This article summarises the introduction of the renewable energy independent power producer (REIPPP) programme in South Africa and the Eskom renewable energy grid integration process. It also addresses the technical evaluations considered by Eskom and how to ensure the grid code requirements are met. The future network design and capacities are addressed via the transmission grid connection capacity assessment and the strategic environmental assessment study. Eskom contributed to this government-led study in collaboration with the Department of Environmental Affairs.
The Department of Energy (DoE) promulgated the “Electricity Regulations on New Generation Capacity” under section 35(4) of the Electricity Regulation Act, 2006 (Act No 4 of 2006). The regulation requires that the DoE produce the integrated resource plan (IRP) for the country. The requirements for different technologies are shown in the updated IRP 2010, namely coal, gas, nuclear and renewable energy (RE). The IRP calls for 17 500 MW of renewable energy by 2030. The DoE has set up the IPP-Project Office to facilitate the procurement of the renewable energy requirements. The IRP has also made a provision for the power utility to establish a 100 MW wind farm, and a 100 MW concentrating solar power plant (CSP).
It is important to note that the South African government procurement programme only allows an open tender process or known as the bidder programme. It makes the initial feed-in tariff concept unacceptable. The IPP-Project Office calls for bidders to submit their project proposals by responding to the request for proposal (RFP). This RFP is updated and released before each bid window.
The DoE has processed five procurement bid windows to date. Bid window 1 was launched in November 2011. The DoE has subsequently granted preferred bidders status for bid windows 1, 2, 3, 3.5 and 4 [5]. The total number of projects and MW that were granted development status are shown in Table 1.
The applications reflect projects submitted and might have included previous unsuccessful applications. As cost estimate letters (CEL) are only valid for one year, the various bid windows required several CEL to be reproduced to ensure that changing requirements, and capacity allocated, are taken into account.
Table 1: Summary of RE bid windows 1 to 4.
Description
Window 1
Window 2
Window 3
Window 3.5
Window 4
Total
Cost estimate letters
~ 270
> 190
~ 500
6
154
DoE applications
54
79
93 < 97
3
77
Wind
(No. / MW)
8 / 634
7 / 563
7 / 787
5 / 676
27 / 2660
Photovoltaic
(No. / MW)
18 / 632
9 / 417
6 / 450
6 / 415
39 / 1914
Concentrating solar power
(No. / MW)
2 / 150
1 / 50
2 / 200
200
7 / 600
Small hydro
(No. / MW)
2 / 14,3
1 / 4,7
3 / 18,7
Landfill
(No. / MW)
(1 bid = 5 sites)
1(5) / 18
1(5) / 18
Biomass
(No. / MW)
1 / 16,5
1 / 25
2 / 41.5
Small RE 1 – 5 (MW)
50
Preferred bidders (No.)
28
19
17
2
13
79
MW allocated
1416
1044
1471,5
200
1121
5052
This was a huge undertaking to process the 83 preferred bidder sites via the preparation of a total of 1120 cost estimate letters across all the bid windows in four years. Eskom initially issued a CEL free of charge. This success rate of 7,4% placed significant stress on the utility’s current resources. Eskom then started following international norms by requesting a processing fee for the cost estimate letters. This reduced the requests to more serious and project ready discussions and assisted with the processing of applications.
The preferred bidders from bid windows 1 to 4 are shown with the high voltage network in Fig. 1. The wind projects are more prominent in the Western Cape, Northern Cape and Eastern Cape provinces. The solar photovoltaic (PV) projects are more dominant to the western half of the country.
Fig. 1: Preferred Bidders from Bid Window 1 to 4 and the Eskom high voltage network.
Eskom RE grid integration process
The grid integration process has been developed with detail following standard defined business sub-processes. The high level RE grid integration process is shown in Fig. 2 [1]. It has been successfully utilised over 5 bid windows. Minor adjustments were made to support new concepts and requirements.
Fig. 2: Eskom high level RE grid integration process.
The RE grid integration process covers the following:
The IPP developer looks into its own potential sites, resource and associated measurements, land agreements and various requirements. Eskom will support them with line routes and substation site selection. Initial high level solutions are discussed with the network planning staff.
