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The Voice of the Networks

Energy Networks Association

High Volts Working Group: Technical Feasibility Report

April 2016

PUBLISHING AND COPYRIGHT INFORMATION

First published April 2016

Amendments since publication

Issue Date Amendment

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© 2016 Energy Networks Association

All rights reserved. No part of this publication may be reproduced, stored in a retrieval system or transmitted in any form or by any means, electronic, mechanical, photocopying, recording or otherwise, without the prior written consent of Energy Networks Association. Specific enquiries concerning this document should be addressed to:

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This document has been prepared for use by members of the Energy Networks Association to take account of the conditions which apply to them. Advice should be taken from an appropriately qualified engineer on the suitability of this document for any other purpose.

ENA High Voltage Management Technical Feasibility Report Issue 1 2016

Contents

Executive Summary ............................................................................................................... 4

1 Introduction ...................................................................................................................... 7

1.1 Scope ................................................................................................................... 10

1.2 Background information ........................................................................................ 10

2 Options Analysis ............................................................................................................ 15

2.1 Short Term ............................................................................................................ 16

2.2 Medium Term ........................................................................................................ 41

2.3 Long Term ............................................................................................................ 54

2.4 Non-viable or Exhausted Options .......................................................................... 57

3 Research and Development ........................................................................................... 62

3.1 REACT ................................................................................................................. 62

3.2 ATLAS .................................................................................................................. 62

3.3 CLASS .................................................................................................................. 62

3.4 DIVIDE .................................................................................................................. 62

3.5 SEESAW .............................................................................................................. 63

3.6 Network Equilibrium .............................................................................................. 63

3.7 Additional international studies and projects ......................................................... 63

4 Conclusions ................................................................................................................... 64

5 Recommended next steps ............................................................................................. 66

6 Appendices .................................................................................................................... 68


Executive Summary

Reactive Power (VAr) is the difference between working power (active power measured in Watts) and total power consumed (apparent power measured in VA). Some electrical equipment used in industrial and commercial buildings requires an amount of reactive power in addition to ‘active power’ in order to work effectively. The reactive power generates the magnetic fields essential for inductive electrical equipment to operate – especially transformers and motors. Power Factor is the relationship between ‘active’ and ‘reactive’ power and indicates how effectively electrical power is being used.

Due to progressive changes in reactive power requirements across the system, system voltages during periods of minimum demand (load) have changed significantly, presenting planning and operational challenges for the System Operator, National Grid (Great Britain).

In an AC power system, voltage is controlled by managing the production and absorption of reactive power. This optimises real (active) power system transfers and ensures secure network operations by maintaining voltages within statutory limits. Reactive power requirements vary over time as load and generation patterns change. When lightly loaded, the system generates reactive power that must be absorbed; when heavily loaded, the system consumes reactive power that must be produced. High voltage excursions can occur when these reactive power requirements are not being fully met.

High voltage excursions have been increasing in frequency throughout Great Britain, and high voltage management has changed from being a challenge mainly in the south during summer to being a year-round national issue. For example, in 2014, a requirement for new reactor installations totalling over three Giga-Volt-Amperes Reactive (GVAr) was forecast for 2016/17, with a further 14 GVAr forecast by 2035/361.

Although these voltage excursions primarily impact the high voltage transmission system2, the issue can affect electrically distant, low voltage areas (which can be influenced by approaches across all voltage levels, both transmission and distribution) as well as regional transmission and distribution systems.

This paper provides a feasibility study of innovative solutions to address these high voltage excursions, through a suite of technical options that may be deployed across the power system. The work also identifies existing network innovation projects that have addressed, or plan to address work in this area and provides recommendations, conclusions, and suggested next steps for implementation.

The High Volts Working Group has identified a range of possible short-term (within 12 months), medium-term (12 months– five years), and long-term (longer than 5 years) technical options that may contribute towards addressing this issue3, each of which identifies:

the actions required for routine or emergency implementation

the commercial or regulatory barriers that may exist, and

—————————

1 www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/System-Operability-Framework/

2 This is due to the philosophy of voltage control across transformations where reactive reserves at the higher voltage are used to support a defined voltage profile of lower voltages.

3 Different option combinations deliver different outcomes, which will require National Grid Electricity Transmission (NGET) and each area’s onshore transmission and distribution network operators to agree the most appropriate option mix. Several other options were investigated but at this stage are deemed non-viable/insufficient to address the high volts issue: target voltage reduction at HV; network reconfiguration; and flow dependent voltage control. Some options will limit/negate the possibility of being able to utilise others.


the gaps in existing systems, policies, processes, data and technology that will need to be addressed.

Short-term options (the next 0 - 12 months)

Switching out the distribution network operator (DNO) network (circuits and transformers).

Effective technical compliance of connections, for customers that currently do not meet their commercial agreements with the networks.

New connection arrangements.

Tap stagger- this option require the taps of two transformers running in parallel to be staggered to generate reactive power

Switching out grid supply transformers.

Target voltage reduction at EHV (not interface – England and Wales).

Target voltage reduction at the transmission and distribution interface.

Increased use of existing transmission generation.

Switching out transmission circuits.

Medium-term options (12 months–five years)

Reactive Power Services from Demand and Generation.

Customer demand response through tariff incentives.

Active power support.

Reactive power compensation.

Using former generation sites for synchronous compensation.

Long-term options (longer than five years)

Developing options and commercial approach for the dispatch of distributed generation.

General findings from the High Volts Working Group project

General findings and conclusions from the High Volts Working Group include the following:

New or existing customer charges should reflect their connection’s network impact.

The transition from distribution network operator (DNO) to distribution system operator (DSO) will require investment to increase the active network capability at distribution level to support both local and whole of system balancing, and ensure optimal use of assets.

Significant investment and development of distribution network automation, control and protection will be required to enable some of these technical options. Across the medium and long term, consideration should be given to purchasing plant and equipment with the additional functionality required to better facilitate some of these options

Evidence indicates that some customers are technically operating outside the limits of their commercial agreements. This will require a determination on the best approach to managing this issue.

National Grid (Great Britain) has forecast that active/reactive power ratios will continue to decline for the foreseeable future, with increasing requirements for upwards of 14 GVAr over the next 20 years, and greater reactive power service requirements (both network and market led). Forecasting high volts4 will continue to be challenging, and further study is required to fully understand the decline in reactive/active power ratios and enable more accurate active/reactive power profile predictions.

It may be more cost effective for DNOs to install reactive power compensation plant adjacent to customer Exit Points. Together with the customer's existing reactive power regime, this represents a desirable approach to reactive power compensation behaviour in respect of the wider network.

The undergrounding of networks (wayleave issues, areas of outstanding natural beauty, national parks, etc.) will increase their capacitive impact in terms of reactive power compensation, leading to increasing reactive power challenges.

————————— 4 ‘High volts’ in this context refers to the risk of operating outside the upper bounds of the statutory voltage limits.


Options that require new or existing load and generation customers to modify their Active/Reactive power flows away from existing normal practice, may be restricted by existing network capabilities. For existing customers this may result in a requirement to reduce active power import / export, or in the medium to longer term, undertake network reinforcement. For new customers this may increase connection costs above what would otherwise have been required.

Network technical losses management should continue to form a part of any future cost benefit analysis.

On a case by case basis, a detailed whole-of-system cost benefit analysis is required to comprehensively determine option implementation costs. National Grid have highlighted that these issues will require consideration by industry parties and Ofgem, and that at the time of the last price control submissions, the high voltage issue and its impact on the transmission network was a developing area of understanding and as such no specific revenue driver metrics relating to allowance for mitigation were agreed. Since that time, the understanding and extent of the problem has increased and as such it is appropriate for a revisit of the funding focus to be undertaken to reflect the various options available across the Network Owners as discussed in this report.


1 Introduction

System voltage profiles during periods of minimum demand have changed significantly in recent years, introducing planning and operational challenges for the System Operator, National Grid (Great Britain). High voltage excursions have been increasing in frequency and operationally, high voltage management has evolved from being a summer challenge mainly in the South to being a year-round national issue.

In parallel with the increasing frequency of these excursions, the costs of providing additional reactive power (MVAr) support are rising due to the increased cost of constraining on out-of-merit transmission connected generators. This is exacerbated where support is being supplied by traditional transmission-connected generation, which is withdrawn ahead of downtime for synchronous generator maintenance.

The SO is required to maintain the transmission system within normal safe operational limits. In line with the spirit of section 9 of the Electricity Act, the Distribution Network Operator’s (DNO’s) will, where the SO makes a reasonable request, work with the SO to determine the most appropriate cost effective solution, whether that includes work on the Transmission or Distribution System. Network owners and operators have a responsibility under their respective licenses to identify the most economic and efficient solutions for their networks, however a framework does not currently exist to allow total system benefits to be realised

In September 2015, the Energy Networks Association (ENA) formed a distribution network operator (DNO), Transmission Owner (TO), and System Operator (SO) working group to:

assess the technical planning and operational challenges associated with this subject, and

identify viable technical options for cost-effective, whole-of-system solutions.

The working group’s approach has involved the following:

Assessment of current and completed innovation projects, including the REACT project by the University of Manchester.

Workshops to identify all possible technical options, including options that may involve future contracted services.

A high-level assessment of the viability of the identified options.

A joint technical and regulatory workshop to identify barriers to viable option implementation.

Work done to better understand the high voltage issue

High voltage effects are localised in nature, but the balance of reactive power between areas of transmission system or between distribution and transmission voltages can also give rise to challenges for the area receiving that imbalance of reactive power. High voltage issues normally manifest first at transmission system level given that the hierarchy of transformer tap change control tends to act to shift reactive power imbalances to the higher voltages.


Figure 1-1 - How distribution network effects can influence reactive power exchange at the interface

High voltage issues can generally be separated into:-

A Transmission network component, relating to:-

o Transmission system loading under planned intact and post fault power flow conditions

and its associated voltage profile;

o The imbalance of reactive power exchange occurring on Line Commutated Controlled

HVDC interconnectors at particular operating points and how these interact with the

transmission system;

o The status of static and dynamic reactive compensation plant and availability of nearby

generation resources to absorb reactive power resources,

o The ability to minimise transmission network gain via the switching out of elements of

the transmission system and via running arrangements and power flow control devices

(for example Quad boosters) to influence where the power flows.

A Distribution system component, relating to:-

o The balance of reactive power (Q) in relation to active power (P) absorbed or generated

at the interface.

Increasingly identified as intrinsic load behaviour, reactive/active power ratio decline is a focus of both international and national research.

While the REACT project confirmed the underlying trend of reactive/active power ratio decline within demand itself, it did not identify its origins. It did reveal however that contributing factors to this decline are the increasing penetration of distributed generation, and increasing levels of underground networks that are more capacitive by nature.

The TO’s and SO have undertaken power system studies to inform the mitigation of the national high voltage issue, which has resulted in the investment of over three GVArs of shunt compensation required over the next few years as a short term measure. Several shunt reactors have already been commissioned and the remaining reactors are currently in delivery.


Further information on the work that NG has undertaken to date to address the high voltage issue is provided in Appendix A.

Figure 1-2 shows the extent of reactive power requirement decline over the period 2010 to 2015.

Figure 1-1 - Minimum reactive power demand, 2010–2015 [page 85, NG SOF, figure 43]

Operational challenges

The SO, in conjunction with TOs utilises established processes under the NETSSQSS planning standards and the data provided under the Grid Code to manage the transmission components year-round, with the TOs responding as appropriate to these factors to ensure the operator has a range of options available. In recent years this has included work with interconnectors to further minimise their reactive exchanges with the transmission network. However with the ongoing decline in the Q/P ratio, the transmission/ distribution interfaces have started to experience export of both active and reactive power with increasing frequency.

From a system operation perspective, this decline has led to a series of significant challenges, including the increasing need to constrain on more generation than before to support reactive power requirements. This is costly and can lead to increased generation downtime, reducing generator availability and making it increasingly difficult to rely on, given increased generator closures and the reduced running of thermal generators (gas and coal). To instruct on generation for reactive power support can require constraining off other generation. Increasingly, this is renewable generation, which is distant from the points of transmission and distribution interface being addressed and unable to directly support these voltage challenges. As an example, there were a number of incidents during 2015 where the curtailment of small and medium-sized embedded generation was the only option to contain voltages at transmission level.

The levels of active and reactive power exchange at the transmission and distribution interface are inherently challenging to forecast due to the uncertainties involving small-sized embedded generation and its associated export. Operationally, therefore, it is becoming increasingly more important to have a diverse range of solutions available under routine or emergency conditions.

Network planning challenges

To ensure the best possible investment decisions regarding whole-of-system reactive power support, it is important to be able to:

forecast the future behaviour of embedded generation, and

research the underlying demand behaviour.

Increased levels of data exchange and collaborative planning will be needed to optimise transmission and distribution solutions. Procedurally, the Demand Connection code (DCC) highlights the need to identify and agree reactive and active power exchange envelopes across the transmission and


distribution interface to enable better network modification planning at the interface. There’s a further opportunity to resolve levels of control and visibility of distributed generation via the EU requirements for generation (RfG) code and the system operation guidelines under development. Across all these areas of code there is a clear requirement to carry out a cost benefit assessment ahead of implementation.

1.1 Scope

1.1.1 Inclusions

To address the High Volts challenge, the working group developed the following scope of work:

Identify all viable short-term, medium-term and long-term technical options for routine and emergency operation and identify any commercial or regulatory barriers that may exist for each.

Identify gaps in existing systems, policies, processes, data and technology that will need to be addressed by network operations and planning.

Make recommendations on how existing network innovation may be used to address these challenges while referencing any international examples of best practice (where appropriate).

Recommend a set of actions and identify their key challenges.

Identify stakeholder engagement requirements and programmes.

