how xcel energy developed a the largest community solar

HOW XCEL ENERGY DEVELOPED THE LARGEST COMMUNITY SOLAR GARDEN PROGRAM IN THE COUNTRY

© 2020 Xcel Energy 1

Ed Shannon | Principal DER Engineer

Alan Urban | DER Engineer

November 4, 2020

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AGENDA• Introduction

• Program History

• Technical Review Process

• Screening

• DER Impact Studies

• Commissioning

© 2020 Xcel Energy

• Operational Challenges

• Non-Technical Challenges

• Non-Technical Challenges

• Where We Are

• Where are we headed next

• Questions

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INTRODUCTION

© 2020 Xcel Energy

Xcel Energy DER Integration Team (North)Chris Punt – Manager of DER Integration

John Harlander – DER Integration

Project Manager

Ed Shannon – DER Integration Engineer

Alan Urban – DER Integration Engineer

Steve Bye – DER Integration Engineer

3 full time contract employees

2 Consulting Engineering Firms


Minnesota Solar*Rewards Community®

Active applications – 362

New applications in 2020 – 330

Completed Project – 337 project for 739MW

Design and Construction – 102 project for 103 MW

In study/screen process – 197 for 194MW

72 MW have scheduled ISD in Q4


Note: Xcel Energy also has 100 MWs of gardens not part of the SRCMN program and X MW of Customer Sited DER

.https://www.xcelenergy.com/staticfiles/xe-responsive/Working%20With%20Us/Renewable%20Developers/SRCMN_Dashboard.pdf

2020 Breakout and DER applications by year


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PROGRAM HISTORY

© 2020 Xcel Energy

Key Moments in CSG History

• 2013: Xcel files petition with MN PUC under docket 13-867, per requirements of Minn. Stat. §216B.1641 as part of MN Solar Energy Standard

• 2014: Official Program launched in Dec 2014: 1 MW nameplate capacity limit; co-location allowed

No “soft launch” to program: no limitation on program wide capacity (ITC credits at risk)

Received 431 MW of applications a month into program

• 2015: Substantial changes to program rules Sun setting capacity limits on co-location

Reporting requirements

Process clarifications/CSG-specific study timelines


Initial Wave of Applications

No cap on co-location

- Up to 40MW!

- Comparable to the PPAs being discussed in our Solar RFP Dockets

- “…was intended to create opportunities for residential and small-business customers to participate in distributed solar generation…”*

- New Cap: 5 MW, reducing to 1 MW after Sept 2015


*Xcel Energy, January 13th, 2015 Docket E-002/M-13-867

Co-Located Gardens


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TECHNICAL REVIEW PROCESS

© 2020 Xcel Energy

Technical Review Strategy

Complete Application Recieved

Technical Screens

Process Track

Power Flow Study

Interconnection Agreement

Screen Eligible?

Study Eligible?

Fail

PassGoal: safety, reliability, and power quality

- Faster, simple screens for lower impact projects

- More detailed studies for complex projects


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SCREENING

© 2020 Xcel Energy

Technical Screens General philosophy: Is a power flow model needed to evaluate certain criteria?

- If not, screen it!


Pros

• Expedient • 10-20 Days, faster w/

automation• Less Costly

• Baked into application fee• Data needed is less than study

Cons

• Not precise • Requires some conservatism to

offset increased risk• Decreasing usability at higher

penetrations• Prescribing mitigations

inappropriate for larger projects

Technical Screens

2014- 2019

- No defined screening process in MN Interconnection Rules (written in 2003)

- < 1 MW DER eligible

- Failure = additional review or full study


Prior to MN Interconnection Rules UpdateNumber Description

1 Is the PV interconnected to a Secondary Network?

2 Is the Short Circuit Current Contribution Ratio (SCCCR) [2] < 10 %

3 Is the voltage variation calculation3 < 2%

4 Minimum daytime load to aggregate generation nameplate, on a line segement delineated by protective device, ratio greater than 125%?

5 Is certified equipment used for power electronics interfaces?

6 Is the PV system configuration and voltage correct?

8 Is the installation on a shared secondary service4?9 Does the installation create a transformer or conductor

overload?10 If > 25 kW, Is the PV system three-phase?11 Does PV cause any protective device to exceed 87.5% of it's

interrupting capability rating? 12 Does the PV cause reverse power flow across a voltage

regulation device?

