southern africa energy program

DISCLAIMER

This report is made possible by the support of the American People through the United States Agency for International Development (USAID).

The contents of this report are the sole responsibility of Deloitte Consulting LLP and do not necessarily reflect the views of USAID or the

United States Government. This report was prepared under Contract Number AID-674-C-17-00002.

SOUTHERN AFRICA ENERGY PROGRAM

SYSTEM OPERATIONS AND RENEWABLE ENERGY

INTEGRATION REVIEW FOR ESCOM MALAWI March 13, 2020

USAID SOUTHERN AFRICA ENERGY PROGRAM (SAEP) ESCOM VRE INTEGRATION REVIEW

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ACRONYMS

Acronym Definition

AGC Automatic generation control

ARC Auto reclose

AVR Automatic Voltage Regulation

CSIR Council for Scientific and Industrial Research

DC Direct current

EMS Energy management system

HV High Voltage

HVDC High Voltage Direct Current

IPP Independent Power Producer

LOLE Loss of Load Expectation

LOLP Loss of Load Probability

MERA Malawi Energy Regulatory Authority

MCR Maximum continuous rating

MVA Megavolt-ampere

MVar Megavolt-ampere reactive

MW Megawatt (1000 kW)

MWh Megawatt hour (1000 kWh)

PFR Primary frequency reserve

PPA Power Purchase Agreement

POC Point of connection

PV Photo-voltaic

RE Renewable energy

RoCoF Rate of Change of Frequency

RPP Renewable Power Plant

RTU Remote Terminal Unit

SAEP Southern Africa Energy Program

SCADA Supervisory control and data acquisition

SCO Synchronous Condenser

SO System Operator

UFLS Under frequency load shedding

SVC Static var Compensator

USAID United States Agency for International Development

UVLS Under voltage load shedding

vRE Variable renewable energy (solar PV and wind)


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EXECUTIVE SUMMARY

The Malawi power utility ESCOM is in the process of integrating utility-scale variable renewable energy

sources (vRE) into the power grid. Integrating vRE has great benefits in terms of diversifying the energy

mix, however, as the vRE shares increase in the energy mix, there are technical challenges that need to

be proactively addressed as part of power system planning and operations. In this context, the Southern

Africa Energy Program (SAEP) has contracted South Africa’s Council for Scientific and Industrial Research

(CSIR) to assist ESCOM to manage the integration of vRE into the grid. The scope of work indicated that

ESCOM had planned to integrate 260 MW of vRE by 2020, with the potential to increase in the coming

years as more power purchase agreements (PPAs) get signed with Independent Power Producers (IPPs).

ESCOM would require assistance in integrating vRE into the grid,

The assistance provided by the CSIR would broadly cover the following areas as outlined in the original

scope of work;

Scope A (Covered in this report):

• Assist ESCOM to develop/revise system plans and operational practices

Scope B (Future work):

• Work alongside ESCOM to integrate a renewable energy asset into the grid

• Facilitate a transfer of skills to ESCOM staff

• Provide light-touch support

The CSIR team visited ESCOM to review existing system plans and operational practices and their

application. In addition, training needs were identified in order to formulate as training scope and plan that

aligns with vRE integration. The visit top ESCOM was a critical part of the fact-finding mission in order to

tailor the support and assistance that ESCOM would require as they embark on vRE integration.

The review of ESCOM’s planning and operations processes and practices resulted in the following findings;

• The review of the planning and operations processes and procedures highlighted that both

processes and procedures need to be improved.

• The very ambitious target by ESCOM to integrate 260 MW of vRE by 2020 resulting in a 39%

share of vRE in the grid, will pose serious technical challenges which have to be proactively studied

• The fact that the planned 400 kV interconnector with Mozambique will only come online after

the planned integration of 260 MW of vRE means that the system will be vulnerable (in terms of

system stability) until the interconnector is commissioned. However, this study excludes the

influence of the interconnector with Mozambique

• ESCOM’s system operator has a SCADA system which is not fully operational as the forecasting,

scheduling and state estimation functions are not activated. As a result, the benefits of having the

SCADA are not fully exploited. In addition, the staff are not adequately trained in its use, and

some substations that should be connected to SCADA are not.


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• ESCOM staff responsible for the planning and operation of the power system have good

knowledge of the system. However, the imminent integration of high shares of solar PV will

present a new dynamic which the staff are not adequately skilled to handle

• One major area of concern is that no Automatic Generation Control (AGC) is available for the

controlling of reserves and during peak loading.

• The current operating reserves are very small and load shedding occurs regularly.

• ESCOM’s planners highlighted that stability studies with the integration of renewables using the

system analysis software, DIgSILENT Powerfactory, had not been completed and they needed

further training on DIgSILENT Powerfactory for the integration of vRE

• Furthermore, although there is an existing Grid Code, the understanding of how the system and

power plant should be operated in compliance with the Grid Code can still be enhanced

• Guidelines for generator scheduling and forecasting must be developed by ESCOM in light of the

high shares of vRE that will be integrated into the grid

The review work clearly highlighted the need for ESCOM strengthen existing systems and practices on

the operations on the existing grid, so that as the vRE continue to be integrated in the grid, there can be

a better appreciation of the grid behaviour. At the centre of all this work, will be capacity building for the

staff responsible for planning and operating the ESCOM grid.

The recommendations given below need to be implemented as part of integrating vRE into the power

system. The stated recommendations reflect good practice that ESCOM should consider adopting.

The key recommendations for implementation are as follows:

1. The training program for ESCOM staff with the primary focus being integration of vRE needs to

be executed without delay. The training must be based on the ESCOM power system and it must

provide answers regarding the level of vRE shares that can be integrated without compromising

system stability. System inertia studies will form part of this training

2. An ancillary services metric related to the LOLP and LOLE must be quantified in order to inform

the level of reserves required rather than applying a general 10% requirement

3. The market rules set out in the market document (Market rules for the Malawian electricity

market, 2016) are sound, and should be implemented accordingly

4. Safety in operating the power system cannot be overemphasized. Therefore, operating regulations

for high voltage system (ORHVS) must be implemented without delay. The safety of operations

personnel and the general public around the power system is paramount. SAEP is already working

on this topic with ESCOM and will continue working with the utility on this integration activity

5. The vRE plants must have the capability to provide day-ahead, week-ahead hourly MW production

forecast. As captured in the SA Renewables Code of 2014, the forecast should be supplied to the

system operator by 10:00 a.m. on a daily basis for the following 24 hours and seven days for each

one hour time-period by means of an electronic interface in accordance with the reasonable

requirements of SO’s data system. This recommendation will be aligned with the work that SAEP

is doing on production optimization


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6. A full investigation on the SCADA system and its use must be launched and aspects that are

disconnected (forecasting, scheduling and state estimation) need to be activated and all the

relevant substations should be connected. This is a task that must be undertaken by ESCOM.

7. ESCOM needs to develop guidelines for generator scheduling and forecasting and ensure that

they are tested before the commissioning of high shares of vRE. Operating guidelines that

include security linking diagrams must be included in the guidelines.

8. SAEP’s further work with ESCOM will include training to upskill grid planners and system

operators, however, ESCOM should augment the existing team with additional staff members,

and where appropriate, structural changes must be made in order to make the operations

efficient.


