity, with no generation on line, and for all plant load levels. Based on high level modeling, a combination of 1.2 MVAr on the 200 Bus, 5.4 MVAr on the 300 Bus 3.6 MVAr on the 400 Bus appears to work best. Care must be taken to avoid possible harmonic resonance problems when adding the distributed capacitors. A means of preventing both the 601 T1 and 601 T2 transformers from being operated in parallel should be implemented. This is because of a 30 degree phase difference due to the plant winding configurations. Synchronization checks and operating procedures will need to be in place for interconnection through each transformer. The Interconnection Customer has requested that the breaker at the point of interconnection be tripped for events on the Transmission Provider’s system. This will leave the Interconnection Customer’s generation and plant islanded with a probable mismatch between the generation and the load. The Interconnection Customer’s plant controls will need to be designed and configured to handle this transition from parallel operation with the Transmission Provider’s grid to an islanded operation with local frequency control. An internal plant transient stability study is encouraged as part of this control design. While the Interconnection Customer is operating their facility interconnected through the alternate 601 T2 transformer, the maximum power exchange at the point of interconnection must



be limited to 20 MVA. Additionally, the Interconnection Customer must accept responsibility for managing the Transmission Providers transmission voltage within a .95 to 1.05 PU level (based on 69kV nominal) through reactive power exchange management. This will avoid a requirement to install a static VAR compensator or similar device on the Transmission provider’s system. When the Interconnection Customer’s facility is connected to the alternate Riddle / Nickel Mountain Source and operating on less than two generators, the total plant load needs to be reduced to 13 MW or less to avoid damage to the Transmission Provider’s system and other customers in the event of a generator trip. The Interconnection Customer will be required to provide independent protective equipment for their main transformers, and internal lines. The Transmission Provider’s breaker is intended for fault protection of the transmission system only.

5.1.2.2 Transmission Modifications Construction of a new 69kV breaker station to be owned and operated by the Transmission Provider and to be located adjacent to the Interconnection Customer’s main substation will be required. This substation will require land provided to the Transmission Provider, and will include a 69kV 1200 Amp breaker, with disconnect switches, total interchange metering, transmission ground fault detection equipment, protective relaying for the transmission line, a control house, and communications equipment connecting to the Transmission Provider’s Portland Control Center.



M R

Change of Owership

69kV

12.47kV

Q0292Sub

Riddle Sub

R

NO

Point of Interconnection

601501

504

6

14 1

13

305109

16

401

402 403

502

4.16kV23.333MVA

Roberts Creek Sub

3U66

NO

MyrtleCreek

23.333MVA

NormallyOpen

NormallyOpen

13.8kV

12108

2.54 Miles

2.31 Miles

1.31 Miles

6.0 Miles

5.82 Miles

Figure 1: System one line diagram



5.1.2.3 Existing Circuit Breaker Upgrades – Short Circuit The increase in the fault duty on the system as a result of the addition of the generation facility with two 23.333MVA generators fed though a 24/40 MVA step up transformer with 9.0% impedance will not push the fault duty above the interrupting rate of any of the existing fault interrupting equipment.

5.1.2.4 Protection Requirements Figure 1 illustrates the interconnection of the proposed generation expansion at the Interconnection Customer’s facility. The normal operating configuration for the interconnection will be to over the 69kV line out of Roberts Creek substation through breaker 3U66. A possible alternate feed will be out of Riddle substation via Nickel Mountain substation. The generation facility needs to disconnect from the 69kV system any time that the source breaker at Roberts Creek or Riddle substation opens. Protective relays will need to be installed at the point of interconnection substation to detect faults on the 69kV system. When a fault occurs on the 69kV transmission system, the generators will need to be disconnected from the transmission system in less than 1 second so that the 69kV breaker at the Roberts Creek substation can automatically reclose to reenergize the line. Most faults are not permanent. The fast interruption of the fault and the re-energization of the system will restore service to the connected load. In the event of a 69kV line fault the point of interconnection breaker will be tripped leaving the Interconnection Customer’s generation and load isolated together from the transmission system. The normal configuration at the Interconnection Customer’s substation is to connect to the Transmission Provider’s point of interconnection through a transformer with the 69kV side winding connected in a wye with the neutral grounded and the 13.8kV side connected in a delta. This transformer configuration provides a ground reference to the 69kV side which makes it possible to detect 69kV phase to ground faults using neutral overcurrent relay elements. The alternate feed is through a delta – wye transformer, with the delta on the 69kV side. The alternate configuration is not a ground reference to the 69kV system which creates a couple issues. To selectively detect phase to ground faults, which are the most common fault on the 69kV line, the generation facility should be source of zero sequence current as well as positive sequence current. The alternate feed does not provide a zero sequence source to the 69kV so the line relays at the point of interconnection are limited to using unbalance voltage to detect phase to ground faults. The problem with this arrangement is that the relays at the point of interconnection cannot distinguish the difference between a fault on the Line 37 or and a fault on the other 69kV line out of Roberts Creek Sub. The line relays system to be installed in the point of interconnection will have multiple relay setting groups. One setting group will be configured for the normal feed and another setting group will be configured for the alternative feed.