1.1.2 Exclusions

The scope excluded:

developments that may occur as market arrangements evolve (but acknowledged where services may be provided by a distribution system operator (DSO) or other service provider), and

small-scale embedded generation. The forthcoming work on the requirements for generators (RfG) and DCC has been considered but the impacts of these European Union (EU) network codes will require further detailed investigation.

1.2 Background information

1.2.1 Normative references

The referenced documents (in whole or part) required for this report’s application include the following5:

Statutory Requirements:

Electricity Safety, Quality and Continuity Regulations (ESQCR)

Security and Quality of Supply Standards (GBSQSS) Standards ENA publications:

Engineering Recommendation P2 Security of Supply.

Engineering Recommendation P28 Planning Limits for Voltage Fluctuations Caused By Industrial, Commercial and Domestic Equipment in the UK.

Engineering Recommendation G59 Recommendations for the connection of generation plant to the distribution systems of licensed distribution network operators.

Engineering Recommendation P29 Planning Limits for Voltage Unbalance in the United Kingdom.

Engineering Recommendation G83- Requirements for the connection of small scale embedded generators (up to 16A per phase) in parallel with Public Low Voltage Distribution Networks.

Engineering Recommendation G5 - Harmonic Voltage Distortion and the Connection of Non-Linear and Resonant Plant and Equipment to Transmission and Distribution Networks in the United Kingdom

Other publications (links are provided in the R&D Section)

————————— 5 For dated references, only the edition cited applies. For undated references, the latest edition of the referenced

document (including any amendments) applies.


CLASS.

REACT.

DIVIDE.

EQULIBRIUM.

1.2.2 Terms & Definitions

For the purposes of this document, the following terms and definitions apply.

Term Definition

Active Power The product of voltage and the in-phase component of alternating current measured in units of watts, normally measured in kilowatts (kW) or megawatts (MW).

Apparent Power The product of voltage and of alternating current measured in units of volt-amperes and standard multiples thereof.

Business as Usual (BAU) The normal execution of standard functional operations within an organisation.

CAPEX Capital expenditure, or CAPEX, are funds used by a company to acquire or upgrade physical assets

CDCM Common Distribution Charging Methodology

Commercial In the context of this report, this relates to anything that affects customer or charging impacts that lie beyond regulatory decisions

Connection Agreements An agreement between the DNO and the User or any Customer setting out the terms relating to a connection with the DNO’s Distribution System (excluding any CUSC Bilateral Agreement).

it should be noted that where classified as large Power stations or where Offshore Transmission Owner arrangements are in place for connection to the distribution system, there will also be connection agreements and obligations in place with the SO relating to Grid Code performance capability and its application, and within CUSC and Balancing Codes related to its operation

Connection Point An Entry Point or an Exit Point of the Transmission or Distribution System as the case may be.

Customer A person who is the owner or occupier of premises that are connected to the Transmission or Distribution System.

Distribution Code A code required to be prepared by a DNO pursuant to condition 9 (Distribution Code) of a Distribution Licence and approved by the Authority as revised from time to time with the approval of, or by the direction of, the Authority.

Distribution Licence A distribution licence granted under Section 6(1)(c) of the Electricity Act 1989 (as amended.including by the Utilities Act 2000 and the Energy Act 2004).

Distribution Network Operator (DNO)

The person or legal entity named in Part 1 of the Distribution Licence and any permitted legal assigns or successors in title of the named party.

Distribution System The System consisting (wholly or mainly) of electric lines owned or operated by the DNO and used for the distribution of electricity between the Grid Supply Points or Generation Sets or other Entry Points to the points of delivery to Customers or Authorised Electricity Operators, or any Transmission Licensee within Great Britain and Offshore in its capacity as operator of the licensee’s Transmission System or the National Electricity Transmission System and includes any Remote Transmission Assets (owned by a Transmission Licensee within Great Britain), operated by the DNO and any electrical plant and meters and metering equipment owned or operated by the DNO in connection with the distribution of electricity, but shall not include any part of the National Electricity Transmission System.

EDCM Extra high voltage Charging Methodology


Term Definition

Emergency An instruction issued by NGET in emergency circumstances, pursuant to BC2.9. to the control point of a User

Embedded Generator A Generator including a Customer with own generation whose generation sets are directly or indirectly connected to the DNO’s Distribution System or to another authorised distributor connected to the DNO’s Distribution System. The definition of Embedded Generator also includes the offshore transmission system operator in relation to any embedded Transmission System.

Entry Point The point at which an Embedded Generator or other Users connect to the DNO’s Distribution System where power flows into the DNO’s Distribution System under normal circumstances

Exit Point The point of supply from the DNO’s Distribution System to a User where power flows out from the DNO’s Distribution System under normal circumstances.

Extra High Voltage (EHV) 22kV and above.

Generator A person who generates electricity under licence or exemption under the Electricity Act 1989 (as amended.including by the Utilities Act 2000 and the Energy Act 2004).

Grid Code The code which National Grid Electricity Transmission plc. is required to prepare under its Transmission Licence and have approved by the Authority as from time to time revised with the approval of, or by the direction of, the Authority.

High Voltage (HV) Above 1000 volts and below 22kV

High Volts Operational and whole-of-system planning challenges relating to the transmission system and presented by changing load characteristics. It also refers to the increased risk of operating outside the upper limits of statutory voltage limits.

Innovation The execution of new functional operations within an organisation.

Large Power Station As defined in the Distribution Code.

Long Term An implementation period of longer than five years.

Low Voltage (LV) Below 1000 volts.

Medium Term An implementation period of longer than one but less than five years.

National Grid Electricity Transmission (NGET)

National Grid Electricity Transmission plc (NO: 2366977) whose registered office is at 1-3 Strand, London. WC2N 5EH.

National Grid Electricity Transmission plc owns the onshore Transmission System within England and Wales and operates the National Transmission System.

National Terms of Connection (NToC)

Unless otherwise agreed, the National Terms of Connection form an agreement between a customer and the operator of the Distribution System through which electricity is conveyed to the customer’s premises.

OC6 OC relates to chapter 6 of that portion of the Grid Code which is identified as the Operating Code.

OC6 relates to the specific area of Demand Control, including procedure for the notification and implementation of Demand Control, the processes of Automatic Low Frequency Demand Disconnection, and Emergency Manual Disconnection, each a defined term within the Grid Code.

OPEX A category of expenditure that a business incurs as a result of performing its normal business operations.

Point of Common Coupling (PCC)

The point on a Distribution System, electrically nearest the Customer’s Installation, at which other Customers are, or may be, connected.


Term Definition

Power Factor The ratio of Active Power to Apparent Power.

Point of Supply The point of electrical connection between the apparatus owned by the DNO and the Customer.

Power Flow Convention

MM

GG

Q

P

DNO’s Network

+Q

-Q

+P-P

P(Import)

Q(Import)

P(Import)

Q(Export)

P(Export)Q(Import)

P(Export)Q(Export)

Lagging PF

Leading PFLagging PF

Leading PF

P = Active Power (kW)Q = Reactive Power (kVAr)

Generators Network

Power Station Generating units (even where sited separately), which are owned and/or controlled by the same Generator and may reasonably be considered as being managed as one Power Station. For the purpose of this document a single generating unit will also be described as a Power Station.

Reactive Power The product of voltage and current and the sine of the phase angle between them which is normally measured in kilovar (kVAr) or megavar (MVAr).

Reactive Power (VAr) is the difference between working power (active power measured in Watts) and total power consumed (apparent power measured in VA). Some electrical equipment used in industrial and commercial buildings requires an amount of reactive power in addition to ‘active power’ in order to work effectively. The reactive power generates the magnetic fields essential for inductive electrical equipment to operate – especially transformers and motors. Power Factor is the relationship between ‘active’ and ‘reactive’ power and indicates how effectively electrical power is being used.

A product of operating certain types of loads in an AC system that must be compensated for to maintain power system security and stability.

Regulatory In the context of this report, refers to economic regulation, by Ofgem

Routine An action performed as part of business as usual.

Series Compensation Series Compensation is a well established technology that primarily is used to reduce transfer reactance, most notably in bulk transmission corridors. The result is a significant increase in the transmission system transient and voltage stability. Series Compensation is self regulating in the sense that its reactive power output follows the variations in transmission line current, a fact that makes the series compensation concept extremely straightforward and cost effective. Thyristor Controlled Series Capacitors adds another controllability dimension, as thyristors are used to dynamically modulate the reactance of provided by the inserted capacitor. This is primarily used to provide inter-area damping of prospective low frequency electromechanical oscillations, but it also makes the whole Series Compensation scheme immune to Sub synchronous Resonance (SSR).


Term Definition

Short Term An implementation period of less than a year.

Shunt Compensation Additional voltage control can be achieved by use of shunt reactors that are sinks of reactive power produced at all levels of the system. Shunt reactors provide passive compensation to the transmission and distribution system, or switched and contribute to voltage control by modifying the network characteristics.

System Operator (SO) National Grid Electricity Transmission (NGET) in its capacity as system operator of the National Transmission System.

System An electrical network running at various voltages.

Total System The integrated system of connected generating plant, Transmission System, Distribution Systems and associated electrical demand.

Transmission and Distribution Interface

The point at which transmission and distribution systems are coupled together. This will normally be at the lower voltage side of the transformation point between the transmission system and the distribution system

Transmission License The licence granted under Section 6(1)(b) of the Electricity Act 1989 (as amended.including by the Utilities Act 2000 and the Energy Act 2004).

Transmission Owner The holder of a transmission licence in relation to which licence the Authority has issued a Section D (transmission owner standard conditions) Direction.

Transmission System A system of High Voltage lines and plant owned by the holder of a Transmission Licence and operated by the SO, which interconnects Power Stations and substations.

User A term used in various sections of the Distribution Code to refer to the persons using the DNO’s Distribution System.


2 Options Analysis

This section presents the outcomes of the High Volts Working Group analysis undertaken between September 2015 and January 2016, which grouped the viable options identified into the following categories:

Short term (see Section 0).

Medium term (see Section 0).

Long term (see Section 2.3).

Options identified as short to medium-term have been categorised as short-term, although certain aspects of their implementation may take longer. The same approach was taken with medium to long-term options. These timelines are based on routine rather than emergency implementation.

Each option includes a high-level description and categorisation on likely use, and the identified routine and emergency measures in terms of the:

actions required

costs

commercial considerations

regulatory considerations

best practice impacts

advantages, and

disadvantages.

As each option could potentially be considered differently in extent of opportunity or value against the above criterion dependent upon whether it could be applied under Business As Usual or alternatively/ additionally under Emergency circumstances, the working group considered each option discretely against these two contexts.

The working group has produced 17 options which it believes are all technically viable. However, as network topologies, operating regimes and design philosophies vary between DNOs, it is likely that a number of options may be more appropriate to some DNOs and some situations than others. It is also likely that some DNOs may be more ready to implement particular solutions, especially where an individual DNO has developed new technologies required to implement the solution as part of an innovation project. Therefore, the range of solutions should be considered as a toolkit from which individual DNOs may select the most appropriate solutions to their networks whilst working closely in conjunction with National Grid.

Different option combinations deliver different outcomes, which will require DNOs, SO, TOs to agree the most appropriate option. Some options will limit/negate the possibility of being able to utilise others.


2.1 Short Term

Nine options were identified for short-term implementation (some of which are available for emergency operation under different timeframes).

2.1.1 Option 1 – Switching out DNO Network (circuits and transformers)

Description

This option involves the selective switching out of plant and/or circuits from the distribution network, with the aim of reducing the capacitive amplification of reactive power flows within the system. Extra high voltage (EHV) cable circuits are considered most effective, since their primary reactive behaviour is a function of capacitance and applied voltage. This means they are not heavily affected by applied load.

Category

Primary Category

Contractual Market Network Design

Network Operations

Secondary Category

Business as Usual Innovation

Network Application

Transmission Distribution

State Routine Emergency

Actions required

Routine

Under ER P2/6, the distribution system is designed to a level of diversity that allows it to be resilient to the loss of a circuit during a planned circuit outage. In practice, this means that in distribution areas where three or more circuits supply demand in parallel, even when they are not normally experiencing a maintenance outage, it will be possible for the DNO and the SO to agree to switch the circuits out to support voltage control at times of similarly low demand. This would coincide with the needs of the Transmission System to contain High Voltages at such times

This type of switching for voltage control, which depends on the balance of operational resourcing and asset use, can occur either:

daily, during periods of low demand, or

across multiple days during the maintenance period (the longer a circuit is out of service, however, the more complex its re-switching can become, due to the range of tests that may then apply).

Routine operation will result from establishing a scheduled and planned sequence of outages relating to circuits that can be easily operated, and that deliver a defined benefit in areas of the network requiring containment. In many cases of transformer switch-out, it may be possible to leave the circuit on hot standby, where the circuit’s HV end remains energised.

Actions required to achieve this include:

Each DNO is to identify a range of possible switch out circuits which could be agreed to be used for mitigation of High Voltage. From this, circuits of most benefit will be identified.

trialling the operation of voltage control circuits within the DNO system

validating the benefits (by DNO and SO), and

agreeing schedules of use between operators.

Emergency


Against ER P2/6 for Demand Groups larger than Category B (60MW peak latent demand), it is required that the network at all times be resilient to the fault outage of a single circuit. As such across the distribution system further DNO circuit switch-outs can be contemplated in Emergency circumstances where the consequence of switching out such circuits would leave the Demand Group considered at risk of loss of supply for the next fault. This would only be contemplated in situations where an unplanned effect, for example a higher than expected distributed generation penetration, had driven a high voltage challenge within the overall system where other BAU options for mitigation were not present/ had been fully exhausted, and the residual risk of overvoltage represented a greater risk/ extent of demand disconnection than such distribution circuit switch-outs would represent. Actions required to achieve this include:- Based on a case study considered within the work group it was clear that such action beyond the above could yield further benefit. Further work would be required to exchange such data between DNO and SO and develop tranches of emergency service to limit any such application of such measures. Code treatment of such actions, in particular with reference to the consequence of any unplanned disconnection arising from operation in such a manner would need to be clarified as would the treatment of regulator instruments of incentivisation in such conditions where whole system risk assessments as discussed above have concluded such measures were appropriate for wider system security of supply.