Technical Screens

- SGIP-based process

- Defined set of screens at state level rather than utility level

- Eligibility based on size, distribution voltage, distance from substation


Updated MN Distributed Interconnection Process (2019- MN DIP)


Implementation ChallengesTechnical Screens

Planning Data

Feeder/Sub Loads

Equipment Ratings

Customer Portal

Generator Information

Customer Information

In Queue Generation

Geospatial

Conductor

Service Transformer

ExistingGeneration

Screen Results

Customer Comms

Data Aggregation

- Manual process to gather data• Inefficient (still faster than

studies)

Future Looking:

- Opportunities to connect data sources

- Integrate into automated interconnection portal

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DER IMPACT STUDIES

© 2020 Xcel Energy

Brief evolution of load-flow tools


~2014 – 2015 PSS/E & Open DSS:7.5 MW DER

~2015, SKM Power Tools: 11.5 MW DER

~2017-18, SKM Power Tools → SynerGi Electric~20.5 MW DER

~2020+, SynerGi Electric: 32.5+ MW DER

Data RequirementsDER Oneline DER Site Plan

© 2020 Xcel Energy | Image source: https://www.xcelenergy.com/working_with_us/how_to_interconnect20

Technical information regarding the DER: equipment ratings & connectivity, grounding bank calculations, primary/secondary service voltages, etc.

Locational information regarding the DER: address/GPS coordinates, cross streets, equipment layout, etc.

Data RequirementsSubstation Information

© 2020 Xcel EnergyImage Source: Burke, J. J. (2017). Power distribution engineering: Fundamentals and applications.

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Device Information Needed

Transformer Rating, impedance, no load losses, voltage ratios, etc.Voltage regulation equipment LTC setpoint, or voltage regulator settings (setpoint, bandwidth, LDC, etc.)Protective equipment Ratings, settings, bus Thevenin impedancesSubstation bus Conductor type & ratings

Usually obtained from substation drawing, transformer nameplate or test report, TR loading database and breaker/recloser settings files.

Data RequirementsFeeder Information

© 2020 Xcel Energy22

Device Information Needed

Regulators Rating, settings, setpoint, bandwidth, mode of operationCapacitor banks Rating, metered phase, PT ratios, switched vs fixed, control settingsProtective equipment Ratings, settings, locationConductor Conductor type & ratings, impedances

DER on feeder Size, power factor setting, generation type (PV, wind, bio, etc.)

Usually obtained from feeder maps, GIS, and/or volt-var management system.

Data RequirementsLoading Information


For peak loads, the substation coincident peak should be less than or equal to the non-coincident feeder peaks:

𝑆 _ 𝑆 𝑆 𝑆 ⋯ 𝑆 𝑆

• Substation transformer loading limits

• Feeder loading limits

• Historical native transformer and feeder peak loads

• Historical native transformer and feeder daytime minimum loading (DML)• DML for fixed PV units: 10 AM – 4 PM• DML for tracking PV units: 8 AM – 6 PM• ~20% of peak load is used for DML where no data exists (based on analysis)

• Ideally by-phase loading and power factor information is obtained

𝑆 _ 𝑆 𝑆 𝑆 ⋯ 𝑆 𝑆

For minimum loads, the substation coincident minimum should be less than or equal to the non-coincident feeder minimums:

Study Analysis

© 2020 Xcel Energy

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Study Scenarios Description Steady state voltage

Equipment overloads

Potential islanding

Reverse power flow

Voltage fluctuation

Power factor control

Base Case 1 Existing system without DER x x

Base Case 2 Existing DER ON, new DER OFF x x x x

Base Case 3 Existing DER ON, new DER ON x x x x x x

Case 4 Max new DER size with PF changes and/or system upgrades x x x x x x

Case 5 Max new DER size without system upgrades x x x x x x

Threshold Criteria DescriptionSteady state voltage ANSI C84.1 Range A high voltage limit

Equipment overloads Any equipment loaded beyond its normal rating

Potential islanding Downstream DML/generation ratio at any reclosing device < 120% requires VSR

Reverse power flow Reverse current on voltage regulators, LTC, or substation bus

Voltage fluctuation Individual: < 2% for LTC or voltage regulating device, < 3% anywhere else on the systemAggregate: < 5% anywhere on the system

Power Factor control Yes/No: Were power factor changes applied to existing or new DER

Each study scenario is performed under both peak loading, and daytime minimum loading

Fault contributions from the substation and DER are also studied. (SLG, 3ph, X/R positive & zero sequence values)

Study Analysis


Mitigations/solutions are proposed only for specified threshold violations and are applied only to the point of clearing the threshold violations. (Minimized DER interconnection cost)

Voltage mitigations/solutions hierarchy:

1. Power factor controls (unity – 0.95 absorbing) DER in study only, no reconductoring

2. Power factor controls (unity – 0.95 absorbing) any DER, no reconductoring

3. Power factor controls with reconductoringa. Engineering Judgment used and trial and error used to determine best mitigation

a. Reconductor largest impedance conductor between PCC and the substationb. Reconductor starting at the DER facility working back towards the substation

4. Power factor controls, reconductoring, and DER curtailment

Reverse power flow mitigations/solutions: cogen mode control for all regulators experiencing reverse flow

Equipment overload mitigations/solutions: upgrade equipment to next standard size or curtail DER if upgrade is not available

Study Analysis


Protection Feasibility Studies• Verify garden can be adequately

protected at proposed size and location

• Verify the interconnecting garden does not cause reduction of reach issues

• Determine what changes are need to accommodate the proposed DER

• No settings are issued

Protection settings and final design is done during the design and construction phase.