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TABLE OF CONTENTS

1. INTRODUCTION AND BACKGROUND .................................................................................. 8

1.1 INTRODUCTION ............................................................................................................................................................. 8

1.2 BACKGROUND .............................................................................................................................................................. 10

2. PRELIMINARY ASSESSMENT OF ESCOM’S NEEDS ............................................................... 12

2.1 Grid Code requirements and compliance for generators ..................................................................................... 12

2.2 Generator Integration processes and studies ........................................................................................................... 12

2.3 Casefile development and model Validation .............................................................................................................. 12

2.4 System Operating Guidelines ........................................................................................................................................ 13

2.5 reports on previous work .............................................................................................................................................. 13

2.6 Summary of concerns and way forward ..................................................................................................................... 14

3. TASK 1 – TRAINING OF STAFF .................................................................................................. 14

3.1 Steady-state models/studies ........................................................................................................................................... 14

3.2 Dynamic models/studies ................................................................................................................................................. 14

3.3 AnalyZing and reporting ................................................................................................................................................. 15

3.4 Summary and timeline ..................................................................................................................................................... 15

4. TASK 2 – ECONOMIC DISPATCH MODELLING .................................................................. 16

4.1 System load and generation dispatch patterns .......................................................................................................... 17

4.2 Generator mode of operation ...................................................................................................................................... 18

4.2.1 Dispatchable hydro generators ................................................................................................................................ 18

4.2.2 Dispatchable generators ............................................................................................................................................ 19

4.3 Real-time dispatch ............................................................................................................................................................ 19

4.3.1 Inputs of real-time dispatch schedules ................................................................................................................... 19

4.3.2 Dispatch algorithm ...................................................................................................................................................... 20

4.3.3 Schedule reports .......................................................................................................................................................... 20

4.4 RE (PV) generation operational modes ....................................................................................................................... 20

5. TASK 3 – ANCILLARY SERVICES GUIDELINES ...................................................................... 21

5.1 Ancillary services requirements .................................................................................................................................... 21

5.2 Methodology for reserves determination .................................................................................................................. 21

5.3 Types of reserves ............................................................................................................................................................. 22

5.3.1 Primary Frequency Reserves .................................................................................................................................... 22


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5.3.2 Regulating reserves (secondary reserves) ............................................................................................................. 23

5.3.3 Tertiary reserves ......................................................................................................................................................... 23

5.3.4 Other tertiary reserves .............................................................................................................................................. 23

5.4 System restoration facilities ........................................................................................................................................... 23

5.4.1 Black start facility ......................................................................................................................................................... 23

5.4.2 Unit islanding................................................................................................................................................................. 23

5.5 Reactive power and voltage control ............................................................................................................................ 24

6. TASK 4 – OPERATIONAL PROCEDURES AND PROCESSES ............................................ 24

6.1 Escom system operator security guideline – a fRAMEWORK ............................................................................. 24

6.1.1 Overview of security guidelines ............................................................................................................................... 24

6.1.2 Generation reliability guidelines............................................................................................................................... 24

6.1.3 Network requirements .............................................................................................................................................. 25

6.1.4 Outage planning ........................................................................................................................................................... 27

6.1.5 Abnormal operation ................................................................................................................................................... 28

6.1.6 Substation design and operation .............................................................................................................................. 28

6.1.7 Energy management system ...................................................................................................................................... 29

6.1.8 Secondary plant requirements ................................................................................................................................. 29

6.2 Active power curtailment mechanism ......................................................................................................................... 29

7. TASK 5 – EVALUATION OF THE GRID CODE ..................................................................... 31

7.1 Countries with vre integration requirements ........................................................................................................... 31

7.2 Grid code requirements for vRE .................................................................................................................................. 32

8. SUMMARY AND RECOMMENDATIONS ................................................................................. 32

8.1 Summary ............................................................................................................................................................................. 32

8.2 Recommendations ............................................................................................................................................................ 33

9. REFERENCES ..................................................................................................................................... 34

TABLE OF FIGURES

Figure 1: Malawi’s solar PV resource irradiation and power potential maps ........................................................................ 10

Figure 2 : Challenges associated with high vRE integration ....................................................................................................... 11

Figure 3 : Power system stability studies ........................................................................................................................................ 15

Figure 4 : The estimated timeline of the ESCOM hand-on training on the ESCOM power system ............................... 16

Figure 5 : A representation of flexibility parameters of power plants (Redl, 2018) ............................................................ 17

Figure 6 : The residual load profile that dispatchable power plants must supply (Formal comments on IRP 2016,

2017) ........................................................................................................................................................................................................ 17

Figure 7: An overview of all the reserves requirements (NERSA, SA Grid Code 2014b) ............................................... 22

Figure 8 : Demand profile and PV output profile.......................................................................................................................... 30


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1. INTRODUCTION AND BACKGROUND

1.1 INTRODUCTION

The USAID Southern Africa Energy Program (SAEP) has engaged South Africa’s Council for Scientific and

Industrial Research (CSIR) to assist the Malawi power utility company, ESCOM, to improve its capacity

for managing the integration of variable renewable energy (vRE) generation into the national grid. ESCOM

had planned to integrate up to 260 MW of solar PV into the grid by the end of 2020 and more is expected

in the subsequent years. ESCOM needs to ensure grid stability as it integrates increasing levels of vRE.

SAEP will review ESCOM’s grid planning and system operations practices and will recommend revised

procedures that take into account the grid impact of rising levels of variable renewable generation. The

Malawi Renewable Energy Strategy (March, 2017) sets a target of 500 MW grid-scale renewable energy

connected to the grid by 2025.

The purpose of this work is to revise ESCOM’s grid planning and system operations practices and provide

recommendations to enable system stability after the integration of solar PV generation

A number of tasks were identified and are addressed in this report and they follow the report outline

with report sections given:

Section 2: Preliminary assessment of ESCOM’s needs

Purpose: The SAEP team will engage with the ESCOM technical staff to gather information on the processes

and procedures for planning and operating the power system.

Section 3: Task 1 - A plan for training of staff

Purpose: SAEP will design a training program for Malawi System Operator (SO) personnel. The training will

cover power system planning for generator integration and will focus on ESCOM’s short-term planning. The

objectives will be to maintain system integrity and security of supply. Although the training will be tailored to

the ESCOM system, leading practice, experiences and learnings from other power utilities will be referenced

during the training.

Section 4: Task 2 - Economic dispatch modelling

Purpose: SAEP will review the procedures for determining the merit order generation dispatch. SAEP will

review ESCOM’s approach to dispatch, including any economic generation dispatch models currently in use.

The review will enable SAEP to understand the rationale for ESCOM’s current practices and provide a basis

for recommendations for the future when vRE will feature strongly.

Section 5: Task 3 - Ancillary services

Purpose: To conduct a review of the processes followed for procuring, scheduling and deploying ancillary

services. If these do not exist, SAEP will conduct an exercise to determine the general approach to the

sourcing, scheduling and deployment of ancillary services.

Section 6: Task 4 - Operation procedures and processes

Purpose: To conduct a review of the processes and procedures followed for operating the ESCOM grid.

Where they do not exist, recommendations on a general approach similar to what was recommended for

tasks 2 and 3 will be made

Section 7: Task 5 - Evaluation of Grid Code


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Purpose: SAEP will review the application of the vRE integration requirements of the Grid Code, and

evaluate if ESCOM has the capability to comply to the Grid Code, and highlight areas where SO will be

required to build capacity.

Section 8: Summary and recommendations

SAEP will compile the findings from all the tasks into a report that outlines recommendations for

improvement. This report will provide the basis for an intervention plan to implement the recommendations

.


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1.2 BACKGROUND

ESCOM had planned to integrate about 260 MW of vRE into the grid by the year 2020. As shown in Figure

1, the solar PV resource potential for Malawi is excellent with most of the country ranging between 1,800

and 2,000 kWh/m2. Generally, large scale solar PV plants are economically viable in areas with resources

potential of about 1,850 kWh/m2 (210 W/m2) according to an International Renewable Energy Agency

(IRENA) study (IRENA, 2015). ESCOM’s installed generation capacity is 370 MW, consisting of about 95

% (350 MW) hydro and 5% (20 MW) diesel generators (Malawi IRP, 2017). The integration of vRE in a

power system dominated by conventional generation sources poses new challenges in how the power

system is planned and operated. Furthermore, the Malawi Renewable Energy Strategy (March 2017) aims

for 500 MW grid-scale vRE generation by year 2025, however, the integrated resource plan (IRP) plans to

add 165 MW of solar and 60 MW of wind by 2032 (Malawi IRP, 2017). A study by IRENA (IRENA, 2015)

estimates the Malawi’s vRE potential to be 6,000 MW for wind and 2,000 MW for solar PV, therefore

even the planned capacities in the IRP remain very low compared to the potential.

The integration of this amount of vRE requires grid impact studies (power flow/ stability) to be

conducted.

Figure 1: Malawi’s solar PV resource irradiation and power potential maps

The introduction of high shares of vRE will change the planning and operations procedures in ESCOM.

Therefore, ESCOM needs to revise its planning and operations documents. ESCOM also needs to equip

the planning and operations staff with the skills they need to maintain the integrity and stability of the grid.

With higher vRE shares, it is apparent that forecasting and scheduling of dispatchable generation will be


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influenced by the short-term forecasting of self-dispatched vRE. ESCOM needs to assess the capacity and

flexibility of conventional power plants to compensate for the fluctuations of vRE.