The minimum information required at the initial stage is: Project Name to track it, geographic coordinates, plant technology and the associated MW installed capacity.
As soon as the developer wants to progress to a cost estimate letter phase (any costs), then the IPP developer needs to submit an application form completed in conjunction with the Eskom Grid Access Unit (GAU). The GAU in turn manages all the customer communication and technical interface within Eskom.
The GAU manages the application, consultation and advisory phases and liaises with the Eskom Engineering functions. It culminates in the issuing of a Cost Estimate Letter (CEL).
Eskom will analyse the grid capacity and consider potential solutions to suit the size of the RE development. It is recommended that the IPP developer discusses the potential high level solutions with Eskom. The utility also needs to comment on these potential developments, and also needs to help to ensure that the required generation can be evacuated. The lack of communication will result in subsequent re-work or amendment of the EIA. These practical solutions could be critical for the IPP business case.
The utility has approved the self-build options of its assets by the IPP developer. The assets are then transferred, upon commissioning to Eskom for operations and maintenance purposes. It is therefore important to understand who will be costing which solutions for the IPP developer and to reflect these in the CEL. The power utility will only cater for certain monopoly works, project monitoring for assets being built on behalf of Eskom, etc.
The DoE is a closed bid application process and the associated bidder selection.
Once the preferred bidders are announced they accept the project, and submit the sign-off and associated payment to the GAU to request the budget quote from Eskom.
The scope of work is cleared by the utility, and project accountabilities cleared between the parties. Eskom shall also authorize the IPP developer to perform the self-buildoption, should this be preferred. The work shall be performed by approved consultants and service providers.
All designs by Eskom and service providers must be cleared and accepted at the Eskom technical evaluation forum (TEF). This should cover all aspects of substation design, equipment standards, line design, servitudes, clearances, protection, SCADA interfaces, metering, etc. Also the responsibilities to maintain roads, for example, shall be addressed at this forum.
The various agreements with Eskom are prepared as part of the budget quote activity. This includes the self-build agreement (SBA) and the transmission or distribution customer use of system (DCUOSA). These documents are signed off by the contracts & legal department. The documents are managed via the GAU to ensure the customer targets are met.
DoE legal advisors compile the power purchase agreement (PPA) to be signed with the single buyer office (SBO). The SBO will manage the energy purchasing agreement and also handle any potential claims that may arise.
Once the IPP developer accepts the budget quote (and makes the required payment) and timelines are submitted via acceptable schedules, the project will continue.
The detailed designs for the assets are discussed and approved at the TEF, by both Eskom’s project engineering and consultants performing work under the SBA. Any deviations or additional technical requirements are approved by the TEF.
Eskom might construct the required assets as agreed, or monitor the works under the SBA. The utility will appoint a clerk of works and certain holding points of the project for inspections, must be adhered to.
Schedules should allow for the required transfer of technical data to Eskom, to allow for proper protection coordination and SCADA communication interfaces, so as to ensure full visibility at the point of connection (POC).
The utility will test and commission its assets. The responsible construction entity then needs to correct any deviations identified. The assets are transferred to Eskom for operations and maintenance purposes.
If the assets are created by the IPP developer, they need to take into account Eskom’s outage schedules well in advance.
The utility then supports the grid connection process. Based on certain criteria that should be met, the IPP could start generating energy and be paid for generation.
The schedule should also allow for the renewable energy technical evaluation committee (RETEC) to carry out the grid code compliance checks. The RETEC team consists of the National Energy Regulator of South Africa (NERSA), Eskom, municipal and industry representatives.
Once all criteria are met, the installation is accepted and as from this commercial operations date (COD) the IPP will be paid as per the PPA. The SBO manages the PPA along with the GAU as a continuous customer interface.
Role of the grid access unit
The grid access unit is the customer interface with all potential generation customers. This includes Eskom’s own generation and independent power producers and shall follow the same process. This is to ensure a fair and consistent approach to grid connection.
