EB EE3 m 0 ZEE 0 m OMEEDD El 3 E3 M a El E3 El E X ~~~~~~~M a S X~~~~~~~~~~~~~~~~~~~~~~Q JOINT UNDP / WORLD BANK ENERGY SECTOR MANAGEMENT ASSISTANCE PROGRAMME (ESMAP) , a f f PURPOSE The Joint UNDP/World Bank Energy Sector Management Assistance Programme (ESMAP) was launched in 1983 to complement the Energy Assessment Programme, establibhed three years earlier. ESMAP's original purpose was to implement key recommendations of the Energy Assessment reports and ensure that proposed investments in the energy sector represented the most efficient use of scarce domestic and external resources. In 1990, an intermational Commission addressed ESMAP's role for the 1990s and, noting the vital role of adequate and affordable energy in economic growth, concluded that the Programme should intensif, its efforts to assist developing countries to manage their energy sectors more effectieely. The Commission also recommended that ESMAP concentrate on making long-term efforts in a smaller number of countries. The Commission's report was endorsed at ESMAP's November 1990 Annual Meeting and prompted an extensive reorganization and reorientation of the Programme. Today, ESMAP is conducting Energy Assessments, performing preinvestment and prefeasibility work, and providing institutional and policy advice in selected developing countries. Through these efforts, ESMAP aims to assist governments, donors, and potential investors in identifying, funding, and implementing economically and environmentally sound energy strategies. GOVERNANCE AND OPERATIONS ESMAP is governed by a Consultative Group (ESMAP CG), composed of representatives of the UNDP and World Bank, the governments and institutions providing financial support, and representatives of the recipients of ESMAP's assistance. The ESMAP CG is chaired by the World Bank's Vice President, Operations and Sector Policy, and advised by a Technical Advisory Group (TAG) of independent energy experts that reviews the Programme's strategic agenda, its work program, and other issues. The Manager of ESMAP, who reports to the World Bank's Vice President, Operations and Sector Policy, administers tne Programme. The Manager is assisted by a Secretariat, headed by an Executive Secretary, which supports the ESMAP CG and the TAG and is responsible for relations with the donors and for securing funding for the Programme's activities. The Manager directs ESMAP's two Divisions: The Strategy and Programs Division advises on selection of countries for assistance, carries out Energy Assessments, prepares relevant programs of technical assistance, and supports the Secretariat on funding issues. The Operations Division is responsible for formulation of subsectoral strategies, preinvestment work, institutional studies, technical assistance, and training within the framework of ESMAP's country assistance programs. FUNDING ESMAP is a cooperative effort supported by the World Bank, UNDP and other United Nations agencies, the European Community, Organization of American States (OAS), Latin American Energy Organization (OLADE), and countries including Australia, Belgium, Canada, Denmark, Germany, Finland, France, Iceland, Ireland, Italy, Japan, the Netherlands, New Zealand, Norway, Portugal, Sweden, Switzerland, the United Kingdom, and the United States. FURTHER INFORMATION For further information or copies of completed ESMAP reports, contact: The Manager or The Executive Secretary ESMAP ESMAP Consultative Group The World Bank The World Bank 1818 H Street N.W. 1818 H Street, N.W. Washington, D.C. 20433 Washington, D.C. 20433 U.S.A. U.S.A. TUNISIA POWER EHFICIENCY STUDY FEBRUARY 1992 ESMAP Operations Division The World Bank Washington, D.C. 20433 I This document has restricted distribution. Its contents may not be I disclosed without Government, UNDP or World Bank authorization. FOREWORD This study, which was carried out at the request of the Tunisian Electricity and Gas Utility (STEG) in agreement with the Inustry and Energy Division of the Bank's Maghreb Department, was seen as a challenge from the begimring. STEG has good performance compared to that of most utilities in developin countries, with transmission and distribution losses of about 13 to 14% compared to 30 to 40% for many utilities of the same size. In addition to reduction of network losses, the study identifies technical, organizational, and Institutional changes that would increase the overall efficiency of Tunisias power system, and recommends the measures and/or additional studies needed to implement the proposed changes. This study was financed according to a special grant procedure, the "Trust Funds Extended Agreement' with the assistance of Mrs. J. Ferry of the Multilateral Aid Division of the French Foreign Ministry. The study was carried out within the framework of a contract between ESMAP and Blectricitd de France (EdF, the Consultant), with the active pat-cipation of a task force composed of representatives of the relevant STEG departments, coordinated by the Planning and General Studies Department, on behalf of STEG Management. fhe preliminary report of the study was examined at a meeting of STEG's Board of Directors on November 6, 1990, and a number of the recommendations ma4e in the report were adopted. The EdF team members were: Messrs. Henri Boyd (project manager), Gerard Aubeat (generadon specialist), Jean-Pau Barret (transmission specialist), Jean-Frangois Bruel (computer distribution specialist), Raymond Sinus (distribution operation specialist), Marie-Line Marcin (technical distribution specialist), Olivier Gourlay (customer management specialist), and Alain Polvent (customer management specialist). The STEG task force members were: Messrs. HEdi Turki and Hassen Mamud (Planning and peneral Studies Directorate), Messrs. Mahmoud Lakhoua, Mekki Ayed, Chekib Ben Rayana, Lamjpd Fekih, Mohamed El Kamel (Operations Directorate), Messrs. Khaed Hammou, HEdi, Turki, Chedl Jeddi, Taoufik Barbouche, Belgacel:. Ghariani (Distribution Directorate). Noureddine Berrah (Senior Economist and task manager, ESMAP) supervised the project, and wrote thbis report, basing it on the reports submitted by the Consultant and on the comments of the STEG task foc. F. Jouve (Power Engineer, ESMAP) contributed extensively to the final preparation of the report ACRONYMS AND ABBREVIATIONS AME Agence de Mattse de l'Energie BCC Bureau central de conduite (Distribution Control Center) BDM Bureau des methodes (Procedures Department) CAO Consumption ascertained during operation CL Core losses COMELEC Comite maghrdbin de I'electricit6 DD Distribution Directorate DPWT DEpartement des techniques gdn6rales (Technical Facilities Departmet) EdF ElectrlcitE de France GT Gas turbine GTD Gestion technique des ouvrages HHV High heating value of fuel HR Heat rate (actual) HV High voltage JL Joule losses LV Low voltage MSI Mise en service industrielle (Commercial Operation) MV Medium voltage NORDEL Nord Electricit6 OBC Optimum base consumption OD Operations Directorate (Direction de l'exploitation) SME Service des Mouvements d'Fnergie ST Steam turbine STEG Socit tunisienne d'dlectricitW et du gas (Tunisian Electricity and Gas Utility) tan phi Tangent of power factor angle UCPTE Union de coordination des producteurs et transporteurs d'electricitd VHV Very high voltage ELECTRICITY MEASURES GWh Gigawatt hour I Joule kcal kilocalory kV kilovolt kVA kdlovolt amperes kW kilowatt Mi mega joule MVA megavolt ampere MW megawatt Ti tera joule toe ton of oil equivalent V volt CURRENCY BQUWIALNT 1 US$ z 0.9 Tuniian Dinar FISCAL YEAR January 1 - December 31 TABLE OF CONTENTS SUMMARY ......................... i ]INTRODUCTION . 1 Organizational Structure of the Tunisian Electricity and Gas Utlity. 1 Demand Growth .. ... . 2 Study Objective and Methodology ............................ 2 Local Participation and Skills Transfer ...... 3 Report Organization. 4 II. ELECTRIC POWER GENERATION .5 Steam Turbines.... 7 Heat rate monitoring .... 7 Analysis of deviaions.... 9 Setting up efficiency monitoring in the STEG plants .... 12 Unavaiability rates ....13 Maintenance . . ...................................... 14 Inventory management ................................. 16 Combustion Turbines .................................... 17 Heat rates ......................................... 17 1vfahiteiaiice .... 17 Unavailability . . ..................................... 19 Hydropower Generation ...... ............................ 19 Efficiency/availability . . ................................ 19 Maintenance . . ...................................... 20 Conclusions and Recommendations ............................ 20 Short-term recommendations .............................. 21 Medium-term recommendations ............................ 21 M]. TRANSA>ON . ........................................ 24 Simulation of Transmission Network Operations ... ................ 24 Actions Needed to Reduce Losses ............................ 26 STEG NetworkControl ................................... 26 Voltage levels .................... .......................... 26 Compesaion ... 27 Operation ........................................... 29 Additional Actions Needed to Improve Transmission Network Efficiency .... 30 14~~ ~ ~ ~ ~ . . .. 3 - T"ifins ...................................., ......... 32 Iierconviicton .. . .... ............. . 32 IV. DISMUBTION........... 34 Data Collection and Loss Assessment Method ......... 35 Status of available data .. ....... ...... 36 Recommeniations .... ...... ..... 36 Loss assessment method............ 37 Reduction of MV Nework Losses. 38 Assessment of MV network losses. 38 Reduction of MV network losses. 39 Reduction of LV Network Losses .... ...41 Assessment of LV network losses. 41 Reduction of LV network losses ....42 Assessment and Reduction of Losses from Transformers . .45 Losses in the HV/MV taunforners. 45 Reduction of losses in HV/MV transformers . 46 Improving the transrmer utilization factor ..47 Losses in the MVLV transformers ..48 Reactive energy compensation ......... 49 Reactive energy billing. 50 Additional Problems Associated with Operation of the MV/LV Networks .... 51 Maintenance .....52 Prevention of risks associated with the use of PCB ...... 52 V. CUS N MANA...ER ...GE. . 53 Metering ....53 Unmetered consumption. . . .. 53 CustomerBilling ... . ....57 Processing new customers... 57 Meter reading. . . ..... 57 Monitoring of special-tariff customers . . ..... .58 Billing procedures and correction of anomalies . . . 58 Distibution of bllls . ....S.... . 59 DebtRecovery. . . .. 59 Tadff Policy .... . ..... 62 'W. CONCLUSIONS .......63 Main Actions Proposed......... 63 bpact on theEnvironient.. 64 Power Conservation at the Level of Final Use ..... .................. 64 I S OG Organizational Structure ................................ 66 2 Calculation of Losses ...................................... 68 3 Equivalence Between the Inmediate Rate of Return and the Internal Rate of Return 87 4 Heat Rates of the Steam Thermal Plants .......................... 88 5 Efficiency Monitoring ...................... .......,.. 94 6 On-Line Monitoring of the Operating Efficiency of the Fuel-Buming Thermal Power Plants 99 7 Unavailability Rates and Availability Statistics for Conventional Thermal Power Units ...................... ................. 107 8 Standard Maintenance Cone pts .. .I ................. ........... 109 9 Load Flow Calculations - Hypotheses and Summary of Results ........... . 112 10 Impact of Compensation on Loss Levels ........... ............... 116 11 Reactive Power Compensaion Survey ............................ 119 12 Economic Analysis of Compensation ............. ................ 123 13 Selection of Network Sample ................................. 127 14 Cross-Section Change ...................................... 142 15 Transformer Operation in the HV/MV Substations ...... .. ........ ... 154 16 Guide for Preparing Maintenance Procedures ............ ........... 155 TABLES I Reduction of MV Network Losses ....... ....................... vi 2 Reinforcement of the LV Network .................. vii 1.1 ElectricityBalance ........................................ 2 2.1 STEG Generating Equipment in 1991 ................. 6 2.2 Steam Plant Heat Rates in 1988 ...... ... ...................... 8 2.3 STEG: Combustion Turbines (1988-1990) ......... .. .............. 18 4.1 Key Features of STEG Distribution Zones ......... .. .............. 34 4.2 Network Losses: MV Sample ............... .................. 39 4.3 Reduction of Losses from MV Networks .......................... 41 4.4 Peak Power Losses: LV Feeder SanIple .......... .. .............. 42 4.5 Estimated Costs of Upgrading the STEG LV Network to 220 V ..... ....... 43 4.6 Network Reinforcement: LV Feeder Sample ....................... 44 4.7 Reinforcement of the LV Network .............. ................ 44 4.8 Losses in the HV/MV Transformers ........... .. ................ 46 4.9 Losses in the MV/LV Transformers ............................. 48 4.10 Savings Achievable by Reducing the Inventory of MV/LV Transformers .... .. 49 5.1 Change in Debt Due to STEG ................................. 60 6.1 Main Actions Proposed ..................................... 63 A2.1 SummuyoflInvestmentsinMVSubstations .............. 77 A2.2 Summary of nvestments MVlLV Substations ..................... 78 A2.3 Summary of Investnents ia LV Substations .......... .............. 80 A2.4 Annual Cost of One kW of Peak Losses .......................... 84 A2.5 Total Annual Cost of one kW of Core Losses in the Transformers .......... 85 A2.6 Annual Cos: of one kW of Losses ............. . ....... . ., .... . 86 A3. 1 Conversion of Immediate Rate of Return into Internal Rate of Retrn ........ 87 A5.1 Sample Variations in Operating Parameters and their Effects on the Heat Rates of a 125 MW Unit .... .................... 95 A6.1 Measurements Needed for Efficiency Monitoring of the Thermal Power Plants 99 A6.2 Cost Estimate for Installation of an Efficiency Monitoring System for Two UJnits .......................................... 101 A7.1 Unavailability Rates and Availability Statistics for Conventional llermal Power Units ...................................... 108 A9.1 Nodes: Active and Reactive Power ...... ....................... 112 A9.2 GeneratingSftData ...... ..... , 113 A9.3 UNOM ± 10% ........... 114 A9.4 Generating Units Expected to be in Operation in 1993 ........... ....... 115 AIO. 1 Perc§ntage Losses on STEG's HV Network Only (evening peak) 116 A10.2 Percentage Losses on STEG's HV Network Only (morning peak) . .117 A10.3 Percentage Losses on STEG's HV Network (night trough) . .118 A;l.1 List of 150 kV and 90 kV substations for which tan phi is greater than 0.5 .. 119 Ai1.2 Compensation Required by Substation to Bring tan phi back to 0.5 . .120 A11.3 Measuring the Effect of the Proposed Additional Compensation. 120 A13.1 heMVVLVoDistributionNetwork. 128 A13.2 Technical Distribution Ratios ..129 A13.3 Regional Distribution ..130 A13.4 Network Development. 130 A13.5 Sales of HV/MV Power by Sector .... 131 A13.6 Power Sales to HV Subscribers. ..99 131 A13.7 Def£nition of the zones ........ .. 133 A13.8 City of Tunis District, source station: Tunis South ... . ................ 135 A13.9 City of Tunis District, source statn: Tunis Center . .. 136 A13.10 City of Tunis District, source stati(n: Tunis West I ................... 137 A13.11 City of Tunis District, source station: Tunis West 2 .... 138 A13.12 City of Tunis District, source station: Tunis North .. . . 138 A13.13 City of Tunis District, source station: Zharouni . .. 139 A13.14 Nabeul District, source station: Hammamet ... 139 A13.15 Nabeul District, source station: Grombalia ... .. 140 A13.16 Nabeul District, source station: Korba .... . . 140 A13.17 Interdependent Criteria, City of Tunis District .. . 141 A13. 18 hiedepntde Criteria, Nabeul District .. . 141 A14.1 Investment Costs for the Various Conductor Types ..... .. . 143 A14.2 Reconductoring of the Haouria MV Feeder (Nabeul District) ... 144 A14.3 Reconductoring of the Belli MV Feeder (Nabeul District) . . . 145 A14.4 Reconductoring of the Lakmes MV Feeder (Siliaaa District) . .. 146 A14.5 Reconductoring into 352 Alu - Threephase Network B2 . . . 148 A14.6 Reconductoringinto 702 Alu - Tbree-phase Network B2 . .. 149 A14.7 Reconductoring of the El Djazira Feeder, City of Tunis District . . . 150 A14.8 Reconductoring of the Enzzitouna Feeder, City of Tunis District .. . 150 A14.9 Reconductoring of the Onas LV Feeder, Ezzahra District .. . 151 A14.10 Reconductoring of the IndEpendance LV Feeder, Ezzahra District .......... 151 A14.11 Reconductoring of th K a Feeder, Ezzahra Dbtraet .D ct................. 151 A14.12 Reconductoring of the Ecart Nord Al LV Feeder, Nabeul District .... ... ... 152 A14.13 Recondutoring of the Ecart Nord A2 Feeder, Nabeul District ........ . .... 152 A14.14 Reconductoring of the Ecart Nord A3 Feeder, Nabeul Distict ............. 152 A14.15 Reconductorlng of the Ecart Nord A4 LV Feeder, Nabeul District ..... ...... 153 A14.16 Reconductoring of the Kaounia LV Feeder, Nabeul District ......... ..... 153 A14.17 Reconductorlng of the Karsoline LV Single-Phase Feeder, Nabeul District ..... 153 A15.1 List of Substations for which it Is more Economica to put only one HVlMV Transformer into Service .......... ......... 154 FGUPeS 1 Load1DurationCCurve, 1989 .. . .. ... ...... 71 2 Calculationof AnnulFuel Cost . . ... ......... . 73 3 HeatRate Vaiation due toShutdownofthcFeedwaterSystem ............ 98 4 ¶h eNetworkin 1989 ...................................... 121 5 nhe Networkby 1993 ............................... . ..... . 122 MACA ]BRD 23592 EXEUTIVE SUMMARY 1. In the past few years, the Tunisian Electricity and Gas Utility (STEG) has made signiflcant progress in improving its operations and reducing losses in the electricity network. Fuel consumption per GWh produced has been reduced by about 23% in five years (from 309 toe/GWh in 1985 to 278 toe/GWh in 1987 and 251 toe/GWh in 1989) and the overall efficiency of the transmission network has been improved ty about 2.5% in five years (from 83% in 1985 to 85.5% in 1989).1/ 2. The diagnostic study carried out as part of the joir.t World Bank/UNDP Energy Sector Management Assistance Programme (ESMAP), with the active participation of STEG experts and support from the Industry and Energy Division of the Maghreb Department (EM2IE), has shown that: (a) because of the progress STEG has achieved in electricity network operation and in customer management, the power loss rate in Tunisia is among the lowest to be fbund in the developing countries, especially with regard to nontechnical losses; however, preserving this achievement requires sustained efforts to Improve management, rigorous application of existing procedures, and improvement of the statistical system and efficiency monitoring; (b) additional savings can be made by introducing more advanced operating methods and by making economically justifiable power efficiency investments both in generation (heat rate reduction in the power plants) and in transmission and distribution (reduction of technical and non-technical losses). 3. PoE w gia1er. The audit of generation activities confirmed STEG's eaicient performance in this area, despite certain weaknesses. The principal recommendations of the study entail: (a) in the short term, (i) continuing rehabilitation and renovation or me old steam thermal plants so as to improve availability and efficiency; and (ii) standardization and upgrading of statistical data on fuel consumption and on generating unit availability; (b) in the medium term, (i) minor organizational changes to ensure better coordination of operation and maintenance; and (ii) introduction of more advanced management methods to improve the efficiency of existing and future generating units, especially as the utility is still faced with a high tempo of investment. 4. Rehabilitation and renovation of old thermal power plants. STEG has begun to renovate its old steam thermal plants, which has significanty increased the efficiency of the units involved. The mission recommends that STEG continue these actions and that it establish a rehabilitation and renovation I/ 7he overjky of de network is dnd as dhe ratio of energy billed to energy sypped, measured at theplan tentale. - ii - program for all the units in the La Goulette and Ghannouch power stations. STEG's experience has confirmed the conclusion ESMAP has reached In a number of countries, that well-planned investments in renovation and rehabilitation have high economic rates of return. The investments made at Goulette I to improve control systems and the installation of pre-heating equipment were recovered in nine months through energy savings alone, without taking into account the fact that renovation of the equipment extends its life and Improves its availability, and hence enables investment in new generating units to be deferred. 5. Improving data quality and availability. Tbis effort should be part of the overall review of the utility's statistical system and its computer master plan, after the Planning Directorate has completed an audit. However, certain measures, such as improving gas metering to make the relationships between the Gas Directorate and the Operations Directorate more transparent, and standardizing and improving the data on heat rate and generating unit availability, (the plant operators record these data monthly and annually), are urgently needed and essential to improved monitoring of the performance of the generating system. 