Implementation steps

Routine

This option can be quickly implemented after identification and assessment of suitable areas of the network. This will require initial trials over a limited area to prove viability.

Emergency

This option can be quickly implemented, provided suitable policies and procedures are developed and suitable areas of the network are assessed. A detailed risk assessment also needs to be considered, where emergency conditions are deemed to increase risk to customers beyond P2/6 security levels (a single circuit security risk balanced by the risk of a transmission overvoltage impact that could otherwise disconnect that site due to cascading protective actions).

Costs

Routine

This option requires initial system capability assessments, then ongoing network planning and operation. It is primarily OPEX-based but is likely to have a CAPEX implication due to increased switchgear duty cycles, representing in both cases additional potential for cost above and beyond those occurring in Business As Usual operation.

Emergency

This option requires initial system capability and risk assessments and then switching operations (as required). It is primarily OPEX-based but again, has potential to have a CAPEX implication due to increased asset duty cycles (depending on the frequency of use).

Commercial considerations

Routine

Currently, distribution network operators (DNO) are incentivised to minimise the number of customers interrupted per 100 customers (CI) and the customer minutes lost (CML) and have invested appropriately to maintain security of supply. Reduced security of supply increases the risk of customer interruptions, so is likely to have a material effect on CI/CML incentives if used for conditions less secure than second circuit outage (depending on the extent of agreed routine switching actions). Where embedded generation is subject to non-firm arrangements at the connection interface, it will be necessary to:

consider the impact that switching out DNO circuits at those times will have on the generators’ non-firm availability, and


establish how the affected parties want to proceed (where appropriate).

Emergency

As described in the routine approach, this option potentially impacts regulatory incentives. However, it is still a viable emergency operation to ultimately reduce the overall impact on customers, provided a risk assessment is conducted and concludes in favour of emergency operation.

Regulatory considerations

Routine

This option will require electrical loss, CI and CML incentive impact assessments as well as establishing how it will fit within the P2 framework. Discussions with National Grid and Ofgem will be required to assess how the Balancing Services Incentive Scheme (BSIS) will look going forward and how it may include reference to any Distribution System measures utilised. DNOs should not be penalised for contributing to more efficient overall total system management, and either an exemption from Ofgem in respect of Interruptions Incentive Scheme (IIS) payments or compensation from NGET will be required where impacts are material. This will also require an Ofgem clarification about whether a regular reduction in security of supply standards will be acceptable and/or appropriate under the licence conditions and P2.

Emergency

Emergency operation of this option will become a viable tool to mitigate high volts if Grid/Distribution Code changes are made and exemptions given by Ofgem for abnormal conditions.

Best practice impacts

Routine

Irrespective of incentives, this option requires a more detailed case by case assessment as to whether it provides a net benefit to the end user. This will necessarily mean that specific solutions are trialled and implemented differently across different areas of the total system relative to network need and network risk. It would be of benefit to develop with the regulator the principles and processes by which such total system cost benefit should be undertaken The risk to quality of supply will increase through business-as-usual employment of this option.A balance to be taken between the switching frequency, the time of an event, and the impacts on the assets, to ensure net user benefit.

Emergency

Under emergency conditions, the overall system risk would be balanced against the implications of implementing this option.

Advantages

Routine

This option can be quickly implemented following a process of identifying and assessing suitable sites/areas of the network. Initial implementation costs will be low, but will require power system analysis, operational planning and network switching. Distribution system trials of this type of action have already proven to give a significant VAr response (where the system lends itself to this type of operation). In areas of the network with more than three transformers and/or circuits, it is unlikely to impact security of supply (assuming a successful return to service).

Emergency

This option can be quickly implemented and may provide a level of response that avoids the need for additional major actions or investments. In areas of the network with more than three transformers and/or circuits, it is unlikely to impact security of supply (assuming a successful return to service).

Disadvantages

Routine


This option may distort existing CI/CML incentives. The frequent de-energising of in-service equipment will lead to an increased risk of ‘return to service’ faults, the associated testing of which may also limit outage durations. This is primarily a localised solution with the most significant gains occurring at EHV. This will generally require areas of the network with a minimum of second circuit outage security (3 x EHV circuits), which means it will have limited benefit in some areas. The additional plant duty cycle will likely lead to an increase in the frequency of maintenance.

Emergency

Although this option’s selection will primarily be to reduce the customer impact from taking other major actions, it is still likely to invoke customer complaints if employed during times when system security is affected. This is primarily a localised solution with the most significant gains being made at EHV. This would generally require areas of the network with a minimum of second circuit outage security (three EHV circuits), which means it will have limited benefit in some areas. Where s single circuit risk is proposed there is an increased risk of customer interruptions.

Option 1 - further Comments

To ensure continued quality of supply to customers, a full site risk assessment should be carried out with an initial focus on low risk sites and circuits. Note should be taken of high sensitivity demands, some of which may not be suitable to be placed at increased BAU risk, or require particular measures to be in place to do so. In addition, connection agreements may include a higher level of security, potentially representing a breach of the agreement or a need to introduce a variation. Periods of low demand (4–6 AM) should be targeted to reduce the level of risk posed to customer supplies. Because of the return to service risks associated with this action, this option is preferred under emergency conditions only.

References

National Grid already switches out transmission circuits. Their current planning philosophy is to switch out only when in doing so remains still possible to meet pre-fault and post fault compliant GBSQSS conditions and contingencies (for example a double circuit fault). Research and development is ongoing to look at increasing this operating envelope (given some cabled transmission circuits can each represent a maximum of some 400MVAr gain a sizeable benefit is possible from extension of such arrangements also, as further discussed under Option 19.).

Quantification

The benefit will be limited as it depends on circuit configuration and the availability of suitable areas of network. Assessment of one DNO area indicated there is only one 132kV circuit with a gain of c8.5MVAr that could possibly be switched out at times of light load. Another area indicated there are two 132kV circuits with a gain of 2.5MVAr and 18.6MVAr respectively that may be available at times of light load. An assessment of the 33 kV network has indicated a potential 100 KVAr per kilometre for 33 kV cable.


2.1.2 Option 2 – Effective compliance of connections

Description

As part of the connection agreements between embedded generators and DNOs, there are customer specific requirements relating to the export of real power at a fixed power factor. As part of the optioneering undertaken by DNO’s it has been found that these terms are frequently not complied with. In some instances, non-compliance with these terms has produced undesirable reactive export from embedded generators onto DNO networks.

It is expected, subject to further study, that the effective compliance of these customers could address a significant component of the cause of high volts. The reactive behaviour of large demand customers is still being investigated, but may also lead to the same findings as has been found for generation customers.

This option needs to be balanced with a particular network’s requirements and operator policy, given that power factors can be set for a variety of reasons of which High Voltage is only one.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

This option’s implementation will require customer contact to reiterate connection agreement requirements and make clear the implications of non-compliance with a view to meeting compliance. A detailed investigation of the effects of both compliance and non-compliance is also recommended so that any necessary mitigation measures can be identified. The costs for implementing this solution will be the customer’s responsibility6.

For new connections (and existing connections as required):

Existing connection agreements should be reviewed to assess their need for change, given the changing service requirements that are likely to be required at a distribution level in the longer term. This revision may present an opportunity for drafting more dynamic reactive power requirements that avoid ambiguity, and the potential to standardise wording across the industry.

A DNO-witnessed commissioning stage should be introduced (similar to G59 relay testing) where real and reactive power controls are tested while provisionally connected to the distribution network7.

For all connections:

To encourage compliance with reactive power flow terms, investigate the mechanisms that are or could be included in the Extra high voltage Distribution Charging Methodology (EDCM)

————————— 6 Specifically, customers operating outside the specified operating window.

7 For example, NG uses an Interim Operational Notification followed by a Final Operational Notification. (Grid Code Compliance Processes CP.6 and CP.7 refer)


and the Common Distribution Charging Methodology (CDCM). Processes for managing Connection Agreement compliance will also need to published and distributed to the industry.

A definition of 'compliance' will need to be formalised for all customers. Most connection agreements do not specify an error band, but closed loop control systems designed to comply with them will have finite static and dynamic errors. In the longer term, ongoing real and reactive power flow behaviour should be monitored.

Implementation Timescale

This solution can be implemented over the short to medium term, but largely depends on individual customer implementation and the delivery of compliance processes as discussed above. It may continue to be effective in the long term, but may also be superseded or supplemented by future solutions.

Costs

Given that in defining the original power factor requirement upon the connection consideration of the most efficient solutions occurred, this option should represent a reasonably low cost solution for all customers requiring network OPEX (assuming coordinated cross-industry efforts). A significant potential CAPEX cost may arise on the customer where non-compliant customers have not already installed plant capable of complying with the terms of their connection agreement, but in other cases it may only require revision of existing control arrangements upon that equipment to meet their connection agreement.

Commercial Impact

This option may require modification to charging and network use-of-service mechanisms to encourage compliance. There will also be ongoing staffing costs for investigating compliance and communicating with customers.

Regulatory Impact

Further support from the regulator would be required in the enforcement of the processes discussed above which may also include changes to the framework documents, for example the NTC and the D-Code.

Best Practice Impact

This option is likely to lead to:

improvements in the clarity of future connection agreements and ensure compliance with reactive power terms before customers connect

an industry standard or policy on connection agreement enforcement, and

encourage better monitoring of the real and reactive behaviour of large demand and generation customers.

It may also be possible to include monitoring, alarms and ramping down, or soft intertrips in SCADA Remote Terminal Units (RTU) located at DNO customer Exit Points as an enforcement tool. This would also help DNOs and the SO by giving greater visibility of output behaviour.

Advantages

This is a low cost option for DNOs to implement, involving the enforcement of existing rules rather than the imposition of new rules. However, additional OPEX would be required to coordinate compliance of connections.

Disadvantages

This option’s overall effectiveness requires further study. It also introduces an ongoing challenge to enforce connection agreements. Full compliance may lead to additional costs/challenges for individual customers, though at a lower cost for all customers.


References

See Appendix 2: Plots of P/Q behaviour of existing generation customers submitted by DNOs.

Quantification

A study of a DNO licence area that has experienced considerable DG connections suggests that a 60 MVAr improvement may be achieved if all customers fully comply with the terms of their connection agreements.


2.1.3 Option 3 – New connection arrangements

Description

This option requires existing and new customers to operate across a range of power factors to ensure their connection doesn’t have an adverse impact on the local or wider network. Possible approaches include:

targeting leading power factors or fixed VAr imports to generators to encourage VAr consumption and ensure optimal management of distribution and/or transmission voltage

running generators for voltage control (PV mode) rather than fixed power-factor (PQ mode)

requiring customers to compensate for the reactive behaviour of their sole use assets (SUAs), or

requiring customers to modify reactive power flows in response to SCADA signals from the DNO.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

For existing connections:

Mechanisms need to be agreed for the retrospective connection agreement variations.

A study of the local network will be required to determine the existing P/Q operating envelope. Most connections to distribution networks were designed on the basis of a fixed power factor; and may be capacity constrained in a different mode of operation.

Operating a Generator in voltage control mode increases the possibility of either that or adjacent generators being more likely to support an islanded network. A risk assessment needs to be undertaken to understand the implications of converting connections without inter-tripping for loss-of-mains to voltage control or voltage-dependent control. Where necessary mitigation may be required to offset this risk

For all connections:

The most suitable reactive power regime needs to be identified for each existing and new connection, given the connection asset constraints and the needs of the network.

A network assessment is required that will quantify the reactive power requirements at the metering point while considering the effect of sole use assets at the point of common coupling on the distribution network.

Each connection’s metering point requirements need to be assessed to ensure net targeting of reactive power flows at an unmonitored remote point (similar to controlling the voltage at an unmonitored remote point using Line Drop Compensation).

The possibility of including network monitoring, alarms, and soft intertrips in SCADA Remote Terminal Units (RTU) located at DNO customer Exit Points (as an enforcement tool) should also be investigated.


Industry and regulatory preferences for either a market-based or network-based solution should be assessed, where customer penalties for ‘bad’ reactive power flows directly contribute to incentives for ‘good’ reactive power flows8.


This option can be implemented over the short to medium term, depending on the complexity of the possible approach. It may continue to be effective in the long-term, but may also be superseded by reactive support from customers.

Costs

This could be a low-to-medium cost solution, requiring both OPEX and CAPEX. Some SCADA improvements are likely to be required, and there is a possibility that issues associated with existing customers will have to be addressed for varied terms outside the bounds of their current connection agreements.

Even when existing plant is suitable to operate in a different operating mode, there may also be significant CAPEX implication for the local network in order to accommodate these changes.

For new customers this might also lead to increased costs.

Commercial Impact

Implementing this option will entail some work for the DNOs developing new connection agreement terms.

Regulatory Impact

Unless there is the prospect of significant compensation for existing customers, this option’s imposition is likely to require a change to the Distribution Connection and Use of System Agreement (DCUSA), taking at least 6 months and requiring agreement from the DNOs, IDNOs, suppliers and Ofgem.

All new connection arrangements will need to be compatible with the increasing array of requirements in the various ENTSO-E network codes.


This option will necessitate a more detailed study of new and existing connections. The conventional assumption that fixed-power factor DG always causes voltage rise will have to be reassessed.

Advantages

The option is cost reflective, since the costs will not be socialised. It is also likely to encourage better monitoring of the real and reactive power behaviour of large demand and generation customers, which could create greater market participation in overall system management.

Disadvantages

This option’s disadvantages include the following:

The imposition of new requirements on existing connections is unlikely to be popular with customers.