The GAU handles the grid applications and interface with transmission grid planning and distribution network planning from the various operating units, project engineering, the contracts and legal department, pricing and the SBO. They also liaise with NERSA’s RETEC teams to ensure that the required milestones and technical requirements are met. At successful commercial operation date of the plant, the required billing interfaces are activated.
The GAU monitors the potential projects and all applications are managed in a database. See Fig. 3 for a view of potential projects in such database. This is a constantly changing database. It assists the various planning groups and serves as indication to local groups for resource planning and future impact.
Fig. 3: Eskom GAU database reflecting potential identified renewable energy projects.
Eskom received a lot of last moment requests for bid window 4 (BW4), with the expectation that the CEL stays valid for as long as possible. As Eskom only processed the applications on receipt of the application fees, it led to delays in delivering a CEL. About one third of the BW4 CEL’s were issued before August 2014 and two-thirds had to be finalised and signed off by the technical team within the last three weeks; prior to the bid closure date. The need thus exists to have a cut-off date for CEL requests and the associated payments, e.g. three months before bid closure.
The Department of Energy wants to launch an accelerated RE procurement programme by the end of June 2015. It means that Eskom will also need to re-evaluate all potential projects and issue new CEL’s at an accelerated rate. It will require every project to go through a proper technical process and be peer reviewed again, to ensure the practical feasibility and validity of the previous scope of work.
DoE process and support
The IPP developers apply to DOE as per the rules and deadlines published in the RFP for that bid window. Eskom is not directly involved in the application process. The DOE IPP-Project Office makes use of various focus groups and advisors for their evaluation process. Projects are ranked as per the RFP evaluation criteria, for the different technologies.
Eskom re-evaluates all cost estimate letters and locations of those formal applications. A decision making matrix and network diagrams are prepared to assist DOE advisors with their decisions, to ensure that the selected top priority projects can actually be grid connected. Various projects might have specific conditions, e.g. the project is subject to the establishment of a new transmission substation or distribution overhead lines. All of these facts are then available to the DOE at the time of committing to a preferred bidder. The utility gives grid capacity and connection support, while the DOE advisors are finally responsible to recommend a final list to the DOE for final bid window approval.
The DOE issued determination 1 for 3750 MW which was over allocated during bid windows 1, 2 and 3. Determination 2 was approved for a further 3200 MW. This covered bid windows 3.5 and 4 with an initial allocation of 1121 MW. The minister also announced that an accelerated bid window in 2015 will be opened with an expected allocation of 1800 MW. This will however require a further Determination 3, that is planned for 6300 MW and in line with the IRP. It will also maintain the momentum of the programme and support future bid submission phases.
Small renewable energy programme
The DOE has launched the RFP for small renewable energy projects, in the range of 1 to 5 MW. This process required the submission of proposals and only those selected from this Stage 1 were allowed to progress to stage 2. This list of 29 potential developers then approached Eskom for their cost estimate letters to participate in a formal application process. It then follows the normal processing procedure through the GAU as described above.
This first round of applications for small RE projects started early 2014, but has not been concluded as yet. The expectation was that DOE would announce these first preferred bidders to a value of approximately 50 MW by May 2015.
There is a lot of interest in potential projects smaller than 1 MW. This however does not form part of the DOE small REIPP programme. Eskom and municipalities are responsible to ensure that safety and regulations are applied. In order to allow the connection of small projects, the following should be considered:
The NRS 097 series of documents specify the minimum technical requirements for LV generators connected to the South African grid. All LV grid connected generator interconnection equipment must be type-test certified, as complying with the minimum technical requirements of NRS 097-2-1. This is an industry document and not the sole responsibility of Eskom.
The maximum generator size to be allowed on low voltage (LV) networks is 350 kW. It further varies on different network conditions. See Fig. 4 for a LV connected generation simplified connection technical evaluation criteria flow diagram [2].
Fig. 4: LV connected generation simplified connection technical evaluation criteria.
The South African Bureau of Standards (SABS) needs to update the SANS 60142 standard with the safety requirements to allow for low voltage generation connections. It further requires the authorisation of technical and competent service providers to issue the required certificates of compliance, before legal connections will be allowed.