6. Orgmioag measures. The mission recommends three minor structural changes to the Operations Directorate to improve coordination and prepare for the introduction of more effective maintenance methods and procedures: (a) create the position of manager for steam turbine generation with the same level of responsibility as for existing positions related to gas turbine and hydropower generation. Creation of this position would improve coordination and standardization of procedures between the power plants and would strengthen the Operations Director's role as the overall manager and arbiter; (b) establish a "Procedures Department" (Bureau des Methodes - BDM) to enhance coordination of operation and maintenance of the combustion turbines. This department could be integrated into the existing BDM for the steam thermal plants and located at La Goulette so as to benefit from the assistance of the Technical Facilities Departnent (DIpartement des Techniques G6ndrales - DPITG); and finally (c) create a small unit (startng with one engineer and one technician), perhaps within the BDM, to develop maintenance procedures and coordinate and monitor their implementation through the maintenance programs. 7. ImW1empentatiqn of online efficiency monitoring of the steam turbines. The report recommends study and implementation of computerized online efficiency monitoring of the steam turbines based on continuous comparison of the performance parameters obtained with unit reference parameters to ensure that fuel consumption approximates optimum base consumption (OBC) as closely as possible. The economic return on this Investment is high since the investment payback period, even using conservative cost and benefit assumptions, would be around 11 months (see para. 2.50). - iii - 8. jbpxduction of wconditional" or predictive maintenance. The report recommends the study and introduction of "conditional" or predictive maintenance programs. STEG could use such programs, which are increasingly being adopted in the developed countries, for each component or family of components, using STIEG in-house, centralized research resources (DPTG). ESMAP's experience in this area shows that such projects have very high internal rates of return, for companies less efficient than STEG. The estimated reduction in STEG's maintenance costs is around 8% to 10%, i.e., a saving of between US$1 million and US$1.25 million in 1990 and of between US$1.2 million and US$1.5 million in 1995. Trapsmiasson 9. Simulations of the transmission network lead to two conclusions (see paras. 3.2 to 3.4): (a) in all operating systems examined, theoretical power losses are about 1% to 1.2%, or only about one third of actual identified losses in 1989, which were around 3.6%. The reason for this discrepancy needs to be found: it could originate from metering irregularities and/or from failure to account for the substations' own power consumption, or to a discrepancy between the model (reference condition, electrical characteristics of lines and equipment) and actual operating conditions; (b) the system power factor is abnormally low during the day, particularly during the morning peak period, around 0.82% in 1989 for the situations studied. Unless STEG implements reactive power compensation, the situation will grow worse over the medium term. 10. Analysis of the causes of technical losses in the network highlighted the need for three kinds of action: (a) increasing the network operating voltage levels and selective reinforcement of the reactive power compensation equipment; (b) improvements in the operation and maintenance of the transmission network; and (c) progressive actions that contribute indirectly to increasing the efficiency of the transmission network, viz., strengthening the planning function and making organiational changes. Voltaye ungrading 11. The simulations show that raising the maximum voltage level from 210 kV to 225 kV reduces active power losses by some 2 MW for a load of 1,000 MW (peak demand in 1993). This upgrade, valued at the incremental cost for a kW of energy at the HV transmission level, produces a savings of about TD 400,000, or US$444,000, per year. - iv - 12. Ihe mission therefore recommends the study and determination of suitable criteria to monitor and control the performance of the network, thus detecting weak points and anticipating low voltage conditions that may arise. This would allow the operators to take timely measures to restore voltage levels and maintain satisfactory service quality, and would avoid the risks of unplanned load shedding. The benefits due to improved service quality are hard to quantify but experience in other countries has shown that a 5% drop in nominal voltage at customer level leads statistically to a 2% drop in load. Poor service quality causes economic losses to customers and financial losses for the utility (see paras. 3.7 to 3.10). 13. The study showed that the system power factor is abnormally low, especially during the morning peak period, and that the situation will worsen unless measures are taken to enhance compensation by: (a) using the gas turbines at Tunis Sud as synchronous compensators, and/or (b) installing additional capacitors: in 1989, for example, 120 to 130 Mvar was needed to improve the power factor from 0.8 to 0.9. By 1993, 211 Mvar would be needed to maintain tan phi, the reactive to active power ratio, at 0.9 (see paras. 3.19 to 3.21). 14. Reducing transmission network losses cannot by itself guarantee a return on investments in compensation equipment, but such investments help to improve voltage control and, hence, to improve service quality and network reliability. Since detailed studies to evaluate all the advantages of compensation are beyond the 3cope of this study, the mission recommends that STEG undertake a study to identify, for all voltage levels, the number and types of compensation devices needed to ensure satisfactory network operation from a technical standpoint while keeping investment costs to a minimum. Improving operations 15. The operation of STEG's transmission network is satisfactory, but to reduce the effects of insulator flashover, which is most marked in the 150 kV lines, and to reduce outages attributable to chemical and marine pollution, the mission recommends that STEG: (a) undertake a study to measure cable sag and conduct a technical and economic analysis of the need to re-tension some cables; and (b) improve insulator cleaning procedures in areas where frequent flashovers occur due to chemical and marine pollution, and study the feasibility of introducing procedures for hot line cleaning of insulators. In particularly polluted areas, it is advisable to introduce special types of insulators, at least on an experimental basis, and to undertake detailed technical/economic studies on the introduction of Gas Insulated Stations (GIS). QxmAIUaLmand ngi 16. To betr fit the management responsibilities for operation and customer management to the technical demarcation between the transmission and distribution functions, two minor orgaiational changes are recommenhied: (4) divide the responsibility for management and operation of the protectve equipment according to the functiona difference between tranmission and distribution; and (b) create a unit within the Operations Directorate to take over the management of high-voltage consumers from the Distribution Directorate. 17. The quality of ntwork analyses should be improved and they should be integrated into periodic power system planning studies. Por this purpose it is necessary to: (a) provide additional data processing resources for the Planning Directorate; (b) improve the methodology used in economic appraisal of investment projects; and (c) syste and conputerie both data collection and statistical analysis. 18. Investigation of the operation of the Maghreb interconnection is beyond the scope of this stdy; however, it should be noted that the present interconnection between the lviaghrebian networks is not being used opimally, essentially beause tariff rates for the energy exchanged are not set on the basis of economic costs and there is no regular coordination and ongoing exchangq of data between the three networks that are curreatly interconnected. 19. The mission reommends that COMELEC (Comit6 Maghrdbin de I'Electricite) make an economic and teenical study to determine whether it is economically feasible to set up a coordination and control center, based on a preliminary review of international experience in regional interconnections, such as that of NORDEL (Nord Electricit6) and of UCPTE (Union de Coordination des Producteurs et Transporteurs de l'Electricit5). 20. In view of the great extent and diversity of STEG's distribution network, the study focussed on three representative network samples, selected in three areas according to the following criteria: - vi - (a) network efficiency as defined by the ratio of energy billed to energy supplied; (b) the ratio: km of MV lines/km of LV lines (see para 4.4). Network data collection 21. A smal portion of the data necessary for loss reduction and planning studies was either not available or not sufficiently reliable or consistent. Therefore, STEG must give priority to: (a) continuing to build network data bases (structure, technical characteristics, loads); the existing database system, Gestion Technique des Ouvrages (GTD), should be improved to include all relevant facilities and their components (equipment); (b) maintaining standardized network mapping (possibly computerized); (c) Improving the data system: collection, circulation and filing of network data and measurements, particularly in the case of the Distribution Control Center (Bureau Central de Conduite - BCC); and (d) continuing and expanding studies to measure voltage drops and current losses on the network, within the framework of the GTD system. Reducing MV losses 22. The esdmated loss factor for the entire STEG network is 3.5% of total peak power. It can be reduced to aut 3% . network reinforcement, i.e., by increasing the conductor size on 639 km of MV lines (see paras. 4.19 to 4.23). The overall cost of the investment is estimated at TD 3.6 million, or about US$4 million. The investment payback period is 3.3 years on average, but analysis of the sample shows hat about 20% of the improvements have payback periods of less than two years; these should be implemented fist (see pan. 4.25). Table 1: REDUCTION OF NV NETWORK LOSSES Area 1 2 3 f STE6 network Length of NV network to be relnforced tkm) 103 536 None 639 Cost (thousnd TO) 996 2627 - 3623 Peak load gain (kid) 894 2190 - 3084 Financial savings (thousand TO) 322 790 1112 Payback period (years) 3 3.3 - 3.3 J/ See pars. 4.22(c): the special case of the Chargufa feeder llne. vii - 23. The estimated loss rate for STEG's LV network is about 6.8%, but it could be decreased to 3.8% by reconductoring 944 km of LV lines, or about 3.1% of the total LV network, for a total cost of some TD 8 million, or about US$9 million. The payback period is about 3.7 years. Tablo 2: REINFORCEMENT OF THE LV NETWORK Area 1 2 3 P/ STEG Network Length of LV Network to be reinforced (kin) 832 - 112 944 Cost (thousand TD) 7184 - 962 8146 Peak toad gain (Id) 3950 754 4704 Financial savings (thousand TO) 1862 - 355 2217 Payback period (years) 3.9 - 2.7 3.7 The report recommends that this program start with the reconductoring of those network scions with the highest return (see para. 4.30). 24. The Tunis city networks are a special case because reconductoring these lines would be more expensive and less cost-effective. However, it is essential to continue upgrading the voltage from 110 V (LI) to 220 V (2) and to complete this program quicldy (two to three years), since the indirect economic effects of this standardizaton on distribution equipment cost, on the one hand, and on the cost of household electric appliances on the other hand, are greater than the savings to be obtaned from reducing losses. .Reducintranfmer lss 25. Although losses in the HVIMV transformers are low, about 0.69% of peak demand, savings of about 3 GWh and 346 kW of peak demand, equivalent to TD 126,000, or about US$140,000, can be achieved merely by changing the operating practice of the 8 HV/MV substations. It is therefore recommmended that STEG: (a) during nonral operation, keep only one transformer energized in the eight substions where this is clearly economically advantageous and technically feasible, without installing any additional switching equipment. The anticipated savings from reduced core losses are about TD 78,500 (US$87,000) per year; (b) carry out technical/economic studies for the five substations where improvements are necessary, comparing the savings of about TD 47,000 a year (about US$53,000) from reduced losses with the cost of the work required (remote- controlled HV switches in particular). 26. Extrapolation of the results obtained from the MV/LV transformer study sample gave a loss rate of 3.3% at peak load. Reducing this percentage wiJl require a better adjustment of the size of -viii - each transformer to the peak load. Ihe technical/economic study of the 10 kV network indicad that it was economic to Interchange about fifty 500 kVA transformers and fifty 630 kVA transformers, for a total cost of about TID 11,000 (UJS$12,100) and an anmal saving of about TD 6,000 (US$6,600), i.e., the payback period is less than two years (see para. 4.46). The standardized transformer sizes STEG has adopted produce significant threshold effects. The 400 kVA category appears to be the least cost in some situations; therefore, STEG should reconsider its announced intention to phase out its use. 27. It shoud also be noted that reducing the stock of transformers from 10% to 5% of total current inventory (about 1,000 units) would reduce associated costs (for storage, acquisition and deliery) by at least around TD 263,000 (US$290,000) per year. Customer Managemen 28. Since 1986, STEG has made major improvements in customer managemet, aimedmaiy at reducing technical losses and recovering debts. It has: (a) trained its personnel in the detection of fraud; (b) checked all the LV meters between 1986 and 1989 and monitored them since then; (c) made an annual check of all MV meter records; and (d) made a significant effort to reduce customer connection time and recover debts. 29. These actions have significantly improved STEG's overall performance, making it one of the best power utlities in the developing countries. STEG's nontechnical losses are esmated at less than 4% of total power sales. 30. The mission's recommendations are designed to complement STEG's progrm and consolidate these achievements by: (a) enhancement and rigorous application of existing procedures; and (b) adoption by STEG of management techniques and methods used in more advanced power utilities. 31. STEG's meter organization and meter reading procedures are effectie and miimize the risks of fraud. They are based both on encouraging company personnel to combat faudulent pracdtes, -ix - and on deterrence of these practices, supported by legal provisions that clearly equate fraud with the theft of electricity. 32. Experience in a number of countries shows that electricity theft spreads rapidly and is difficult to eradicate once it becomes pervasive; it is therefore recommended that STEG: (a) ensure that procedures are strictly applied and strengthen deterrence through organizing swift, targeted meter monitoring campaigns, based on statistical analysis of metering data in areas where problems are frequent; and conducting monitoring campaigns in response to a specific type of problem or a specific client category (e.g., large customers, poor payers, those with billing irregularities, etc.). To increase their deterrent effect upon consumers, these campaigns should be well publicized in the appropriate media; (b) increase procedural monitoring of the billing and data processing that is done at the end of each billing cycle to detect irregularities in consumption due to metering evasions or metering irregularities; (c) introduce computerized mana,ement of the meters in service; (d) encourage installation of meters on the outside of plant buildings; and (e) where justified, gradually introduce electronic metering, which is more reliable and more adapted to monitoring multiple and complex tariffs. 33. Customer billing is done automatically in two computerized centers, Tunis and Sfax. Billing is generally satisfactory, since STEG agents deliver the statements to customers within three to five days. It is recommended that STEG: (a) use a stricter management criterion for signing on new customers (see para. 5.17); and (b) begin distributing bills by mail once the quality of the postal service, tested by pilot mailings, is considered to be adequate for STEG's needs. Debt recver 34. lhe management measures STEG has taken have enabled customer arrears in payment to be reduced from the equivalent of 64 days of average turnover in 1984 to 49 days in 1985 and 30 days in 1988 (see para. 5.26). Three-quarts of the arrears are attributable to government agencies, local authorities, and public corporations. x 35. The mission recommends that STEG establish a long-term objective of reducing arrears to the equivalent of 20 days of rAverage turnover by: (a) focusing on enhancing recovery of debts from public and parastatal organizations by: improving the budgeted prepayment system to avoid difficulties in collecting the balance of the debt at the end of the year (see para. 5.25); statistical analysis of the power consumption of clients using this system, which would enable them to better forecast their electricity consumption when they prepare their annual budgets, and extending budgeted prepayment practices to the local government bodies, adapting the system as necessary to meet their special circumstances; (b) encouraging professional clients, particularly the govermnent corporations and agencies, to pay their bills through direct debits from their bank account; and (c) incorporating Into the computer applications now being developed an indicator that would monitor the level of debts outstanding after 20, 30 and 55 days. Such an indicator would improve information on the customer arrears and increase personnel awareness of the need for quick debt recovery. CQoncusion 36. The main investment programs and actions proposed are summarized in the table below. lkbe 3: PROPOSED ACTIONS Annuat Pavback Rate of Actions Costs savings period return (USS 000) CUSS (000) (years) tX) 1. Set up continuous ecornmic efficiency 1,000 1,250 < I > 100 monitoring of steam turbines 2. Reinforce NV network 3.300 1.300 2.5 40 3. Reinforce LV network 9,000 2,500 3.6 28 4. Better management of NV and LV transformers Low 150 1.2 5. Decrease the customer portfolio to 20 days Low or 780 - turnover nil 6. Other ifprovement actions: maintenance, Low or .1,720 technical and financial management nit - xi - 37. Estimates of the economic impact of power plant emission reduction programs vary in a wide range, I to 10, according to existing studies. However, additional environmental benefits from the proposed power loss reduction programs can be conservatively estimated at US$7 million, that is about half of the total investments needed for their implementation. 38. To complement this supply-side program, it is recommended that STEG set up a task force to: (a) study, in coordination with the Agence de Maltrise d% l'Energie (AME), the promotion of well targeted end-use electricity conservation programs that are economically and financially viable for the utility, the consumer, and the local authorities; and (b) participate in their imp ,nentation through better customer information, possibly in associaion with partners, local authorities, and/or private promoters Interested in promoting such programs. - xii - C I .1 |b:t i 0 g~i il l Ziiil a;i t § 0f*§1 ii }1iftx 11 S I Ii I i JjJ z .iH@d [d di i 1 *1 1 MAW _ - 1 Amg one~~asebtion Mlswtabs ued bswam Pa ubsego1 1. Pagubusme,iuee. Oste a p_dlbeof -mag.ref So 1 gdb , ,t , _perathus (Or4nte an M.e~ a uie Dpt _~~~~~~~~~~~e t- fbe _el s.ubh =dar t W m* we ub Ofe p _ 0 t. e_aar Aam s _m SW aumw dr trs q*en* usab to, i ee oalatoma. Tr.WWAdeslm 3. PresAde netle* oeIt 1nseIIhn. Stdo teauebof plNaci Reduction Ofloen medaputUnre*um A, - eser at HYdens' wfedUm. hiprve operating uelbIty. em 130 Mvm. Swuw of hi FOUMty owvoftemof gams' OfWItWis nWm be ebtine tluarho taiefor syncwwonn cowan. -nl network -patm Adliorn elonmdtet study (2 manw- mownftl. 4. Inuprw operaton. - ineasuranes* of wiftoag drops. WMN anow network operation atea +reeclktlon ofthe Problem of Ihigher voltae leve (210 to 225 kV polluion of the InLsultors upgrade roduces hues. by 2MW. VIN iurSOM newvotk taeNbilty. 5. brnprov demand forecsastI VWd Valorizatio study of demanid More detaied plannin studies. planning, forecasting deficiencies. more effiient maagmemen of the Establishment and ronortorin of a genrawtit ngwits. -tth reser" Creation of e' tltt schedule for -wna power. Additioal equipmnent for data ^ _ _ d~~~~~~~~oleto and storage conection 9w _torms. k prowd efficiency of he S. Study the advisabilty of setting FeasIbIty study. Interconnection betwee the Maghseb up a Coordinaton and Cotrl country networs 4technical) 7. Redue trnfomer vnwto. Effectv inv ry oensus. Estimted savins on fixed nveevmet The purpos of th action Is to rduce costs TD 1.5 nionm (US$11.7 millon). nventory to 5% of tota stoci (about Savings on associae costs: 1000 unts) To 263,000 (US$290,000) per year. S. Provide noetwork ocropnsetlon. Study of the advisabIlIy of placing Reduction of kBoso (WRA -80%). condensers on the MiV networh 9. Reconto 2nd section of Cost TD 8.2 million VJS$9 Mon). Reduction of Dses: ID 2 miln Reconductort of MV NWd LV lns. network (US$2.2 miflionI. Cost ID. I11.100 mIlion Reduction of kmsqs: TD 6.500 10. Intecange the MViLV (US$1 2,300). (US$7,250) pe, wowr' AdApttion of wilt sizes to urilt as transfomwna. __ __ ____ DIstribution 1I1. Improve corrputeioted data Detection of abn1ma power Monitoring of mesasuweent anoinalIes. Adept to the local context. (customerNOQOD maaeencnsu mption OPbEing Mmonioig of speed of payment of management) Wwaring sina of i. ratio of debts bhl. due accordin to the nmber f days Cn uwied nstat* u p a 6~~~~~~~~o delay _npyet(etrcvr -uam -ategomenageen 12. MIN custfecs by mall, cincraseod producvty. Monto the quaTaty of nd distribution. 