This solution requires regular review of connection arrangements to ensure that reactive regimes remain appropriate.

Where connections are looped into the network, a position on the net impact between the metering points and the points of common coupling will be more complex to manage/assess.

Some DNOs currently dictate lagging power factors to generators for reasons including the reduction of network losses and compatibility with Negative Reactance voltage control schemes, the solution would be incompatible with those regimes.

————————— 8 Determining (and pricing) what is ‘good’ and ‘bad’ will be technically challenging, given reactive power needs to

be generated and consumed (or neither) in the right places to avoid voltage or thermal excursions.


Running generators in voltage control mode may lead to undesired reactive flows if the interaction between generator and transformer voltage control is not carefully coordinated

For new customer’s alternative, more expensive, connection options may have to be considered in order to allow operation over a wider power factor range, when compared to current practice.

Option 3 - further comments

This option provides synergies between such arrangements as those that already exist within the Grid Code for transmission connected customers.

References

Grid Code CC.6.3.2:

“All Power Park Modules and parties connected via OFTO assets to the transmission are obliged under Grid Code CC.6.3.2. and System Technical Code section K respectively to provide a 0.95 pf lead- lag MVAr range at their point of interface with the transmission system suitably compensating for their associated connection assets, Under Synchronous Generation connection agreements these principles of offsetting the effect of cabled connection assets are futher replicated within the associated Bilateral Agreements to ensure that where voltage regulation challenges are present the obligations to offset impact are appropriately allocated.”

Quantification

This option’s net benefit has not yet been assessed but will depend on the chosen approach, and may even be negative if local network requirements take precedence. It may also be high if a small improvement can be achieved at many sites.


2.1.4 Option 4 – Tap Stagger

Description

This option require the taps of two transformers running in parallel to be staggered to cause circulating reactive current and an increase in I2X losses. This can be implemented at primary substations, BSPs and GSPs. It may also be possible to cause circulating reactive currents between interconnected BSPs and GSPs through the 33kV and 132kV networks.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Routine

A detailed feasibility study needs to be carried out within each network to assess the tap stagger capability, costs for implementation, and net benefit to customers. Consideration needs to be given to the suitability of local control units and communication links. Existing AVC schemes will also need to be modified. In some cases control systems will need to be developed to include automation, scripting, and telemetry. The CLASS trials could form the basis for this development. There is ongoing work with some relay manufacturers to provide the tap stagger functionality at distribution level. Further study is required to assess the opportunity to extend the concept to have circulating currents between BSPs and GSPs through the 33kV and 132kV networks. Where existing protection schemes are triggered by circulating current or reactive power flows, assessments should be carried out and guidance provided to ensure that erroneous operation does not occur.

Emergency

The implementation of this option is possible on an emergency basis at sites which have suitable remotely operated AVC scheme. A review of voltage control schemes at all primaries is necessary to identify suitable sites. At 33kV and 132kV it might also be possible to achieve benefit by doing this manually by a control engineer but this would be time consuming and resource intensive. Where existing protection schemes are triggered by circulating current or reactive power flows, assessments should be carried out and guidance provided to ensure that erroneous operation does not occur.


Routine

Implementation of tap stagger is dependent on the existing tap stagger capability. In some locations this could be implemented in the short term. Where new AVC schemes and control systems are required the implementation timeline would be extended.

Emergency

Implementation of tap stagger as an emergency option can be achieved in short timescales where suitable AVC and remote control systems already exist.


Costs

Routine

The individual network feasibility studies will be Opex in nature and the level of costs will vary dependent on the number of sites that require AVC scheme assessment. Where implemented there will be an ongoing Opex associated with the operation of the scheme and more frequent maintenance requirements. The Capex associated with this option is dependent on the need identified from the feasibility study. The benefit of this option needs to be quantified on a case by case basis.

Emergency

The Opex and Capex requirements are the same as for routine except that there would also be a requirement for additional Opex to cover manual operation of the tap stagger.

Commercial Impact

Routine and Emergency

The commercial arrangements at customer sites need to be considered. Where metering is affected by circulating current or reactive power flows assessments should be carried out and mitigation measures taken forward.

Regulatory Impact

Routine

This option will potentially increase technical losses on the system. This needs to be considered from a regulatory perspective with regards to Distribution Licensees requirement (SLC49) which targets losses to be as low as reasonably practicable.

Emergency This option will potentially increase technical losses on the system. This needs to be considered from a regulatory perspective with regards to Distribution Licensees requirement (SLC49) which targets losses to be as low as reasonably practicable.



Detailed investigations will need to be carried out for each site in order to determine the applicable changes to AVC schemes and operational procedures relating to those sites with a view to minimising risk to customers and plant.

Advantages

Routine

Tap stagger has the potential to be quick to implement depending on the existing capability of sites. CLASS has already demonstrated the minimal impact of tap stagger on quality of service to customers. Depending on the outcome of feasibility studies, there may be significant benefit nationally.

Emergency

Tap stagger has the potential to be quick to implement depending on the existing capability of sites. CLASS has already demonstrated the minimal impact of tap stagger on quality of service to customers. Depending on the outcome of feasibility studies, there may be significant benefit nationally.

Disadvantages


There is a potential for technical losses to be increased and the capacity of substations to be reduced.


Use of this option could create other voltage issues on DNO networks, so there will be a need to limit tap stagger to maintain voltage step changes within statutory limits. This will place a limit on the maximum MVAr benefit that can be achieved. The increased tap changer duty cycle may cause increase contact wear resulting in the need for more frequent maintenance and replacement. This option will not be suitable for all primaries that have transformers that run individually for operational reasons.


This option may contradict with separate initiatives to switch out transformers for voltage control- you can tap stagger or deplete the number of transformer for roughly similar per transformer value, but you clearly cannot do both at the same site.

References

http://www.enwl.co.uk/class

Quantification

CLASS trials show an implementation cost £20k per primary for compliant AVC schemes, and £80k where significant upgrades are required.

The benefit has been shown to be up to 0.8MVAr per primary substation. There are approximately 4000 primary substations nationally although not all of these are suitable for tap stagger as previously indicated. The maximum national benefit could be up to 2GVAr.

As DNO networks vary significantly in context, for example in their demand and network characteristics, the benefits of tap stagger would need to be further developed by additional trials taken forward by each licence area.

Levels of MVAr benefit at transmission level from such arrangements can be quite significant. At GSP level up to a 120MVAr benefit can be achieved for a 4x SGT site.

http://www.enwl.co.uk/class


2.1.5 Option 5 – Switching out Super Grid Transformers (SGTs)

Description

During times of low demand, the loading on the grid supply transformers at a GSP (Grid Supply Point) will also be low. This option proposes to switch out a lightly loaded SGT which in turn will increase the loading on the remaining transformers thus increasing the losses resulting in lower voltage at the transmission level. Having the switched out transformer on "hot" stand-by would further increase the effectiveness of this option and improve supply security during implementation. An operational procedure will need to be agreed between National Grid and the DNOs prior to implementation. Selecting which grid supply transformer to switch out at a particular GSP is critical thus detailed study is required. In addition, an assessment of demand security should be made dependent on the grid supply transformer outage pattern. It is recommended that a grid supply transformer with a shunt reactor connected on its tertiary winding should not be switched out entirely but left on "hot" stand-by.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required


Detailed system studies will be required to identify suitable sites for switching out SGTs. Trialling this option and verifying its effectiveness will also be required. National Grid and DNOs will need to agree on an operational procedure which could be in the form of standard outage requests. A Grid Code change would be required to formalise this process.



System studies to identify suitable sites and an assessment of demand security should be made dependent on the grid supply transformer outage pattern. Validation of this option will require trials to be carried out. Once the validation process is completed, implementation timescale could potentially be short.

Costs


Due to higher duty cycle on the switchgear there are CAPEX implications. The OPEX costs would be low depending on the frequency. However, there is potential to have high OPEX costs if generation and/or demand are required to be constrained

Commercial Impact


There is the possibility of commercial impact as DNOs may have agreed with customers in their connection agreement to provide a certain level of security e.g. for steel works and very large generators. Switching out SGTs could potentially breach this connection agreement and require alternative agreements to be made, although this will be the exception rather than the norm.


Regulatory Impact


This option has the potential to reduce the security of supply thus raising the CI CML Risk and may also conflict with DNOs' security of supply and IIS requirements.



As this option is not currently utilized as a routine measure, operational procedures will need to be agreed between National Grid and the DNOs.

Advantages


This option will be quick to implement as National Grid already has the capability to switch out SGTs. Sites having three or more SGTs will have less of an impact on security of supply. System security risk assessment will need to be carried out prior to implementation.

Disadvantages


The number of suitable sites could potentially be low as this option will likely be only viable for GSPs with three or more SGTs due to demand security requirements. In addition, SGTs having tertiary connected shunt compensation equipment will not be suitable for de-energisation. There may also be existing customer connection agreements that could be affected and thus limits the number of SGTs.


Switching out SGTs would limit the ability to apply tap stagger.

References

N/A

Quantification

There is a concern that DNOs are exposed to a CML loss due to a transmission failure event giving a perverse set of incentives that will need further consideration.

The switching out of SGTs may impact customers with non-firm connection arrangements at those times. Further discussion with the customer would need to be entered into to understand their expectations for access at these times. Where appropriate, these customer’s connection agreements may need to be revisited.


2.1.6 Option 6 – Target voltage reduction at EHV on distribution networks

Description

The target operating voltage of transformers is often higher than the nominal design voltage for the networks. This accounts for voltage drops across the network; however the target voltage can be reduced to nominal whilst remaining within statutory limits at the lower boundary. Reducing the target voltage causes an increase in the current drawn through the transformers thus increasing MVAr demand of reactive network elements. Additionally, capacitive elements operating at lower voltage will produce less MVArs.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required


The first course of action required to implement this option is to run a series of network studies to assess network impact. Where viable, the target voltage of a transformer can be changed remotely if remote control is installed. Where remote control is unavailable, an engineer would need to carry out the manual operation of the tap changer on site. Currently the vast majority of EHV transformers in the UK lack remote tap changer control and therefore would require significant resources to implement. Further assessment is required to understand the impact of voltage reduction on demand across all the voltage levels.



This option is quick to implement where remote control of target voltage exists, pending system studies of the impacts. Where manual intervention is required, timescales will be extended.

Costs


The installation of remote control on all EHV transformers will require additional CAPEX. Additional OPEX may also be required due to the increased number of operations and hence additional maintenance but this is unknown at this point. Where manual intervention is undertaken, OPEX costs would increase significantly.

Commercial Impact


Consideration of the quality of supply impacts would need to be assessed in more detail.

Regulatory Impact

Routine


This option will potentially increase technical losses on the system. This needs to be considered from a regulatory perspective as this may be in conflict with Distribution Licensees requirement (SLC49) which targets losses to be as low as reasonably practicable.

Emergency

The resultant increase in network losses should be accounted for from a regulatory perspective and exemptions given when this operation is instructed by the System Operator with the necessary changes made to the grid code.



An additional impact of reducing system voltages is that the effective power flow ratings of circuits are reduced and so cause a reduction in overall system capacity. This may cause conflict when operating the network for outages.

Advantages


This solution modifies the voltage profile at EHV level; hence its impact on the HV network and the majority of customers will be minimal due to the downstream primary voltage control. Also, as this solution is at the higher voltage levels there are fewer transformers to make this change to.

Disadvantages


This solution will require more operations than applying target voltage reduction at the transmission and distribution interface. It is difficult to effectively evaluate the reactive power gain from this approach because four quadrant monitoring is rarely fitted to EHV transformers. Studies and trials are required to quantify benefits and other consequences such as possible conflict with generators running in PV mode.


Consideration needs to be taken on how EHV connected generators interact with this in practice.

References

No documentation currently exists as this is not a current process.

Quantification

Further studies are required to understand the benefit of this option.


2.1.7 Option 7 – Target voltage reduction at the Transmission and Distribution interface

Description

The target operating voltage at the interface between Transmission and Distribution systems is generally operated higher than the nominal design voltage to assist in managing the voltage profile downstream at times of high demand and to reduce network losses. The current higher voltages at the interface accounts for voltage drops across the Distribution networks; however the target voltage can be reduced to nominal whilst remaining within statutory limits at the lower boundary, particularly at times of lower network demand which generally coincide with the minimum demand periods; it is these periods which typically present a challenge to the transmission system operator. Lowering the target voltage at the transmission and distribution interface will increase the current drawn through the super grid transformers (SGT) thus increasing the MVAr demand generated by the reactive elements. Additionally, capacitive elements operating at lower voltage will produce less MVArs.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Routine

Super grid transformers target voltage is set by the System Operator in agreement with the DNO at each super grid site and it is controlled by the System Operator within a selectable range. The same process could be used to address high volts as currently exists between DNO and TSO. To implement this option a series of studies to assess system impact would need to be carried out. Where viable, the target voltage of a transformer can be changed remotely if remote control is installed. Further assessment is required to understand the impact of voltage reduction on demand across all the voltage levels. If a change in target voltage is required, there would need to be coordination between transmission and distribution operators.



At this level implementation can be achieved within minutes as SGTs target voltages can be updated remotely by NGETs control room. Significant shifts in voltage may require studies to confirm voltage compliance is maintained on the downstream Distribution networks but implementation would be agreed between the Transmission and Distribution control rooms in any case.

Costs


As this option reflects existing network design capability but would require additional planning liaison, whilst some operational costs could result these are expected to be minimal. There is similarly no evidence to suggest that the incremental changes in tap changer action involved in setting different voltage targets periodically would lead to any significant asset maintenance or management impacts. Considering that the System Operator already has remote target voltage control capability, CAPEX is not required.