Typical challenges associated with high vRE integration, especially solar PV, include:

• Reverse power flows, which have implications for system capacity and protection philosophies

• Voltage fluctuations, which could lead to voltage instability, thus a need for intelligent control

• Power quality issues (harmonics, flicker, voltage dips or swells, voltage transients)

• Power system stability (transient, frequency and voltage)

• Big data challenges (large data storage requirements, data analytics, data monitoring)

Figure 2 below depicts issues that require attention when integrating high levels of vRE. For ESCOM, the

priority challenge areas will be control and regulation issues. These issues are addressed partly by

adequate grid planning and system operations processes, and also by capacity building and training of the

staff responsible for the ESCOM power system.

Figure 2 : Challenges associated with high vRE integration

In a power system in which vRE is being integrated, there is a requirement for technical capacity building

in order to ensure that the planners and operators of the grid have the skills to manage the grid.


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2. PRELIMINARY ASSESSMENT OF ESCOM’S NEEDS This section gives a preliminary assessment of ESCOM’s need for support from a system operator

perspective within the context of vRE integration. The assessment is based on SAEP engagements with

ESCOM personnel. The focus of this section is to capture observations based on the engagements and

also make comments on the some of the basic requirements for vRE integration.

2.1 GRID CODE REQUIREMENTS AND COMPLIANCE FOR

GENERATORS

All generators connected to the grid have to satisfy and thus comply with generator requirements as

stipulated in the Malawian Grid Code. This section looks at key technical requirements from the Grid

Code to see if they are incorporated in system operator processes as well as whether they form part of

normal generator operation. These key requirements are as follows:

• Voltage control and reactive capability requirements

• N-1 contingency requirements

• Frequency requirements and ancillary services

o Primary reserves (governing, dead band, credible contingency etc.)?

o Secondary reserves automatic generation control (AGC), regulating up and down?

o Tertiary reserves (10 minute, cold or hot reserves, emergency reserves etc.)?

• Plant testing and compliance

Assessment Summary: The Malawi Energy Regulatory Authority (MERA) grid code is similar to the

South African Grid Code and their renewable generation code is also based on SA Renewable Power

Plant (RPP) code. Therefore, most of the requirements tabled above are as per SA grid code. Therefore,

knowledge sharing from the South African experience will be important. It was discovered from the

discussions that most of these requirements, although covered by the grid code, are not always well

understood and as thus are not enforced on everyday operation of the generator like they are supposed

to. The specific requirements include, voltage control and reactive power capability, frequency

requirements and ancillary services, and lastly, plant testing and compliance.

2.2 GENERATOR INTEGRATION PROCESSES AND STUDIES

The generation integration studies as well as processes are required for the stable integration of vRE into

ESCOM’s power system. The type of processes followed to integrate new generation onto the grid as

well as the studies undertaken in this regard are very paramount to assist planning engineers with proper

modelling of the grid so that they are able to diagnose, quantify and mitigate the network risks better.

Assessment Summary: Processes for generator integration are clearly given in the IPP framework and

are available on the ESCOM website. ESCOM has identified a set of studies that are required for

integration of RE generation. From this list it seems that ESCOM, like other utilities, conducts standard

studies when connecting conventional generators. However, ESCOM pointed out that they require

training on the studies to integrate vRE generation.

2.3 CASEFILE DEVELOPMENT AND MODEL VALIDATION

A casefile is a software model of the network and the connected generators that captures the actual

power system dynamics of a particular grid. Such a model should be as accurate as possible so that any

simulation results can be relied upon by the system operator. As such, to confirm/affirm the model, the

casefile is usually validated against field measurements. In order to develop a case and ensure that it can

be validated, the following processes and tests are required:


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• casefile development

• model validation

• Field testing of generators)

Assessment Summary: ESCOM indicated that a report was available for the validation of generator

parameters and can be used for verification when setting up the casefile. ESCOM, however, pointed out

that models have not been updated with the parameters of plants that were recently rehabilitated

(retrofitted). ESCOM undertook to provide this information, which is currently held by EGENCO, the

state-owned generation company. The case file and model validation processes still need to be

developed because the information that can be supplied by EGENCO can be sufficient to case file

development once validated.

2.4 SYSTEM OPERATING GUIDELINES

Different power systems or grids may exhibit different behaviours under the same disturbance conditions.

ESCOM grid is no different from this phenomenon. It is important that ESCOM’s power system engineers

develop guidelines for system controllers (artisans) on how to operate the system when the network is

subjected to abnormal conditions. These system operating guidelines will help ESCOM to minimize

operator errors.

Over and above the system operating guidelines, ESCOM needs an overarching guideline that addresses

the issues of security of supply and system reliability. Known as the system security guideline, this

document lays out the planning and operating criteria and forms the basis for all simulation studies done

by engineers in the system operator environment. This document informs most of the content in the Grid

Code when it comes to system operations issues. ESCOM needs to consider and address the following

issues:

• Security/reliability guideline – what is the content of this document and is it comprehensive

enough?

• Operating procedures and guidelines in place (i.e. for special power system equipment or

conditions)

Assessment Summary: ESCOM is in the process of developing a system operating guideline. ESCOM

highlighted that their market operator procedures/rules can address this, but it became clear when these

were retrieved and read that they certainly do not cover what is needed here. ESCOM, however, pointed

out that they do have specific procedures for specific network equipment, and these are available on their

website, but they are not adequate.

2.5 REPORTS ON PREVIOUS WORK

This is work that has been done either by ESCOM engineers or ESCOM consultants. This work mainly

consists of studies done to address general network constraints and risks. This work covered the

following areas;

• Network Assessments/appraisal documents

• Concerns and problem areas

• Relevant consultants’ reports

• Some key learnings from these reports

Assessment Summary: ESCOM has a lot of impact reports that are specific to certain generator

integration and other network equipment but they do not have routine system diagnosis/assessments


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that are done periodically (i.e. for instance yearly or biennially). It became clear that they will need to be

assisted in order to frame and streamline processes for vRE integration.

2.6 SUMMARY OF CONCERNS AND WAY FORWARD

SAEP discussed with ESCOM a high-level plan to train ESCOM staff on conducting relevant power system

studies for high vRE shares and on carrying out general generator integration studies. There is flexibility

to spread the total training period of four weeks over a few months to minimize the disruption of the

regular work of participating ESCOM staff. ESCOM welcomed this but also expressed an urgent need for

training on scheduling and forecasting for RE generation so that they are able to produce day- or week-

ahead generation dispatch patterns. SAEP undertook to provide guidelines bench-marked against leading

international practices.

The training and the studies constitute Phase 2 of the SAEP intervention. ESCOM would indicate the

number and names of people to be trained and would ensure adequate representation of the key

operations and planning departments. ESCOM requested SAEP to develop a draft training program to

outline objectives, content and the target groups. This draft training program would be shared with

ESCOM for comment before being implemented.

3. TASK 1 – TRAINING OF STAFF This sets out a training framework for Malawi System Operator personnel by SAEP. The training will be

on power system planning for generator integration and will mainly be on short term planning that is done

in a system operation environment. The focus will be on network integrity and security of supply of the

ESCOM Malawi power system, thus making the training more specific to the ESCOM system rather than

being generic. However, best practice and learnings from other power systems will be applied as part of

the training. The training will not address all challenges associated with solar PV integration; but it will

address the pressing issues that will enable ESCOM planners and system operators to properly and safely

operate the power system.

At this stage, only a high-level training program is provided; a detailed training program with a more

definitive timeline and tasks will be developed during the next phase of the project.

A high-level training program is given below.

3.1 STEADY-STATE MODELS/STUDIES

This will include the following activities:

• Casefile development/tuning (i.e. set up plus integrity tests)

• Scenario formulation (generation integration and grid upgrades)

• Voltage studies (voltage rise tests and voltage profiles)

• Thermal studies

• Contingency analysis

• Fault level studies

• Fault ride through etc.

Duration: 1 Week

3.2 DYNAMIC MODELS/STUDIES

Dynamic or power system stability studies that can be covered by the training will include what is shown

in Figure 3.


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Figure 3 : Power system stability studies

Here are some tasks that will form part of setting up the work for power system stability:

• Scenario formulations for the types of studies required

• Casefile set up in terms of load types (i.e. load frequency characteristics, voltage dependency

etc.)