1I& Int"oduce electronic meterdng Mnor flexibl 1reponse to compolex 14. ncoragof very low Cot. The utty wc saw puR-i funds. n~eted prepayment for pa*f LeC 'pll 10uttob IS I. INTRODUCTION 1.1 In 1986, the Tunisian Electricity and Gas Utility (STEG) initiated a program to reduce losses in the electricity network. As a result, the overall efficiency of the system has been improved through reduction of: (a) the heat rate of power stations from 309 toe/GWh In 1985 to 278 toe/GWh in 1987 and 251 toe/GWh in 1989; and (b) transmission and distribution losses from almost 17% of power supplied in 1985 to 14.5% in 1987 and 1989. 1.2 It nonetheless became clear that an overall review covering the origins of losses from generation to distribution, network operating methods and custownr management would enable STEG to consolidate the results achieved. Such an approach would also make it possible to establish priorities for enhancing the overall efficiency of the power supply system: investments to be made to reduce losses, Introduction of new management methods, collection of the data needed for network control and for improved monitoring of system performance. By agreement with the Industry and Energy Division of the Maghreb Department (EM2IE), the Tunisian Government decided to undertake this study as part of the joint World Bank/UNDP Energy Sector Management Assistance Program (ESMAP). .rjanlzatlonalStructure of the Tunisian Electrict and Gas Utiliy 1.3 STEG is a statutory government corporation, of a commercial and Industrial nature, established by Decree Law No. 62-8 of April 3, 1962 on nationalization. This law makes STEG responsible for the generation, transmission, distribution, import and export of electricity and fuel gas under the supervision of the Ministry of the National Economy. 1.4 STEG has five (5) departments and ten (10) directorates which report to the chairmn and managing director and are responsible for operating the electricity and gas systems and managing the utility. A more detailed description, as well as the corporation's organization chart, is provided in Annex 1. 1.5 STEG's Board of Directors has 14 members: - 1 Chairman and Managing Director - 1 Assistant Managing Director - 8 directors representing the State - 2 directors representing employees -1 financial controller - 1 technical controller. -2- Neither consumer representatives nor any nongovernmental organizations active in the energy field or In environmental protection are represented on STEG's board; if they were, more consideration might be given to the problems that gas and electricity consumers experience and to involving consumers in the development of the sector. penzan GrowX 1.6 From 1962 to 1989, total electricity consumption grew at a very high average annual rat of some 11%. Since 1982, the pace of growth has slowed somewvhat, but it is still substantial, about 7.5% between 1982 and 1989, as shown in Table 1.1 below. Table 1.1: ELECTRICITY BALANCE Year 1982 1987 1989 1996 1. National production (GWh) 3174 4549 5235 7400 a. STEG 2738 4016 4562 6680 b. Self-generated 436 533 673 7200 2. National consumption (GWh) 2792 4031 4605 6660 a. Detivered by STEG 2374 3544 3987 6000 b. Setf-generated 418 487 618 660 3. STEG network losses a. in GWh (Ia - 2a) 409 514 575 830 b. 'n % of power supplied 17.2 14.5 14.6 13.8 Source: STEG. 1.7 STEG's medium-term forecasts show that the growth in electricity consumption will slow slightly from 1989 to 1996 but will continue to be significant, about 6% a year. Thus, to minze the investments required to meet future demand, STEG should consolidate the actions already taken to reduce losses and enhance the efficiency of the system. Study objece -and meaongy 1.8 The principal aim of this study, therefore, is to analyze: (a) STEG's three main technical functions, viz., the generation, transmission and distribution of electricity - so as to identify the actions and investments needed to reduce the technical losses linked te the generation, transmission, and distribution of electricity; and - 3 - (b) customer management, In order to reduce nontechnical losses - which are atributable not only to meter fraud as generally understood but also to the reliability of the meters used and the utility's policy for connection of new customers - and to optimize the fnancial cycle by improving customer billing and the recovery of arrears in payment. 1.9 The following four tasks were carried out: (a) a technical audit of power generation based on visits to the principal sites, wlrking sessions with power station managers and staff from the central departments, a review of operating procedures, and an analysis of available statistical documents; (b) technical audit of transmission based on site visits, discussions with transmissions staff, an analysis of operating procedures, and computerized network simulations; (c) a technical audit of distribution based on field surveys, discussions with headquarters and regional staff, and computerized simulations of the medium- voltage network and of a representative sample of STEG's diverse low-voltage network. (d) a review of the procedures used throughout STEG's customer management cycle, from metering and meter reading to bill collection. 1.10 Task objectives were to assess the losses in each area considered and to identify the actions required to reduce them to economically acceptable levels. To ensure the overall consistency of the approach and the recommendations, a preliminary study was made to estimate the incremental costs of the equipment at the various stages involved - generation, transmission and distribution -- as well as fuel costs. To ensure that the recommendations proposed would be compatible with STEG's usual selection criteria, the method used for the calculations and the results contained in Annex 2 were submitted to and discussed with STEG officials before the economic evaluation was made. L-ocalartiCiaion and skills transfer 1.11 S1EG participated actively and effectively in all phases of the study: diagnosis, economic evauation, and review of the consultants' preliminary reports. The study was monitored by a task force comprising representatives of all the directorates involved, and coordinaed by the Planning and General Stadies Directorate. 1.12 Two study visits to France were organized, enabling six (6) members o the task force to visit transmission and distribution facilities in France, to familiarize themselves vwith the network - 4- models used by the consultant, and, in the case of transmission, to particirate In simulations of the Tunisian network. 1.13 To ensure lasting benefits from the effort undertaken to reduce losses, and to strengthen the network analysis funk on within STEG, the study was complemented by: (a) organization of a seminar to increase awareness of the problems of network losses, and presentation of the analytical methods and models needed for loss reduction; and (b) transfer of a PC-computer model for study of the distribution networks, and training of engineers in its use. Action (b) was made possible thanks to STEG's participation in financing the local costs of the project. NM rgan1oaion 1.14 The report layout reflects the approach adopted for the study. Following a short introduction focusing on the background to the study and the methodology adopted (Chapter 1), four chapters present the results of the analyses, and recommendations for reducing losses and improving management in the areas of generation (Chapter II), transmission (Chapter Im), distribution (Chapter IV) and customer management (Chapter V). Chapter VI summarizes the main conclusions of the study. -5- H. ELECTRIC POWER GENERATION 2.1 Installed capacity rose from 273 MW in 1972 to 1,179 MW in 1989, in three stages: (a) Installation of a 30 MW steam turbine (La Goulette, Ghannouch); (b) installation of gas turbines (particularly in the south) using gas from El Borma and gas oil; (c) installation of 150 MW steam turbines (Sousse, Rades). The detailed list of generating equipment given in Table 2.1 (on following page) reveals that, although hydropower capacity doubled between 1972 and 1989, it is stll limited (about 5% of installed power). -6 - Tabte 2.1: STEG GENERATING EQUIPNENT in 1991 Net Year installed Maximf. brcught into capacity capacity Plant Unit service (NW) (MW) Fuel used 1. StMtuines Goulette 2 STI 1965 28 22 Fuel ofl ST2 1965 28 22 Fuel oil ST3 1968 28 22 Fuel oil ST4 1968 28 22 Fuel o@11 Ghannouch STI 1972 30 28 Fuel oil/Gas ST2 1972 30 28 Fuel oil/Gas Sousse STI 1980 150 140 Fual nil/Gas ST2 1980 150 140 Fuel olI/Gas Rades ST1 1985 160 150 Fuel oil/Gas ST2 1985 160 150 Fuel ol/Gas Total ST 790 724 2. Cal turb(nes Gharmouch GT1 1971 15 15 Gas GT2 1973 22 20 Gas GT3 1973 22 20 Gas GT4 1983 34 30 Gas Douchemm. GT1 1977 31 25 Gas GT2 1977 31 25 Gas Tunis South GT1 1975 22 20 Gas GT2 1975 22 20 Gas GT3 1978 22 20 Gas Sfax Gt1 1977 22 20 Gasoit GT2 1977 22 20 Gasoil N. Bourguiba GT1 1978 22 20 Gasoil GT2 1978 22 20 Gasoil Netlaoui GT1 1978 22 20 .iasoit Korbe GT1 1978 22 20 Gas GT2 1984 34 30 Gas Kcasserine GT1 1984 34 30 Gas GT2 1984 34 30 Gas Robbana GT1 1984 34 30 Casolt Total GT 489 435 3. Hvdtre r Nebeur 1 1956 6.5 Hydropower 2 1956 6.5 Hydropower El Aroussia 1 1956 4.9 Hydropower Fernana 1 1958 9.7 Hydropower Kesseb 1 1969 0.7 Hydropower Sidi Salem 1 1983 36.0 Hydropower Total hydropomer 64.3 20 Total Inventory 1343.3 1179 -7- Steam Turbines 2.2 STEG's steam thermal equipment consists of the following: (a) six 30 MW units with a single-stage turbine (Ghannouch 1 and 2; La Goulette 3 and 4) or a double-stage turbine (La Goulette 1 and 2); (b) four 150 MW units, of more recent design, and equipped with three-stage turbines (Sousse 1 and 2; Rades 1 and 2). Because the two categories are different in age and design, there are considerable differences between their reference heat rates (as determined during the commissioning tests when they were brought into service). The 30 MW units are rated at 2950 kcal/kWh, while the most recent 150 MW units (Radbs, using naural gas) are rated at 2350 kcal/kWh. The difference in performance between the 30 MW and 150 MW units is mainly due to: - higher steam temperature (540°C instead of 500°C) and higher pressure (145 bar instead of 66 bar) at the turbine intake; - addition of a steam superheater; - an increased number of stages. These improvements increase cycle performance and reduce the heat rate. Re$at rate monitoring 2.3 Heat rates are regularly monitored in the plants and recorded in the operating logbooks. In the plants visited, the logbooks were up-to-date and well maintained. Monthly and annual statistics are produced by unit, by plant, and by unit size. All deviations from the heat rates recoraied in the commissioning tests are analyzed and included in the monthly reports, copies of which are forwarded to the Operations Directorate (OD). 2.4 STEG's Research and Development Service is developing efficiency monitoring software at the Sousse plant, and intends to supply it to other plants once it becomes operational. 2.5 The software processes data on the operating parameters of the equipment, including: boiler, turbine, and alternator efficiencies, and heat rates. The parameters are currently measured through brief tests at flat power outputs. The heat rate values thus obtained are compared, after correction, with their reference values. It should be noted that the Rades plant has one computing device - 8 - per unit; these dvices print out lists of values on demand, and can perform operations such as inegration, derivation, and averaging. The La Goulette plant has on-line computing resources (the Bailey micro Z system), in the central control room for the four units. 2.6 Analysis of the heat rates obtained from the various readings on the equipment operadng parameters (aggregated in Table 2.2) ieveals that: (a) the Soeue and Radbs plants, which account for over 80% of steam-driven insiled capacity and about 50% of total installed capacity, perform very well. Heat rates for the two plants are very close to the reference values, particularly if allowance is made for deviations due to output variations and to operating guidelines that require the fuel- buming circuits of gas fueled units to be kept heated (Rades). At Sousse, however, the very wide discrepancies in monthly heat rates compared with the annual average should be noted (see Annex 4). (*) the performance of Gabbs is quite poor. The average heat rate for 1988 exceeds the reference value by 17.4%, a considerable difference, even allowing for the age of the equipment and variations in load; and (c) in La Goulette, heat rates have definitely been improving since the following major Improvements were made to the plants: (i) new boiler controls; (ii) more efficient fuel heaters and fuel pumps brought into service; (iii) riser tubes replaced (unit 2) and intermediate superheater and economizer replaced (unit 4); (iv) units 2 and 3 overhauled and turbines repaired (blades and seals). able 2.2: STEAM PLANT HEAT RATES IN 1988 Annual heat rate Reference heat rate EffRcJ2= differec Plant (kcat/kWh) (kcal/kWh) KCat/kWh I Sousse 1 2630 2565 65 2.5 2 2613 2565 48 1.9 Radbs 1 2428 2350 78 3.3 2 2437 2350 87 3.7 Gabbs 1 3357 2860 497 17.4 1 3215 2889 326 11.3 2 3215 2889 326 11.3 ¢*ulette 3 3215 2958 257 8.7 4 3215 2958 257 8.7 Mm;g: Annual heat rates are not dSrectly ccqtrable with reference values because the tatter were measured at nominal output when delivered and thus take no account of load variations. Nevertheless the efficiency differences noted can be considered indicative of unit performance. -9 - 2.7 Differences of actual heat rates from rated values are usually divided into the following three categories: (a) Intnal differences due to unit control: These may result when shift teams do not respect correct operating procedures; (b) Internal differences due to the equipment: These are caused by the condition of the equipment (e.g. wear in some components, partial unavailability etc.); and (c) Exen differences: These are essentially the result of meteorological changes (air temperature, temperatre of the cooling source, etc.), which have a direct impact on performance. Also included in this category are differences resulting from operating procedures imposed by the national control center (variations in load and frequent unit start-ups seriously affect heat rates). Internal differences due to unit management and equipment condition (maintenance) are indicative of the quality of unit operation, but operators have no control over external differences. In these cases, only the operators of the National Control Center can effect any improvements. 2.8 Consequently, unit performance can be described as follows: Heat rate = Adjusted rated value + eternal differences + internal differences due to unit management + intemnal differences due to equipment condition + unexplained differences As STEG's existing information system does not enable a distinction to be made between the various categories of difference, the following analysis of differences is more qualitative than quantitative; it is based on visits to plants and conversaions with operators. 2.9 Itra diffaences due to unk control ad MUM training: In STEG these are minimal. Detailed inspections of control rooms and conversations with unit contol teams show that: (a) shift supervisors and command console operators are well aware that compliance with the reference variables for the main operating parameters (steam pressure and temperatre, condenser vacuum, excess oxygen, etc.) has a positive impact on efficiency; (b) the staff are familiar with the operating procedures, operating diagrams, and instructions, and these are kept updated; - 10- (c) panel equipment readings that are obviot, sly wrong or inconsistent with other parameters are reported to the Technical Service so that it can carry out repairs or recalibrate the instruments; and (d) on the whole, recruitment and training of operations staff are satisfactory. 2.10 However, to alleviate the scheduling problems connected with providing training and skills upgrading for the rotating shifts (who ensure round-the-clock operation of the plants), the following improvements to in-service training are recommended: (a) the preparation of training packages, comprising both text and diagrams. Each package would deal with a specific subject (the alternator, the feedwater system, the turbine, etc.) and the complete set of training packages would constitute a body of training appropriate to the functions and level of each staff member. The packages would be distributed to the various members of the shift teams, who would study them individually. Consequently, each team would work together to upgrade the group's expertise. The department superintendent would be responsible for the overall management of the training program; and (b) training center instructors should receive frequent feedback from operations to ensure that a proper balance is maintained, at the control level, between technical knowledge itself and the transferability of such knowledge. 2.11 Internal differences due to equipment: A large number of localized technical problems partly account for the high or even random heat rate values obtained from some units: (a) in Sousse, substantial air leaks from the air preheaters; (b) condensers are frequently clogged by algae and marine organisms; as a result, residual pressure in the condensers increases, leading to impaired performance. This problem is particularly serious in Gabes, where, in addition, the condenser tubes are often blocked by phosphogypsum, a viscous substance discharged by phosphate companies in the ore- washing process; and (c) the quality of the heavy fuel oil being used has deteriorated (higher specific gravity). As a result of improvements in the distillation and cracking processes, the oil supplied to the thermal plants has a higher viscosity (the percentage of heavy components has increased); therefore, new and more efficient precombustion fuel heating systems must be installed; consequently, steam consumption by the auxiliary equipment has increased, and heat rates have risen slightly. - 11 - 2.12 Numerous improvements currently underway (particularly to older equipment) should reduce the intnal differences due to equipment and thus improve plant performance: (a) in addition to the extensive repairs in La Goulette described in para. 2.6(c), circuit modifications and other improvements have been completed or are in progress in Ghannouch and La Goulette; (b) improved fuel preheating in La Goulette enables the use of fuels of international standatd (i.e., with a viscosity between 310 cSt and 380 cSt instead of between 110 cSt and 310 cSt), so that savings can be made when the fuel is purchased; (c) due to improvements to the control assembly, at La Goulette, the boilers can operate using only small amount of excess air; thus, boiler efficiency is increased, since dry gas losses have been substandally reduced; and (d) routine repair of leaks in the demineralized water system (analysis of water samples, checkn for packing leaks) reduces the differences due to water losses. 2.13 In the Ghannouch plant, substantial savings in well water have been achieved by: (a) use of filtered sea water instead of brackish well water to regenerate the membranes in the water demineralization system; (b) use of seawater to ensure the watertightness of the circulation pumps; (c) use of seawater to clean the main condenser. 2.14 The Technical Service tests the measuring devices at the operators' request. The oxygen meter readings are checked on site with a simple, portable exhaust gas analyzer, which gives rapid and sufficienty accurate results. The device (similar to the ORSAT) operates on the principle that e various components of a known sample of gas are absorbed when they are passed through various solutions that have the appropriate chemical properties. Such tests, made only when operators request them, ensure the measuring devices in the plnts are reliable. 2.15 To ensure that the measures STEG has undertaken are sustainable, and to refine the results already achieved, it is recommended that routine tests be carried out on all equipment (at intervals to be determined). Priority should be given to testing the components that affect the heat rate (checks ft leaks, monitoring of pump performance, recording the performance indices of the auxiliary electric and steam equipment, checking fuel combustion, etc.). The results should be entered regularly into logbooks reserved for that purpose, and should be used to anticipate and plan for maintnance operations. -12 - 2.16 UInexlained differences: The high heat rates (and the wide discrepancies among them) recorded for the Ghannouch and Sousse units when these are burning gas are not only due to problems of unit control or to the condition of the equipment. Inspections performed by the STEG Operations Directorate have revealed that, in these plants, measurements of gas flow were highly inaccurate. Gabbs (which uses gas from the El Borma field) has an additional problem with fluctuations in the high heat value (HHV). Routine gas chromatography measurements in Gabbs indicate that the composition of the incoming gas varies in relation to the amount of propane extracted from it by the upstream liquefaction facility; these variations in gas content account for the fluctuations in HHV. 2.17 To make gas flow measurements more reliable, STEG staff plan to install gas gauges at the high pressure stage (before pressure reduction) in addition to the meters at the Sousse and Radbs plants (done exclusively for large-scale customers). Such measures will not solve the problems related to gas metering, which make any heat rate calculation less accurate. Even where dual meters are intalled, it is recommended that the gauges be calibrated by means of standard meters which have counters that adjust for flow according to variations in pressure, temperature, and density. Before the calibrations are made, a precision recorder should be used to read gas flow under a constant load and for a reasonably long period (several days). Using this method, abnormal variations in gas flow could be identified at the same time as heat rates are being computed, over a significant time period. 