Any generation higher than 350 kW will be considered to be medium voltage (MV) or HV connected.
The Eskom tariff framework for small scale generation awaits finalisation and NERSA approval. NERSA is also in the process of investigating this requirement.
Technical evaluations
Eskom is supporting the industry to establish new generation projects. The utility makes available line routes and substation positions with the required geographic positions. This dataset does not contain detailed infrastructure capacities, as these are constantly impacted by evolving development plans and project capacity allocations. Potential developers are therefore encouraged to discuss the development requirements with planning staff before embarking on their own planning submissions.
The IPP developers and environmental consultants should take the Eskom requirements into account for their Environmental Impact Assessments (EIA) per project. The Department of Environment requires that all related projects be addressed in the EIA. Various EIAs are in progress where practical solutions for the grid connection have not been considered. This includes aspects such as identifying the correct local voltage for the appropriate development. The upstream network must also be suitable for the project and must allow space for the transmission or distribution lines to enter the substation and allow for potential future expansion of the substations. It must also be noted that these facilities are servicing the wider industry and society and therefore these potential space requirements must be planned to cater for these purposes. It is also important that safe working distances are considered in the proposals.
The power utility needs to service the area and minimise impact by power lines. It means that new lines might have to be installed with more capacity than just one IPP, to optimise the distribution networks and use of space into substations. Planning and design considerations must ensure that future load growth and distributed generation needs are adequately planned to avoid bottlenecks in the process.
Eskom receives several requests for PowerFactory or PSS/E network case files from the industry. It does not distribute network case files, just as most utilities worldwide do not share their case files either. The transmission case files contain the generators and controller models and information, for which Eskom signs a non-disclosure agreement with the power producer. It also contains customer information that is not for public dissemination. The utility has proposed, via the grid code industry expert team, for the use of reduced network models, and to supply only the applicable data as required for the project to support its plant design and grid code compliance studies to the intended user. The final technical decisions for the grid connections will reside with Eskom or any other responsible utility. They should use the latest operational conditions and also consider the future network design especially where new RE generation is shifted between different networks and substations, as new infrastructure is added
The network and grid planning application standard for generation grid connection – application standard for planning studies, shows various technical studies that are performed to ensure the proper integration of renewable energy projects into the network.
Over-voltage is defined and aligned with operational requirements for different networks. As Eskom has contracts with large customers, the operational voltage should not exceed 107,5% of nominal, with 110% used for equipment design standards; although the transmission 400 kV network only allows 105%. The low voltage is typical used as 90% for HV systems ≤132 kV.
The utility specifies the minimum fault level as used for harmonic allocations. These should however not be used for equipment fault ratings or design fault levels. If new networks are added, or existing equipment upgraded, the equipment specified should be rated to at least the rating specified in Table 2. It refers to the point of connection (POC) as the point where Eskom interconnects with the REIPP plant. As renewable energy plant increase to 17 500 MW by 2030 it is important to note that Eskom cannot yet predict where such plant will be and guarantee lower fault level will not be problematic. It is further recommended to not exceed 90% of fault levels indicated to allow for contingencies.
Table 2: Minimum equipment fault level ratings.
Equipment voltage level
Short-circuit rating at POC
11 kV
25 kA
22 kV
25 kA
33 kV
25 kA
66 kV
25 kA
88 kV
40 kA
132 kV
40 kA
The quality of supply needs to consider various parameters such as voltage unbalance. See Fig. 5. It was found that some photovoltaic plants tripped at about 0,5% voltage unbalance, although Eskom indicated that such plant should withstand a 2% unbalance. As this unbalance is experienced on single phase traction supplies off the 132 kV networks, these types of developments should be limited or designed to meet such requirements.
Harmonics and flicker components are proportionally allocated to different users, as Eskom cannot influence it on its own. Developers therefore need to consider these requirements for their plant design and also limit harmonics and flicker, as they are also a customer andnot just a generator. Each RE site shall be equipped with a meter to track the dip and voltage quality. Data history is being built up, and corrective steps are then considered where possible to reduce any related impact.