Challenges


Data integrity• multiple sources, SCADA, modelling issues, field verification, ahead in queue construction, equipment

assumptions (cap bank, regulators, LTC setpoints & settings)

New Processes Required• Daytime minimum load – new process for planning to pull and validate as part of the load forecasting

process

• Phase II Studies – Study required to look at TR upgrades or dedicated infrastructure

• How to spread the knowledge of all projects going on. Same feeder might have upgrades for DER interconnections, a capacity planning project, and/or a reliability project.

Consultant challenges• Newer space in the consulting world

• Training

• QA studies & re-studies

Challenges


Types of system impact studies• Sequential review (serial review of queued DER one at a time)

• Batch studies (serial review of multiple sequentially queued DER in one report)

• Cluster studies (simultaneous review of multiple sequentially queued DER)

Resource availability• Studies tend to come in waves, this can overwhelm available resources (internally & externally)

Highly penetrated feeders/substations • Inability to close-off feeders to additional DER interconnections

• Create complex studies where feeder may have as many as 25+ projects and as much as 35 MWs of generation

Extremely complex and time intensive to complete

Daytime Minimum load included in studies• Changes in DML cause systems issues in the existing gen case

This requires mitigations to be completed before current project study starts

Commissioning

All DER are required to perform a Witness Test

• Xcel Energy witnesses and records results• Site construction matches approved drawings

• Functional test of anti-islanding and open phase responses

• Verification of settings

Electrical Contractor witnesses on behalf of Xcel Energy

• 1-4 hours onsite per test

• Capacity for 6 tests per day, 4 days a week.


Operational Challenges

Despite the large amount of DER interconnected over the last 5 years, we have had relatively small number of operational issues.• High Voltage This was the most common issue experienced

Usually due to DER producing instead of consuming Vars

Regulators set to bi-directional mode instead of cogen mode

• Voltage fluctuation Inverter control loop parameters too strong

Identified by harmonic problems and inconsistent power factor

Resolved by Inverter manufacture changing control loop response time and decreasing control loop gain


Power Quality/Reliability

Operational Challenges

Feeder switching can take an entire day• Some feeders with 20+ individual sites Abnormal configuration impacts not studied: need to remove gardens

Risk during Hotline Work increases, remove to return risk to expected levels

• Some sites using only fuses 3 operations to isolate site

Now requiring reclosers at every new site

• Easy to establish clearance

• SCADA control in the future


Operating the System

Study Deadlines

Pre-MN DIP deadline was 50 days from deemed complete• 5 projects all submitted on the same feeder and applications deemed complete on the same day

all had the same due date. Caused multiple deadlines to be missed

• Required the assumption that the previous in queue DER moved forward, this caused a significant numbers of restudies as projects withdrew

• Post MN DIP deadline is 30 business days Study process needs to be near perfect to be hit the deadline

Model complication, RFIs, QA failures, complication due to queue depths have caused multiple deadlines to be missed


DER System Capacity

• One program can take up all DER capacity on sub/feeder

• Need to consider Customer options

Operational flexibility

Changing load characteristics


An Energy Policy Discussion

*Steady state voltage or rapid voltage change limits may be reached before thermal capacity

Maximum Thermal DER Capacity*

??%Contingency?

??%Reserved Capacity?

??%First Come/First Serve

Equipment Ratings Daytime Min Load

100% of CapacityFirst Come/First ServeTo

day

Future

At risk loads could create overloads!

How does non-export DER effect capacity?

State Of The Program

• In 5 years Xcel Energy has interconnected approximately 750 MWs of Community Gardens. Interconnected on only 15% of our total feeders.

• There is currently an additional 100+ MWs in design and construction.

• There is an additional 200+ MWs in the screen or study process.

• It is currently the largest SRC program in the country

• Successful!


Where Are We Headed NextHosting Capacity Analysis

• Move towards using Hosting Capacity results for some screens

More Automation of Screens

Advanced Inverter functions• Where and how to use• Standard vs Unique vs localized settings

Time Series Analysis

MISO & Transmission Studies

????• Batteries, EV, FERC 2222 ancillary markets, Benefits from ADMS implementation

Community Garden programs ramping up in other states (Colorado)


QUESTIONS


[email protected]

[email protected]

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