2.18 To ensure continuous measurement of gas HHV, one solution would be to install an online gas spectrum analyzer to provide regular readings of mean values at 20-minute intervals. Because the equipment is expensive and gas reserves in El Borma are limited, an additional economic feasibility study is needed to determine if such an investment is justified. Settlng up efficiency monitoring in the STEG plants 2.19 The method STEG uses to calculate the heat rate, which consists of comparing the electrical energy registered at the terminals of the main transformer with the thermal energy contained in the fuel, provides accounting parameters essential to the management of generating equipment. However, the results do not give a precise indication of the quality of operation of the units, because: (a) they do not clearly show the impact on heat rate of the various aspects of equipment maintenance or of unit management (the internal differences); and (b) they include items unrelated to plant operation such as differences due to generating schedule changes imposed by the National Control Center. 2.20 Because STEG recognizes the importance of optimal management of fuel consumption, and its impact on efficiency, it is taking steps to monitor heat rates in the plants. Unit heat rates are included in the contracts between STEG headquarters and plant managers, as one of the performance criteria to be monitored. - 13 - 2.21 In addition, efficiency monitoring software is being tested in the plants. This software should enable heat rates to be calculated in conformity with international standards by assessing the various components of the units - boilers, turbines, alternators - and evaluating condenser cleanliness. 2.22 Although these measures are important, they do not ensure effective monitoring of the quality of plant operations because they do not provide continuous monitoring of differences between actual heat rates and optmum base consumption (OBC). Consequently, the following recommendations are made: (a) evaluate the software now under development and estimate the resources that would be needed to complete it and adapt it to the method of continuous efficiency monitoring summarized in Annex 5; (O) evaluate exisfing efficiency monitoring software that could be adapted to STEG's needs; (c) compare the three possible solutions (internal development of a new system, purchase and adaptation of existing software, or a combination of the two), taking into account the cost, the resources required in each case, time required to implement the system, etc.; (d) during a first phase, apply the method selected to one 30-MW plant and one 160-MW plant; and (e) in a second phase, extend the measures to the remaining plants. Annex 6 contains terms of references outlining the specific tasks to be performed and the technical assistance required to complete them. Unavailability rats (1988) 2.23 As defined by UNIPEDE in 1977 (see Annex 7), unavailability rates for STEG plants in 1988 are the sum of the following: (a) unavailability rates resulting from scheduled maintenance work; and (b) miscellaneous unavailability rates, that is, any factors attributable to plant operaion. 2.24 The unavailability rate is as follows for the various plants visited: (a) Sousse: Tle mean unavailability rate for the two units was 13.5% in 1988. (b) Rlh: A steam leak from the HP cylinder seal in unit 1 caused available power to be restricted to 15%-20% from April 1988 until the unit was overhauled the following year. - 14- (c) Qhawn=gh: Takdng into account only unavailability due to plant operations, in 1988 the mean unavailability rate for the two steam units was 18.13%. (d) La geujtett: The low unavailability rate for unit 1 (13.6% in 1988) is partly due to overhaul of the unit and to renovation work done in the previous year. Unavailability rates for the other units are: Unit 2: 55.5%; Unit 3: 88%; Unit 4: 69%. These figures are high because of prolonged shutdowns of the units for renovation work (similar to that previously performed on unit 1). Although some individual results are similar to the mean values recorded for similar units in the United States and Europe over a 5-year period, the lack of statistical data limits the scope for any real comparison. Commissioning of some units such as Rades 1 and 2 has been performed too recently for the availability data on these units to be regarded as reliable indicators of the quality of operation. Other plants have only recently begun to use units that can exchange heat; that situation in addition to the presentation of operating results in the form of averages makes it difficult or even erroneous to make assessments of unit performance. 2.25 To improve both the number and the quality of statistics on equipment unavailability, a unified format should be developed for the annual report of activities for all the STEG plants, to facilitate data analysis and comparison of the results according to unit capacities. It would also be desirable to present the results by month and by unit in the form of tables and bar charts or graphs, and to avoid the use of overall averages (heat rates, unavailability rates, unit utlization rates, etc.). Maintenance 2.26 STEG currently practices routine preventive maintenance in its plants, modified step by step, in the light of experience (see Annex 8 for definitions of the various types of maintenance). A group comprised of representatives of the various units and the Studies Directorate is developing "maitenance" software at the Sousse plant and will supply it to the other plants when it is ready for use. The software complies with STEG's maintenance policy; it is programmed to schedule routine maintenance, taking into account maintenance done in response to current work orders, as well as the operating record of the equipment, so that the time periods between routine maintenance interventions can be modified accordingly. 2.27 Routine maintenance also depends on. continuous monitoring of significant parameters or of operating parameters that reflect changes in the performance or degree of wear of a component, as follows: (a) vibration readings on the main turbogenerators, in compliance with manufacturers' standards (using portable or fixed equipment); - 15 - (b) analysis of oil samples (turbines, diesel engines) since this often indicates the condition of the interior parts; and (c) vibration analysis (of the steam and gas turbine blades) by the Technical Facilities Department (DPITG) to detect cracks. This type of maintenance, 'modulated' by the equipment operating record and by permanent monitoring of the equipment while it ;s in service or during scheduled shutdowns, is increasingly pricced in developed countries, particularly in the United States, where it is referred to as "conditional or predictive maintenance." 2.28 The maintenance procedures developed by pov. r utilities depend on the type of equipment being used, taking the safety of personnel and the impact of unavailability on overall service quality into consideration. International experience has shown that conditional maintenance is advantageous for generatig equipment, particularly for high-powered units; for example, In develope countries - particularly in the United States - conditional maintenance has reduced maintenance costs for some components (such as feedwater flow controls) of 300 MW and 500 MW nuclear and thermal power units to about 30% of their previous level. 2.29 For Tunisia, it is recommended that a small task force be established at the central management level, responsible for developing maintenance guidelines specific to STEG equipment and adapting maintenance procedures to match these guidelines, so as to improve equipment availability and reduce overall maintenance costs. 2.30 Considering that units with increasingly high power levels are being introduced, the following measures should be taken to develop conditional maintenance for the generating oquipment: (a) increased - and more routinized - vibration recordings of the turbogenerators, at least for the most recent equipment, that used in 150 MW or larger systems), and adoption of routine inspection procedures (analysis of oils, monitoring of insulator status), needed to improve monitoring of the pattern of change in the varicus components; and (b) more efficient use of DPITG's technical and human resources by introducing routine gas turbine inspection procedures (ultrasound, thermography). 2.31 The introduction of conditional maintenance procedures complements the establishment of plant efficiency monitoring; financial resources dedicated to monitoring equipment components will serve both objectives. Routine monitoring of some components could later be incorporated into more advanced computerized systems (expert systems) that could be used tQ4,determine the type of work to be performed during equipment shutdowns so that routine maintenance on components that do not require it could be avoided. -16- 2.32 Inventory management software is being developed for the plants. Tbis conventional inventory management model has the following features: (a) cataloguing and categorization of equipment; (b) (automatic) request for replenishment of items once they fall below a predetermined level; and (c) adjustment of this level to match acwal inventory turnover. This software is being tested at Sousse and will soon be supplied to the other plants. 2 31 Inventory levels in STEG's plants are higher than those maintained in power utilites in developed countries because the observed average time lapse between order and delivery is, in some cases, as long as two years. This excessively long delay has the following consequences: (a) large numbers of staff are required to follow up on orders, analyze the bids, and issue new requests for bids in cases of nondelivery; and (b) subsi funds are tied up in 'precautionary" purchases of items to be kept in reserve to guard against the risk that a unit's unavailability will be extended when it is overhauled, due to a lack of spare parts (lack of inventory). 2.34 Although some operations are either unavoidable or cannot be performed in less than the dme allotted, an in-depth analysis should be made of the various stages of the spare parts procurement process, from the decision to obtain supplies to the delivery of equipment at the storage facility, to identify the causes of delays. The analysis should lead to: (a) intenally, elimination of superfluous operations, changes in certain management rules, and/or possible changes in signature requirements; and (b) extrnally, preparation of document to be discussed with government authorities, with a view to reducing the length of time needed for importing goods; the documents would enmmerate the benefits to be expected from simplification of Import procedures. 2.35 For the procurement of consumables (for the cental warehouse), the utility should further stanrdize supplies in order fp simplify acquisition procedures, without jeopardizing the utility's ability to encourage competition between the various suppliers in order to obtain the most advantageous financial conditions. - 17 - (:ambustion Turbines Heat 2.36 Desiga considerations (exhaust gas temperature) restrict the perfomance of the combustion turbines. The observed decrease in the performance of the turbines In service Is mainly due to dirt blocking the air prefUiters and filters. The uilt control operators constantly monitor perbrmance. Filters are regularly dhanged and the compressor blades are cleaned either manually or by the use of carboplast. Average heat rates are classified by Ite and by year (see Table 2.3); this practice Illustrates the need for more detailed investigation to discover the reason for these differences and to use the results to implement a program for reducing fiuel consumption. For example, a 1% reduction in heat ra in 1989 could have produced fuel savings of about 15 million thermies or 1500 toe. 2.37 Because of their marginal use, combustion turbines are installed ad hoc in locations where power generaon is insufficient. They are often used in spite of their high heat rates,2/ because they can be insWlled rapidly and require a lower capital investment than steam thermal units. Because these low-capacity units are widely dispersed, maintenance resources are also dispersed; thus, It is difficult to plan overaill gas turbine maintena, manage inventory, and take prompt maitenance actions when necessy. STEG's combustion turbine maintenance resources are inadequate: (a) a general storage facility at La Goulette 1 (on the site of the former plant); (b) a maitnance office in the Operations Directorate; and (c) on-site team to provide unit control and preventive maintenance. STEG does not have enough personnel to ensure adequate maintenance of the gas turbines, and the professional experience of existing personnel is insufficient (of the 15 members of the maienance staff, 10 have less tma two years' experience). ai The sue4y progressmade in Ireasingdte reiabiry of cmbustx twubiesmd bipro*Ig their heat rae, d the adanagesa of bnwpora*8 a en cycle, hould be notd Tabl 2.3: SMEG - STATISTICS FOR THE COMBUSTION TURBINES 1988-1990 lt Puiss. 18-s 1969 - - 1990 C_ut des N. CAt deaN. Caoatd.l -NW__ de awch fin do dimrag ________ _ _ _ tI ID CS 10 fibO0 t -D CS ID FiabD -W DI CS ' TO FibO D aot 19 fin coOt 19 Gha.maudl t 1S J3 IW 33 S1 l 755 39 3311 65.2 31.5 104.1 23 4311 75.7 33,6 8273 16 2 22 494 38 3450 10. 94, 3200.7 2__ 3_S n,7 36.7 16383 134 3550 ,Sa 92.2 74547.6 , - i_ _ s 1 22 4758 17 3565 94 9 *9 4642.3 165 3481 972 ff, 7 3702 2 3753 434 95f3 90324.9 3135 4 4 MA _ . . 3c9.t 22 3754 9 100 2360,6 123 3740 99.71 93 = 20280.8 S70 I 31 4118 54 3913 76. 981 130 26 373S 19.3 88 1 1808-1 37 3797 94.61 100 6787'? S 841 8auceaChu - -& 2 31 4016.8 75 3861 9*, A' 4*780 34 3915 93 4 100 39,.1 4 3707 100 100 6301%2 983 1 22 261.3 50 44S 6. 98 7 390S5 1Sl 3850 96.9 93.3 363L2 108 8N 99 100l 26196.7 5803 TInis Wud 2 22: *132 IS4 383 6 ".a 329. 133 4511s stt s 3 130 3t58 9.1 a 9 100I 3575 -_______ _ ._ 22 623.1 1 4 3635 s 97.7 597.3 1SS 375S4 ". s.r 253 89 364S 83 9 23635 3474 1 22 .. 9.. 1731 3527 93.6 9,.4 1661 !"I 9233 92,3 s 902 161 3485 94.9 35. 19693.8 18ts 2 334 1f3s9 229 3SSO 3.3 ff 6 1934j 8 322 3328 94.2 ss,s 156S.7 226 3? 94.9 90.2 1j57r2 1310 1XZ t 34 1260 19 3705 M 3 s,5 1110,9 203 3m 97 913 I 1278,7 204 343 137 8s8 121703 1436 Kasserta. - - - *~~~~~~~~~~~~~~~~~~~~~~~~~~~~ *a- -~~~~~~~~~ --M ass 110313 2 34 141? 210 3450 n.y1 .SC 1f05,7 221 3572 96,3 96.51 1 217S 203 3509 99.3 949 1123s.a It P. Bout4iba 1 22 22.3 22 4531 3.s S6.4 29.3 33 463? 8 s.91 tJ 9 4 042 n5 ss4 12,5 2173 R 22 S 5. 3 4740 67.8 67.3 41 52 4389 9.6 100 *3-1 1.4 '4127 63.2 1OO 12254-3 2001 1 22 55 68 4970 70.4 n . s 33 21 3889 9r f f.2 Z 1t9 3875 " .9 F 402 1480 2 22 76 57 468 78,9 79 32e8 24 4 797 85,3 19.6 12 4041t -99 , t ff 6782,9 1990 net 2mal 1 22 49.2 28 488 99,7 tO 2.5 1?7 433 j , too Si 13 40 %.4 tO1 5634,5 12S4 RobbUt I t 35 175.8 50 S231 9S 100 83, 26 4W3 9,4 92.3 37.2 22 4223 97 682 1700 49 HM: Houts of Opetation; ND: Number of Statups; CS: Heat Rate (kcal/kwh) TD: AvaBabiit Rate (%); Fiab. D: Statp Reiability (%) - 19 - 2.38 To facilitate maintenance and planning operations for all combustion turbine installations, we recommend that STEG establish a "Procedures Department" (Bureau des Methodes - BDM), which would have the same responsibilities as the existing BDM for the steam thermal plants. Tbis unit could be located close to the general storage facility at La Goulette so that it could perhaps benefit from support from the DPTG (in the form of laboratories and workshops). It should be provided with a drafting office and should have a documents manager who would be responsible for putting together a complete set of technical information on the various units. The set would include flowsheets, repair charts, the operating records of the machines, and information on the range of maintenance actions to be taken. 2.39 With regard to training, the consultant proposes that staff members who have attended short training courses abroad (organized by the manufactrers) should organize seminars, possibly with assistance from the Khledia training center, to pass on their knowledge to others. Unavailabiltv 2.40 If more resources are provided for maintenance and training, equipment availability and start-up reliability should be improved. The equipment start-up average (about 88% in 1988 and 1989) is too low. (Under normal conditions, the average should be between 95% and 100%.) Hydropower Generation 2.41 The hydroelectric instatlations in the west of Tunisia are used mainly to: (a) regulate water flow from the wadis when water levels are high; (b) irrigate farmland; and (c) provide drinking water for the large towns. The remahing capacity is used to power turbines following an hourly quota managed in cooperation with the National Control Center. (Mhe water is used mainly during peak hours, to avoid sturting up more expensive equipment, such as gas tirbines.) l!fflciency/WAvalb ty 2.42 The performance of foot-of-the-dam hydropower installations that receive highy sedimented water is generally poor. In such cases, turbine blades suffer wear (as at Nebeur) and the - 20 - turbines have to be remetalled. This technical problem is under control in the STEG installations, and there is no real problem of unavailability. 2.43 Equipment scarcity and equipment aging are the main causes of maintenance problems. Consequently, operators have considerable autonomy in performing maintenance. The equipment operators handle routine maintenance, while teams that include personnel from other plants perform major maintenance and overhauls, with support from DPTG when necessary. Conclusions and Recommedations 2.44 The audit of STEG's generating operations confirmed that the utility performs these fumctions well, despite some shortcomings. Improved procedures for equipment management and operation and improvements in the operators' technical knowledge would help overcome these shortcomings, consolidate the considerable progress achieved over recent years, and increase the efficiency of existing and future generating resources, bearing in mind that STEG is still facing a rapid tempo of investment. 2.45 STEG is aware of the need to increase the efficiency of its system and has taken a number of steps in recent years to: (a) reduce fuel consumption in the plants by: (i) overhauling and modifying the systems in its aging units, particularly in the Ghannouch and La Goulette plants; (ii) developing a software application to improve monitoring of fuel consumption in the steam plants. STEG's experience confirms the conclusions reached by ESMAP in several countries, that investment in renovation produces high economic returns. In Gabas, modifications and improvements to systems by the plant's maintenance personnel have produced savings of about TID 105,000 (about US$117,000) per year through reductions in water losses, and the investments made in improving regulation and in installing fuel heaters at La Gouette 2 were recovered in nine months through the energy savings obtained; and (b) improve management and equipment operation by modifying procedures and developing computerized systems that enabled better maintenmce in the steam plants (through a pilot project at the Sousse plant) and better inventory management by the plants. -21 - Shortem recommendation 2.46 The following measutes are recommended: (a) continue to renovate those aging thermal steam generating plants whose renovation has been proven cost-effective in STEG studies, which, incidentally, considered only the savings to be made from reduced water loss (Gabbs) and reduced fuel consumption (La Goulette). In addition to these benefits, renovation extends the usefil life of equipment and defers the need to invest in new generating equipment; (b) evaluate the "fuel efficiency monitoring" and "maintenance' software being used in the steam thermal plants to ascertain whether it can be adapted to more advanced management methods such as online efficiency monitoring based on the continuous monitoring of deviations from optimum base fuel consumption togedter with 'condidonal predictive maintenance' based on continuous monitoring of the units while they are in operation; and (c) improve the availability and quality of the data needed for introducing more advanced management and operating procedures in the plants. This measure could be incorporated into a thorough review of STEG's data gathering and processing system, but some measures, such as improved gas metering at the Ghannouch and Sousse plants, are urgently needed. MediUMe recommendaio 2.47 Continuation and consolidation of its existing activities will enable STEG to upgrade the quality of its management and adopt the most advanced methods for operating its generating units and monitoring their performance. 