Fig. 5: Quality of Supply parameters to be considered.
The rapid voltage change, or now called voltage variation test, is designed to help secure voltage stability and prevent large voltage fluctuations for cloud cover transients, and large generation rejection. It might restrict the size of plant on weak networks, but helps with effective decision making, as Eskom cannot allow any size plant where it is not suitable. See Table 3 for the voltage variation test criteria.
Table 3: Voltage variation test criteria.
Criteria
Basis
Reference
Limit
Voltage variation test (sudden loss of generation)
Non-fluctuating generation 1, i.e. more stable (disconnection due to fault or inadvertent trip)
RSA grid code [6] and internal Eskom planning criteria
≤ 5%, at minimum leading PF of 0,975 for generation plants ≥ 20 MW and ≤ 5%, at minimum leading PF of 0,9875 for generation plants < 20 MW
≤ 5%, at minimum leading PF of 0.95 for all generation plants ≥ 20 MW and ≤ 5%, at minimum leading PF of 0,975 for all generation plants < 20 MW
Fluctuating generation such as solar PV or wind generation
Fluctuating generation such as solar PV or wind generation
RSA grid code [6] and internal Eskom planning criteria
≤ 3%, at minimum leading PF of 0.975 for generation plants ≥ 20 MW and ≤ 3%, at minimum leading PF of 0,9875 for generation plants < 20 MW
The following factors influence the voltage variation test:
Fault level
Power factor
X/R ratio and the magnitude of X and R
Line loading
Change in network configuration
N-1 reliability scenario(s)
The technical analysis needs to address the thermal loading of plant such as transformers and lines or cables. The planners also need to make conscious decisions about losses reduction. The focus on losses, voltage control, voltage variation and certain limits are co-dependent variables and need to be optimised for future applications as well.
The standard for the interconnection of embedded generation [7] addresses the operational and safety aspects. This includes the excitation control and governor requirements and protection requirements for synchronisation and the prevention of out of synchronism closure, islanded operation and voltage ride through capabilities. The protection interface requirements are addressed to ensure that RE plant properly integrate with Eskom requirements, as the responsible grid operator.
The requirement at the Point of Utility Connection (PUC) is defined to ensure that the REIPP plant can be successfully protected and isolated by the plant operator. Eskom does not have control over the Point of Generator Connection (PGC) within the plant itself. Eskom further defines that the Quality of Supply requirements to be met at the Point of Common Connection (PCC) where other customers could connect and potentially be influenced. It is required from the REIPP to clear these design interfaces with Eskom at the Technical Evaluation Forums. It also covers the following requirements:
DC systems and auxiliary supplies
Eskom system metering and REIPP plant facility metering
SCADA as well as minimum requirements for data exchange
Pre-commissioning and commissioning tests
Maintenance tests
The REIPP programme allow for sharing the risk during serious system events. It allows a grid availability of 98% for Transmission (>132 kV) and 95% for Distribution (11 ≤ 132 kV). It means that if Eskom does not meet the availability per annum, then Eskom needs to compensate the RE IPP developer as per the power purchase agreement. A study was done on the Distribution Supply Loss Index (DSLI) measuring the availability across 3524 substations over a nine year period. The results are shown in Table 4.This reflects an average of unavailability of 7,7 hours per annum in the distribution network and only four incidents where availability dropped below 98% due to major equipment failure. Due to backfeed capability and emergency response this was not felt by customers.
Table 4: Eskom substation availability measured by the DSLI.
Province
Number of substations
Average availability
Eastern Cape
204
99,93%
Free State
324
99,93%
Gauteng
658
99,93%
KwaZulu Natal
475
99,86%
Limpopo
293
99,89%
Mpumalanga
510
99,95%
North West
311
99,91%
Northern Cape
229
99,92%
Western Cape
520
99,88%
Grand Total
3524
99,91%
Grid code compliance
The grid connection code for renewable power plants (RPPS) connected to the electricity transmission system (TS) or the distribution system (DS) in South Africa is NERSA’s responsibility. Eskom supports the grid code development and needs to adhere to the grid code requirements [6]. The grid code for renewable energies is under continuous development and the latest version 2.8 is dated July 2014.