• Fine tuning for a specific event

• Conducting simulations as per scenarios

Duration: 1 – 2 weeks

3.3 ANALYZING AND REPORTING

• Collating and analyzing results against set criteria in current operating guidelines

• Framing of a high-level system operating philosophy for integration of RE generation in Malawi

system operator

• Concluding and giving recommendations

Duration: 1 – 2 weeks

Note: The training program will not be continuous but the different tasks with the approximate

durations above will be staggered across two to three months to allow personnel involved to still attend

to their job responsibilities.

3.4 SUMMARY AND TIMELINE

The estimated timeline given in Figure 4 is based on SAEP’s view of how the training will likely unfold.

However, the actual timeline will be a subject of discussion with ESCOM Malawi taking into account the

level of detail that will be required.


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Figure 4 : The estimated timeline of the ESCOM hand-on training on the ESCOM power system

4. TASK 2 – ECONOMIC DISPATCH MODELLING The current dispatch practice used by ESCOM is not economical considering the system is constrained,

and the system will remain constrained for the foreseeable future. A study on the production optimization

of the existing generation fleet is underway, and that study will inform how economic dispatch of the

power system should be done in an unconstrained environment.

Notwithstanding the fact the economic dispatch is currently not being followed due to a constrained

system, ESCOM should adopt a standard way of developing short-term forecasts of the system load as

this is key for generation economic dispatch.

The South African Grid Code’s System Operation Code (NERSA, 2014b) which is the key reference for

the entire Section 4, provides the basis for a proposed economic dispatch practice. Considering that the

Malawi electricity supply is unbundled with the generation company of Malawi (EGENCO) as a standalone

entity, the interaction and relationship between the ESCOM System Operator1 and EGENCO will be

important to ensure successful dispatch practices.

With higher shares of vRE, there will be a need for flexibility in the operation of the conventional power

plants in order to accommodate the variability of solar PV. The concept of residual load profile (i.e. Load

– vRE) is important in order to assess whether the existing plant can match the profile. With high vRE

shares, the emphasis will be more on flexibility than on baseload generation. This will be the new way of

operating future power systems (Redl, 2018). In general, thermal power plants are less flexible (longer

start-up times and lower ramp rates) than gas-fired power plants. Figure 5 shows the key flexibility

parameters that will be important for the operation of the conventional power plants. And Figure 6 shows

the typical profile of residual load from a system with high vRE shares (solar PV and wind). The variable

nature of vRE requires the power system to be supplemented by flexible generation.

1 System Operator, is a word used in the South African Grid Code to refer to the utility system operator, in the Malawi context, it will be

ESCOM’s transmission operations function


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Figure 5 : A representation of flexibility parameters of power plants (Redl, 2018)

Figure 6 : The residual load profile that dispatchable power plants must supply (Formal comments on IRP

2016, 2017)

The following sections (4.1-4.4) are based on the South African System Operations Code. SAEP strongly

advises that MERA adopts the same Code for ESCOM’s power system.

4.1 SYSTEM LOAD AND GENERATION DISPATCH PATTERNS

The System Operator shall produce a forecast of system energy demand for each hour of the dispatch

day (as well as indicative forecasts of system energy demand for each hour for the six days following


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the dispatch day). This demand shall include network technical losses for each hour of the dispatch day

(as well as expected exports to, or expected imports from, neighboring networks), indicating the

required total net sent-out from all generators (non-dispatchable generators will indicate their

estimated output). The demand forecast shall be produced by 10h00 on the day preceding the dispatch

day and shall be made available to all participants.

The system operator shall determine the required reserves for each hour of the dispatch day (as well

as for each hour of the six days following the dispatch day). These requirements shall determine the

minimum reserve requirements for each of the following categories:

(a) Regulating Reserve (Up)

(b) Regulating Reserve (Down)

(c) Instantaneous Reserve (Up)

(d) 10 Minute Reserve

(e) Supplemental Reserve

The system operator shall establish agreements with generators and demand side for the provision of

the required reserves in line with the Systems Operations Code.

4.2 GENERATOR MODE OF OPERATION

4.2.1 DISPATCHABLE HYDRO GENERATORS

A dispatchable hydro generator shall provide a daily submission of the expected hourly availability of

each generating unit. The schedule should include indicative hourly availability for the six days following

the dispatch day. This schedule shall be provided by 10h00 on the day preceding the dispatch day. The

information provided shall include:

(a) The official generating unit name (as in the system operator registry)

(b) Availability indicators in the form of:

(i) The hour (0h00 to 23h00 – the hour start-time)

(ii) The hourly declared available capacity (in MW), being the maximum sent-out to

which the generating unit may be scheduled in the hour

(iii) The flexible indicator (either F or I), indicating whether the generating unit is flexible

(or able to be dispatched by the SO) in that hour (F), or inflexible to central dispatch

(I)

(iv) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether

the generating unit is available to provide Instantaneous Reserve in the hour (A) or

not (U)

(v) The Regulating Reserve Availability Indicator (either A or U), indicating whether the

generating unit is available to provide Regulating Reserve in the hour (A) or not (U)

(vi) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether

the generating unit is available to provide 10 Minute Reserve in the hour (A) or not

(U), the preferred run flag (either Y or N), indicating whether the generator

prefers to run this generating unit in that hour (Y), or not (N). This allows the

generator to set the preferred regime to meet the water commitments imposed by

the water authorities

A dispatchable hydro generator shall also provide an indication of the energy limit applicable to the

dispatch day (in MWh) above which the system operator may not schedule additional energy from the

power station, as well as the energy limit applicable to each of the six days following the dispatch day.

An indication of the total energy limit for the full seven days (in MWh) shall also be provided above


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which the system operator may not schedule additional energy from the power station.

A hydro generator may declare itself to be must-run if river or dam conditions require it or there are

contractual issues requiring them to release water downstream. They must fully declare to system

operator all the issues around such a declaration.

4.2.2 DISPATCHABLE GENERATORS

A dispatchable demand-side resource or generator shall provide a daily submission of the expected

hourly available capacity of each resource. The schedule should include indicative hourly availability for

the six days following the dispatch day. This schedule shall be provided by 10h00 on the day preceding

the dispatch day. The information provided shall include:

(a) The official demand-side resource name (as in the system operator registry)

(b) Availability indicators in the form of:

(i) The hour (0h00 to 23h00 – the hour start time)

(ii) The hourly declared available capacity (in MW), being the maximum response to

which the resource may be scheduled in the hour

(iii) The flexible indicator (either F or I), indicating whether the demand- side resource

is flexible (or able to be dispatched by the SO) in that hour (F), or inflexible to central

dispatch (I)

(iv) The Instantaneous Reserve Availability Indicator (either A or U), indicating whether

the demand-side resource is available to provide Instantaneous Reserve in the hour

(A) or not (U)

(v) The Regulating Reserve Availability Indicator (either A or U), indicating whether the

generating unit is available to provide Regulating Reserve in the hour (A) or not (U)

(vi) The 10 Minute Reserve Availability Indicator (either A or U), indicating whether the

generating unit is available to provide 10 Minute Reserve in the hour (A) or not (U)

A dispatchable demand-side resource shall also provide an indication of the energy limit applicable to the

dispatch day (in MWh or hours) above which the system operator may not schedule additional response

from the demand-side resource, as well as the energy limit applicable to each hour of the six days

following the dispatch day. An indication of the total energy limit for the full seven days (in MWh) shall

also be provided if appropriate above which the system operator may not schedule additional energy

from the demand-side resource.

4.3 REAL-TIME DISPATCH

4.3.1 INPUTS OF REAL-TIME DISPATCH SCHEDULES

The system operator shall have the ability to determine a real-time dispatch schedule. This real-time

dispatch schedule shall be authorized for use by AGC at the SO’s discretion. In addition, the system

operator may determine a revised Constrained Schedule for each hour of the dispatch day based on

revised input data during the day.

Revisions to the interconnector schedules may be submitted by the International Trader(s) at any time

for the remainder of the dispatch day, indicating the revised hourly expected imports or exports.

Revisions to the availability of dispatchable generators or demand-side resources may be made to the

system operator at any time for the remainder of the dispatch day, indicating the revised hourly

availability for the generating units.


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When dispatchable generators become aware that there is a constraint limiting their output they must

declare that constraint with the reason and the expected time for the constraint to be lifted.

4.3.2 DISPATCH ALGORITHM

The real-time dispatch algorithm shall adjust the Day-Ahead Constrained Schedule (or a revised

Constrained Schedule determined on the day, following the same methodology as the day-ahead

schedule) based on the revised input data and the real-time network model. This dispatch algorithm shall

take into account the transmission and distribution network and generator constraints (including ramping

and energy constraints).