2.48 Q:anLional measurss: To improve coordination and prepare for implementation of more efficient maintenance procedures, three minor structural changes in the Operations Directorate are recommended: (a) create the position of manager for steam turbine generation with the same level of responsibility as for existing positions related to gas turbine generation, hydropower generation, and transmission. Providing an intermediary between the plant managers and the Operations Director would ensure (i) separation between the management and operation functions; (ii) individual representation of steam generation in the Operations Directorate, similar to that for the other generation functions; and (iii) reinforcement of the Operations Director's coordination role; - 22 - (b) create a "Procedures Department" (Bureau des WMthodes - BDM) to enhance and coordinate maintenance and operation of the combustion turbines. Tbis department, which should play the same role as the existing BDM for the steam thermal plants, could be located at La Goulette so as to benefit fror# the assistance of the DPTG; and (c) create a small unit (consisting initially of one engineer and one technician), to be responsible for developing maintenance procedures and programs and updating them in line with equipment operating records supported by operating reports from the generating plants and by the results of inspections and monitoring of equipment in operation. 2.49 Individualized training for steam turbine operators: It is recommended that STEG develop an individualized training strategy for the operations shift teams, by preparing a set of training packages based on operating documents (procedures, instructions, etc.). The advantage of this strategy is that specialized staff can receive well-synchronized training and advanced training despite the problems connected with shift rotation. 2.50 Installatio of on-line steam turbine efficiency monitoring: The mission recommends installation of an efficiency monitoring system for the steam turbines, based on continuous computerized monitoring of performance parameters and their comparison with unit reference parameters, to ensure that actual fuel consumption approximates optimum base consumption as closely as possible. 2.51 According to the consultant's estimates (confirmed by previous ESMAP studies) the cost of preparing and implementing the project would be about US$1 million. If implemented, the benefits would be about US$1.1 million in 1991, based on the following very moderate assumptions: (a) a 1% gain in heat rate for STEG's steam thermal equipment, or 2.6 toe/GWh on the basis of 1988 operating conditions; and 0b) a toe/fuel oil cost at the 1988-89 level of US$100/toe. The payback period, about 11 months uder the conditions assumed by ESMAP, indicates the definite benefits of the project. STEG should define and prepare the project in more detail following the terms of reference provided in Annex 6. 2.52 plfnnaion of conditional fpredictive) mainteance Vroam: It is recommended that STEG implement conditional, predictive maintence programs (being used increasingly in the developed countries) for each equipment component or group of components, based on updated operating records and on development of local and centalized inspection and monitoring (in DPTG). Such a program would provide improved data on component aging and would considerably reduce maintenance costs by decreasing routine maintenance. ITe financial benefits of the program are difficult to estimate, as STEG does not itemize maintenance costs for accounting purposes. A reliable estimate of the savings to be expected from such a project would require a very detailed financial and technical study of STEG's -23 - maintenance program, which is beyond the scope of the present study. However, ESMAP's experience in this area indicates that such projects have very high internal rates of return (about 45% in the case of Syria: complete reorganization of the maintenance management system). By way of illustation, Tunisia's estimated maintenance costs for thermal equipment were TD 11.25 million, or US$12.5 million, in 1989, and are likely to be between TD 13.5 and TID 14.5 million (between US$15 million and US$16 million) in 1995, based on a standard cost, observed in a number of developed countries, of US$10 per kW. It follows that a mere 10% saving on maintenance costs would reduce STEG's operating epenses by US$1.25 million in 1990 and US$1.5 million in 1995. -24- m. TRANSMISSION 3.1 bI 1989 the STEG network comprised: (a) 2,852 km of lines divided between three voltage levels: 920 km at 220 kV, 1,256 kma at 150 kV and 676 an at 90 kV; and (b) 41 transformer substations, with a total insaled power of 3,805 MVA for 92 transformers of sizes ranging from 15 MVA to 200 MVA. The map at the end of this report provides a simplified diagram of the network. Simnulation of Transmission Network ();raions 3.2 An in-depth study of selected operating situations on the transmission network (selected in close coopeation with Tunisian counterprs) was carried out in three phases: (a) collection and preparation of the data needed to create a representation of the network compatible with the computer model used; (b) simulaton of network operations and deermination of losses in accordance with the operating samples selected (differentiated according to consumption level, available power, degree of compensation, and voltage level); and (c) loss anlysis, and a search for solutions appropriate to the problems identified. The data used in the study, related to the present and projected network, are given in Annex 9. 3.3 Studies of network operation under several operating scenarios were made for the years 0989 and 1993, using the following parameters: (a) md: Three demand scenarios were used: (i) maximum, or evening, peak, exceeded for only one or two hours in the year under study: 700 MW in 1989 and 1000 MW in 1993; (i) average, or morning, peak, exceeded for about 1000 hours in the year under study: 646 MW in 1989 and 829 MW in 1993; and (iii) off-peak, or night, period, exceeded for about 7600 hours in the year under study: 420 MW in 1989 and 542 MW in 1993; - 25 - (b) oleag loek: The minimum acceptable voltage on the 225 kV network is 200 kV. For the maximum voltage, three values were used: 210, 225, and 235 kV, to enable an assessment of the sensitivity of reactive energy compensation and of power losses to the voltage level; (c) 1989 cpnsation stas: Three compension situations were considered for 1989 (situation at the time the study was made): (i) a total absence of compesaUdion; (ii compensation using only existing resources; and (ui) additional compensation obtned by installing new equipment to obtain an overall tan phi of 0.5 as viewed from the RV network; (d) 1923 compesi status: Two compensation situations were considered for 1993: (i) a total absence of compensation; and (i) compensation needed to obtain an overal tan phi of 0.5, as viewed from the RV network. Tan phi was se at 0.5 as this is the value at which the network can operate satisfactorily; It avoids large transmissions of reactve power and guarantees a large margin of security against voltage collapses; and (a) =aft pgM sta Three scenarios for power generation andlor exchanges of power with Algeria were examined: (i) imports from Algeria without compensation; (Ii) a supply of up to 250 MW from a thermal plant at Cap Bon; (iii) installation of gas turbines to produce an additional 200 MW (see Annex 9, page 4). The latter two cases were examined with and without additional compensation in 1993. There is little or no likelihood that power will be supplied in 1993 from a plant in Cap Bon, but this hypothetical case, studied at STEG's request, is useful to understanding the longer-term problems facing network operations If this plant is brought into service. 3.4 The simulations of transmission operations, the results of which are given in Annex 9, leads to two major conclusions: (a) theoretical energy losses in 1989 total between 0.9% and 1.3% under the operaig condidons studied; they represent only about one third of actal identified losses, which were about 3.6%. In the medium term, these losses should not increase under any of the conditions studied provided that STEG adopts measures for improving tan phi tirough increased compenston. The sensitivity study shows that these losses vary as follows: 0) for the morning peak in 1989, total losses are about 7 MW, the sensitivity of losses to compensation is about 0.2%, i.e., 1.6 MW for 170 Mvar of compensation; and (ii) for the morning peak in 1993, total losses vary from 6 MW to 18 MW depending on the generation hypothesis considered; the sensitivity of losses to compemation is about 0.15%, i.e., 1.2 MW for 218 Mvar of compensaion; and -26 - (b) the values for tan phi are abnormally high during the day, particularly at the morning peak, about 0.7% in 1989 for the cases studied. There are no prospects for improvement in the medium term and there will even be some deterioration unless steps are taken to improve compensation. By 1993, 211 Mvar (i.e., 171 Mvar more than the present 40 Mvar) will be needed to maintain tan phi at its overall 1989 level, whatever generation hypothesis is used. Actions Needed to Reduce Losses 3.5 It is difficult to draw distinctions between direct and indirect causes of technical losses in transmission networks, as electrical phenomena are complex and interactive. Nevertheless, the study findings, the results of additional work undertaken, and the outcome of discussions with STEG transmission network managers and operators favor three types of action, that would ensure: (a) improved system control, through optimization of flows to maintain a high voltage level, thereby guaranteeing a secure supply, and a sound management of compensation capacity; (b) improved operation and maintenance of the transmission network, with particular tntion to managing the transformgrs, maintaining the transmission network in good condition, and maintaining the equipment; and (c) progressive actions that contribute indirectly to increasing the efficiency of the transmission network: additional resources for planning and network studies, organizational changes, and training for operations and maintenance personnel. STEG Network Control 3.6 The network control system STEG has implemented is satisfactory and enables collection of the data needed for making real-time responses to any incident or contingency. Nevertheless, the simulation of network operations has shown that network efficiency could be significantly improved by means of improved system control and investments in compensation. YQV a level 3.7 For voltage levels of 150 kV and under, the transformer on-line tap changers ensure that the proper operating voltage is supplied, provided that the transformers do not reach their operating limits. However, the 225 kV level that STEG us as its primary operating voltage level is too low and, as a result, the voltage level drops off when outages or difficult operating conditions occur. -27 - 3.8 Toe simulations of network operations indicated that raising the maximum operating voltage level from 210 kV to 225 kV reduces active power losses by about 2 MW for a load of 1000 MW (the maximum demand forecast for 1993); this reduction, valued at the incremental cost of the cost of lkW of HV power (see Annex 2) gives a financial saving of about TD 400,000, or US$444,000. 3.9 When overall voltage levels are increased, service quality improves, and the risks of unplanned load shedding due to voltage drops and to engine re-start failures, are reduced. Statistically, a 5% drop in nominal voltage produces a 2% drop in peak load. Thus, low supply voltages, in addition to being detrimental to consumers, also cause financial losses to the utility. 3.10 It is therefore recommended that STEG: (a) study and determine performance criteria for network operation, such as a minimum of voltage levels and possible deviations from those norms (operational planning). Establishing such criteria will enable STEG to: (i) identify weak points in the network, especially if changes may have been made in operating guidelines or if there have been losses of reactive energy generation capacity; (ii) determine the reactive power capacity available from connected generating units, on the basis of manufacturers' charts indicating their ability to supply reactive power at the alternator terminals; and (iii) anticipate the onset of a voltage collapse so that timely measures (such as: connecting capacitors, disconnecting reactors, increasing the demand for reactive power from the alternators, blocking tap-changers on the VHV/HV transformers, and load shedding) can be taken to raise voltage; and (b) update its manual procedures for secondary voltage regulation. Even if automatic secondary voltage regulation theoretically improves the quality of voltage regulation and allows coordination of the alternator outputs, it is much better to maintain voltage levels by reactive power compensation. Substantial loss reduction will also be realized by reactive compensation. Comepeation 3.11 To ensure acceptable service quality and satisfy demand at least cost, i.e., by limiting voltage drops and reducing active energy losses, one must have sufficient compensation capacity (reactors and capacitors) and operate it correctly so that the production and consumption of reactive power can be suitably controlled. Simulations of network operations, and discussions with the operators, during the main mission, showed that STEG can make much progress by: (i) providing compensation by operating the existing reactors more efficiently; (ii) possibly using gas turbines as synchronous compensators; (ii) properly managing the step-up transformer taps on the generating units; and (iv) installing additional capacitors. -28 - 3.12 Oeation of thg m gret: STEG's method of operation of its reactors does not always enable it to maintain continuous control over the generation and consumption of reactive energy and, subsequently, to maintain a high enough voltage level to provide adequate service quality and minimize losses. For example, all reactors are disconnected manually between 7:00 a.m. and l1:00 p.m. (16 hours a day), except for the 6-Mvar reactor at the Ghannouch substation (Robbana feeder) which is not equipped with a breaker. This means that during the morning peak when there is a shortage of reactive energy (see Annex 10), the additional 6 Mvar of demand causes additional losses. Annex 12 shows, however .bat loss reduction alone is insufficient economic justification for installing a breaker. 3.13 Use gf the Tunis South gas turbine a synchronous-cgmpensatrs: Should difficulties in maintaining voltage level arise that jeopardize network reliability, one solution would be to use the gas turbines in the Tunis South plant as synchronous compensators, providing a margin of security of 3 x 20 Mvar. The results given in Annex 10 show that the power loss reduction obtained is less than the gas turbine consumption (0.8 MW). The only justification for using this equipment, therefore, is to resolve local constraints connected with maintaining voltage levels. 3.14 Manament of step-up transformer taps on the generating units: Current management of these taps is inefficient, because taps have to be selected before the transformers are energized. This practice sometimes leads to unbalanced taps on the same site, with no possibility for the Service des Mouvements d'Energie (SME) to intervene. Because taps can only be set when the units are tripped, it is recommended that the SME be made responsible for managing taps and that it develop a seasonal management procedure that would allow savings in reactive energy, and would contribute to improving the voltage level at almost no cost (labor costs, about twice a year). STEG's operations forecast for 1989 indicated that a preliminary study of such procedures had been made, but no subsequent action was taken. A complementary study should be made on the autotransformer taps, which are also set manually. 3.15 Installation of supplementary capacitors: A convenient measure of reactive level is the ratio of the reactive power to the active power. This ratio is given by the tangent of the power factor angle and is termed "tan phi" hereafter. The simulation of transmission network operations showed that, in 1989, an additional 130 Mvar would have been necessary (124 Mvar if the Ghannouch reactor had been fitted with a breaker) to reduce the overall tan phi from 0.7 (the value recorded at that time) to 0.5, the value usually regarded in similar networks as being the upper limit needed to ensure a reasonable loss level. In the medium term, 211 Mvar will be needed by 1993 in order to maintain the overall tan phi at O.5. 3.16 A more detailed study was made for substations with a reactive to active power ratio exceeding 0.6 (for the year 1989). The compensation requirements at these substations to reduce the ration to 0.5 were also determined. The results of the study are given in the tables and network diagrams provided in Annex 10. -29 - 3.17 Examination of the results obtained, particularly in the sensitivity studies, shows that the reduction of losses obtainable on the transmission network by means of reactive power compensation would not be sufficient to justify installation of compensation equipment on the VHV and HV networks (see Annex 12). On the other hand, compensation plays a useful role in maintaining a high voltage level under both normal and abnormal conditions, thereby considerably improving operating reliability. Furthermore, installing compensation as close as possible to the load, i.e., close to HV customers that have a high reactive load (cement works), or in MV substations, can be justified by means of specific studies carried out on a case-by-ase basis. It is recommended that STEG, before making any decisions on investment, increase its tariff incentives to encourage its customers to make their own investment in compensation equipment. 3.18 Taking equipment out of service in off-peak hours. Taking equipment, particularly transmission lines, out of service during off-peak hours ensures better control of the voltage level. It also provides the generating units with a wider operating margin for possible exchange of reactive power. To be effective, these measures must not compromise network reliability under normal conditions or under contingency conditions (tripping of one line or one unit). Taking VHV/HV or HV/MV transformers out of service may reduce the losses caused by these transformers at low load (by eliminating the core losses of the transformers that are removed). The transformers should only be taken out of service while observing the n-i rule (the "n-I" rule is respected if tripping of one line or unit enables the load to be supplied without overload or any unacceptably low frequency or voltage). The equipment must be returned to service quickly when required by an increase in load or to restore the n-i condition. Operation 3.19 STEG's operation of its transmission network is satisfactory on the whole, but additional measures should be taken to improve management of the VHV/HV transformers, improve the mechanical tension on some lines, reduce the effects of pollution on the insulators, and improve inventory control. 3.20 Manaent of the VHVM V trasformers. Some of the equipment appears to be oversized in relation to the load transmitted. The low load levels observed on some occasions should lead the dispatchers to undertake more rigorous management, such as (a) taking some transformers out of service; and (b) avoiding circulating currents of reactive power by Installing automatic devices when units are operating in parallel. Despite existing constraints, such as the ring-bus in the design of most of the transmission stations, and the operational practices for the distribution system, it appears that new operating guidelines can be established after an appropriate study. Also, transformer procurement practice should take into accunt -30 - losses over the desired lifetime of the equipment. The discounted cost of the losses are to be added to the investment cost for the transformer. 3.21 Mechanical tension on some lines: Some lines have a high degree of sag and the effects of creep are particularly noticeable on the 150 kV network. The mission recommends that STEG make field measures of cable sag to obtain the data required for a technical and economic study of the need to re-tension some cables. 3.22 Effects of pollution on the insulators: In some areas where the network is affected by pollution from chemicals and algae, and by sandstorms, STEG sometimes has to reduce the network's operating voltage. In addition to manual cleaning and silicone treatment of the insulators, two procedures currently in use in Tunisia, it is recommended, wherever water is available, that STEG study the feasibility of spraying the insulators with water, as this can be done without interrupting the voltage supply to the system. STEG is also interested in current research on specific insulator types (such as the aerofoll design) suitable for areas where the rainfall is too low to clean the insulators without human intervention, and has set up a committee to study pollution problems as well as the feasibility of instalig Gas Insulated Stations (GIS) in certain regions. 