The major difference will be the functions that are enabled for detecting phase to ground faults. This will provide the most selectivity on the detection of phase to ground faults. The changing of the inservice relay setting group can be accomplished by changing the position of a control switch and this can be configured to be operated either locally or remotely from the Transmission Provider’s control center. The tie line between the new point of interconnection and the Interconnection Customer’s substation will be protected with a differential relay system. The Interconnection Customer’s two 69kV transformers will be located in the same substation yard which will be adjacent to the point of interconnection. A low impedance current differential relay system will be applied to detect faults on this bus. This system will be able to use the same current transformers (CTs) on the existing power transformer overcurent relays are using. The bus differential relay will trip the Interconnection Customer’s transformer circuit breakers as well as the circuit breaker in the point of interconnection. The protective relaying systems for the 69 - 12.5kV and 69 – 13.8kV transformers will be the responsibility of the Interconnection Customer. The protection for the transformer needs to detect and clear faults in the transformer in eight cycles or less. In addition to the line protective relaying, a relay used for under/over voltage and over/under frequency protection of the system will be installed at the point of interconnection. If the voltage, magnitude or frequency, is outside of the normal operation range this relay will trip open the tie breaker.

5.1.2.5 Data (RTU) Requirements The installation of a Remote Terminal Unit (RTU) is required at the Transmission Provider’s point of interconnection for the control of that substation. Data will be required from the Interconnection Customer’s generation facility for the Transmission Provider’s operation of the Transmission Provider’s transmission system. The data from the RTU will be communicated back to Transmission Provider’s control center. The data from the Interconnection Customer’s facility will be fed into the RTU via a data port on the RTU through a digital communication link between the Interconnection Customers control system and the RTU. This data stream will need to be configured in the DNP-3.0 protocol.



In addition to the control and indication of the 69kV breaker in the point of interconnection the following data from the point of interconnection and the Interconnection Customer’s substations will be needed: From the point of interconnection substation: Analogs: Net Generation MW Net Generator MVAr 69kV A Phase Voltage 69kV B Phase Voltage 69kV C Phase Voltage Accumulator Pulses: Interchange metering kWH From the Interconnection Customer’s substation: Analogs: Generator unit 1 Real Power Generator unit 1 Reactive Power Generator unit 2 Real Power Generator unit 2 Reactive Power Status: CB 1 CB 14 CB 12 CB 13 CB 601 CB 501



5.1.2.6 Communication Requirements Interconnect Customer will request a T1 lease to be installed between the point of interconnection substation and the Transmission Provider’s Dixonville 230kV substation. At the point of interconnection substation, Transmission Provider will install a small multiplexer to drop out the SCADA and alternate meter circuits. A Ground Potential Rise calculation will be required for the telco to evaluate the routing of the T1 into the point of interconnection substation and the need for protection equipment. At the Dixonville 230kV substation, the T1 will be routed into a Digital Cross-Connect System that will send the circuits to the Portland and Salt Lake Control Center EMS systems. The Transmission Provider will install a dial-up off of the Roseburg Service Center VoIP switch to the point of interconnection for MV-90 access and voice. The Transmission Provider will install a line sharing switch at the point of interconnection substation to terminate the dial-up circuit.