4.3.3 SCHEDULE REPORTS

Each generator or demand-side resource shall be informed of the expected sent- out (or response in

the case of the demand-side resource) and capacity allocated to reserves for each hour of the remainder

of the dispatch day as determined in the revised Constrained Schedule determined on the day.

The system operator shall also provide a revised general adequacy report indicating the expected

demand, reserve requirements, the capacity available to meet the demand, capacity allocated to reserves

and the total expected sent-out determined by the revised Constrained Schedule.

The system operator shall maintain a daily report on the revised Constrained Schedule (where applicable)

and the real-time dispatch schedule. This report shall be produced and submitted to NERSA on request.

4.4 RE (PV) GENERATION OPERATIONAL MODES

A qualifying generator that is non-dispatchable, such as PV, shall be registered with the system operator

for collecting information regarding maintenance outage scheduling, production planning, day-ahead

scheduling and balancing purposes.

PV generators shall be considered as self-dispatchable in terms of their license conditions or power

purchase contract and under normal operating condition will have a priority over dispatchable generators

to dispatch power over the grid.

Specific data relevant to a non-dispatchable generating unit or generating facility shall be submitted by the

generator and maintained by the SO. This data shall include:

(a) Official power station name

(b) Official generating unit or facility names

(c) Location of the power station

(d) Metering arrangement, including the device identification number and telephone number for

remote interrogation

(e) If embedded within a network other than the TS, the name of the Distributor responsible for

the network

(f) The type of generating unit(s) or generating facility (for example, coal-fired thermal, pumped-

storage, hydro, wind, solar PV etc.)

(g) The MCR generated and MCR sent-out of the generator and the expected load factors

A non-dispatchable generator shall provide a schedule of the expected sent-out for each hour of the

dispatch day (as well as indicative schedules for each hour of the six days following the dispatch day).

This schedule shall be provided to the system operator by 10h00 on the day preceding the dispatch day.

The information provided shall include:

(a) The official power station name (as in the system operator registry)

(b) The hour (00h00 to 23h00 – the hour start time)


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(c) The expected sent-out in the hour (in MWh)

(d) The expected available capacity of the power station in the hour (in MW)

5. TASK 3 – ANCILLARY SERVICES GUIDELINES

5.1 ANCILLARY SERVICES REQUIREMENTS

It is important for ESCOM to develop technical requirements for ancillary services. These requirements

can then be used as a medium-term view for ancillary services for a five-year horizon or so (depending on

what ESCOM deems a feasible period). These requirements should be used for contracting generators

within the Malawi power system for provision of ancillary services.

The process for determining the ancillary services requirements can serve as a guide towards the

development of ancillary services requirements for the ESCOM system operator. These requirements will

need to be developed by ESCOM itself or ESCOM may need to contract the services of a competent

consultant that will work closely with ESCOM in this regard – this could also form part of the SAEP

support but will need to be scoped appropriately.

The following requirements are defined as ancillary services:

• Reserves

• Black Start

• Islanding

• Reactive Power Supply and Voltage Control

5.2 METHODOLOGY FOR RESERVES DETERMINATION

ESCOM does not have a methodology to determine the ancillary services that the system requires.

Therefore, a methodology for this will need to be developed. A separate document can be used for

developing and defining such methodology or such a methodology can still be included as part of the

ancillary services requirements.

An overview of the reserve classes as captured in the SA Grid Code (NERSA, 2014b) are shown in

Figure 7.


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Figure 7: An overview of all the reserves requirements (NERSA, SA Grid Code 2014b)

5.3 TYPES OF RESERVES

The types of reserves and deployment thereof is important when setting up the ancillary services

requirements for the network. And a power system impact study is required to determine these

requirements.

5.3.1 PRIMARY FREQUENCY RESERVES

Primary frequency reserve (PFR) is generating capacity or demand side managed load fully available within

a few seconds (ESCOM to quantify) to arrest a frequency excursion outside the frequency dead-band. The

reserve response must be sustained for at least a few minutes (ESCOM to quantify). It is needed to arrest

the frequency at an acceptable level following a contingency, such as a generator trip or a sudden surge in

load. Generators contracted for PFR are also expected to respond to high frequencies (above upper dead-

band limit) – this should be stipulated in the Malawian Grid Code. The PFR requirement quantification will

need a dynamic frequency stability study – ESCOM personnel will need the right skills set for this type of

simulation.


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5.3.2 REGULATING RESERVES (SECONDARY RESERVES)

Regulating reserve is generating capacity or demand side managed load that is available to respond within

a few seconds and is fully activated within a few minutes (ESCOM to quantify these times). The purpose

of this reserve is to make enough capacity available to maintain the frequency close to scheduled frequency

and keep tie line flows between control areas within schedule. Automatic Generation Control (AGC) is

used for this regulation reserve – ESCOM will need to develop an algorithm for the AGC by means of

relevant studies and in the process identify which units to contract for this service.

5.3.3 TERTIARY RESERVES

Tertiary reserve is generating capacity or demand side managed load that can respond within a few minutes

when called upon. It may consist of offline quick start generating plant (e.g. hydro or pumped storage) or

demand side load that can be dispatched within a few minutes (ESCOM to quantify applicable times). The

purpose of this reserve is to restore PFR and regulating reserve to the required levels after an incident.

The tertiary reserve requirement can be defined as per below formula:

• Tertiary Reserve = Total Operating Reserve – PFR – Regulating Reserve

However, ESCOM will still need to develop its own criteria for determining total operating reserves in

their system.

5.3.4 OTHER TERTIARY RESERVES

Further tertiary reserves can be quantified such as:

• Supplemental reserve: generating or demand side load that can respond in a few hours to restore

operating reserves

• Emergency reserve: should be fully activated within a few minutes. Emergency reserves can include

interruptible loads, generator emergency capacity (EL1) and gas turbine capacity

5.4 SYSTEM RESTORATION FACILITIES

It is the responsibility of the System Operator to contract for black start and unit islanding services to

restore the system following a total blackout or an incident in which power to part of the system is

interrupted (Malawian Grid Code should stipulate these requirements).

5.4.1 BLACK START FACILITY

Black start facilities need to be capable of starting themselves, energizing a portion of the transmission

network and starting up other connected base load generators as part of the restoration of the power

system. At least two units at strategically placed locations should be capable to provide this facility. The

ESCOM System Operator should determine the minimum specifications for the black start facilities. The

power stations contracted for this service must prove the capability of the facility by doing partial and full

black start tests every few years as required by Malawian Grid Code.

5.4.2 UNIT ISLANDING

A unit islanding generator is capable of maintaining its own stability and supplying its own auxiliaries while

being disconnected from the power system. Unit islanding should be a mandatory ancillary service for all

generating units in the power system.


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5.5 REACTIVE POWER AND VOLTAGE CONTROL

Reactive power supply and voltage control form part of the ancillary services required by the System

Operator to efficiently perform its main function of supplying electrical power. These requirements should

be stipulated in the Malawian Grid Code for all generating units. Currently this is an area that would

require further investigation.

6. TASK 4 – OPERATIONAL PROCEDURES AND PROCESSES

6.1 ESCOM SYSTEM OPERATOR SECURITY GUIDELINE – A

FRAMEWORK

This outlines a framework of what ESCOM should consider as a guide to developing fully-fledged security

guidelines for its system operator, as presently this is an area of concern.

6.1.1 OVERVIEW OF SECURITY GUIDELINES

The Security Guidelines documents the System Operator’s responsibility in performing its role in

maintaining system security. While it is realized that due to economic constraints, the security guidelines

will not always be met, it is the responsibility of the System Operator to highlight where these operating

requirements are violated and these violations will serve as a trigger to consider further expansion.

The purpose of this framework is to highlight the risk management practices necessary to ensure secure

operation of the power system. It also highlights longer term planning requirements for generation and

network adequacy. This document, when fully developed, should be superseded by the Malawian Grid

Code and any requirements specified in the respective licenses issued by the regulator.

6.1.2 GENERATION RELIABILITY GUIDELINES

Generation reliability is dependent on the availability of sufficient plant, associated fuel, water availability

(dam levels) and secondary resources in both the long term and short term. Generation reliability

describes the consideration from a System Operator for reserves in the long term and on a day-ahead

basis. The risk of losing plant due to transmission constraints as well as the outage planning process should

be considered. The understanding of loss of load probability (LOLP) and loss of load expectation (LOLE)

are important in terms of quantifying the reserves requirements rather than an arbitrary figure (or

percentage) which might reflect the capability of the system.