3.23 MA : The Operations Directorate is currendy reorganizing work procedures and maintemnce. The reorganization, based on decentralization, creation of regional storage facilities, and computerized inventory control, should improve the maintenance of the transmission network and thus improve equipment availability. It is recommended that STEG complete this program, placing ger emphasis on: (a) decentralization, except for equipment that is very expensive, or is sensitive to climate changes. An air-conditioned storage facility will be maintained in Tunis. It should be noted that the current inventory control system is too centralized, and there is no justification for centralization of some equipment, relay protective devices, for example; (b) staff expertise and quality; and (c) development of a system of data exchange between the storage facilities and networking of computerized management systems. Additional Actions Needed to Improve the Efficiency of the Transmission Network 3.24 In addition to the measures recommended previously to improve unit control and operation, actions needed to enhance the overall efficiency of the transmission network i 100 monitoring of steam turbines 2. Reinforce NV network 3,300 1,300 2.5 40 3. Reinforce LV network 9.000 2,500 3.6 28 4. Better management of NV and LV transformers Low 150 - - 5. Decrease the cuwtomer portfolio to 20 days Low or 780 turnover nit 6. Other foprovement actions: maintenanew Low or 1,720 technical and financial ement nit - 64 - Imp acon the snroment 6.4 The recommended measures, to improve generating unit efficiency and reduce network technical losses, will have a beneficial, though modest, impact on the environment; (a) improving the performance of the steam turbines by at least 1% would be the equivalent, in 1990 conditions, of reducing fuel consumption by about 9,000 toe, or almost 400 Tl, which cowresponds to a reduction in CO2 emissions of about 90,000 t and a redfiido2 in NOx emissions of about 240 t; f/ (b) a reduction of technical losses by about 1.5% of peak demand corresponds to an average reduction of electricity consumption of about 2.5% and to fuel savings, under 1990 conditions, of about 30,000 toe, or almost 1,350 T1. These savings correspond to a reduction in emissions of about 300,000 t of CO2 and 850 t of NOx. 6.5 EstImations of the economic impact of reducing emissions from utility plants vary greatly, in a range of 1 to 10, according to different studies and different technical experts. By totaling the savings considered in the present study at the cost for reducing the emissions, one obtains a value of US$7 million, indicatng the supplementary beneffts to be obtained from the proposed loss reduction program, about half the sum of the investments proposed to accomplish the loss reduction program. PoQW csatio the amvlW of fn us 6.6 Many electric utilities in the developed countries, faced with the problem of finding the sites and capt needed to increase the power supply, have undertaken programs of promoting customer consvaton of energy. STEG has the required organizational and management capacity to promote these kinds of ptograms, which have been proven to be economically and financially advantageots in several countries.7/ 6.7 Ilvesdgation of the techncal, Cconomic, and financial conditions required to implement such a program is beyond the scope of the present study, but stdies conducted in severd countries have demonstrated the advantage of such programs, precisdy targeted and supported by adequate financial resources. It is therefore recommended that STEG create a task force to study: mNote dt, to inyrove th perfawe of te elecic gerang stem and so redwuce te cowapyin offuel per GMV preced, MGha0 thakene decio to iall a 300MW combnd cyce plant Ts decision, wIcfh wiX allw SM to beer eute dw tehcal and econm paers of tie combhied cyck, wi udote ha a *4g*swcant pcf STa IG's generaing syem an, conseque*, on thistechoo in te region ZI Ape*ne has wt elecrk sutilie, palcurly in the Unied Sas, have given p the ea*V soluon - to incuase* - in repose to de pressmre ofn l costrans and soMge qfsiab sies, on e one hnd, ad so he ety of indentproduers ito the marke t pail deregulaton of he sector, an the odter. MG can reachth innvati phse Iewwtinin wiho waiing to be co*td w*h tee conorio, and c ths redau the weed fr large invem tat arreadaces. -65- (a) in association with the Agence de Matris. de i'Energie, the promotion of progrms designed to save power at the level of final use, that are economically and finanlaly profitable for the utility, the consumer, and the local authorities, and (b) implemion of the programs by providing better information to consumers, possibly in association with any partrs, local authorities, and or private promoters, who would be affected by the promotion of such programs. -66- A lI Page I of 2 STEG ORGANIZTIONAL SMRUCTURE STEG 'a managed by a Board of Directors with 14 members: - 1 Chairman and Managing Director - 1 Assistat Managing Director - 8 Directors represen the State - 2 Directors representing employees -1 inancial Controller - 1 Technical Controller Ten Directorates and five Departments, reporting to the Chairman and Managing Director, are the backbone of the company's structure. 'he five departments are: - Management Audit - Internal Audit - Technical Audit - Public Relations - Central Services The ten directorates are: - Data Processing - Planning and General Studies - Distribution - OpeatiGas - Equipment - Gas - Financial Affairs - Legal and Adminisrative Affairs - Procurement and General Resources - Rosearch and Development - 67 - AM I Page 2 of 2 BOARD OF DIRECTORS Nartagement Audit| Chairman & anaging Director Internal Audit Lea l Advisors Teehnfeal Auditl Assistant anagn Director Contract Comittee (Permanent) Pubtic Retations . . . ~~~Centrat Smfervce H DlstrObutlon j |~~~~~~~~~Leatan Adofnistr tlon e Operations IAffafrs Procurenent and Equipoent General Resources _ _ _ _ I Research and Gas . eveoprent Pltaming and General | Studle D | ats Processing IF oat ion -68- Amu 2 Page 1 of 19 CALCULATION OF LOSSES METHOD Short-term Maryinal Cost 1. The short-term marginal cost is the generation, transmission and distribution cost entailed in supplying one additional kWh in a given year with a fixed amount of equipment. 2. The short-term marginal cost is based on the establishment of a reference cost for fuel, based on the load curve at J-1 or a study of projections. The reference cost takes account of the real cost of fuel and an opportnity cost that takes account of real-time contingencies in fuel supply. In the case of projections, It is necessary to add unit start-up costs (usually from 45 minutes to one hour of fuel cost at full plant load), together with transmission costs. The marginal short-term generation costs are used for projecdtg operating costs. In France, the reference costs over five years are based on fuel costs. These costs are updated in line with changes in the macroeconomic situation and discount rates. Projections of hourly or daily marginal costs make it possible to optimize allocations in accordance with probable availability and problems with generating equipment. Likewise, they enable an optimum generation schedule to be determined. For Tunisia, a five-year study of marginal generation costs would compare the economic benefits to be derived from either operating the power plans simultaneously, as is done at present, or staggering unit shutdowns and startups. Long-Term Maginal Cost 3. The long-term margina' cost is the additional generation, transmission and distribution cost entailed in supplying one additional kWh in any given year in cases when the utility is able to increase generating capacity. It takes ito account fuel, operating and capital costs. Long-term marginal cost Is also calculated on the bas13 of the incremental cost. In fact, the system is adapted to the new load level by making the necessay capital investment one year ahead of schedule. The cost of this early investment is the sum of the following three items: the annual financial charges (discounted), -69 - pAnn Page 2 of 19 depreciation over the first year, and the fixed costs of operation and maintenance of the equipment for one year. 4. The esdmat savings from loss reduction (presented below) are calculated by taking into account the ncremental costs of equipment at the various study levels (generation, transmission, and distribution), as well as fuel costs. Calltging Fue Cost S. The 1989 load duration curve for all Tunisia was used to calculate fuel costs. The results appear in the ZTEG tariff study of April 1988. Loa Duration Curve (see Fig. 1) 6. This is the curve showing demand for the 8,760 hours per year, in decreasing order, from the maximum to the miniWmum load peak. The load ' urve for generation at national level in 1989 has been used. It is based on 13 values, as shown in thetable in Figure 1. 7. Calcuations would have been more precise if the load duration curves for each of the HVIMV subsaons had been used, because consumption paterns can vary depending on the type of area srved (e.g. urban and predominantly residential areas, urban and predominantly industial areas, gricultral areas, sparsely populated areas, etc.). In addition, the load diagram for high-voltage Indusi om ers may also differ from that of customers connected to the distribution network The national load duraion curve refers to an annual duration of peak power utilization totaling 5,830 hours (see section below). The annual duration of peak power utilization for the main substations in queston is about 5,900 hours. The difference is thus negligible. 8. It is therefore proposed that the load duration curve for the country as a whole be used in determining the share of fuel oosts in the anmual cost of I kW of losses at peak periods. This approach is consistent with the degree of accuracy of other data used in the various calculations of loses. Marginal Cost of Fuel 9. The STEG tarff study gives marginal fuel costs for 1994 for the peak, day and night tariffpeods based on both domestic Tunisian prices and intemrational market prices. The latter valu will be used, since they reflect the real cost to the country. -70- AM2 Page 3 of 19 10. Available data relate to different time periods, since we have: - the load duradon curve for 1989; and - the margina fuel cosS for 1994. 11. However, the curve for 1994 is likely to be very similar to that for 1989. In fact, no extensive equipment modifications are planned for the short term, and even !f new applications develop or pricing adjustments are made, they would not have a significant Impact on the shape of the load curve in so short a space of time. 12. Fuel costs for 1994 relate to the future generating system over the medium term. lbey can thus be regarded as entirely reprsentative and used to measure the effects of the recommendadons proposed for reducing losses in the medium term. Anna fuel costs due to losses will be calculated for the following two cases: Joule-effect ogses: the following assumptions will be made: Peak power use: 5,900 hours; Lad level depends on the shape of the national load duration curve (see Figure 1); Hourly fuel costs are as shown in the STEG pricing study (April 1988). Core losses in transfrmers: the following assumptions are made: Use: 8,760 hours; Hourly fuel costS are the same as above. -71 - Annex 2 Page 4 of 19 LOAD DURATION CURVE 1989 Peakpower : 771 MW Minimum power : 230 MW Averge power : 513 MW FIGURE 1 800 v v - _ C _ _ 3;:~~~~I IA.- I I_ I _ _ __I _ as 70 I I I I 1- I IA SLL9 i It- I 5 ai L nn~~~~~~ . . .: . ._ I I2 I - I a--- . . . . .T . _~~~~~ . . . . . . . . .E . . 600 R n n . -1-]-a-1 2 1 I 2 I a I I LI__ I _ :I w~~~~~~~~~~~~ - - - - 3 - - 1- - . . . _. _ *- * t. g . * * _ ; ;1 I aI: a I- t :: I _ I I F a P (MW) 400 :_ * a a I a . . . .^ . . . . . . . *. E*_n 300 ..... 200 . . . . . . . . . . 100 tit 0 I L 8 1000 2000 3000 4000 5000 6000 7000 8000 HO'WS VALUES TAKEN INWO ACCOUNT Relative P POWERMMW Half-hours Hours 150 770 3 1.5 142.7 732 245 124 133.8 686 623 435.5 123.8 635 1605 1238 114.1 585 3093 2784.5 104.8 538 3584 4576 94.4 484 2273 5713 84.2 432 3093 7259.5 75.7 388 2568 8543.5 66.7 342 227 8657 1 | 54.5 280 70 8692 -72- AM Page 5 of 19 Calculation o Fuel Cos Result from Jule-effect Losses 13. Joule-effect losses are proportional to the square of the load. The standard loss curve can therefore be calculated from a curve derived as follows from the load duration curve: a time variation In the ordinate is proportional to the square of such variations in the load duration curve (see curve in Fig. 2). The curve is divided Into three periods: - a first period of 1,252 hours, corresponding to the peak; - a second period of 4,223 hours, corresponding to the daytime hours; =an ht period of a total duration of 9 h x 365 = 3,285 hours. 14. The annual Joule-effect for each of the above periods is determined on a chart by constructing equivalent rectangles with a surface area equal to the areas subtended by the curve representing lost eergy. The following results are obtained (see Fig. 2): - 78% of the peak losses for the peak period; - 54 of the peak losses for the daytime period; - 32% of the peak losse for the night period. Annal energy losses cofresponding to 1 kW of losses are therefore as follows: - peak: 0.78 x 1,252 = 976 kWh; - daytime hours: 0.54 x 4,223 = 2,280 kWh; - night hours: 0.32 x 3,285 = 1,051 kWh; The marginal costs in millines/kWh considered for 1994 are given in the April 1988 STEG tariff study). - peak: 38.2 - daytime period: 30.3 -nightperiod: 23. The annual fael cost for 1 kW of peak losses will therefore be as follows: (976 x 38.2) + (2,280 x 30.3) + (1,051 x 23) = 130,540 millimes = TD 130. CALCLLATION OF ANNUAL FUEL-COSTS 1 X 0.9 0.P S hae of e boad 0.7 t \ 0.6 - - hae Joub . cu~~~~~~~~~ecuv %PEAKP 0.5- 0.4- - 0.3 - - 0.2 - - 0.1 - O- I . | - I I -I -I'II $ 0 1000 2000 3000 4000 5000 6000 7000 8000 I.- FIGURE2 -74- Annax 2 Page 7 of 19 Mr.: Ihe cost calculated above relates to the power output level. At each point on the network, losses will be calcuated for the corresponding supply network. The above calculation refers to the duration of the fbllowing peak power utilization: average load (see Fig. 2) is 513 MW. Thus, annual power outut Is: 513 x 8,760 = 4,493 GWh. Peak power is 771 MW; the duration of peak power utilization is therefore: 4.493 x 10' = 5,828 hours 771 The load factor P is as follows: Ppeak 0.66 771 Caculaion of the Fuel Costs Resulting from Core Losses in tie Transformers 15. In this case, the load duration curve is horizontal. For IkW, power output levels per period are as follows: - Peak: I kW x 1.252 h = 1,252 kWh - Dayme: 1 kW x 4.223 h = 4,223 kWh - Night: 1 kW x 3.285 h = 3,285 kV h The anmual fuel cost at the power output level will therefore be as follows: (1,252 x 38.2) + (4,223 x 30.3) + (3,285 x 23) = 251.3 x 103 millimes, = TD 251. -75 AM 2 Page 8 of 19 IHNREbf-b CT S IN 3ISTA 16. The purpose of this study is to propose values for the incremenl costs per kiowatt, so that savis from loss reductions can be etmated. Most of these costs are taken from the Apri 1988 STEG tariff study. Consequently, the financial data given below are expressed In 1989 Tunisian Dinrs. Generating Costs 17. Ihe incremental cost for generating equipment is based on the insttalation cost of the 150- MW unit to be installed at Rades. The gross development cost is determined as follows (based on an instlion cost of TD 673 per kw): Depreciation (over 30 years): TD 22.41kW Financial charges (10%): TD 67.3/kW Fixed operang costs: 'ID SAlWk Total TD 97.71kW Fuel savings are calclated to be TD 41 per kW, which leads to a net incremental cost of TD 56.7 per $W, rounded to TD 57 perkW. Ihe number of kW installed per additional kW at the peak is 1.25 (see STEG load curve). The incremental cost is thus 57 x 1.25, i.e.: Incremental cost for generation: TD 71 per kW. -76 Annex 2 Page 9 of 19 Iment B Co Hy TIanmi«ion 18. The investment program for transmission scheduled in the 1987-91 plan i TID 15 million, for a total of 117 km of lines. 'Te investment cost per kn of lines is TD 128,000. The technical components of the transmission program call for construction of 0.32 m of lines per additional installed kVA HVIMV and 1.825 installed kVA HV/MV per additional peak tW. Invertment in HV transmission per additional peak kW is thus: 128 x 0.32 x 1.825, i.e., TD 75 per kW, The incremental cost is therefore: Deputiation (over 30 years): Ti) 2.5/kW Financial charges (10%): TID 7.SkW Fixed operating costs: TD 07.7/LdV Total TID 10.7/kW karet Cost f HV/KV Substations 19. The investment program for transmission scheduled in the 1987-91 plan is TID 21 million, for a volume of 363 MVA of installed capacity. The investment cost per instaled MVA is TD 57,500. The technical component of the transmission program call for construction of 1.825 insalled kVA 1V/MV per additional peak kW. Investment in HV transmission per additional peak kW is thus 57.5 x 1.825 ='TD 105/kW. The incremental cost is therefore: Depreciation (over 30 years): TD 3.5/kW Financial charges (10%): TD 10.5/kW Fixed operating costs: TD 0.9kWW Total TD 14.9/kW -77- AL2 Page 10 of 19 20. GnzI: The total investment In distribution is given in the dir4tives of the distribution master plan for the 1987-91 period of the Vllth Plan. Iglte AM: SUSARY OF INVESTIENTS IN NV SUBSTATIONS (thousand TO) SgEG financing Third party financing Total Rural investments 3.200 26,000 29,200 urban investments 4.500 0 4 500 Industrial Inestments 0 17,000 17,000 Saitation invlecments 17,200 0 17,200 Total 24,900 43,000 67,900 21. a: The value of the MV marginal cost is equal to the ratio of total MV investment to the increase in MV peak power. The latter represents 86% of the increase in total power, i.e.: Total peak power in 1987: 710 MW Total peak power in 1991: 910 MW Difference: 200 MW Difference on MV network: 172 MW (ratio of 86% for MV and LV at peak power) 22. Total MV investment for the period is TD 67.9 million from all sources in the Tunisian economy, regardless of origin; STEG's investment is TD 24.9 million. - This gives an incremeal cost (excluding losses, and considering only STEG's investment): Investment per additional peak kW: 24.900 = TD 144 per peak kW 172 -78- Annex 2 pop 11 of 19 Depreciation (over 30 years): TID 4.81kW Financial charges (10%): TD 14.4/kW Fixed opeting costs: TD 3.1kW Incremental cost TI) 22.2/kW Thbis gives the following total incremental cost (excluding losse, ant including all sources of investment): Investment per additional peak kW: 67,90 - TD 395/peak kW 172 Depreciation (over 30 years): TD 13.2fkW Financial charges (10%): TD 39.5/kW Fixed operating expenses: TID 3.0nkw Incremental cost TD 55.71kW 23. Q:imI: The total investment in distribution is given in the directives of the distributi mn mtr plan for the 1987-91 period of the VlIth Plan. Iable A2,J: SUNNARY OF INWESTMETS IN tN/LV SUBSTATIONS (thousand TD) STEG Finanring Third Party Financgn Total Rural intmmnts 1.000 6,300 7,300 Urban nventments 7,000 0 7.000 Industrfal Investments 0 0 0 (Cl. Ind.) Sanitation Investments 8,600 0 8,600 Total 16,600 6,300 22,900 24. hUrEe cost h Ie marginal cost of I MV/LV kW is equal to the ratio of tota investen t the increase in LV peak power. The latter is equivalent to 48% of the Increase in tot power, i.e.: -79- &nnZ 2 Page 12 of 19 Total peak power in 1987: 710 MW Total peak power In 1991: 910 MW Difference: 200 MW Difference for MV/LV substations: 96 MW 25. Total investment in MV/LV substations for the period is TID 22,900 million from all sources in the Tunisian economy, regardless of origin; STEG's investment is TD 16 million. - This gives the following incremental cost (excluding losses, and considering STEG's investment only): Investment per additional peak kW: 0§M = TD 173/peak kW 96 Depreciation (over 30 years): TID 5.7/kW Financial charges (10%): TD 17.3/kW Fixed operating costs: IP 2./kW acremental cost TD 25.0/kW f investment from all sources is included: -"2.90= 239/peak kW 96 Depreciation (over 30 years): TD 8.0AW Financial darges (10%): TD 23.9/kW Fixed operating costs: m 2./LkW Incrementa cost TD 33.9/kW iL,: The fixed operating costs for MV and LV were considered to be identical, in accordance with the STEG tariff sudy; i.e., TID 6 per kW for all the MV/LV substations and the LV network. Dbution of ID 2 per kW for MVILV substations and TD 4 per kW for the LV network were mumed. Low Votgb" Network 26. Gnera: The volume of investment in disibution is given in the directives of the distribution master plan for the 1987-91 period of the VIIth Plan. -80- Am2 Page 13 of 19 Tabtg a..: IAAY OF IWNESTMENTS IN LV SUBSTATIONS (thousand TO) STEG Finaring Third Party Financing Total Rurat invstments 2,800 23,700 26,S00 Urban Investments 10,500 10,500 21,00 IndLustriaL Investments 0 0 0 Soitation Investments 17,200 0 17,200 Totat 30,SOO 34,200 64,700 27. In ol Cg: The margh cm of k LV kVA is equal to the rato of total investment to the increase in LV peak power. The latter is equivalent to 48% of the increase in total power, i.e.: Total peak power in 1987: 710 MW Total peak power in 1991: 910 MW Difference: 200 MW Difference on LV network: 96 MW (200 MW x 48%) 28. Total low voltage investment for the period is TD 87.6 million (including nonSTEG fincing); STEG's investment i TID 47.1 million. - - This gives the following incremental cost (excluding losses,, and considering STEG's investment only): Investment per additional peak kW: 3020 = TD 318/peak kW 96 Depreciation (ovcx 30 years): TID 10.3/kW Financial charges (10%): TD 31.0/kW Fixed opeating costs: M 4.0Q/lW Incremenal cost TD 46.4JkW -81- Anne Page 14 of 19 This gives the following cremental cost (excluding ses, ad Including investment from all sources): Investment per additionl peak kW: ft110 = TID 674/peak kW 96 Depreciation (over 30 years): TID 22.41kW Fincial charges (10%): TI 67.4/kW Fixed operating expen: M 4CAlO.W. Incremental cost T) 33.9/kW Su of mn 29. Ihus, the study leads to consideration of two scenarios, dependig on whether funding consists of STEG financing alone or financing from all sources. Inrmna cm: Scenari 1 First scenario: STEG financing alone: Incrementa cost of generton: TID 71.0/kW Incrementl cost of HV transmission: TD 10.7/kW Incremena cost of HV/MV substations: TD 14.9/kW Incremenl cost of MV distibution: TD 22.2/kW Incremental cost of MVILV substations: TD 25.0/kW Incremental cost of LV disibution: TD 46.6/kW in relation to the marginal peak kW) The distributon of losses over the entire network Is approximaely as follows: 2.5% for the RV network 2% fot the HV/MV transformers 5% for the MV network 3% for the MVALV transformers 6% for the LV network -82 - Page IS of 19 Calculadon of incremental cost per kW, taking upstream losses into account: - HV network: (71 + 10.7) x 1.015 = TID 83.7/kW - HV/MV transformer: (83.7 + 14.9) x 1.02 = TD 100.6/kW - MV network: (100.6 + 22.2) x 1.05 = TD 128.9/kW - MV/LV transformers: (128.9 + 25) x 1.03 = TID 158.5/kW - LV network: (158.5 + 46.4) x 1.06 = TD 217.2ikW RESULTS NV/NV NV/LV HV Transformers MV Transformers LV Incremntal costs . TD/k bi.7 100.6 128.9 158.5 217.2 (includin tosses) Irementl Costs: Scenario 2: Second scenario: taking into consideration total investments (STEG and others): Incrmental cost of generation: TD 71.0/kW 3ncremental cost of HV transmission: TID 10.7/kW 3ncremental cost of HV/MV substations: ID 14.9/kW Incremental cost of MV distribution: TD 55.7/kW Incremental cost of MVILV substations: TID 33.9/kW ncremental cost of LV distribution: TID 93.8/kW (in relation to the marginal peak kW) The distribution of losses over the entire network is approximately as follows: 2.5% for the HV network 2% for the HV/MV transformers 5% for the MV network 3% for the MVALV transformers 6% for the LV network -83 - AM 2 Page 16 of 19 Calcuation of incremental cost per kW, taking upsteam losses into acout: - HV network: (71 + 10.7) x 1.025 TD 83.7BMW - HV/MV transformers: (83.7 + 14.9) x 1.02 = TD 100.61kW - MV network: (100.6 + 55.7) x 1.05 = TD 164.11kW - MVtLV transformers: (164.1 + 33.9) x 1.03 = TD 203.9/kW - LV network: (203.9 + 93.8) x 1.06 = TD 315.6&kW RESJLTS NV Nl/NV NV NVJLV Transformers Transformers LV Incroentat cost in TD/ld 83.7 100.6 164.1 203.9 315.6 (inctudIng Losses) 30. Ibis second scenaio will be used in calcat the cost of losses. In faCt, it is closew to act coss and akes Into accout al the power savings for the community. Generally, the margial cos method should inclu&a all costs, so that tariffs can reflect energy costs as accurately as possible. 