The renewable energy projects are visited by the RETEC team to check for grid code compliance. The teams in different provinces consist of technical people from NERSA, Eskom’s system operator, Eskom’s network operator and municipal network operators. They test for the various grid code requirements and either approves plant, or grant temporary exemptions to allow them time to meet the requirements. Where there are very specific reasons that are not critical, the RETEC team may recommend an exemption to the grid code advisory committee (GCAC). The operating units support RETEC via the network optimisation sections. They are responsible to resolve any local requests and support any exemptions to the GCAC.
Transmission grid connection capacity assessment (GCCA)
Eskom produced the transmission grid connection capacity assessment (GCCA) of the 2016 transmission network [3]. The criteria are being reviewed to align with the grid code requirements.The GCCA “rules” initially catered for N-1 transformer capacity during low load scenarios. The South African Grid Code for Transmission does not require N-1 reliability criteria for generation plant smaller than 1000 MW albeit that it might be still applicable to specific older generation plant and their design criteria.
The transmission grid is being studied to produce a new 2020 to 2022 view. It addresses the larger supply area EHV steady state limit, as well as the stability limits. It indicates the expected grid capacity available for the transmission substations. It reflects non-diversified generation for various technologies, until such stage that Eskom has gained sufficient operating experience in specific areas to influence future capacity studies. The GCCA document should be used by all planners in transmission and distribution, as well as all developers and their consultants. It should be noted that even though there might be capacity available in the GCCA document, each planner will still need to do a grid impact assessment for any generation application.
An extract of the GCCA 2016 transmission substations is presented in Table 5. It clearly shows some limitations at some of the more preferred substations. Komsberg was granted two 140 MW wind developments and an accordingly a new 400/132 kV substation is required to evacuate the power. It will also help to open up the substation for further projects. Eskom governance processes require firm projects to be available to allow for such developments. The strategic development of potential grid connection capacity is receiving attention.
Table 5: Selected transmission substations with capacity available after BW4.
Main transmission substation
Sum of GAU MEC MW
GCCA MW available
REIPP 1-4 MEC MW
Main transmission substation
Sum of GAU MEC MW
GCCA MW Avail
REIPP 1-4 MEC MW
Aggeneis 400/220 kV
690
175
Juno 400/132 kV
30
131,2
108,8
Aries 400/22 kV
30,35
9,65
Koeberg 400/132 kV
116
220
279,8
Aurora 400/132 kV
174
499,8
250,2
Komsberg 400/132 kV
490,4
0
280
Bacchus 400/132 kV
310
593,81
62,19
Kronos 400/132 kV
1037,2
80,1
169,9
Boundary 275/132 kV
1150
183,28
228,15
Matimba 400/132 kV
250
200
60
Ferrum 275/132 kV
305
32,3
224
Mookodi 400/132 kV
460
530,9
Ferrum 400/132 kV
555
445,3
100
Muldersvlei 400/132 kV
175
861,6
138,36
Garona 275/132 kV
85
75
50
Olien 275/132 kV
656
61
239
Grassridge 400/132 kV
261
358
642,25
Paulputs 220/132 kV
235
35
294,65
Gromis 220/66 kV
140
45,4
Pembroke 220/132 kV
74,2
223,4
20,6
Harvard 275/132 kV
155
555,4
64
Poseidon 220/132 kV
355
91,14
158,4
Helios 400/132 kV
225
224,1
275,9
Poseidon 400/132 kV
560
19
481,2
Hydra 1 400/132 kV
75
469,05
Roodekuil 220/132 kV
75
0
Hydra 2 400/132 kV
887,5
265
235,5
Ruigtevallei 220/132kV
380
0
69,9
Impala 275/132 kV
135
842,7
16,5
Upington 400/132 kV
1256
146,1
383,9
The grid capacity is checked for each network and the associated substations, as different limitations might apply at various levels. Refer for example to the Hydra substation with its 2 x 240 MVA 400/132 kV, and to be established 1 x 500 MVA 400/132 kV sections. (Refer to Fig. 6 for the high level Hydra requirements). The two 132 kV busbars cannot interconnect due to high fault levels, but also due to the practical layout in the substation on opposite sides of the substation. It means that any spare capacity cannot be added up for both busbars. Any grid capacity study should regard these as two separate substations. Any 132 kV networks connected to the busbar Hydra 1 cannot just be transferred to the Hydra 2 busbar, as new routes and corridors need to be established. Any new developments must be routed to the new Hydra 2 section. The utility works with consultants to ensure all parties understand the complexity around each substation.