6.1.2.1 Reserve margins

The setting of reserve margins is a function of the reserve philosophy applied in terms of operating

reserves in the short-term, and long-term generation adequacy. Therefore, the following aspects will be

important determining reserve margins:

• Long-term reserve margin requirements (i.e. generation adequacy standard): the long-term reserve

margin requirement is important as it will guide the long-term generation expansion plan with regards to

the size and timing of new capacity

• Operating reserves philosophy: It is important to have a philosophy on how operating reserves are

determined and set. From the philosophy, the policies and procedures can be determined

• Operating reserve requirements: the requirements for operating reserves are for normal operations

and to ensure that the post-contingency loading of generators and system frequency remains within the

set limits


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6.1.2.2 Primary fuel supply

Storage requirements of the primary fuel are important aspects of the dispatch regime in a power system.

Consideration should, therefore, be given to the following:

• Hydro power stations dam levels: a hydro power plant can improve flexibility by utilizing its full power

and storage capability. Therefore, the dam level is a key factor in determining what the hydro plant

capacity

• Pumped storage dam levels (gen hours): dam levels will influence how the pumped storage plant is

used to provide both capacity and energy

• Diesel fuel storage levels: diesel storage levels are an important input to the dispatch of the diesel plant.

The storage size can influence whether the plant is used to cater for short- or longer-term variations

6.1.2.3 Renewable energy availability

Variable renewable energy is self-dispatching; however, it can be forecasted just like the weather. The

availability of the day-ahead and week-ahead vRE forecast at an hourly resolution is important for the

operations of the power system. Factors such as the following should be considered:

• Accurate forecasting: the need to provide accurate forecasting in order to ascertain the expected

production from vRE is essential. With vRE increasingly being the bulk power supplier, forecasting will be

an integral part of the system operator function

• Adverse weather conditions: adverse weather conditions will no longer only be considered as an input

in terms their effect on infrastructure, but also as key variable in determining the generation output

6.1.2.4 Network impact on generation reliability

Traditionally this only considered transmission network impact but now with proliferation of distributed

vRE generation this should consider distribution networks as well. The following factors should be

considered even at distribution level:

• Generation integration requirements as per Grid Code: the grid code provides the connection

requirements for generators and these should be applied even in parts of the grid where traditionally there

was no generator integration, as this will have bearing on the reliability of the generation supply

• Single Contingency criteria (n-1): generation from vRE will have to be evaluated against these criteria

as vRE supply will be essential for security of supply

6.1.2.5 Generation outage planning

Variable renewable energy introduces a new paradigm in generation outage planning of considering

residual demand (demand-vRE), instead of the traditional approach of primarily relying on system demand.

With the new paradigm, changes to the following must be considered:

• Long-term outage planning: long-term outage plans will have to take output from vRE into account since

the system supply sources profile will be different with seasonal effects due to vRE in the grid

• Short-term outage planning: these outage plans must take into account short-term meteorological effects

of vRE generation

6.1.3 NETWORK REQUIREMENTS

The network should be planned and designed to ensure that the Security Guidelines can be met. The first

priority in operating the power system is to ensure safety to all personnel, the public and maintain the

security of the transmission network. Therefore, it is important to have operating regulations for high

voltage systems (ORHVS) for the safe operation of the ESCOM system. Also, customer requirements

should be met as economically as possible. In terms of system security, the network should, at any given

time, be able to accommodate a single contingency (Malawi Grid Code, 2010). Following a contingency,


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the network should again be set up to cater as far as possible for the next contingency. Therefore, the

following factors should be considered:

6.1.3.1 Load categories

Categorization and spatial location of loads is an important aspect of network design and operation.

Therefore, the following aspects need to be considered:

• Geographic corridors: power corridors and their location are key aspects of how the system should be

operated, both in terms of system stability and security of supply

• Local load: refers to the load in the vicinity of the power plant which might not be large but will reduce

the amount of power that can be evacuated from the power plant

• Load centers: it is important to understand the location of key load centers in the grid as a key input to

how the system will be operated

• Sensitive customers: this would include customers with a certain level of power quality requirements

6.1.3.2 Contingencies

The following list gives possible single contingency (n-1) on the network. Contingencies are considered to

be forced outages and not equipment planned to be taken out of service. Planned outages should still leave

the system in an (n) state from an operational perspective.

Typical contingencies would include:

• Loss of a single transmission circuit (this may include for example the line, transformer, circuit

breaker and possibly a series capacitor): the loss of a single circuit will often result in changes in thermal

loading and voltages, therefore these losses should be closely studied and monitored

• Loss of any single generator: as a single generator loss results in a state change for a power system, it

must still be considered even if the remaining generators can still supply the full load

• Loss of any single section of busbar and attached equipment: a loss of section of a busbar can affect

power transfer capacity through a substation thus limiting the power that would be transferred through

the power line

• Loss of the single pole of an HVDC link: the loss of single pole of an HVDC link in a two-pole system

with earth return might not result in a loss of power, however this loss has to be registered as a contingency

because the system is no longer in a normal state

• Loss of any reactive device: this will involve the loss of devices like static var compensators (SVC),

thyristor switched capacitors, and reactors which act as sources or sinks of reactive power. The loss of

these devices is sometimes overlooked as part contingencies, but their availability is key to system

operations

• Loss of a double circuit tower: this is severe event which could be caused by the weather, but such

outages are not common

• The occurrence of a three-phase fault followed by correct protection operation involving loss of

plant (not including an auto-recloser operation): this fault can be severe although they are less

common, but the impact can be significant if the it involves a large power corridor

• The occurrence of a single-phase fault followed by a stuck breaker and associated protection

operation (not including an auto-recloser operation): this type of fault can result in a line or

transformer outage that affects large parts of the grid

6.1.3.3 Unacceptable response to next contingency

The system operator can define this unacceptable behavior in line with the Malawian Grid Code and other

guidelines.

6.1.3.4 Acceptable loading of equipment


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Conductor current ratings and templating temperature can be used to develop a standard or criteria for

determining acceptable load equipment.

6.1.3.5 Power system stability

The integration of vRE will inevitably result in a decline in system inertia which will have an impact on

various aspects of power system stability. International benchmarking can be used to develop criteria for

limits on system stability. Key aspects to consider for power system stability include:

• Voltage stability and limits: voltage stability refers to the ability a power system to maintain bus voltages

within limits. In a voltage stable system, the system operator has full control of both voltages and power

transfer

The following voltage control factors should be considered and catered for:

- Ferranti voltage

- Switching voltage

- Voltage collapse

• Angular Stability: a power system is angle stable if the generator torque angles are sustained at less than

90 O and the power angles are sustained at less than 90 O. The focus areas for angular stability are:

- Transient stability

- Frequency stability

• Small signal stability: this refers to oscillations or constant changes (MW, Mvar, voltages, angles,

frequency) that the system will constantly experience as part of its operations, and instability can be

triggered by a minor operating event like line switching. Oscillations don’t always result in instability,

however, oscillatory instability (small-signal instability) occurs when the oscillations grow so significant that

the system becomes unstable due to operational limits being violated

6.1.3.6 Remedial action schemes

Where the transmission capacity of the network is inadequate to meet the security guidelines, a remedial

action scheme may be installed as a temporary measure taking into account the expansion planning options

in the near future, the time frame for implementation and the period of risk to protect the power system

against voltage collapse or other fast power system phenomenon. The remedial action scheme may

disconnect load (or reactive power equipment) from the network in order to bring the system quickly

within limits following a disturbance.

6.1.4 OUTAGE PLANNING

Although the network may be designed to meet the security guidelines, plant outages are required for a

number of reasons. When the plant is taken out of service, a risk analysis must be performed to determine

the risk introduced due to the equipment outage. While it is understood that there will always be some

risk involved, this risk should be minimized and communicated with customers.