5.1.2.7 Substation Requirements: Install a 69kV circuit breaker, metering unit and associated disconnect switches that allow for the connection of the Q0292 project to the Transmission Provider’s 69kV transmission line 37-1. Since the substation will be build adjacent to the project, the Transmission Provider’s and the Interconnection Customer’s facility’s ground mat are to be tied together. The Transmission Provider’s portion of the yard is to be included in the client’s fenced in area and is to contain gate(s) that are accessible by the Transmission Provider’s personnel and their vehicles. The major equipment identified is as follows: 1 – 72kV 1200A breaker 2 – 69kV, 1200Amp, TPST, vertical break, manually operated switch 3 – 48kV, MCOV dual rated surge arresters 1 – 12.5kV Station service transformer (kVA rating to be determined during design process) 1 – 69kV Voltage transformer 3 – 69kV Voltage metering units 1 – 125Volt, 100AH Battery system with zone 4 seismic rack 1 – 130Volt D/C, 12A LaMarche battery charger 1 – 13’ x 23’ Transmission Provider standard Trachte control building



5.1.2.8 Metering Requirements Point of interconnection metering: A revenue metering package will be installed at the Transmission Providers point of interconnect substation. Two revenue grade meters (primary and back-up) will be installed in a standard 12” panel to measure bi-directional quantities. The primary meter will be used for SCADA, which will include: bi-directional MWH and MVARH quantities, MW, MVAr, and per phase volts and amps. The back-up meter will be used to provide real-time data to the alternate control center. Both meters will be capable of being accessed by the Transmission Providers MV-90 data acquisition system. A dial up phone line will be required to access both meters to download billing data. The metering instrument transformers shall be extended range CT/VT combination unit that is 0.15% accuracy class. These units must be rated at 115kV. Expect up to 45 weeks lead time for the instrument transformers. The Transmission Provider strongly recommends the Interconnection Customer install meter by-pass switches to reduce operational disruption. If customer elects not to install metering bypass switches, the customer’s generator will need to be taken off line for metering testing, repair and service. Generator Meters: At the Interconnection Customers power house, two new revenue meters will need to be installed for each of the two generators. Each of the primary generator meters will provide real-time MW and MVAr quantities to the RTU, as well as accumulated KWH values. Each of the backup generator meters will provide real-time data to the alternate control center. If required, new revenue meters will be installed for any station service and/or parasitic loads. If revenue quality CT and PT do not exist for either of the generators, new CTs and PTs will need to be installed. Dial up phone lines or cell phones are required to access all four meters on both generators.



5.1.3 Cost Estimate Interconnection – Direct Assignment Facilities Q0292 Interconnection Customer substation – Engineering, procurement and installation of communication and metering equipment.

$170,000

Q0292 Point of interconnection substation – Engineering, procurement and installation of a 69kV 1200 Amp breaker with disconnect switches, transmission ground fault detection equipment, protective relaying for the transmission line and a control house.

$2,200,000

Sub-total Direct Assignment Costs $2,370,000 Interconnection – Network Upgrade Costs Dixonville 230kV substation, Medford Service Center, Portland Control Center and Salt Lake Control Center – Engineering and installation of communication upgrades.

$30,000

Sub-total Network Upgrade Costs $30,000 Total Cost – ER Interconnection Service – Interconnection Only $2,400,000

5.1.4 Schedule It will take approximately 18 months from the execution of a large generator interconnection request to engineer, procure, and construct the facilities necessary to interconnect the proposed Project.

5.1.5 Maximum Amount of Power that can be delivered into Network Load, with No Transmission Modifications (for informational purposes only)

The Transmission Provider’s local network loads can consume up to 35 MW of output for all loading conditions. When combined with other existing local area generation, during spring run-off conditions, the locally generated power will exceed the local network loads but can be delivered to network loads in adjacent areas via the Transmission Provider’s grid without upgrades.

5.1.6 Additional Transmission Modifications Required to Deliver 100% of the Power into Network Load (for informational purposes only)

To deliver 100% of the generator output to network loads with equivalent functionality, without the offsetting load at the Interconnection Customer’s facility, would require conversion of the Transmission Provider’s 69kV transmission system in the area to 115kV. This would require a rebuild of approximately 22 miles of transmission line, rebuild of two distribution substation, and 115kV line terminations at two additional substations.



5.2 Network Resource (NR) Interconnection Service Network Resource interconnection service allows the Interconnection Customer to integrate its large generating facility with the Transmission Provider’s transmission system in a manner comparable to that in which the Transmission Provider integrates its generating facilities to serve native load customers. The transmission system is studied under a variety of severely stressed conditions in order to determine the transmission modifications. If any, which are necessary in order to deliver the aggregate generation in the area of the point of interconnection to the Transmission Provider’s aggregate load, and assumes that some portion of existing network resources are displaced by the output of the Interconnection Customer’s large generating facility. Network resource interconnection service in and of itself does not convey transmission service.