Fig. 6: Hydra 2×240 MVA 400/132 kV and 1×500 MVA 400/132 kV sections.
Strategic environmental assessment (SEA)
A further study looked into the strategic future network, taking into account various scenario planning approaches till 2040. It defines the five strategic environmental assessment (SEA) corridor routes based on available information and known expectations. This is illustrated in Fig. 7. The request is that provincial and municipal development plans need to recognise these corridors and accommodate them in their own development plans. Eskom further produces the transmission ten year development plan and distribution network development plans; taking the provincial and municipal development plan information into account. These plans are expanded and also consider the potential renewable energy projects, to develop robust network solutions.
The SEA networks aim to service the eight renewable energy development zones, as shown in Fig. 7. (For more information on the REDZ, refer to work by CSIR and Department of Environmental Affairs) [4]. The objective is to secure all the needed environmental approvals for transmission overhead lines within the proposed corridors, which will be valid for longer periods. The current EIA validity period does not support longer term strategic projects. The objective is now to determine the least impact areas within these corridors for the routing of future main transmission lines.
Eskom also needs to consider potential nuclear and gas based generation at various locations, and develop power evacuation corridors along with the renewable energy scenarios. The proposed five SEA corridors will be developed with 400 kV, 765 kV and HVDC, depending on the preferred gas and nuclear site implementation plans. These power corridors will vary in capacity of between 3000 and 6000 MW. The northern corridor also needs to consider potential imports from outside South African borders and cater for capacities up to 7000 MW.
Fig. 7: Proposed strategic environmental assessment (SEA) corridors.
Conclusions
Eskom supports the grid connection of renewable energy IPP’s through customer services processes and actual deliverables. It has been demonstrated that the utility covers a wide field of requirements to ensure the successful grid integration of renewables.
It is a major achievement to process more than 1120 individual project proposals, of which 83 have been granted development status to the value of 5052 MW, from 2011 to 2015. The industry is further supported by proper guidelines and grid capacity studies. It is also proud of the fact that more than 2000 MW is currently connected to the grid. The power utility has learnt valuable lessons thus far, which have contributed to the steep learning curve in terms of allowing renewable energy and distributed generation to grow in South Africa.
Acknowledgement
The author would like to acknowledge the inputs of Mobolaji Bello,Kurt Dedekind, Pervelan Govender and Kevin Leask in contributing to this paper. The contributions of the grid access unit personnel are also acknowledged.
References
[1] R Smit: “Process for Eskom IPP renewable energy grid integration”, Energize RE: Renewable Energy Supplement, June 2013.
[2] M Belo: “Network and grid planning application standard for generation grid connection – application standard for planning studies”, Eskom, October 2012.
[3] C Mushwana: “GCCA 2016 Report Rev 2”, Eskom, June 2014.
[4] https://redzs.csir.co.za/
[5] Department of Energy: “REIPPPP Preferred Bidders for Window 4 Announcement”, 16 April 2015.
[6] NERSA: “Grid connection code for Renewable Power Plants (RPPS) connected to the electricity Transmission System (TS) or the Distribution System (DS) in South Africa”, July 2014.
[7] A Craib: “Standard for the Interconnection of Embedded Generation”, Eskom, October 2013.
Contact Riaan Smit, Eskom, Tel 021 980-3452, riaan.smit@eskom.co.za
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