6.1.4.1 Types of outages

The types of outages referred to here are:

• Line outages: line outages are due to failure of power lines of terminal equipment

• Transformer outages: transformer outages could be due to internal insulation failures and external

equipment failures

• Bus section outages: these outages can affect the overall system security and reliability; therefore, it is

important to keep track of these outages

• Reactive power equipment outages: reactive power equipment is critical for ensuring system flexibility

therefore their availability is critical and their outages should be closely monitored


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6.1.4.2 Risk analysis

The taking out of the piece of equipment should not result in any of the “unacceptable results of next

contingency” defined above. In all cases the next worst single contingency should be considered. The

following should be taken into account when conducting the risk analysis:

• Outage duration: the duration of outages is an important input to the reliability calculations of the power

system

• Shortest return time: the return time is a key input especially for critical plant and feeds into the

maintenance strategy

• Weather conditions: weather conditions are an essential input especially for outdoor outages, where rain

or lightning could be a factor in planning outages

• Condition of remaining equipment and servitudes: the condition of equipment and servitudes influence

expected network performance (e.g. a well-maintained servitude will reduce the likelihood of earth faults

due to veld fires or vegetation encroachment)

• Loading during time of outage: generally, outages are planned when the load is reduced. However, with

vRE, the traditional open window for planned outages can change because of the residual load (load-vRE)

profile being different from the normal load profile

• Impact of next contingency: it is important to know and be ready for the next contingency (n-2) to avoid

a situation where there is a risk of collapse or blackout when a second outage takes place while

maintenance on the first outage is underway

• Generation pattern: with vRE, the generation pattern of the conventional plants will change overtime

and this will influence both the timing and the time of maintenance that will be required

• Risk of not doing the work: it is always important to understand the impact of not maintaining

equipment on their expected performance and how it will influence system performance

6.1.5 ABNORMAL OPERATION

The power system is not designed to handle all possible contingencies and combinations of contingencies,

but it is essential that the emergency and restoration plans are sufficient to address the impact of all

possible disturbances. Load shedding schemes are important aspects of abnormal operation. Therefore,

the following systems should be considered when addressing these:

• Under frequency load shedding (UFLS): it is important to ensure that load is shed to maintain healthy

system frequency

• Under voltage load shedding (UVLS): keeping voltages healthy is important to keep the system intact

even during abnormal conditions and load can be shed accordingly to maintain healthy systems voltages

to avoid voltage collapse

• System restoration: system restoration procedures need to be in place to ensure that in the event the

system collapses, there is a standard procedure to safely restore the system

6.1.6 SUBSTATION DESIGN AND OPERATION

Substation design has to be done with system security and redundancy (e.g. n-1 firm) considerations. The

design and operation of the substation are very important to the system operator when operating the

power system, therefore the following should be considered:

• Substation design: busbar configuration and buszone allocation for transformers are key aspects of

substation design

• Busbar linking arrangements: at certain voltages specific busbsar linking is required to align with reliability

level expected system wide for that voltage (e.g. it is important to have busbar with circuit breaker bypass

for voltages above 132 kV)

• Standard design fault levels per voltage level: design fault level for voltage level will inform the design

of the substation equipment


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6.1.7 ENERGY MANAGEMENT SYSTEM

The ability to control the power system depends critically on the observability and remote controllability

of the network. This functionality is provided through a network of substation control systems,

telecommunication circuits and the energy management system (EMS). The entire system should be

available and fully operational at all times. So, the underlying factors to consider here are:

• Availability of the EMS: the state and the information on the availability of the EMS is essential for

understanding the resources that one can deploy during operation, both under normal and emergency

conditions

• Observability of the EMS through state estimation: observability of the EMS is very important, because

a system that is not observable can be difficult to control

• Visibility of the EMS: the EMS’s visibility is important for operations, and if the EMS is visible inadvertent

operations can be avoided

• Telecommunication requirements: telecommunications are a critical part the EMS, therefore these

requirements must be applied to ensure availability and controllability of the EMS

6.1.8 SECONDARY PLANT REQUIREMENTS

Information and data on the protection operations and the systems status in terms of outages is important

to have readily available, Additionally, it is important to have life cycle management plans for secondary

plant. Therefore, it is important to have the following information and datasets:

• Protection operation: keeping information on the operation of protection is very important for system

operations

• Protection equipment outages: a log of equipment that is on outage is a key input into the operational

decisions

• Protection systems and equipment life cycle management: life cycle management plans are essential

part of the documentation required for the operation of the power system

6.2 ACTIVE POWER CURTAILMENT MECHANISM

Solar PV generation will always have its peak generation around noon, however, if the PV generation

coincides with low-load condition, there is a high likelihood of overvoltage especially if the PV generation

is connected at the end of a radial power line. Therefore, in order to avoid an overvoltage situation, the

PV output has to be curtailed, and the curtailment can be in the form of reduced output between 0% and

100% in order to maintain a stable power system. Figure 8 shows the demand profile and the PV output

profile, highlighting a time window where system overvoltage due to high PV generation can be expected.

It is important to note that the solution is not to switch the PV generation off and on, but to control the

output in such a way that voltage limits are not violated, and over-frequency due to excessive generation

is avoided in order to maintain system stability.


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Figure 8 : Demand profile and PV output profile

It is important to have an established mechanism to manage PV curtailment, because a PV plant without a

control scheme, which only switches on and off, can pose instability problems especially during periods of

high PV generation.

The proposed curtailment mechanism for ESCOM

This section is based on the South African Grid Code and the latest Malawian Grid Code (2018).

The active power limit that the solar plant will be permitted to generate will be set by ESCOM. In this

case it should be the maximum output of the PV plant. However, if conditions change, the instruction

should be automatically issued via tele-control or other method agreed to between ESCOM and the PV

plant owners. The active power is defined as the amount of power (MWs) at the POC that a PV plant can

produce.

As part of normal operation, the steady-state voltage quality (i.e. voltage regulation (magnitude), voltage

harmonics, voltage flicker, voltage unbalance, voltage dips) must be maintained. The current drawn from

or injected into the POC is the driving factor for voltage quality deviations.

Voltage Ride through capability, which is the capability of the PV plant to stay connected to the network

and keep operating following dips or surges by short circuits or disturbances on any or all phases, is an

important capability that a PV plant must have. At POC the nominal voltage should not be less than 0.9

and higher than 1.0985.

The design criteria should be done such that the PV plant should not stay connected to the grid for longer

than four seconds if frequency is higher than 51.5 Hz. When the frequency is less than 47.0Hz for longer

than 200ms, it can be disconnected. It needs to stay connected during the RoCoF of values up to and

including 1.5Hz per second. The continuous operating frequency range is between 49 and 51Hz.

Synchronizing must be after 3 seconds, with voltage within 5% of nominal voltage and frequency is between

49 and 50.2HZ or as otherwise agreed.

The PV plant should be designed to withstand jumps of 20 degrees at the POC without disconnecting or

reducing its output. Once operating conditions are normal, normal production output should be resumed

within 5s.


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The PV plant should be able to withstand voltage drops to zero at the POC for a minimum period of 0.15s

without disconnecting during 3phase faults. It should be able to cater for up to 120% of the nominal voltage

at the POC for a minimum period of 2s without disconnecting.

The PV plant shall provide maximum voltage support by supplying a controlled amount of reactive current

to assist in stabilizing the voltage. At 50.5Hz the active power needs to linearly decrease until 0 at 52Hz.

The mechanism employed for the curtailment of PV must respond to both voltage and frequency in a

controlled manner (gradual reduction over time) as specified by the grid code to ensure system stability.

7. TASK 5 – EVALUATION OF THE GRID CODE

7.1 COUNTRIES WITH VRE INTEGRATION REQUIREMENTS

Power system integration of all generation sources is governed by the grid code, which prescribes the

minimum connection requirements and the operational requirements. Therefore, it is important to ensure

that the connection requirements are prescribed in line with optimally utilizing the capability of modern

technology to meet the power system requirements. In general, coal and nuclear plants are not as flexible

as gas plants and therefore there is a case for requiring more flexibility from gas plants compared to coal

and nuclear. It is thus important to ensure that either the Grid Code or the power purchase agreements

(PPA) for gas plants reflect their technical strength in terms of providing flexibility and ancillary services.

The contracts and tariffs set for gas independent power producers (IPPs) can be structured such that the

gas technology is utilized in line with its capability based on both medium and long-term power system

requirements.

It is important to note that the future power system will have more renewable energy (RE) and distributed

generation as opposed to high reliance on fossil fuels and centralized power generation. As the world

decreases its reliance on fossil fuels, the role of flexible generation will be more critical due to the

variability of RE sources. Although there are other initiatives, such as spatial aggregation or RE sources,

which can be implemented to reduce the variability of the residual load, gas plants are seen as one of the

primary sources to respond to the variability challenge. It is therefore important to ensure that when

power plants are being procured, that the investment remains relevant in view of the future power system

flexibility and other requirements to accommodate high shares of vRE as is the case in the ESCOM system.