Commercial Impact


Where EHV Distribution networks are near their thermal design limits, operating at higher voltages provides a slight enhancement to the power the existing assets can provide and so can delay capital reinforcement. Where networks are near full utilisation there must be a cost benefit analysis performed to make a decision on whether reducing the voltage in a specific area is cost effective considering the cost of the Distribution capital reinforcement versus the cost of the actual MVAr removed from the system as provided by NG.

Regulatory Impact


This option will potentially increase technical losses on the system. This may be in conflict with the distribution losses discretionary award and transmission losses incentives, which target losses to be as low as reasonably practicable. Coordination between measures to reduce losses and measures to increase reactive absorption is needed.



None

Advantages


This option has been trialled and deemed successful. As this control already exists the implementation of this solution could be immediate and at no additional cost. This solution modifies the voltage profile at EHV level; hence its impact on the HV network and the majority of customers will be minimal due to the downstream primary voltage control. Also, as this solution is at the higher voltage levels there are fewer transformers to make this change to.

Disadvantages


The actual extent of reactive gain depends on the network loading and electrical characteristics. Also, this measure may interfere with performance of other equipment (such as shunt connected reactors).


This option does interact with some of the other solutions e.g. tap stagger and switching out networks and so must be considered as a whole to address the VAr issue, making sure the most appropriate option is taken. Consideration needs to be taken on how distributed EHV connected generators interact with this in practice.

References

Existing R&D: DIVIDE Project.

Quantification

The NG South West summer time trial reported a 30MVAr reduction as a result of lowering the target volts at all GSPs in the South West peninsular (WPD South West region and a small part of SEPD). Different network configurations may yield different MVAr responses and a further piece of work lowing target volts along the South coast of England is planned for this Easter.


2.1.8 Option 8 – Increased use of existing Transmission generation

Description

This option requires the SO to increase the degree of constraining on of available generation in areas most effective of managing high volts issues, displacing generation that would otherwise run in other areas. The generation, one constrained on, would be instructed to absorb MVArs to their maximum capability.

This action is becoming increasingly more costly and problematic to procure given the decline in transmission system demands at system minimum conditions also occurring across recent years, and the progressive closure of thermal generation sited close to the transmission-distribution interfaces observing imbalance. This option describes the current default SO action, explores its longer term sustainability and whether any latitude for enhancing it exists.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Where generation is constrained on to provide services it requires a minimum generation MW output (normally 55% of its maximum output) to be accommodated within the balancing of the system. in order to achieve this accommodation, the SO has already had a number of experiences (known as Negative Reserve Active Power Margin events, either nationally or locally) where it has needed to take action to remove DG contributions at these minimum times to achieve balancing space to constrain on the transmission connected generation to provide high voltage containment benefit. DG can additionally be instructed off the system by instruction from the SO to the DNO in emergency conditions via use of Grid Code BC.2.6 arrangements- for example where difference between forecast and actual active or reactive power exchanges occur in real time. Limited opportunity exists to enhance this existing action which continues, year on year to increase in BSIS cost to GB consumer. One option discussed within SOF 2015 of obtaining lower minimum generation operating level capability from existing generation could potentially enhance capability, however would equally increase the emissions in such low load operation from those generation subject to such restrictions which could hasten timeframes of closure. However the current position in routine operation is of declining generation resource availability

In the context of emergency operation, whilst generation can be dispatched in real time where available the challenge for the SO is in estimating the requirement based on the scale of demand forecast error. The SOF 2015 chapter 6 notes the growing average demand forecast errors due to DG penetration. The operator needs a view up to five hours ahead on the extent of the challenge in order to schedule in the balancing market services which would otherwise not be available. This demand forecast error of up to 800MW on minimum demand equates to an uncertainty in being able to bring on some 3-4 units of transmission generation operating at Declared Minimum Operating Level. This drives in the short term closer working across the industry to reduce or better quantify these uncertainties to support emergency action, or alternatively de-load or disconnect DG across periods where supporting transmission generation cannot be made available due to such forecast uncertainty. As with routine, any increased constrained on transmission generation would increase the risk of DG curtailment in order to facilitate the balancing consequence of accommodating the minimum generation level of the constrained generation at times of ever lower minimum system demand. As discussed in National Grids Future Energy Scenarios 2015 and SOF 2015.



Implementation is only viable across short- medium timeframes. The problem in the sustainability of this option is that, as discussed in the FES 2015 chapter 7 balancing sensitivity, when transmission system net demand declines past 2019/20 in the FES scenarios we cannot be bringing off the 10s of GW of additional projected DG in these scenarios to find space for transmission generation at minimum output to run in the right locations. FES also notes that those generators are becoming increasing unavailable to the operator as closures and a reduced transmission system demand overnight constrains the energy market diversity at those times. A final note is that existing generators notwithstanding emissions positions include plant towards the end of its technical life. as such the availability of this option declines across the short-medium horizon, but may provide time for other options to be developed.

Costs

Capex costs are extremely small as existing suppliers of service already by virtue of being Balancing Market participants may be dispatched to provide reactive power support. Conversely however Opex costs are very high (BSIS cost) - currently spending £90m p.a. on gen contracting + c. £3m per month utilisation over April- Oct. costs increasing year on year

Commercial Impact

Given the incentives surrounding energy market payment are biased towards payment and incentive of MW supply it is difficult for long term contracting to ensure continued availability of generation potentially at even lower MW output operation than would normally apply to provide the reactive power services more specifically valued at times of lower active power balancing. Economic, age and emission restriction drivers influencing peak and other aspects of year round operation continue to drive a picture of generation closure or reduced availability at these periods of low demand.

Regulatory Impact

Regulatory challenges come in the mechanisms whereby continued generation service is available, be it transmission connected or embedded at times of limited transmission system demand are not clear. The mechanisms to dispatch small and medium generators for reactive support or to reduce the output of generation unable to support voltage management which are not Balancing Market participants are not clear and as such may lead to inefficient actions in overall dispatch such that the limited degrees of freedom in MW balancing actions at these times are also respected.


None.

Advantages

Existing measure which will continue to be utilised where available, economic and sustainable.

Disadvantages

Rapidly unsustainable due to gen unavailability/ closure. Excessive use of generation for reactive power absorption can be counterproductive to the operator resulting in vulnerabilities to single generator trip conditions, degradation of network stability margins and foreshortening the periods between the generators requiring maintenance.


This option conflicts with alternative options to convert existing generation to synch comps- you cannot do both with the same plant.

References

Existing network experience- see National Grids 2014 and 2015 System Operability Framework.

Quantification

In practice the SO has been, where practicable constraining on additional transmission generation to address this distribution system trend of increased MVAr export at low demand periods to the


transmission system, spending some £90m p.a. in recent years on the constraining on of such generation, together with approximately £3m/ month costs of utilisation of reactive power over an extended summer period of high usage.


2.1.9 Option 9 – Switching out Transmission Circuits

Description

Lightly loaded transmission circuits have an associated high MVAr gain which naturally increases the voltage level of the power system. At the transmission level, National Grid has nominated a number of circuits which the control room are able to switch out for voltage management purposes. Switching out lightly loaded circuits is a key component in the reactive power management strategy of National Grid and multiple circuits are switched out daily. An assessment of system security should be made in case the switched out circuit fails to return to service. The main advantage of the option is that it is an established measure used in daily operation and is effective in directly reducing the transmission level voltage. The disadvantages are the potential high asset costs and risks associated with frequent switching of the circuits. A longer term solution would be to design transmission circuits from the onset as voltage control circuits.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

It is possible to further extend depletions if post fault restoration of circuits is done- impact would be degraded post fault voltage stability and thermal performance ahead of restorations- such additional depletions would need to be behind high reliability automation systems and enhanced plant specifications on the circuits involved. A longer term solution would be to design transmission circuits from the onset as voltage control circuits.


This option may be achieved in the Short/Medium term as system studies are required to further identify potential voltage control circuits and assess system security risks.

Costs

This option has potentially high CAPEX implications due to increased duty cycle on switchgear assets. The increased maintenance durations due to assets being switched at high voltages and/or high transient inrush conditions could result in medium OPEX cost implications.

Commercial Impact

N/A

Regulatory Impact

This option reduces the security of supply thus has the potential to increase NGET ENS and DNOs CI CML risk.


Maintenance practices and procedures of plant switched frequently at high voltages and/or high transient inrush conditions would need to be reviewed and updated as required.


Advantages

The main advantage of the option is that it is an established measure used in daily operation and is effective in directly reducing the transmission level voltage.

Disadvantages

The disadvantages are the potential high asset costs and risks associated with frequent switching of the circuits. In addition, DNOs are reluctant to reduce the security of supply and expose their customers to increased risk of interruption.

References

There is a National Grid SO internal business procedure for switching out voltage control circuits.

Quantification

National Grid has designated approximately 30 circuits totalling 3 GVArs of reactive gain that can be switched out of service for voltage control purposes during periods of low demand. The voltage control circuits are grouped into four different usage categories depending on their MVAr gain, ease of switching and wider impact on the transmission system.


2.2 Medium Term

Five options were identified for medium-term implementation (some of which are available for emergency operation under different timeframes).

2.2.1 Option 10 – Reactive Power Services from Demand and Generation

Description

This option enables new and existing demand and generation customers to provide a reactive support response to the network as a service rather than a mandate. A prerequisite to this option is that a customer complies with existing connection agreement limits, and corrects for sole use assets.

This option looks to incentivise the customer to provide reactive power support to deliver a benefit to the network over and above the requirements of their connection agreement. This must be within their capability to deliver, and the DNOs capability to accept such services within their networks at those times. DNOs will need to determine the maximum cumulative response capabilities of the network and any restrictions that may have to be applied.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Routine

Incentive levels need to be set appropriately to cover the initial setup cost and operation of communication channels. It also has to offset any loss of generation revenue during the response, but produce a wide enough uptake to prevent it becoming a premium rate service. A study of the local network will be required to determine the existing P/Q operating envelope. Most connections to distribution networks were designed on the basis of a fixed power factor; and may be capacity constrained in a different mode of operation.

A monitoring system would have to be put in place to enable the service and ensure that the system is achieving the desired response. Implementing the response will require reliable communication channels to inform the customers when they are required to provide the service. The need to provide the service will ultimately be triggered by high voltage on the transmission network; however the implementation of the service could be via NG direct, NG via a DNO / DSO or by third party aggregators. A coordinated approach to planning, managing, and operating these services will be required between DNOs and TSOs. Identifying the appropriate funding mechanism for payment to customers for these services will need to be clarified with the regulator.

Emergency

It may be possible to implement provision of reactive demand on an emergency basis but if no commercial agreements have been set up between parties and no communication links installed it will require direct communication between the DNO control room and the active participation of the customer in order to realise any benefit . Any agreed reactive power flows need to take into account the capabilities of the existing network, which may ultimately be the limiting factor.



Routine

Implementation timescales are likely to be medium to long. There would be a need to set up adequate incentive schemes and monitoring systems; these are likely to be on the critical path for any implementation.

Emergency

For an emergency response this could be implemented in a short timescale but offers no guarantee as to whether generators are prepared to respond, unless direct control schemes and/or commercial agreements are in place.

Costs

Routine

The costs will mainly be OPEX for operating and managing the communication channels and making incentive payments to customers. The costs for the customer will be a combination of CAPEX and OPEX with the need to install suitable equipment, and carry out the ongoing maintenance and operation. Future EU codes will require generators to have sufficient generator capability as the normal. Even when plant is suitable to operate over a wider power factor range, there may also be significant CAPEX implications for the local network in order to accommodate this wider range. For new customer’s alternative, more expensive, connection options may have to be considered in order to allow operation over a wider power factor range, when compared to current practice.

Emergency

As an emergency response this can only be applied to sites which already have appropriate capability and suitable network connections able to accept this capability. If done under an ad hoc arrangement costs would be low.

Commercial Impact

Routine

New Connection agreements will need to be drawn up providing details of requirements together with incentive payments for providing the service and penalties if service is unavailable. However customers should not be incentivised to mitigate for any adverse effect their sole use asset may impose on the network.

Emergency

This option may require new connection agreements if existing connection agreements are not sufficient.

Regulatory Impact


No framework exists for DNOs to manage and control customer reactive response within the distribution network. It is expected that changes may also be required to relevant industry codes. Identifying the appropriate funding mechanism for payment to customers for these services will need to be clarified with the regulator, and may necessitate a move towards DSO.


Routine

This will need to be assessed as the option is developed.

Emergency


Advantages

Routine


The market led approach offers the potential to have wider participation from existing customers, with a greater opportunity to have a more precisely tuned response to the network needs. An advantage over a fixed power factor or time of day regime is that it can help to avoid costly losses when the response is not required.

Emergency

Ad hoc arrangements with specific generators may provide a viable short term response to cover emergency conditions at very little extra cost providing the customer is only asked to undertake the response in a very few infrequent situations.

Disadvantages

Routine

Market response to events on the transmission system may result in non-optimal running conditions for the distribution network. This can lead to congestion challenges and power quality issues. Furthermore, this may increase technical losses on the distribution network. Even though a customer may be willing and capable of offering reactive services the existing network may be unsuitable to cope with the new reactive power flows. Network reinforcement or restricting reactive flows to within the current network capabilities may be required.

Emergency

Emergency response is likely to require significant effort at the time of the emergency in order to achieve benefits. If no agreements have been put in place and no financial rewards are available many customers may not agree to provide the service.


Due consideration needs to be taken to the impact on voltage profiles in coordination between this, distribution voltage control schemes, and the options listed above which are Switching Out of Transmission/Distribution Network, and Tap Stagger.

References

A joint funded innovation project between NGET and UKPN called “Specification of Embedded Efficiency from Solar And Wind connections (SEESAW) project may provide further learning on this subject.

Quantification

A full cost benefit analysis and an expression of interest would need to be carried out in order to understand the full reactive capabilities available to the network from market participants.