31. As indicated above, the anmal cost of 1 kW of peak losses is calculated by adding the annal fuel costs (as a function of the load duration curve), the incremenal cost of genation equipment, and the incremental cost of the works upstream of the point selected. The dibution of losses over the entire network is approximately as follows: - HV network: 2.5% - HV/MV transformers: 2% - MV network: 5% - MVILV transformers: 3% - LV network: 6% -84A Page 17 of 19 The following two cases will be examined: the general case, which follows the profile of the load duradon curve used in the calculation (about 5,900 hours of peak power use), and the case of transforner core losses (8,760 hours of power use). Ibe aoew 32. Calculation of the annual cost of one kW of peak losses. The incremental cost of one additional kW was given In a preceding paragraph. At this point, therefore, we need to calculate only the cous of fuel (including losses) at each level of the network: - Generation: 'ID 130tkW (see above) - HV network: 130 x 1.025 = TID 133.2/kW - HV/MV transformers: 133.2 x 1.05 = TD 135.9/kW - MV network: 135.9 x 1.05 = TD 142.71kW - MVILV transformers: 142.7 x 1.03 = TD) 147/lW - LV network: 147 x 1.06 = TD 155.8/kW Calculation of total costs: - HV network: 83.7 + 133.2 = TD 216.9/kW - RV/MV transformers: 100.6 + 135.9 = ID 236.5/kW - MV network: 164.1 + 142.7 TID 306.8/kW - MV/LV transformers: 203.9 + 147 = TD 350.9/kW - LV network: 315.6 + 155.8 = TD 471.4/kW We obtain the following table: Table A4: ANNUAL COSt OF ONE KW OF PEAK LOSSES Cost at this use levet (TDAIV) Arnual peak power use __,__ NV NV/NV NV VIVLV Transformers Transformers LV 5,900 hours 216.9 236.5 306.a 350.9 471.4 - 85 - Ame 2 Page 18 of 19 The Cae ofTnufm Cm Lo= 33. The incremental costs of the investments were calculated previously. To these we will add annual fuel costs (including losses) calculated for the network under consideration. IMM I=,&=rme>. Calculation of amual fuel costs. - Generation: TID 251/kW (see above) - HV network: 251 x 1.025 I TD 257.2/kW - HV/MV transformers: 257.2 x 1.02 - TD 262.4/kW Total cost: - HV networt: 83.71 + 257.1 = TD 340.9/kW - HV/MV transformers: 100.6 + ;62.4 - TD 363/kW Calculation of annual fuel costs: - MV network: 262.4 x 1.05 = TI 21 5.51kW - HV/MV transformers: 275.5 x 1.03 = TD 283.8/kW Total cost: - HV network.: 164.1 + 275.5 = TD 439.6/kW - HV/MV transformers: 203.9 + 283.8 = TD 487.7/kW We obtain the following table: tablLAZJ: TOTAL ANUL COST OF ONE KU OF CORE LOSSES IN THE TRANSFORMERS cost at this use level (in TO/kM) AnnuAl peak powr use MV/NV NV V/LV NV Transformers Transformers LV 8,760 hours (core tosses fraud transformers) 340.9 363 439.6 487.7 -86- A= 2 Page 19 of 19 TI2t9 284.: ANUAL COST OF ONE KW OF PA LOSSES Cost at this use leve (in tD/l) Amsl peak poet use NV/V NV/LV HV Transformers NV Transformers LV 5,900 hours 216.9 236.5 306.8 350.9 471.4 8,760 hours (core losses from transformers) 340.9 363 439.6 487.7 - 87 - Page 1 of I EQUIVALENCE BKTWEN THE IMMETE RATE OF MAND THE ITERNAL RATE OF PEFUR Tb*t AM.: CONVERSION OF IMMEDIATE RATE OF RETURN INTO INTERNAL RATE OF RETURN FPrmclal tRR IRR IRR Igo payback period Iniediate Duration: 10 years Duration: 20 years Duration 30 years 10 years 10 0 7.8 9 11 1.8 9 10 12 3.5 10 11.6 13 5 11.5 12.6 14 6.6 12.7 13.7 15 8 14 14.8 16 9.6 15 15.8 17 11 16 16.8 18 12 17.2 17.9 19 13.7 18.4 18.9 S yearo 20 15.1 19.4 19.9 21 16.4 20.5 20.9 22 11.7 21.6 21.9 23 18.9 22.6 22.95 24 20.2 23.4 24 25 21.4 24.7 25 4 years 25 21.4 24.7 25 30 27.3 29.8 30 3 years 35 33 34.9 35 40 38.5 40 40 45 43.8 45 45 2 years 50 49.1 5.0 50 , 2 years 55 54.3 55 55 60 59.4 60 60 65 64.6 65 65 70 69.7 70 70 75 75 75 75 Page 1 of 6 BEAT RATES OF THE STEAM THERMAL PLANTS Sousse P oE Plant - Units 1 and 2 ouasl heat rates (1908) 10 9 B 7 6 5 4 3 2 2450 .2500 2501 2550 2551 2600 2601 2650 26S1 2700 2701 MO Ml 2800 i2niU Annual heat rate data distribution KcaL/Kwh 2800 x 2700 x N 2650 x x x x 2600 N 25S0 N 2500.x 2450 I I I I I I I I I11 J F N A N i J A S 0 N 0 NsM: X " 200 Kcat/ltmh Standard deviation: ; u 86.9 Reference value (for gs and at neminal load): 2565 Kcal/Kih -89- Am Page 2 of 6 Sousse Power Plant - Unit 2 Annual host rate (1988) 10 9 8_ 6 4 3. 2450 2500 2501 2550 2551 2600 2601 2650 2651 2700 2701 2750 27S1 2800 Arnal heat rate data distribution alCst/Kwh anoo 2750 2700 x 2650 x x x 2600 x x 2550 x x x 2500 2450 J F n A N J J A S 0 N D Ne: ' * 2613 fctat/E Standard deviationt V * 71.4 Reference value (for ges and at roganal toad): 2565 Kcal/Kth -90- AM0CA Page 3 of 6 Radbs Power Plant - Unit 1 Annual heat rate (1988) 10 8 6 5 4 3 2 _ 2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650 Annual heat rate data distribution Koal/Kwh 2650 2550 2500 x 2450 x x x x x x x xx 2400 2350_ 2300 J p N A N J J A S 0 N D un: 2428 Kcat/" Standard dewiation: Q .28 eference value (for gas and at nominal load): 2350 iIKet/uh -91- Page 4 of 6 Radf Power Pla - Unit 2 Anwnul heat rate (19B8) 10 3 2 1 H- 2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650 Anmuat heat rate data distributi on KceI/Kwh 2650 .. . . .. . . 2600 2550 2500 x x 2450 . x x x x x x x x 2400 x 2350 2300 I II III I I I I Il J F N A N J J A S 0 N D Wean:u a 243? Kcal/KAh Standard d.vfation: u 17 Reference vlume (at nrmnal load): 2350 Kcat/Kwh -92 A 4 Page 5 of 6 Radbs Power Plant - Unit 1 AnmuaI heat rate (1989) 10 9_ 7_ 4 3 2_ F - _ ___ __ 2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650 Arlat heat rate data distribution Kcal/Kwh 2650 2600 2550 2500 2450 x x x x x x x 2400 2350 2300 ,IIIIIII I I I I I J F N A N J J A S 0 N 0 Nean: It., 248 KCca/h Standard devfatfon: 7 a 13.4 Reference value (at nminal load): 2350 Kcat/Kwh -93- AM 4 Page 6 of 6 Radbs Plant - Unit 2 Anmuat heat rate (1989) 10 9 8 6 4 3 2_ 2300 2350 2351 2400 2401 2450 2451 2500 2501 2250 2251 2600 2601 2650 Anual heat rate data distribution Kcat/Kwh 2650 2600-..._... 2550 x 2450 x x x x x x x x . x x x 2400 2350 2300 J F N A N J J A S 0 I 0 Me-n: t 2434 Kca1/Kih Standard deviation: ?F u 11.7 Refererice value (at nominal Load): 2350 Koal/Kwh - 94 - Anna Page 1 of 5 FFI CIENCY MONITORING Monitorin Variations in Unit Heat Rates 1. The table on page 2 of this annex (Table AS.1) gives examples of variations in the opwaing parameters of a 115 MW unit (MONTEREAU) and of the magnitude of the corresponding eases in heat rate. al Excess Consumtion of Fuel due to one Additional kcal/lWh 2. 3Q MW Systm. For an annual utilization of 6,500 h, the energy generated will be: 6,500 x 30,000 = 195,000,000 kWh Excess consumption of heat due to one additional kcal/kWh is 195,000,000 kcal. For example, if a fuel oil has a HHV of about 10,000 kcal/kg, excess annual consumption will be 19,500 kg (20 metric tons). 3. IfI MW m. On the same basis, excess fuel consumption will be: 6,500 x 160,000 104,000 kg (100 metric tons) 10,000 4. Ihus, continuous monitoring of heat rme variations - and eliminaon of their causes - makes considerable fuel savings possible, especially in the case of units with a high unit capacity rating. -95- MM z Page 2 of S Table AS.1: SANPLE VARIATIONS IN OPERATING PARETERS AND THEIR EFFECTr ON THE HEAT RATE OF A 125 NW SET (FOR A BASIC OPTINU14 CONSUPTlION OF 2200 kcal/kIh) Parameter causing 'NW1j the hvsic c -war - --- re - the variation COB Consurptton recorded In kcaL In X o BOC Output P 125 NW 60 NW 85 3.8 Output O COS I COS 0 0.9 6 0.3 Cooling water 21.50C 13.5"C 25 1.14 Ambient air 26.5§C 16.54C 10 0.45 Condenser temerature 33.60C + 30C 10 0.45 * Fouling * Air Intake Sensible heat 5% 10% 22 1 (Exes 02) Superheated steam 124.5 bar - 10 bar 11 0.5 pressure Superheated steam 5400C - IOC 5 0.23 teqerature Resuperheated steam 5400C - 1OC 5 0.23 teeperature HP steam reheaters NS 43 2 LP steam reheaters HS 71 3.2 JEfficiecM Monitoring Methodology S. The purpose of efficiency monitoring is to continually monitor fuel consumption per unit of power generated so that the causes of variations in the heat rate can be eliminad as quicldy as possible. Definitions 6. HIaRate: kcal/kWh. This is the amount of fuel (expressed in heating value) used to produce 1 kWh. ^,Xal HOtRate = .' IbTis is the heat rate obtained under normal opeing condions -96- AmixI Page 3 of S - watt-hour meters; and - fuel flow meters. QOtimm Rase Consumpton (OBC): Ibis is the theoretical heat rate of the plant when all operating conditions are simultaneously at their optimum, i.e.: - equipment in perfect condition; - unit contrui parameters at their rated values; - output at its rated level; and - zero reactve power (Cos phi = 1). Dviations: This refers to the various variations in heat rate attributable to the differences between the actual and optimum (OBC) values of the corresponding physical parameters. Sg.: These variations are always positive or zero values (if not, the OBC should be recalculated). Some variations in heat rate are independent of one another (e.g., steam water losses, unit output, etc.), whereas others are interrelated (e.g., temperature of the exhaust gases, atmospheric conditions, etc.). For overall calculation of interdependent variations, the approximation method is applied to dependent varations. Ei = relative deviation in consumption from the OBC ei = absolute deviation (in kcal/kWh) OBC = Optimum Base Consumption ei = EixOBCx(l + c') i-n i-n With CAO Eeie ; giving I: CS = OBC + eI It 1= 2 CAO: cow=pduascePWddigunit)operadon HR - OBC(I + }E1) + 52)-. + E)...( + R) BR -OBC+e1+e2+...+eL..+on lwfirxiade in el M is obtie by deloplg te prod atnd disregading de Wm Z. * 97 * AnnA Pago 4 of S Q&IWQD f Ho Boa D2iffienc« 7. lTe calculation of heat rat differences comprises the following three successive stages: - processing of the data obtained for each load level (30MW and ISOMW); - calcuation of differences for each load level; - calculation of weighted average deviations. PiM Pa mmnguIingjfa CdgW a timda . Ihe energy produced for eac load level i determined as follows: - by using the load diagram; - by using a meter calibrated for several tariff levels (the same number of tariff levels as of load levels). Cafl1atioD. of &Aye : Each month, arithmetical averages are calculd for each opeating difference for a given load level. &W.: The deviations are much easier to calculate if a set of nomograms i developed giving direct * readin of deviations corresponding to variations in physical quantites based on the OBC (see exmple at the end of tds document). The deviations are classified a follows: - externa deviations (due to conditions unrelated to plant opeation, such as the weather); - nteral deviations (due to equipment condition, unit control, etc.); - deviations resulting from a combinadon of the above. ating MWd Al=gg Deyigi= Since deviations are calculated for each load level, the average for each deviation is obtained by introducing a weighting to take account of the enr generated at each load level. By applying the correction term of the dependence relation to the relative values of the deviations, we obtain the absolute value for each deviation. HEAT RATE VARIATIONS DUE TO SHUTOWN OF THE FEEDWATER SYSM 440 420 400 380 kJ/kWh 360 340 320 300 I _ l l 0 50 100 150 200 250 300 Net Output (MW) FIGURE 3 - in oq~~~~~~~~~~nlat -- 0n 4; i - 0 - - ,C #t 2' 0 B b W||B5 WEAr§' 44o .4tX W 1i - I L I I I I IX -100- Page 2 of 8 3. The term "Measurements needed" means direcdy usable measurements that can be made using various sensors and calculation algorithms. A summary flow chart of the software is given on page 4. 4. When a parameter deviates from the reference value that Indicates optimum efficiency, the computer in the control room displays in real time the amount of the deviation, the resulting increase In the heat rate, and the financial loss involved. S. The continuous display of data related to the main unit managemement parameters that affect efficiency enables appropriate correctve measures to be adopted at any time. 6. This application also makes it possible to carry out performance tests that enable operators to check the specifications guaranteed by the manufacturers, and to monitor changes in the performance of the main components. 7. This aspect of continuous performance monitoring is especially important to mantenance planning (i.e., predictive maintenance). 8. With this application, predictive maintenance and operating efficiency can be considerably improved. However, it is difficult to quantify in advance the savings that will be obtained. 9. Installation of similar equipment for comparable power units has shown that one can expect an overall heat rate saving of about 1% in the STEG steamn facilities, or an expected saving of: 2MQ = 2.6 toe/GWh 100 2.6 x 3,720 = 9,672 toe 260 toe/GWh = fuel consumption in 1988 3,720 GWh = thermal steam power generation in 1988. A0essment of Coot 10. Because automated programs are already in operation (Radbs) or under study (La Goulette 11), before introducing software for the on-line monitoring of operating efficiency, there should be a study mission to: - evaluate the "efficiency monitoring' application that STEG is cfurently testing; - 101 - Anext Page 3 of 8 ensure that it is compatible with software for the on-line monitodring of operating efficiency; aain what additional hardware is nesary and how long it will take to adapt it (study + on-site installation). 11. A preli inary cost evaluation for a power plant with two generating units breaks down as follows: Table A6.2: COST ESTIMATE FOR INSTALLATION OF AN EFFICIENCY NONITORING SYSTEM FOR TWO UNITS Cost (IS dottars) Unit cost Totat Neasurement senors (10) s 2 16,500 33,000 Neasurement lines (20) Y 2 16,500 33,000 Data collection penels (40) x 2 10,000 20,000 .Data collection software x 1 6,500 6,500 Data processing software x 1 10,000 10,000 Computer x 2 8,900 17,800 Travel, trips, study costs 66,700 Subtotal 187,000 Contirngencies (11.5%) 21,505 Estimated Cost 208,505 12. Study costs comprise: - 2 weeks on site to assess feasibility (2 specialists); - 2 weeks abroad for project study and preparation (2 specialists); - 4 wees on site to install and adjust the equipment and to train local staff (2 speciaists). If any of STEG's existing hardwara is compatible with the project, a reassessment will be needed. -102- A1U§L" Page 4 of 8 Summary of the Software Flow Cht Neasured powr DfrneLosu I doe to reduced load level Condenser lnlet teperature characteristic curves _Loss 2 due to ext. temp. + theoretical vacu Reactive power Characteristic curves Loss 3 due to alternator performance Type of fuel used Characteristic curve/unit Loss 4 due to type of fuel used Loss due to other causes Loss 5 due to other causes Sum of losses I to 5 a EXTERMAL DEVIATIONS Deviation from Measured vacuum theoretical vacuum and loss Loss 6 due to condenser curve NW f(vacuum loss) Devilation from theoreticat Feedwater outlet temperature t nperature obtaied l Loss 7 due to feedwater system characteristic curve f (feedwater flow loss) Pressure and temperature 2 curves Loss 8 due to steam characteristics NP outlet pressure Deviation from P intake MP Loss 9 due to resuperheater load loss P Calculation of the real and isentropic enthalpies, then Loss 10 due to MP housing at UP inlet and outlet I comparison with a perfor- I mance curve f(P) l -02 at economiser outlet Comparison with theoretical 02 given by an 02 curve Loss 11 due to fuel coui,ustion regulation l f ' fuel used) r Copearison of flows of de- Loss 12 due to excessive flow of superheated fILowa of desuperheated steam superheated steam with steam curves f(P)ll rDeviation from amblent air| |Tenperature at RA outlet h temperature and use of a Loss 13 due to performance - - | ~~~GV performance curve dulopronm 02 In chimney stack Deviation from econamiser Indicates entry of air into reheaters 02 measurement Sum of losses 1 to 6 = SUI OF EXPLAINED INTERNAL DEVIATIONS Reference power output - sum of tosses I to 13 a SUM OF UNEXPLAINED DEVIATIONS -103- Annex Page 5 of 8 TERMS OF REFERENCE Supplyof an On-Line SBy for Monitoring the Operating Efficiency of Fuel-Burninm lbermal Power Plas 21 Main Ob3ecive 13. STEG is inviting bids from consultants (corporations or public agencies) to design, supply and Implement a system for the on-line monitoring of the operating efficiency of fuel-burning thermal power plants. 14. This system will be adapted to match the hardware already available in each of the units and the efficiency monitoring software being tested by STEG. The objective of this system is to reduce losses in unit performance by continuous control room monitoring of the main parameters, to enable operators to take corrective action in real time. This system also makes it possible to monitor the condition of the main components and to undertake maintenance actions as part of a conditional maintenance strategy. 15. Ibis program consists of providing and installing a complete on-line operating efficiency monitoring system for 150 MW units (in Sousse) and 30 MW units (in Gabes), taking existing equipment into consideration. 16. In particular, the project consists of the following components: - a feasibility study to be conducted on-site; - an additional study to be conducted outside of Tunisia; - on-site installation of the system, which comprises: . the computer; • the software; . data collection panels; . additional sensors and lines (if necessary) 21 In airstphs, dtes tnns of reference ptyp only to kWe Soe and Gab&splanu. -104- A Page 6 Of 8 - commisiornig of the equipment in the prence of STEG officis. 'he prject is estmat to require: -6 man-week at the sites for the feaibflity study; - 6 man-weelm outside Tunisia for project study and preparation; - 16 man-weeks to nsa and adapt the equipment and to train local staff. The total cost is estimated at P 2.07 million. The project is finaced by .... 17. STEG is a commercial and industial stautory government entity established by Nationalzaton Decree-Law No. 62-8 of April 3, 1962. This document makes STEG responsible for the gnaton, tra ion, distribution, import and export of electric power and fuel gas under the supervision of the Miisty of the National Economy. STEG has four steam power plants: - Goulette U, with four 30-MW units consuming fuel oil; - Ghannouch, with two 30-MW units consuming fuel oil or gas; - Sousse, witi two 150-MW units consuming fuel oil or gas; - Rades, with two 160-MW ailts consuming fuel oil or gas. STEG also has 19 gas turbines with capacities ranging from 15 MW to 30 MW. 18. This prject, consistng of the installation of a system for the on-line monioring of operating efficiency, results from a recommendadon by the UNDP/World Bank mission fo improving the perform of STEG's power generation system. 19. The project includes all necessary resources for achieving the main objecdves defed above. It wil be Implemented in the Sousse and Gabbs power plants. -105 -M Page 7 of 8 20. The sensing devices that are already installed and operating properly will be used to the extent possible. A data collection panel and appropriate software should be installed so that measurement signals can be made compatible with computer data input. 