What is considered as the future in some countries, is already a reality in other countries that either have

a high share of renewables or they have a large portfolio of flexible generation such as gas as part of their

primary energy supply. Therefore, it is important to study or investigate what other countries are doing

with respect to grid code requirements in order to benchmark or learn from others as part of formulating

what needs to be included in the Malawian Grid code.

Some of the countries and regions with codes or standards that contain requirements for integrating VRE;

• United Kingdom: National Grid

• Nordic Countries: System Operator Agreement; Denmark Grid Code

• Europe: ENTSO-E Union for the Coordination of Transmission of Electricity (UCTE) Handbook

• Germany: Transmission Code

• Ireland: EirGrid Code; SONI Grid Code

• North America: NERC Reliability standards for bulk Electric Systems of North America

• South Africa: Transmission Code, and System Operations Code

Countries that specify the requirements have a very good understanding of the gas technology and their

system operators fully appreciate the technical capability of these technologies. Therefore, power plants

will have specific connection requirements and operation or performance requirements. As in the case of


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Northern Ireland, the system operator has a specific document called “Minimum function specification for

CCGTs” which clearly spells out the technology’s capability and what the system operator can expect

from it.

Therefore, it is possible to have clear requirements for power plants in a grid code, and even better if the

integration requirements for all plants are contained in a single document, which is not the case in some

countries.

7.2 GRID CODE REQUIREMENTS FOR VRE With regards to the grid code requirements for integrating vRE, it is important to note that the system

operator has to ensure that the system is reliable (secure and adequate). Therefore, the power plants that

are integrated into the power system have to meet certain minimum requirements irrespective of what

technology they are. Malawi’s Grid Code (MERA, 2018) has requirements for renewable energy power

plants similar to the requirements used in South Africa for renewable power plants (NERSA, 2014a).

The adoption of the South African Renewables code is a very good start. One of the key learning points

in systems with VRE is that renewable energy power plants’ connection requirements depend on the size

and the location of those power plants in the grid. Small-scale renewable generators are often connected

to the low and medium voltage networks and utility-scale plants are connected to high voltage grids, and

the integration challenges at these three voltage levels are often different. These differences need to be

well understood so that regulations specified in the code do not unnecessarily limit what can be connected,

or worse make the rules so relaxed such that the system is put at risk.

Some of the key basic studies that need to be done for the integration of the vRE include:

• Thermal limits – study to check thermal limits for normal and contingency conditions

• Technical losses – to study the technical losses (I2R) during normal grid configuration

• Fault level (short-circuit currents) – this study is important to ensure that equipment short-circuit

limits are not exceeded for safe operation and supply security

• Voltage regulation (e.g. voltage rise) – to check the voltage limits for shared and dedicated

networks for both normal and contingency conditions

• Rapid voltage change (e.g. sudden loss of generation) – to check the impact of fluctuating

generation from solar PV and wind on the allowable voltage change for both small and large plants

as defined by the standards and codes

These basic studies are always required a first pass for vRE to be considered for grid integration. However,

there are a number of other considerations (viz. Power Quality, reactive power and voltage control, MW

that are captured in Section 8 of the Malawian Grid Code (MERA, 2018) that must also be considered.

The Malawian Grid Code as it stands, incorporates international best practice. However, there is a need

to demonstrate how the Grid code requirements are applied as part of operating the power system.

8. SUMMARY AND RECOMMENDATIONS

8.1 SUMMARY

The review of the ESCOM system has resulted in a number of findings which can be summarized as

follows:


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• The review of the planning and operations processes and procedures highlighted that both

processes and procedures need to be improved.

• The very ambitious target by ESCOM to integrate 260 MW of vRE by 2020 resulting in a 39%

share of vRE in the grid, will pose serious technical challenges which have to be proactively studied

• The fact that the planned 400 kV interconnector with EDM will only come online after the planned

integration of 260 MW of vRE means that the system will be vulnerable (in terms of system

stability) until the interconnector is commissioned. But this aspect needs to be studied in order

to quantify the limitations

• ESCOM’s system operator has a SCADA system which is not fully operational with the

forecasting, scheduling and state estimation aspects not connected. As a result, the benefits of

having the SCADA are not fully exploited. This is worsened by the fact that the staff are not

adequately trained in its use. Additionally, some substations that should be connected to SCADA

are not and this needs further investigation

• ESCOM staff responsible for the planning and operation of the power system have good

knowledge of the system. However, the imminent integration of high shares of solar PV will

present a new dynamic which the staff are not adequately skilled to handle

• One major area of concern is that no Automatic Generation Control (AGC) is available for the

controlling of reserves and during peak loading.

• The current operating reserves are very small and load shedding occurs regularly.

• ESCOM’s planners highlighted that stability studies with the integration of renewables using the

system analysis software, DIgSILENT Powerfactory, had not been completed and they needed

further training on DIgSILENT Powerfactory for the integration of vRE

• Furthermore, although there is an existing Grid Code, the understanding of how the system and

power plant should be operated in compliance with the Grid Code can still be enhanced

• The development of guidelines for generator scheduling and forecasting has been highlighted as a

pressing need in light of the high shares of vRE that are about to be integrated into the grid

8.2 RECOMMENDATIONS

The recommendations given below need to be implemented as part of integrating vRE into the power

system. The stated recommendations reflect good practice that ESCOM should consider adopting.

The key recommendations for implementation are as follows:

i. The training program for ESCOM staff with the primary focus being integration of vRE needs to

be executed without delay. The training must be based on the ESCOM power system and it must

provide answers regarding the level of vRE shares that can be integrated without compromising

system stability. System inertia studies will form part of this training

ii. An ancillary services metric related to the LOLP and LOLE must be quantified in order to inform

the level of reserves required rather than applying a general 10% requirement

iii. The market rules set out in the market document (Market rules for the Malawian electricity

market, 2016) are sound, and should be implemented accordingly

iv. Safety in operating the power system cannot be overemphasized. Therefore, operating regulations

for high voltage system (ORHVS) must be implemented without delay. The safety of operations


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personnel and the general public around the power system is paramount. SAEP is already working

on this topic with ESCOM and will continue working with the utility on this integration activity

v. The vRE plants must have the capability to provide day-ahead, week-ahead hourly MW production

forecast. As captured in the (SA Renewables Code, 2014), the forecast should be supplied to the

system operator by 10:00 a.m. on a daily basis for the following 24 hours and seven days for each

one hour time-period by means of an electronic interface in accordance with the reasonable

requirements of SO’s data system. This recommendation will be aligned with the work that SAEP

is doing on production optimization

vi. A full investigation on the SCADA system and its use must be launched and aspects that are

disconnected (forecasting, scheduling and state estimation) need to be activated and all the

relevant substations should be connected. This is a task that must be undertaken by ESCOM.

vii. ESCOM needs to develop guidelines for generator scheduling and forecasting and ensure that they

are tested before the commissioning of high shares of vRE.

viii. SAEP’s further work with ESCOM will include training to upskill grid planners and system

operators, however, ESCOM should augment the existing team with additional staff members,

and where appropriate, structural changes must be made in order to make the operations efficient.

9. REFERENCES

i. Independent Electricity System Operator, I. (2016) ‘Market Rules for the Ontario Electricity Market’,

(February).

ii. IRENA (2015) ‘RENEWABLE ENERGY ZONES’, (October).

iii. Malawi, I. (2017) ‘Ministry of Natural Resources , Energy and Mining Integrated Resource Plan ( IRP ) for

Malawi’, I(May).

iv. MERA (2010) ‘Malawi Grid Code 2016’, (February), pp. 2–4.

v. MERA (2018) ‘Malawi Grid Code 2018’, (May).

vi. NERSA (2014a) ‘Grid Connection Code for Renewable Power Plants Connected to the Electricity

Transmission System or the Distribution System in South Africa’, 8(July), p. 17.

vii. NERSA (2014b) ‘The South African Grid Code - System Operation Code’, p. 24. Available at:

http://www.nersa.org.za/.

viii. Redl, C. (2018) ‘A word on flexibility: The German Energiewende in practice: how the electricity market

manages flexibility challenges when the shares of wind and PV are high’, p. 37.

ix. Republic of Malawi (2017) Malawi Renewable Energy Strategy.

southern africa energy program

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