2.2.2 Option 11 – Customer Demand Response through Tariffs

Description

This option refers to the use of tariffs to incentives the operation of customers within specified power factor limits.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Market Changes to incentivise Time of Use to enable more useful outcomes for the system. Stronger power factor signals could be included in half hourly tariffs for time of use kVA and also time of use VArs.

A study of the local network will be required to determine the existing power factor operating envelope. Most connections to distribution networks were designed on the basis of a fixed power factor; and may be capacity constrained in a different mode of operation.


Medium to long term as Use of System charges are set through to 2018.

Costs

Opex only for DNO, although customer may require capex to implement solution.

Commercial Impact

There is a major commercial impact to the proposed solution. The distributors can only apply charges through their Use of System (UoS) charges. In all but a handful of cases, these charges are billed to the supplier who is registered for the relevant metering point (import or export). The supplier may or may not pass through charges in the same format (or even to the same value) as the distributor – there is no requirement for, or compulsion on suppliers to pass charges through as they are levied.

UoS charges are also only one component of the customer’s ultimate bill – they therefore only make up a proportion of the end costs. Changing (or in some cases introducing) power factor charges in UoS may not result in particularly material cost signals overall. It is also potentially the case that many customers will place production or lifestyle priorities ahead of cost considerations and will simply tolerate higher charges, taking no action.

In relation to time of use type charges in UoS, the times at which a distributor wishes customers to use or not use their networks may or may not align with cost signals in the energy market. The energy cost in a customer’s bill is normally the largest single component, so variations in energy charges to reflect market conditions (or the supplier’s energy purchasing position) are likely to be the strongest element. Variations in UoS charges may simply be lost in the mix.

Therefore, cost signals in UoS may or may not act as viable incentives for modifying customer behaviour. To work well as a driver to implement power factor adjustment by customers, the charges would have to be pretty severe. However, distributors could only charge on a cost reflective basis – based on their own costs incurred. There would have to be changes to the existing methodologies (CDCM and EDCM) to incorporate a different approach and this is likely to take a lengthy period to


achieve. The DNOs have issued their UoS charges for the period through to March 2018, so April 2018 is the earliest possible date for any changes to UoS charging to be implemented.

However, distributors must now provide a minimum of 15 months notice of new (or amended) UoS charges, so any changes to the basis of charging would have to be fully resolved and approved by the late autumn of 2016 for April 2018 implementation. Given the extent of charging development and governance processes involved, it is unlikely that this target could be achieved and an earliest implementation date of April 2019 may be more realistic.

For matters such as influencing power factor on distributor networks, as this is a dynamic variable rather than a fixed condition, having fixed parameter penalty or incentive arrangements (as has traditionally been the case) may not be a sensible approach. It is however challenging to foresee a mass customer market which can respond dynamically. There may be some large scale embedded generation and large demand sites which could provide response services, but this would be more appropriate for bespoke contract arrangements (between the customer and the relevant system operator) than by amendments to the mass UoS tariffs.

Regulatory Impact

The proposed solution entails significant market revisions. DUOS tariff methodologies are subject to DCUSA governance and its change process.


Code changes and guidance notes to new customers would be required

Advantages

The proposed solution is cost reflective and makes effective use of existing infrastructure.

Disadvantages

Implementing significant incentives to drive change is likely to be a major challenge and the proposed solution entails a significant change to the market. As discussed within the Commercial Impact section above there may be limited incentives which can be practically employed to incentivise changes in customer behaviour.


None

References

National Grid Demand Turn-up (Power Responsive)

http://www2.nationalgrid.com/UK/Industry-information/Future-of-Energy/Power-Responsive/

http://www.powerresponsive.com/

Quantification

This option requires detailed investigation to understand benefits and challenges.




2.2.3 Option 12 – Active Power support

Description

Increasing active power flow in the network increases the voltage drop and helps to reduce the voltage in the transmission network. It also allows additional generation to be connected which could then be used to provide additional reactive compensation. This option includes the development of active power incentives, an active power market, and the necessary infrastructure to provide active power support.

This option will predominantly target storage customers, commercial demand customers, and distributed generators. At this stage of development it will exclude domestic customers.

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

Routine

Incentive levels need to be set appropriately to cover the initial setup cost and operation of communication channels. It also has to offset any loss of revenue during the response, but produce a wide enough uptake to prevent it becoming a premium rate service. A monitoring system would have to be put in place to enable the service and ensure that the system is achieving the desired response. Implementing the response will require reliable communication channels to inform the customers when they are required to provide the service. The need to provide the service will ultimately be triggered by high voltage on the transmission network; however the implementation of the service could be via National Grid direct, National Grid via a DNO / DSO, or by third party aggregators. A coordinated approach to planning, managing, and operating these services will be required between DNOs and TSOs. Identifying the appropriate funding mechanism for payment to customers for these services will need to be clarified with the regulator. A study of the local network will be required to determine the existing P/Q operating envelope of the network. Shifting or creating demand risks network overloads, even where individual customers do not exceed their Agreed Supply Capacities, due to demand diversity assumptions made by DNOs.

Emergency

It should be possible to implement provision of active power support on an emergency basis providing that appropriate commercial agreements and control systems are in place


Routine

Implementation timescales are likely to be medium to long. There would be a need to set up adequate incentive schemes and monitoring systems; these are likely to be on the critical path for any implementation.

Emergency


For an emergency response this could be implemented in a short timescale but offers no guarantee as to whether customers are prepared to respond, unless direct control schemes and/or commercial agreements are in place.

Costs

Routine

The costs will mainly be OPEX for operating and managing the communication channels and making incentive payments to customers. The costs for the customer will primarily be OPEX to carry out the ongoing maintenance and operation, with a CAPEX element if additional equipment is required.

Emergency

As an emergency response this can only be applied to sites which already have suitable capability and if done under an ad hoc arrangement costs would be low.

Commercial Impact

Routine

New Connection agreements will need to be drawn up providing details of requirements together with incentive payments for providing the service and penalties if service is unavailable. Payments need to be kept well below the costs of the active power consumed to ensure that the customer is encouraged to shift his demand profile, but not to create demand for demand’s sake.

Emergency

This option may require new connection agreements if existing connection agreements are not sufficient.

Regulatory Impact

Routine

No framework exists for DNOs to manage and control customer active power response within the distribution network. It is expected that changes may also be required to relevant industry codes. Identifying the appropriate funding mechanism for payment to customers for these services will need to be clarified with the regulator, and may necessitate a move towards DSO.

Emergency

None.




Advantages

Routine

The market led approach offers the potential to have wider participation from existing customers, with a greater opportunity to have a more precisely tuned response to the network needs. An advantage over a time of day regime is that it can help to avoid costly losses when the response is not required. There are potential synergies available with National Grid’s current balancing service contracts, for example frequency response.

Emergency


Ad hoc arrangements with specific customers may provide a viable short term response to cover emergency conditions at very little extra cost providing the customer is only asked to undertake the response infrequently.

Disadvantages

Routine

Market response to events on the transmission system may result in non-optimal running conditions for the distribution network. This can lead to congestion challenges and power quality issues. Furthermore, this may increase technical losses on the distribution network.

Emergency

Unless an automated emergency disconnection scheme is in place, an emergency response is likely to require significant effort at the time of the emergency in order to achieve benefits.


None

References

National Grid Demand Turn-up (Power Responsive)



Quantification

A full cost benefit analysis and an expression of interest would need to be carried out in order to understand the full active power support capabilities available to the network from market participants.




2.2.4 Option 13 – Reactive Compensation

Description

This option involves installing reactive compensation equipment (e.g. shunt reactors, static VAR compensators etc.).

Category

Primary Category


Network Operations

Secondary Category


Network Application



Actions Required

For all connections, an initial whole system assessment and cost benefit analysis would be required to understand the optimum location for reactive compensation to be installed i.e. either on the transmission or distribution systems. Where the optimum solution is on the distribution network, the affected network owner will need to apply for additional funding from the regulator.

Depending on the location and system requirements, differing reactive compensation equipment could be utilised. A coordinated approach to the control and operation of the equipment would need to be developed to ensure an appropriate response to transmission and distribution system requirements.


This solution could be initiated in the short term, but due to a significant project lead time would be implemented over the medium to long term.

Costs

The costs associated with this are primarily Capex for the cost of additional plant. These costs are expected to be high. There is an associated Opex cost for the ongoing operation and maintenance of the plant.

Commercial Impact

There is minimal commercial impact but each case would need to be balanced with the transmission and distribution regulatory requirements to minimise losses.

Regulatory Impact

This option will potentially increase technical losses on the system without an appropriate control philosophy. Flexible or automated switching are alternative options to minimise this impact that could be investigated at additional cost. This needs to be considered from a regulatory perspective as this may be in conflict with Distribution Licensees requirement (SLC49) which targets losses to be as low as reasonably practicable. Any additional expenditure will need to be agreed with Ofgem.


Reactive compensation will have a direct impact on distribution and transmission voltages and could allow additional generation to be connected.

Advantages

The option is relatively simple to implement, the technology is proven and in relatively widespread use.


Disadvantages

There is a high initial cost for this option, and the lead time from inception to installation plant which at transmission voltage scale has been shown to be approximately 2.5 years. The equipment takes up significant space. The lead times for plant are relatively long with limited manufacturer capability which would need to be managed on a whole industry level. Technical losses will also be increased.


In areas of the network where the requirement for reactors is more variable, or where there is the potential output change to rapidly transition between a lightly loaded system to a highly loaded system, it may be that other more flexible options, for example synch comps, SVCs, Statcoms, Variable Shunt Reactors, may be a more appropriate solution.

References

REACT Project

Quantification

ENTSO-E estimates the cost of shunt reactors to be:

275kV: £20k per MVAr

132 kV: £31k per MVAr

The REACT project concluded that one MVAr at 11kV equates to 1.01 to 1.03 MVAr of benefit at the T/D interface.9 REACT also quotes typical 132kV reactor costs at between £25k and £45k per MVAr and at transmission level £40k per MVAr.

————————— 9 Source: Deliverable 5, Second Year Final Report Stage 2 – REACT Project, 18 August 2015, section 4.1.2, p20

for the two GSPs under analysis.


2.2.5 Option 14 – Using former generation sites as synch comps

Description

Internationally a number of electricity systems have responded to the impact of closing synchronous machines with measures to retain the turbogenerator in a de-clutched form, operating as a synchronous compensator by Network Owners. This approach has tended to manifest in more vertically integrated markets than that of GB, and has tended to be in response to issues surrounding a dynamic voltage control deficit.

Within GB, the SO and DNOs (should any embedded medium scale synchronous generation closure have relevance to the management of high volts containment) could choose to flag value for such generation to remain connected- funded via a suitably formulated and agreed Market arrangement with Regulator and government.

In order for such generation to operate in synch-comp mode, capital works on the associated generation fleet to either de-clutch or to support the entirety of the turbo generators mass being motored by the electricity system would need to be agreed, as would arrangements to support the operational costs associated with motoring that mass via the electricity system or some other fuel source (suggesting some degree of energy balancing impact). It is noted that in the closures of these existing generators, much of the associated material surrounding the Turbo-generator is "sold-on" to external parties and as such the market would need to be appropriately forwards looking and forwards incentivising were it to achieve the desired objective of this option.

This option, whilst focusing in on the opportunities surrounding existing generation sites, does not preclude the re-planting or development of off-the-shelf synch comps by other providers in similarly effective locations.

Category

Primary Category


Network Operations

Secondary Category


Network Application


*


*limited scope at distribution level.

Actions Required

Whilst technical solutions are known and in practice internationally, they imply high cost modification, logistical challenges which may require planning/ consent to effect and clearly a sufficiently robust market incentive for such modification to take place to ensure effective generation do not decommission without replacement services. Finally, given effectiveness of the service is locational and resource is limited the facilitation of market arrangements surrounding scarcity pricing would need consideration as whilst TOs and DNOs and others could compete with other sources of dynamic response, there would be a natural time lag between the need identification of and construction of around 2.5 years to install any alternative to the generator.


This work would fit into medium- long term in delivery but has a short term critical path to it should the retrofit of existing plant anticipated to close in the next few years is to be considered against this option.


Costs

Capex costs would be specific to the project under consideration and the extent of works associated with the conversion. Introduction of a clutch would require multiple £ms in cost both for the plant itself but further the more extensive modification of generator turbine support and housing as the additional clutch is introduced into the overall drive-train of the unit. Alternatives would involve additional generation supporting the operation of the turbine shaft in a synchronous compensation mode. Opex would continue to be analogous to the existing costs in managing the operation of the generator turbine ahead of its conversion to synchronous compensation operation.

Commercial Impact

Commercial impacts relate to the current Reactive Market, where utilisation derives payment but value is low in materiality in comparison to MW payments currently defining the availability of the generation. Value to such dynamic voltage support capability is more appropriately evaluated in comparison to Statcom/ SVC TO/DNO investment avoidance- this is in having dynamic capability available post fault which is not funded currently within such Reactive Markets. there is however past experience (note the past Indian Queens arrangements) in the SO procuring synchronous generation services from the market, against past market environments.

Regulatory Impact

Regulatory impacts relate to the lack of a clear framework to incentivise or manage such changes of use. Additionally, Grid code changes and additional compliance tests to accommodate the use of such providers may be required.


Given the experience of both the procurement and operation of synchronous compensation, no significant areas of best practice change are anticipated.

Advantages

There is potential for such approaches to represent a cost effective alternative to SVC technology where specific requirements are identifies and the costs and duration of conversion is compatible with the value and timeframe of network need. This option provides additional technical benefits to SVC or STATCOM type solution in voltage control from:

high overload capability

fast response

fault-ride through supporting voltage; dips during fault conditions

transient and temporary over voltage (TOV) suppression, and

increased system inertia f) limited control interaction issues.

Disadvantages

High costs to modify, costs in fuel/ losses associated with operation. High maintenance overhead & staffing/ support requirement requiring skill sets non-core to TO/DNOs.