5.2.1 Study Results The related capacity restrictions on the Transmission Provider’s system are in the general vicinity of the Interconnection Customer’s project. No restrictions were identified that would require system upgrades to accommodate network resource interconnection service. Consequently, the study results that apply to interconnection as an energy resource are the same for a network resource, as described above.

5.2.2 NR Requirements

• Rebuild Line 37, 37-1, 37-3 and 37-4 to 115kV, replacing all conductor smaller than 4/0 ACSR with 795 ACSR.

• Add a 115kV ring bus at the Roberts Creek substation. • Remove the 115kV to 69kV transformer and 69kV line position at the Riddle substation

and install a 115kV breaker and line position. • Rebuild the Winston and the Myrtle Creek substations to 115kV high side. • Rebuild the Interconnection Customer’s substation to 115kV.

5.2.2.1 NR Cost Estimate Interconnection – ER Only $2,400,000 NR Interconnection $26,000,000 Total Cost – NR Interconnection Service – Interconnection Only $28,400,000

5.2.3 Schedule It will take approximately 60 months from the execution of a large generator interconnection request to engineer, procure, and construct the facilities necessary to interconnect the proposed Project.



6.0 PARTICIPATION BY AFFECTED SYSTEMS Transmission Provider has identified the following affected systems: None



7.0 APPENDIX 1: PROPERTY REQUIREMENTS Property Requirements for Point of Interconnection Substation The following applies to property acquired by an Interconnection Customer on which a point of interconnection substation will be built to accommodate the Interconnection Customer’s project. The property will ultimately be assigned to PacifiCorp, the Transmission Provider.

• Property must be environmentally, physically and operationally acceptable to the Transmission Provider without any material defects of title (or as deemed acceptable to the Transmission Provider) and without unacceptable encumbrances. The property shall be a permitted or permittable use in all zoning districts. Property lines shall be surveyed and show all encumbrances, roads (private or public); easements (prescriptive or express) etc.

Examples of potentially unacceptable environmental, physical, or operational conditions:

Environmentally unacceptable conditions could include but are not limited to known contamination of site; evidence of environmental contamination by any dangerous, hazardous or toxic materials as defined by any governmental agency; property is in violation of building, health, safety, environmental, fire, land use, zoning or other such regulation, ordinances, or statues of any governmental entities having jurisdiction over the property; underground or above ground storage tanks; known remediation sites on property; ongoing mitigation activities or monitoring activities; asbestos; lead-based paint, etc. At a minimum, a phase I environmental study is required for company land being acquired in fee. Evidence will be required prior to execution of the interconnection agreement.

• Physically unacceptable conditions could include but are not limited to inadequate drainage; in flood zone; erosion issues; wetland overlays; threatened and endangered species; archeological or culturally sensitive areas; inadequate sub-surface elements, etc. Geotechnical studies are required by company.

Operationally unacceptable conditions could include but are not limited to inadequate access for company equipment; existing structures on land that require removal prior to building of substation; ongoing maintenance for landscaping or extensive landscape requirements; ongoing homeowner's or CC&R's that are not acceptable to company.



• Property should be acquired by fee ownership. If fee acquisition is not possible, then the term shall be perpetual and the use exclusive and provide the Transmission Provider with all property rights it deems necessary (perpetual easement). All contracts are subject to the Transmission Provider’s approval prior to execution.

• The Interconnection customer is required to identify any and all land rights to the subject

property, which are to be retained by the Interconnection customer prior to conveying property. All retained land rights are subject to the Transmission Provider’s approval.

• If the Interconnection Customer is building facilities to be owned by the Transmission

Provider, then the Interconnection Customer must obtain all permits required by all relevant jurisdictions for the use including but not limited to conditional use permits, Certificates of Public Convenience and Necessity, California Environmental Quality Act, etc., as well as all construction permits for the project

• Interconnection Customer will not reimburse through network upgrades for more than the

market value of the property.

• Property must be assignable to company and without litigation, suit, liens, condemnation actions, foreclosures actions, etc.

completed for q0292 - oati · completed for . q0292 . ... substation by replacing an idle...

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