This option conflicts with alternative options to increased use of existing transmission generation - you cannot do both with the same plant.

References

Germany- redundant transmission generation conversion to synch comp operation. Example discussed below. In cases such as old nuclear sites as discussed in this example where a continued support presence is required in staff and electrical infrastructure some of the ongoing costs can be offset.

http://www.energy.siemens.com/ru/pool/hq/automation/power-generation/electrical-engineering/e3000/download/biblis-a-rwe-power-ag-electrical-solutions-generator-synchronous-condenser_sppa-e3000.pdf

USA – Keys Electrical System





https://online.platts.com/PPS/P=m&s=1029337384756.1478827&e=1098466519740.8526804947352021850/?artnum=20D0yB40b81016e0iW1v27_1

Quantification

Costs are technology dependent and the optimal solution may vary significantly between original vendor suppliers.

Across NGETs Future Energy Scenarios, closures of existing thermal plant are anticipated, and it is observed that between FES 2015 and FES2014 there was an increased reduction in thermal capacity of 2GW, which occurred with further projected closures of a number of existing coal, older non-converted CCGT plant, and Magnox Nuclear generators anticipated between now and 2020/21, based on age and emission related restrictions. These power stations:

utilize a range of generation scales between 250 MW and 660 MW in unit capability each

have a reactive capability compatible with Grid Code Connection Condition CC.6.3.2 (a range of 0.85 power factor generation of MVArs, 0.95 power factor absorption of MVArs), and

provide total system support of between 82 MVArs and 217 MVArs of absorption capability per unit.

The benefit of conversion would be considered against the cost benefit of alternatives.




2.3 Long Term

One option was identified for long-term implementation. It is available for emergency operation in the short term.

2.3.1 Option 15 – Dispatch of Distributed Generation

Description

This solution requires the switching in/out or modification of PQ set-points on new and existing generation connected to the HV/EHV system. This is the converse of option 12 above which increases distribution system demand. For this option, the generation output is modified to increase distribution system loading which both decreases the gain of the transmission and distribution systems but also provides balancing space for localised reactive power support decisions.

Category

Primary Category

Contractual Market Network Design Network

Operations

Secondary Category


Network Application



Actions Required

Routine

Further investigation is required to understand the commercial implications of managing a distributed generator’s export. This would need to consider the existing commercial framework and terms of connection. Either a DNO or TSO could dispatch/manage the customer’s generation export. The frameworks involved need to be created to manage this (relates to potential DSO evolution). This would include understanding:

what level and type of service can be provided by customers

whether the customer’s equipment can interface with existing network control systems

what would need to be put in place to cover potential failure to disconnect

the level of generation that networks would have full control of

is the automation and control infrastructure in place to disconnect generation without having to interrupt supplies to other customers, and

the impact on customer/DNO equipment due to a significant increase to switching operations.

Emergency

Standard terms of connection should allow for any customers to be disconnected in emergency conditions. This would include understanding:

the commercial implications of disconnecting customers who only have generation versus maintaining supplies to those with demand and generation, and

system impacts of switching out entire customer substations that may leave large cables connected to the distribution network which could negate the benefit of disconnecting the substation.



Routine

This will require regulatory and commercial frameworks to be setup. This may therefore only be suitable as a long term solution. The level of interaction between customer, DNO and TSO may make this only viable when DSOs are established.

Emergency

Currently the option to constrain distributed generation active power under emergency conditions is available via the Grid Code and Distribution Code.

Costs

Routine

This may require Capex to establish enhanced automation and control systems with customers. Opex would be required to cover the increased operation and maintenance costs, the establishment of a despatch system at distribution level and to establish an availability and constraint payment mechanism with customers

Emergency

This is dependent on whether any enhanced automation and control is required for standard emergency curtailment of generation.

Commercial Impact

Routine

This would require a change in the market and commercial agreements with customers. This could include development of a market, tariffs, customer incentive mechanisms, and new business models.

Emergency

Generators may request changes to the existing frameworks to allow for more significant constraint payments than currently exist on the distribution network.

Regulatory Impact

Routine

Code changes would be required to facilitate changes in terms of connections. Ofgem will need to consider other dependent incentive mechanisms.

Emergency

None


Routine

A co-ordinated market across both distribution and transmission would be required so that the optimum whole of system solution is obtained in each instance.

Emergency

This will lead to interruptions to customers, and would require appropriate policies to manage this.

Advantages

Routine

This provides effective use of existing infrastructure and network connected resources, while also enabling a market led solution for high volts. It would also establish a market at distribution level, thereby providing an ancillary market for distributed generation services and enable more cost reflective charging.


Emergency

This is a cost effective option that is available immediately. It could provide a high impact response, by releasing network capacity and by getting the desired generation response on the system in emergency conditions

Disadvantages

Routine

This may prove expensive in the shorter term depending on the level of automation required to achieve the level of response. However, it’s expected that this would provide a whole system net benefit in the longer term.

Emergency

Assuming that suitable constraint payments exist for emergency operation, then no obvious disadvantages are present.


This option is currently being carried out internationally.

References

1. DSO/Ofgem Flexibility project.

2. German work on controlling high volts with distributed generation:

CIRED 760: Derivation of Recommendations for the Future Reactive Power Exchange at the Interface between Distribution and Transmission Grid

Philipp SCHÄFER, Hendrik VENNEGEERTS, Simon KRAHL, Albert MOSER

http://cired.net/publications/cired2015/papers/CIRED2015_0760_final.pdf

CIRED 964: Flexible reactive power exchange between Medium and High Voltage networks

Ignacio TALAVERA, Peter FRANZ, Sebastian WECK, Jutta HANSON, Sebastian STEPANESCU, Richard HUBER, Hans ABELE


Quantification

Under emergency conditions the disconnection/curtailment of generation could provide benefits in the short term however work must be undertaken to understand the level of capability that exists in the DNO networks and the actual response that would be seen at a Transmission level.




2.4 Non-viable or Exhausted Options

The High Voltage Working Group also considered a number of other options considered non-viable due to either technical or commercial constraints.

2.4.1 Option 16 – Switching Out Distribution Connected Capacitors

Description

This covered the disconnection of capacitor banks originally required by the DNO networks to maintain statutory volts and supplement the reactive power requirements of the local network.

Category

Primary Category Contractual Market

Network Design

Network Operations

Secondary Category


Network Application



Reasons for lack of viability

There are a limited number of capacitor banks remaining on DNO networks that fall into one of three categories:

Units that have already been permanently switched out.

Small units that are required to support the local network but have minimal impact on the wider network.

Large units that are already operated in coordination with the SO.

Hence there is no scope to gain further benefit from this option.

Further Comments

Where shunt capacitors are installed in the future, due regard should be given to their operability for system high volts issues.


2.4.2 Option 17 – Target voltage reduction at HV

Description

The target operating voltage of transformers is higher than the nominal design voltage for the networks. This accounts for voltage drops across the network; however the target voltage can be reduced to nominal whilst remaining within statutory limits at the lower boundary. Reducing the target voltage causes an increase in the current drawn through the transformers thus increasing MVAr demand of reactive network elements. Additionally, capacitive elements operating at lower voltage produce less MVArs.

Category

Primary Category


Network Operations

Secondary Category


Network Application




This option has been considered but discounted due to the high amount of work required to perform analysis to quantify the benefits and check the consequences it has on the voltage profile on the HV and LV network. There is also a potential clash with the demand reduction option for OC6 (i.e. 3% & 6% voltage reduction) and this would require further investigation.

Both the EHV and Transmission interface voltage reduction solutions offer the most effective MVAr gain and the simplest implementation rather than the high volume of transformers that would require automation at the HV level as well as the potential impact on the end user.

Further Comments

The impact on reactive behaviour should be assessed when changes are made to HV target voltage for other reasons (e.g. demand reduction, losses reduction, increasing generation headroom).


2.4.3 Option 18 – Network Reconfiguration

Description

Reconfiguration of the Distribution Networks to increase distribution losses or to modify voltage profile/ GSP tapping to increase parallel network bias to provoke a more lossy supply.

Category

Primary Category Contractual Market

Network Design

Network Operations

Secondary Category


Network Application




The adoption of this solution would have both Regulatory and Commercial impacts for Distribution Networks Operators (DNOs) to consider. To assess the benefits significant network studies would be required to be undertaken which may show that the benefits of such a solution will be varied across the UK and have limited application on networks which don’t have fully SCADA and telecontrol availability to allow network configuration to be carried out remotely.

The introduction of measures to increase technical losses would conflict with Distribution Licensees requirement (SLC49) to manage losses to be as low as reasonably practicable.

The adoption of this solution may also have a detrimental impact on the operation the IIS (CI/CML) mechanism, if through reconfiguration customers were placed at a reduced level of security (and hence greater risk of interruption) than they would normally be afforded. As such DNOs are unlikely to be supportive of such a solution unless the impacts to customers can be sufficiently mitigated through changes to the mechanism.

However, it may be possible, based on a cost benefit analysis, that the costs or value associated with these risks is outweighed by the benefits to the wider GB system/customers through a reduction in system management costs and therefore in the best interests for the consumer that this option be considered.

Reconfiguration of the network could be counterproductive to the aim of reducing voltage, for example creating a circuit with high impedance could result in an increase in voltage for a generator connected to it. It is also feasible that through adopting a revised network arrangement that existing generators will either be constrained off completely or be subject to an output restriction which they are currently not subject to and ultimately this will have a commercial impact for those generators involved.

In addition, there is the potential for increased voltage fluctuations/flicker (and non-compliance with ER P28) arising from increased network switching and reconfigured network running arrangement which would affect customer equipment connected to the affected network.


2.4.4 Option 19 – Network Solutions

Description

This solution involves the optimisation of existing reinforcement projects or the development of new projects in order to consider possible options for reducing the magnitude of the high volts issue on the transmission system. In reality this option will likely lead to an increase in network losses, for example considering the use of higher loss transformers and greater utilisation of network assets.

Other options could include carrying out reinforcements to allow the removal of capacitor banks or cables (and other network equipment with undesirable reactive behaviour).

Category

Primary Category


Network Operations

Secondary Category


Network Application




In the current regulatory climate this option would present a challenge against the current regulatory framework for technical losses management without suitable incentives to do this on a standardised basis for high volts management.

The findings of REACT that capacitance of networks is an important factor in the management of high volts is contradicted by the drive to install underground cable circuits in preference to installing overhead lines, due to difficulties in securing planning permission and consents. These are factors that are beyond the working group’s ability to implement.


2.4.5 Option 20 – Flow dependent voltage control

Description

Flow dependent voltage control strategy (i.e. when resources are at the LV, control the HV volts from the LV rather than the normal assumption that reserves always exist at 400kV and the higher voltages)

Category

Primary Category


Network Operations

Secondary Category


Network Application




In all likelihood this option would require a distribution system operator role to be developed with potentially new services and associated agreements between parties being required. This solution represents a significant change in established voltage control practices that have stood since the 1930’s. However, as we move to a low carbon dominated network, this maybe inevitable.


3 Research and Development

The challenge of managing high volts on the transmission network is being actively addressed through research and development. This section provides a non-exhaustive summary of related innovation projects.

3.1 REACT

http://www.smarternetworks.org/Project.aspx?ProjectID=1460

The REACT project confirmed an underlying trend of active/reactive power ratio decline, contributed to by both demand and generation. While it did not focus on the origin of these effects it provides future trending based on carrying forward the historical behaviour. The underlying cause of the load behaviour is currently the subject of international and national research focus.

The project noted increasing level of underground cable on the networks, and that assumptions relating to overhead line circuits need to be reviewed as the networks become more capacitive in nature. This is something that the ATLAS project plans to assess.

REACT made predictions about the scale of compensation requirement (of an equivalent order to the separate assessments conducted within SOF 2015), and found that reactive compensation when installed with active control can be used without significant losses.

3.2 ATLAS


The ATLAS project will build on the outputs of REACT and should give further insight into the declining active/reactive power ratios at GSPs by the end of 2017.

Relative to REACT, there will be more detailed analysis of forecasting the active/reactive power demand at primary substations during periods of minimum load. The project will also assess the contribution of cables to the reactive power gains on the networks using REACT’s recommendations instead of detailed network modelling. ATLAS will extend the analysis to understand the impact of different generation types, and other low carbon technologies (REACT considered only future PV trends). This will help to develop scenarios of active and reactive power consistently for primaries, BSPs and GSPs for a complete DNO network (REACT considered a sample of GSPs across all DNOs).

3.3 CLASS


The CLASS Project showed how voltage management could provide demand response and a reactive mechanism for frequency management/voltage control. It also confirmed that these approaches do not:

affect customers or compromise a DNO's existing demand control obligations, or

have a detrimental effect on asset health. The CLASS trial utilises existing infrastructure to deliver reactive power at GSPs.

3.4 DIVIDE


The DIVIDE project aims to:

improve the modelling capability of the existing voltage-dependent behaviour of active power demand, and

identify future capability and strategies to maximise benefit.





3.5 SEESAW

This is still at proposal stage. The SEESAW project aims to address the technological/commercial challenges and opportunities for embedded generation resources for use in:

a range of voltage control strategies, and/or

the provision of reactive services during periods of no or low MW output.

3.6 Network Equilibrium


The Network Equilibrium project will demonstrate how voltage and power flow management approaches can improve the utilisation of DNOs’ electricity networks. These methods will unlock capacity for increased levels of low carbon technologies during normal operation and outage conditions (maintenance, new connections and fault restoration).

3.7 Additional international studies and projects

Additional work ongoing internationally includes several international technical groups:

CIRED – Voltage and reactive power optimal control in distribution network with distributed generation, – J. Shi, Y. Liu, 2007.

EURELECTRIC.

ENTSO-E.

European Commission- work has commenced on both a Reactive Power working group and Active Power working group to address the TDI challenges associated with this.



4 Conclusions

Forecasting high volts will continue to be challenging, given the underlying cause of declining reactive/active power ratios is not fully understood. The origins of the decline in reactive/active power ratios will require further research to enable more accurate reactive/active power profile predictions.

The High Volts Working Group identified a series of possible technical options to address this issue for implementation in the short, medium, and long term10.

Short-term options (the next 0 - 12 months)

The identified short-term options (the quantitative impacts of which will vary depending on a particular network’s location) include the following:

Switching out the distribution network operator (DNO) network (circuits and transformers).

Effective technical compliance of connections, for customers that currently do not meet their commercial agreements with the networks.

New connection arrangements.

Tap stagger.

Switching out grid supply transformers.

Target voltage reduction at distribution EHV.

Target voltage reduction at the transmission and distribution interface.

Increased use of existing transmission generation.

Switching out transmission circuits.

The commercial and regulatory barriers relating to these options would also need to be overcome, and that is a dependency not considered in the timeline. For effective compliance of connections, DNOs have already begun to analyse customer’s impact on the system and address accordingly.

Tap stagger and target voltage reduction is currently being trialled in some areas with a view to sharing results with the wider industry.

Medium-term options (12 months–five years)

The medium-term options provide additional flexibility when it comes to operating the system. However, a combination of additional incentives payments, and changes to existing regulatory, technical, and commercial approaches will be required before these options can be implemented at both the transmission and distribution level.

For distribution-level implementation, appropriate monitoring/metering systems will be required to ensure the system is achieving the contracted response. Both distribution and system network operators will need to assess their network’s maximum cumulative response capabilities, the appropriate locations for the service, and identify restrictions that may have to be applied.

The identified medium-term options include the following:

Reactive power services from demand and generation customers.

Customer demand response through tariff incentives.

Active power support.

Reactive power compensation.

Using former generation sites for synchronous compensation.

Long-term options (longer than five years)

Introducing the possibility of dispatch of distributed generation was identified as a longer term option, which could develop increased market participation and flexibility.

————————— 10 Several other options investigated but deemed non-viable/insufficient to address the high volts issue included:

switching out distribution connected capacitors; target voltage reduction at HV; network reconfiguration; and flow-dependent voltage control.


Non-viable/Exhausted Options

A number of options were identified but discounted due being fully-utilised or constrained by factors outside of the group’s influence.

Switching out distribution-connected capacitors

Target voltage reduction at HV

Network solutions, involving the development of new (or the optimisation of existing) reinforcement projects.

Flow dependent voltage control

General findings from the High Volts Working Group project

General findings from the working group include the following:

Charging methodologies are one possible mechanism for optimising system management. Charges to new or existing customers should reflect their connection’s network impact.

The transition from distribution network operator (DNO) to distribution system operator (DSO) will require investment to increase the active network capability at distribution level to support both local and whole of system balancing, and ensure optimal use of assets.

Some options identified in this report will negate the ability to use others.

The distribution network does not have the same level of automation, protection and control as the transmission network, and significant investment and development in the medium and longer term will be required to enable the market-driven options so far identified.

Across the medium and long term, consideration should be given to purchasing plant and equipment with the additional functionality required to better facilitate some of these options

Evidence indicates that some customers are technically operating outside the limits of their commercial agreements, requiring an assessment of the best approach to managing this issue (including enforcement or adjusting existing commercial agreements). Additionally, there may be a preference for a market-based approach, where one customer is penalised for sub-optimal reactive power flows to provide incentives to another customer for optimal reactive power flows. Determining (and pricing) what is deemed to be optimal and sub-optimal will be technically challenging.

National Grid (Great Britain) has forecast that active/reactive power ratios will continue to decline for the foreseeable future, with increasing requirements for upwards of 14 GVAr over the next 20 years, and greater reactive power service requirements (both network and market led). Forecasting High Volts will continue to be challenging, and further study is required to fully understand the decline in reactive/active power ratios and enable more accurate reactive/active power profile predictions.

It may be more cost effective for DNOs to install reactive power compensation plant adjacent to customer Exit Points. Together with the customer's existing reactive power regime, this represents a desirable approach to reactive power compensation behaviour in respect of the wider network.

The undergrounding of networks (wayleave issues, areas of outstanding natural beauty, national parks, etc.) will increase their capacitive impact in terms of reactive power compensation, leading to increasing reactive power challenges.

Network technical losses management should continue to form a part of any future cost benefit analysis.

On a case by case basis, a detailed whole-of-system cost benefit analysis is required to comprehensively determine option implementation costs. National Grid have highlighted that these issues will require consideration by industry parties and Ofgem, and that at the time of the last price control submissions, the high voltage issue and its impact on the transmission network was a developing area of understanding and as such no specific revenue driver metrics relating to allowance for mitigation were agreed. Since that time, the understanding and extent of the problem has increased and as such it is appropriate for a revisit of the funding focus to be undertaken to reflect the various options available across the Network Owners as discussed in this report.


5 Recommended next steps

Table 5-1 lists the recommended steps required to implement the short and medium-term options and their indicative timelines.

This timeline is indicative timeline only, and is dependent on other work streams that do not fall within the remit of this working group (e.g. Ofgem Flexibility Project).

Table 5-1 – Recommended next steps

Recommended step Due date Responsible

1) GSP Planning

Identify TSO PQ forecast requirements at each GSP

February 2017

SO

2) Whole System CBA

Identify three solutions from the report to use as test case for whole systems solutions

Complete trial of whole system CBA on each solution and map the process. Also, identify data exchange requirements for T&D on whole system CBA

Produce short report on lessons learned from the trial and recommendations on how the process could be rolled out in SO, TOs and DNOs

July 2016

April 2017

September 2017

HV WG

HV WG

HV WG

3) Option Implementation

Review short term options and trial/implement as appropriate

Complete short term options cost benefit analysis using the new process (action 2) CBA assessment and ensure continued optimum solution for addressing the issue.

Review medium and long term options and trial/ implement as appropriate.

Complete medium and long term options cost benefit analysis using the new process (action 2) CBA assessment and ensure continued optimum solution for addressing the issue

April 2017

April 2019

2019 onwards

2019 onwards

SO, TOs, & DNOs

SO, TOs, & DNOs

SO, TOs, & DNOs

SO, TOs, & DNOs

4) Stakeholder Engagement

ENA to post this report on their website for feedback and also provide to Energy UK for their members information.

Identify if customers would like to have more flexible power factor control, and assess network impacts of this.

Discussion on services inherent/available now (Customers – Industrial and commercial), where services would require investment, and what signals customers would require for this.

May 2016

Ongoing

Ongoing

ENA

SO/TOs/DNOs

SO/TOs/DNOs

5) Legislative/regulatory changes

Agreeing what active/reactive technical requirements are mandated versus what are services (including ensuring that the SO/DNOs don’t end up paying users to mitigate system issues that the individual users are causing). Once established, ensure compliance before market participation.

DNOs, TOs and NGET to propose options across networks for addressing transmission high voltage issues (based on GSP requirements), including as required derogations that may be required for specific options (e.g. switching out network).

Assess whether there are appropriate funding mechanisms in place for addressing this new challenge of high volts efficiently and present a position statement.

Ongoing/ as required

December 2017

Ongoing

DNOs/SO/ OFGEM

SOs/TOs/DNOs

SO/ OFGEM


Recommended step Due date Responsible

6) Data exchange between transmission and distribution for addressing whole system solution for high volts

Assess requirements both in EU Network codes, and in GB

Develop approach and recommendations, including actions relating to data confidentiality

Propose code changes as required

Address confidentiality issues

June 2017

TDI Steering group to assign to appropriate group

7) Innovation

Develop summary paper and scope for TDI/R&D group on the further innovation study required.

Procure innovation research into the causes of declining Q/P ratio, and refine forecasting with the TSO, and complete study and present outcomes

June 2016

Ongoing

HV WG

ENA R&D managers

Steering Group

8) Commercial Arrangements

Review connection agreements, charging mechanisms and for DNOs, TOs and SOs to ensure flexibility when contracting services and that the high-volts issue isn’t exacerbated through new connection agreements.

Ensuring commercial framework can be developed for flexible and shared services contracts (covering both transmission and distribution system services).

April 2017

April 2018

HV WG recommendation for COG Connections

Shared Services Group

Indicative timeline is dependent upon prerequisite recommendations.


6 Appendices

Appendix A: National Grid work to address high volts issue and decline

The reasons for Q/P reduction were initially considered to relate to a combination of:-

1. Distributed generation growth (reducing the distribution system loading leading to higher gain

effects, and possibly also exporting reactive power at these times)

2. Changes to distribution network (more cables, different operating regime, lower loss design),

3. Demand reduction effects (recessionary pressures, removal of industrial and other load- e.g.

council street lighting turn-off)

4. Changing types of load (for example low energy less inductive light bulbs & power electronics,

prevalence of air conditioning).

5. Energy efficiency measures (devices becoming less inductive in reactive power demand at

lower active demand loading levels).

In order to understand the first of these factors, National Grid in 2014 utilising distribution system data constructed equivalent distribution models to illustrate the change in distribution system network gain against typical system demand conditions, for typical embedded generation output levels.

Figure A1 - How Q/P ratios have changed over the period 2010-2015 (reproduction of figure 42 within the 2015 NG SOF)


Figure A2 - Distribution gain effect calculation relating to embedded distributed generation

This effect at peak demands related to an average 29% contribution to Q/P decline across the GB system which across off-peak periods can become more prevalent- this contribution is greatest at those sites for the periods of time for which active power is exported is limited. In these cases the presence or otherwise of embedded generation makes the greatest impact.

In relation to the second area of Q/P change, the joint NGET and DNO REACT project identified key factors relating to the assumptions surrounding distribution network modelling, highlighted the effect of undergrounding at higher network voltages on increasing voltage at transmission level and related supply level monitoring of reactive and active power with the transmission system challenge. Reference to the REACT work can be found via the hyperlinks within the appendix.

The effects relating to the third area of Q/P change of demand reduction have been found to be minor/ negligible. The Q/P declines have continued beyond initial recessionary and other demand reduction actions and as such no clear trend has yet to be established in such areas.

In relation to the fourth and fifth areas of Q/P change, to date analysis in these areas has been very limited and is difficult to draw any conclusions from, which is a situation reflected internationally. A recommendation to the European Commission for further work in this area has recently been well received (TSO-DSO co-operation platform- feedback from workshop Reactive Power Management- Brussels 26 February 2016), and it is expected that further understanding will develop over time. Notwithstanding further EU research it is possible that in parallel, British standards relating to demand power factor of appliances could be reviewed in order to better understand the contribution and any mitigation measures associated with high voltage containment. This is however an area outside of the immediate expertise and remit of the network owners and operators involved in this paper and would require taking forward within a separate initiative.

This analysis resulted in the following conclusions on provisional reactive trends within the 2014 Future Energy Scenarios relating to peak demand conditions, trends which equally apply to the periods of minimum demand overnight condition.


Figure A3 - The 2014 Future Energy Scenario Peak demand, Q/P ratio trend, versus time (Gone Green shown for illustration)

The importance of controllability

Across the options generated by the group we have a variety of approaches considered which have the potential to introduce risk (predominately quantified in relation to CML/ CMI) and or other impact (for example increased technical losses) when compared to current operational approaches. In all cases however these need to be balanced by both the benefits the approaches provide and the ability to control the manner in which the option is applied. For example, the REACT research illustrates a case study of the switching of 20MVArs of shunt reactor capacity at Norton (NPG) and Kearsley (ENWL) grid supply points on a time control, no control and no reactor offset over a typical summer day. This analysis noted an increase between 2.5-4.1% in technical losses which would occur from an uncontrolled solution but reduced to between 0.7-0.9% for a time controlled system as shown in the following figures 1-7 to 1-9.


Figure A4 - Daily Q profiles at a) Norton (NP) and b) Kearsley (ENWL) GSP using the improved network models of 18th June 2013.

Figure A5- Energy Losses at Norton GSP Group Using Shunt Reactors at Primaries

Case Energy Losses

MWh % Increase (%)

A: no shunt reactors 64.1 1.036 --

B: shunt reactors without time control 65.6 1.062 2.5

C: shunt reactors with time control 64.6 1.046 0.9

Figure A6 - Energy Losses at Kearsley GSP Group Using Shunt Reactors at Primaries

Case Energy Losses

MWh % Increase (%)

A: no shunt reactors 88.8 1.253 --

B: shunt reactors without time control 92.4 1.304 4.1

C: shunt reactors with time control 89.5 1.262 0.7

It is noted that, as both the National Grids SOF and chapter 7 of the Future Energy Scenarios illustrate, the minimum periods of demand for high voltage are expected to progressively change towards both overnight and afternoon (solar-offset) demand periods and as such, time control may become increasingly more complex; however there are other approaches of automation or control that can be applied. All options presented are currently assessed against existing capabilities for control. Note that there is further opportunity for enhanced control and/or automation measures to be considered ahead of the implementation of options. This will minimise the risks and costs associated with the ongoing operation of these approaches (for example in addition to shunt reactor investments, the switching in or out of circuits, varying of voltage profiles or adoption of tap-stagger measures at particular times.

6 12 18 24-20

0

20

40

60

80

time (hr)

Q (

MV

Ar)

Case A: no shunt-reactor

Case B: shunt reactors / no control

Case C: shunt reactors / time control

6 12 18 24-50

0

50

100

150

time (hr)

Q (

MV

Ar)

(a)

(b)


Figure A7: Typical summer voltage profile, GB transmission system 2014/15 (Peak voltages in red)


Appendix B- Plots of PQ Characteristics at points of connection

The following plots show data from distributed generators at the exit point from the distribution network. In each case they show large power factor breaches of connection agreements.

Key

Green area Agreed PQ Envelope

Purple dot One half hour reading

Figure B1: Site A

Figure B2: Site B


Figure B3: Site C

Figure B4: Site D

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