21. About 24 major measurements - such as active power, steam characteristics, boiler characteriics, etc. - will be used in the application. Curves and nomograms for calculaing deviations will be established on the basis of commissioning tests. Convendonal hermodynamics equations will be used to calculate heat, consumption, losses, etc. The computer, to be itlled in the control room, should continuously indicate losses and their causes, in units of heat and in cost tem. 22. The contracting party wil be entirely responsible for project execution, and will provide all the services and equipment necessary for its proper implementation. 23. The bid should take the form of a turnkey project, to include computers, software, software interf , and Installation. However, STEG will be responsible for importg the equipment and for proviing experienced technical and data processing specialists to monitor installation and assist wih wring. STEG will be responsible for the following: . access to the power plans and to the necessary data; * consultant travel within Tunisia; . providing instrument specialists and electrical equipment, as needed; assistance in obtaining all administrative documents necessary to enable the contractor's personnel to enter Tunisia or to facilitate imports of equipment. Qon Of tilel3id 24. The bid should include the following main elements: - a work plan in line with the terms of reference; - estimates of the time required, by specialty and by location; - a description of the bidder and of its experience in similar projects; Page 8 of 8 - the personnel to be assigped to the project, with complete rdsumds and accounts of preious experience. 25. Bids must state the total prlce, and be sealed. Nevertless, bidders may suggest alterate methods of achieving the objectives stated In the tems of reference. Any alternative method must be clearly defined and should be submitted as a separate bid with iemized costs. 26. The payment schedule will be subject to negotiation. The bidder must propose a schedule that takes into account the performance objectives. 27. - 3 weeks on site t assess feasibility (2 specialists); - 3 weels abroad for project study and preparation (2 specialists); - 8 weeks on site to install and adjust the equipment and to train local staff (2 specialists). -107 - Anum 7 Page I of 2 UNAVAILABILITY RATES AND AVAILABILITY STATITCS FOR CONVENONAL THERMAL POWER UNITS IQ/ 1. The UNIPEDE/CME Mixed Committee described in the document "Availability and Unavailability Rates in Thermal Power Plants - Definitions and Methods of Calculation,* published i 1977, the typical unit sizes recommended for use in thermal power plants. The unavailability rate over a specified period is defined as the ratio of the energy that a capacity equal to the unavailable capacity could have produced during this period to the energy that the maximum capacity could have produced during the same period. The unavailable capacity is the difference between the maximum capity possible (with all equipment supposed to be running properly) and the available capacity (maximum capacity at which the station can be operated under actual equipment conditions). 2. The overall unavailability rate is designated as G and is divided into unavailability rate due to planned maintenance, G1, and unavailability rate for all other reasons, G2 (G1 + 02 6). The availability rate (ratio of the energy that the available capacity could have produced over a given period to the energy that the maximum capacity could have produced) is the difference between 1 and the overall unavailability rate G. 3. The conventional thermal units have been divided according to their unit capacity and their geographical location. Annual unavailabilitv rates for the years 1981 through 1985 4. The unavailability rates shown in the following table (Table A7.1) distinguish between unavailability due to maintenance work and unavailability for all other reasons (unplanned unavailability). The sum of the two rates represents the overall unavailability rate. 5. The results show that, for a given capacity range per set, unavailability rates are similar in Europe and in the United States. The unavailability rates for other countries are notably different dtm those calculated for Europe and the United States. The difference is significant in the 100-199 MW unit capacity category, where the overall unavailability rate for the other countries is on average some 6% higher than in Europe and the United States. Overall unavailability rates for a unit capacity of 100-199 MW are calculated as: 19% in Europe and the US; 25% in other countries. lQ, Sowrce: UNIPEDElWorld EniuV Coference. 108- An . Page 2 of 2 rabls A7.1: CONVENTIONAL 100-199 NW THE2"AL UNITS ANNUAL UNAVAILABILITY RATES IN X Year Europe United States Other countries A TA A T 1981 49,260 399 53,91? 380 11,482 77 1982 48,400 393 57 aM 412 11.785 80 1963 47,792 386 57,343 407 13,008 90 1984 47,435 380 56,678 401 13,158 91 1985 29,764 237 8,497 55 G1 G2 0 GI 02 a G1 02 a 1981 11.4 8.8 20.2 10.7 8.2 18.9 11.9 10.6 22.5 1982 11.6 8.0 19.6 11.9 7.2 19.1 13.0 10.6 23.6 1983 10.7 7.8 18.5 11.7 6.9 18.6 17.1 10.6 27.7 1984 9.6 7.3 16.9 11.6 5.9 17.5 13.5 10.8 24.3 1985 10.4 7.5 17.9 12.7 12.3 25.0 Average 10.8 7.9 18.7 11.5 7.0 18.5 13.8 10.9 24.7 Number of sets on January 1 a T. Average maximum capacity of the units on January 1 a A (in NW). Unavalabi ilty rate: G1 = annual maintenance program; 02 a all other causes; a a the sum of the two. -109- Ane Page 1 of 3 SrANDARD MAUNTENANCE CONCEPIS Maintenance Those activities necessary for enabling a machine to be maintained in - or restored to - a specific condition, or to fulfill a certain purpose. Maintenance performed after the appearance of a malfunction. Maintenance It includes: - Detection The identification of a malfunction or a malfunctioning component as a result of close inspection, whether continuous or periodic. - Location The identification of the specific components causing the malfunction. - Diagnosis The identification of the probable cause of the malfunction, using logical deduction based on a set of data. Diagnosis makes it possible to confim, add to or modify hypotheses regarding the origins and causes of malfunctions, and to specify what corrective maintenance operations are necessary. - Emergency Action taken on out-of-service equipment to get it back into working service order, at least temporarily. Considering this objective, the results obtained can be temporary and the normal regulations governing procedures, costs and quality can be disregarded. In such a case, repair will follow. - Repair Thorough and specifically targeted corrective maintenance in response to a malfunction. Maintenance performed according to predetermined criteria to reduce the Maintenance likelihood of equipment malfunction, with its consequent impact on the services provided. There are two types of preventive maintenance: RtOWIe Maintenance performed according to a schedule based on time intervals or on actual equipment use. Mainteanc Cnditional Maintenance contingent upon certain predetermined events (self-diagnosis, sensor data, measirements of wear, etc.), indicating the degree of deterioration of the W=anc equipment. - 110- Anna Page 2 of 3 Preventive maintnan comprises the following operations: - lspecdon Examinations performed as part of a specific function. It is not necessaily limited to a compsrison with pre-established data, and the characteristic method used is that of inspection "rounds." - Monitoring Ascertaining that equipment complies with pre-established data, at which point a judgment is made as to its condition. Monitoring can: . include data collection; . include a decision (acceptance, rejection or postponement of maintenance); . lead to initiation of corrective actions. - Maintenance A detailed and predefined examination of all or part of the various components Examination of the equipment (depending on whether the examination is general or specific). It may include first-level maintenance operations. Some corrective maintenance operations may be performed if anomalies are observed during the maintenance examination. - Test An operation enabling a system's responses to an appropriate and predetermined stmulus to be compared to those of a reference system or with a physical phenomenon that indicates it is operating correctly. In addition to the actions defined above, maintenance also includes certain typical operations that are not systematically included in any one type of maintenance. They are: - Overhauls Eaminaons, monitoring and action for protecting equipment from any major or critical malfunction for a given time or for a given effective period of use. Depending on the scope of the operation, it is usual to distinguish between partial and general overhaus. In both cases, this operation involves removing various subunits. This distinguishes overhauls from maintenance examinations. An overhaul can be either a preventive or a corrective maintnce operation, depending on whether it is performed in response to a maintenaue schedule, a measur ent of wear, or a malfimction. - Modifications Operatio of a definitive nature performed on equipment to improve its operation or to change its characteristics. - 111 - &M a Pag 3 of 3 - Standard Replacement of a component, assembly or subunit with an Exchange Identical new or reconditioned item, in accordance with the manucr specifications. Finally, there are two standard maintenance operations concepts - renovation and rebuilding - at are closely related to manufacturing and are often performned by manufacturers. Consequently, they ar beyond the scope of the maintenance carried out within power plants. AnnmL2 -112- Page 1 of 4 LOAD FLW CALCULATIONS - Y OF R Table A9.1: IODES: ACTIVE AND REACTIVE POWER Plant Rated kV F Q 2 -P 3F P 14 a Radeos 150 0 0 0 0 0 0 0 0 Rados 225 0 0 0 0 0 0 0 0 Tunis South 90 60 19 62 52 43 23 64 21 Tunis North 90 25 13 41 24 25 1 27 14 Tunis West 90 47 12 41 34 21 16 50 13 Mnita 90 0 0 0 0 0 0 0 0 Mn la 225 0 0 0 0 0 0 0 0 M. Jemit 90 16 9 13 10 8 5 17 10 Hamnamet 90 0 0 0 0 0 0 0 0 HaNmet 1SO 23 14 24 12 17 4 25 15 Enfidha 150 20 11 17 12 7 5 21 12 Ta eroulne 90 39 19 26 23 15 2 42 21 Ta erouine 150 0 0 0 0 0 0 0 0 Ta rculne 225 0 0 0 0 0 0 0 0 Aroussia 90 0 0 0 0 0 0 0 0 M. sourguTba 90 40 13 22 14 32 13 42 14 Oued Zargua 90 10 5 8 5 6 2 11 6 Fernana 90 0 0 0 0 0 0 0 0 iendouba 90 15 6 12 7 8 4 16 7 Nebeur 90 0 0 0 0 0 0 0 0 14saken 150 40 11 31 26 18 11 42 12 Akouda 150 25 14 26 13 15 2 27 15 Mason 90 0 0 0 0 0 0 0 0 Nasen 90 0 0 0 0 0 0 0 0 Nasen 225 0 0 0 0 0 0 0 0 Oueslatia 225 12 6 7 2 5 2 13 7 M. Mchergua 225 16 7 24 15 10 0 17 8 Sousse 150 15 6 12 6 12 3 16 7 Sousse 225 0 0 0 0 0 0 0 0 Grmbtalia 90 12 7 22 16 14 8 13 8 Korba 90 23 12 11 13 7 2 25 13 Tunis Center 90 10 5 10 8 2 8 11 6 Tunis Center 90 t1 6 10 8 5 5 )2 7 La Goulette 90 30 17 19 12 11 4 32 18 Zahrouni 90 21 11 16 12 15 9 22 12 Mdhl a 150 13 8 9 2 3 2 14 9 Mettocuf 150 41 17 30 19 21 8 43 18 Kasserine Nord 150 0 0 0 0 0 0 0 0 Kasserine 150 19 9 11 7 14 5 20 10 Naknassy 150 8 3 6 3 7 4 9 4 Foriana 150 3 1 3 1 3 1 4 2 Sfax 150 49 22 '6 31 21 10 52 24 souchema 150 S 0 0 0 0 0 0 Bouch_a 225 0 0 0 0 0 0 0 0 Robbana 150 25 11 14 3 10 2 27 12 Zarzis 1S0 I5 7 6 1 5 2 16 8 Ghannouch 150 43 21 34 45 20 27 46 23 S. Monsour 150 17 7 13 2 7 2 17 8 S. Mansour 225 0 0 0 0 0 0 0 0 S. Salei 90 0 0 0 0 0 0 0 0 KItairouan 225 7 2 8 4 6 1 8 3 Noknfne 150 13 5 22 12 10 3 14 6 Mateuw 90 7 3 0 0 0 0 8 4 Taborka 90 6 2 0 0 0 0 7 3 Gomwart 90 5 1 0 0 0 0 6 2 ALGERIAN BORDER NODES Elkala 90 Aou1net 90 Aouinet 22S DJebl 0k* 150 S urce: STEC, DEX, OPIME, various studies. (1) Evening peak (Decalber 1989) Total load: 780 NM 342 NVAR (tg phf a 0.438) (2) Morning peak CSeptenier 6, 1989) Total toad: 646 NM 4S4 NVAR (tg phi a 0.703) (3) Valley CSepteuier 1969) Totat load: 420 NW 196 MNAR (tg phi f 0.467) (4) Future netuork Decerber 1990) Total toad: 836 NM 382 MVAR £uiinnt: Data includ, the capcItors and the reactors. TL* A.2: GEMATINB SET DATA Year Cons. cans. brought of Aux. of Aux. cose w1 Case M2 s (32 Turbine Alternator into Turbine nianl Equip. Equip. P. win Cmnwection P P P Plant Nanufacturer wanufacturer service ips cos phi (HU) (MM) (M) nods Rados al1 MITStISHI MITSURISII 1965 0.8 8 20 40 Rados 145 0 0 odts. 1R2 MITSUBISNI NITStBISII 1985 0.8 8 20 40 Rados 140 140 130 Saiuss SR11 KW no 1980 0.8 7 15 40 Souse 120 120 90 Soisse 612 KM 1 KU 1980 0.8 7 15 40 Sousse 120 120 90 Goulette SR1 CEN C 1965 0.8 2 3 7 Goulette 20 23 15 Goulette GR2 CEN CEN 1965 0.8 2 3 7 Goulette 20 23 15 Goulette CR3 AEG AEG 1968 0.8 2 3 7 Goulette 0 20 15 Goulette GR4 AEG AEG 1968 0.8 2 3 7 Goulette 0 0 0 K. Ilorth t1G FIAT ALSTHTM 1984 0.8 1 1 10 K. Nord 30 30 0 K.L orth 102 FIAT FIAT 198U 0.8 I 1 10 K. %rd 0 0 0 Korbe TGI ALSITHON ALSiHITI 1978 0.8 0.8 0.6 5 Korbe 0 0 0 KOrb0 T42 FIAT ALSJTIM 1984 0.8 1 1 10 Korba 0 0 0 Rd*dne TGI FIAT ALSUHI 1984 0.8 1 1 5 Robbn 0 0 0 Ghamrauch TOI ALSHTHC ALSNTHM4 1971 0.8 0.8 0.6 Ghanrmich 0 0 0 Ghanmouch TG2 ALSUTHTI ALSITUOM 1973 0.8 0.8 0.6 6 Ghannouch 0 0 0 banwmuch 1T3 ALSWTIII ALSIUM 1973 0.8 0.8 0.6 6 Ghann_ch 17 16 15 ShaGiouch 764 FlAT ALSNTHC" 1973 0.8 1 1 10 Ghanmoch 30 30 20 Ohaiouch TVI CEm CEN 1972 0.9 2 3 11 6hard 28 28 20 Ghawuch TYZ CEl CEm 1972 0.9 2 3 11 Ghanouch 27 27 20 T. South T61 ALSHTMCN ALSTMlt 1975 0.8 0.8 0.6 5 T. Sud 20 0 0 T. South T02 ALSHTNM ALSHTI1M 1975 0.8 0.8 0.6 5 r.Sud 0 0 0 T. South TG3 ALS0THNN ALSHTHWS 1978 0.8 0.8 0.6 5 T. Sutd 20 20 0 Bouchnm_ T6I FIAT FIAT 1977 0.8 1 1 10 Bouch_iwi 25 25 0 Bouchwmm T02 FIAT FIAT 1977 0.8 1 1 10 Soum 0 0 0 N. 3ourguibe TG1 ALSHTUCR ALSHTUGI 1978 0.8 0.8 0.6 5 N. Bourguibe 0 0 0 N. ourguiba TGZ ALSHTH0N ALSNTH 1978 0.8 0.8 0.6 5 M. Buraiba 0 0 0 Sfax TGI ALSHTHUI ALSITrEDI 1977 0.8 0.8 0.6 5 Sfax 0 0 0 Sfax T02 ALSHTH ALSRTHN 1977 0.8 0.8 0.6 5 Sfax 0 0 0 Nleoul TG ALSHTIIUI ALSKTUO 1978 0.8 0.8 0.6 S Metlsou 0 0 0 Fernae CH 1958 0.8 0.5 0.2 0 FeMnna 5 5 a S. Salem Go 1982 0.9 2 3 0 S. Satem 25 25 0 Nebsur GHI 1956 0.8 0.2 0.2 0 Mor 4 4 0 Nbeur GN2 1956 0.8 0.2 0.2 0 ebobr 4 4 0 Sou STEGM, DiD, DPIE, varisos studies. (1) Evening pek (Dece - r 1989) Total petien: 800 1M (2) fInfnt peek (Septeober 1989) Total prodfetaon: 660 NW (3) Eveninr troush (Septeoar 1989) Total production: 430 VW I4I -114-- Page 3 of 4 Da on the Existina ReactorCsi8 nsaled Reactors in ngh eation Total genati in service - on the Oueslatia-Bouchema feeder : 20 Mvar - on the Robann hannouch feeder : 6 Mvar (not equipped with a breaker) Night: - 58 Mvar (reactors only) - on the Maknassy-Ghannouch feeder : 6 Mvar - on the Tajerouine-Oueslatia feeder : 20 Mvar - on the Mdhila-Maknassy feeder : 6 Mvar Caacitors Insalled (on the 30 kV MV busbars) in ervice durina the day * to Menzel Bourguiba : 9.6 Mvar - to Tunis Ouest : 8.4 Mvar - to Tunis Sud : 8.4 Mvar Day: + 40Mvar(capacitorsandreactor- to M'saken : 9.6 Mvar Ghannouch) - to Medaoui : 9.6 Mvar A Imi e VoljW I&.* lable A9.3: UMN0 A 10X Vottage (kV) N n. uax. 90 81 99 150 135 165 225 202 247 115 - 1Aim2 Page 4 et 4 Table A9.64 GEIIEtATING UNITS EXPECTED TO BE IN OPERATION IN 1993 IN ADDITION TO THOSE IN SERVICE IN 1989 Sets Norning peak Evening peak Evening trauoh Netlaoul IGT X X Sfax 2GT X X W. ourwulbe 20T x X Robbae lGT X X Klob 2GT X X La Goulette 2ST I get 2 Sets Souchem IGT X Kessarine North 1OT X Tunis South 2GT X ou8se 2ST X Mgo: OT a gas turbine; ST * steam turbine. tIM.-AIlM: LOSSES IN STEG'S IV IETWMK OgLY (excludiIg losses on tbo intterC0eCti on with Algeria) Evening peak Without Wi th existing Wf th Without cwftr ?m o calpnsatian capreacitors adci torsL cameration wi thout Wi th Uithout With Cotilpensetion O 40 130 O0 211 O 211 Vottage: 2351cV 1.26 1.23 1.19 1.9 1.8 0.8 0.7 225 kV 1.28 1.26 1.23 1.8 2.0 1.9 0.8 0.8 0 210 kV 1.30 1.11.26 2.3 1 2.1 0.9 0.90 Tan phi 0.489 0.438 0.278 0.489 0.489 0.278 0.438 0.278 A Dand 780 MW = 1000 NW _ Z Generating Stem turbines 620 NW equip 64#~~~~G turbines 140 M1 218S CAP 80" CT in service hypotheses Hydropower 40 MW Contribution P = 224 NW P a 200 MW from Atgeria I_ Exports to 10 W 0 NW 5 NW 12 I3 Algeria _s____ _ table A10.2: LOSSES IN X 11 STIE1S NV IETM GMLT (EXCludirg tossE on the intercomwtion with Alteria) brning pk 1969 1993 c_pacitors Capa_.t_ with existing With Without capacitors emitfonat Without lithout with Without With .______ _ cc sation and reactors camcitors consation Ca_pensation 0 40 130 0 0 211 0 211 ( KYAR) _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ Voltage: 235 kV 1.13 1.05 0.94 1.4 1.2 0.8 0.7 225 kV 1.15 1.05 0.96 2.2 1.5 1.2 0.8 0.8 210 IkV 1.21 1.11 1.02 1.6 1.4 0.8 0.8 Tan phi 0.764 0.703 0.501 0.7 64 0.703 0.764 0.703 Dem _d -_, 646 KW 829 mV Generating Gas turbines : 500 mm equipment .as turbines : 120 mm CAP BON CT in service hypothesis Hyropower : 40 M P = 224 15U P 200NU Exports to 7N 0NM 40OW 22 1W ALgeria - - IL> Table -10.3: LOSSS IN X ON1 $lU'S N TIEK OLT tEnd:fir tilosmes an the intercometion with Algeri) Night troa* 19" ~~~~~~~~1993 Without With existing Uithout Without Wfithout coat! §on r reactors ractors reactors Coepenation 0 0 0 0 (WAR) . ._... Vottage: 235 kV 0.95 0.90 1.0 0.9 225 kV 0.98 0.90 1.0 1.1 1.0 210 kcy 1.24 1.09 1.3 1.1 Tan vhi 0.328 0.467 0.328 0.328 0.328 Thermal _utout 420 HU 542 NW __ Generating Gas turbines : 395 NW 117 W o equipment Gas turbines : 35 Wi Contribu- CAP SwO ST in sermice hypotheses ydropoer : 0 NW tion from p tt2 NW p = 125 NW Alteria _ Exports to 6 HU 3N8 O NM Rports of 7 NW Algeirfe A l ri o _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ ~ ~ ~ ~ ~ ~ ~ ILt I'~~~~~~~~~~~~C .0 0 t a |~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~~a li; ! L 5'a- r -i a. a. § X 5 3 - 120 - Am 1I Page 2 of 4 TIlte All2: CONPENSATION REQUIRED BY SUBSTATION TO BRING TAN PHI BACK TO 0.5 September 89 orning peak consu_tfa n Existing Capacitors capacitors requ red to reduce SubstatIons Nu NVAR QI NVAR tan phi to 0.5 Tunis South 62 52 8.4 21 Tunis West 41 34 8.4 14 N. Jemil 13 10 3 TaJeroulne 26 23 10 N. sourguiba 22 14 9.6 3 N. %aken 31 26 9.6 11 Grombealia 22 16 5 Korba 11 13 7 Tunis Center 1 10 8 3 Tunis Center 2 10 8 3 Zahronil 16 12 4 Netleoul 30 19 9.6 4 Kasserrne 11 7 9.6 4 Sfax 36 11 13 Ghannouch i 34 45 28 Total 45.6 130 In service from 7 a.m. to 11 p.m. TheTsm values take into account the existing capacitors and reactors. ki Currently, one 6 NYAR reactor on the oharnouch-Robbana feeder Is in service 24 hours a day, as it does not have a breaker. Table A11.3: NEASURING THE EFFECT OF THE PROPOSED ADDITIONAL CONPENSATION . Evening Deak | Norno oeDk Night trough Additfo- Additio- No Capacitor nl No Caoac. + nal With capacitor + capaeftor capa- existing capac- 0 reactor existing existing (0 citor reactors tor reastors reactors reactor) (0 _49 048 7" 0- rea ctrtor) Tan phi 0.489 0.438 0.278 0.764 0.703 0.501 0.328 O.U67 -121 - AnnexL11 Page 3 of 4 THE NETWORK IN 1989 I 4 r~~~~~~~~~~-3v I I7 t S.t u f w It %M 0~~t 60% Lo uo xsig caaios I.~~eatr Iufnl in seKice _ G t g \s 62oFGURE 4 ) -122 - Awnx i1t Page 4 of 4 THE NETWORK BY 1993 FG S t %AAF '8 t,aJ_~~~~~~~~~~~~~~~~~~~~sl Tn l s _ _ _ F 1^u>: / 1 lAt~~~~~~~~~~~~~~*:4 ""f "e ~IqU 5- - 123 - A 12 Page 1 of 4 ECONOMIC ANALYSIS OF COMPENSATION 1. This economic study is a fairly summary calculation of the gains that could result from comp~nsatlng for reactive energy. There is a twofold benefit, technical and economic, in compesating for part of the reactive energy absorbed by the loads. (a) The technical beneft has already been mentioned: introducing compensation incresues the network's operating margins, making operations easier and more reliable by reducing the scope for voltage instability. (b) Compensation also offers a significant economic benefit by reducing losses on the network as a whole. 2. The purpose of this annex is to calculate the economic gains. The simulations made Involved calclatng the number of capacitors to be insiled to improve the load factor, as "seen" from the VHV transmission network substations. The relevant numbers of capacitors must then be allocated among these substations and those on the lower voltage networks that they supply (HV and MV). In particular, they should be installed in MV substations as close as possible to the demand so as to secure the malmum reduction in losses on these MV networks. I calculafio 3. At peak hours, active losses on the network, in relation to the power supplied, are regularly reported to be around: - 2.5% on VHV and HV networks - 2% in HV/MV ransformers - 5% on the MV network - 3% in MVALV transformers - 6% on the LV network 4. On the MV and HV networks, where the capacitors will prefrably be installed, peak hour lossa are generally 3 to 4 times greater than on the VHV network. . 124 - Annex12 Page 2 of 4 S. We have shown that the installation of capacitors "seen" from the VHV transmission network would reduce active losses on this network (Annex 9). The same is true for MV and LV network losses when capacitors are connected on these networks. It should, however, be noted that, given the small size of the capacitor banks to be installed on the MV network and other ;onstra involved, in pardcular the space available in the substations, Installing capacitors on the MV network will not necesarily be optimal. The capacitor banks will be grouped and installed in the substaions to the extent possible, producing a useful but not necessarily optimal reduction in MV losses. 6. Consequently, If the active losses on the MV and HV networks are 3 to 4 times higher than on the tranmission network, the reduction in these losses through the use of "non-optimal" mas of compensation will not be as large. We will arbitrarily reduce the ratio in question to 2 In order also to take account of the fact that only 86%, rather than 100%, of the power supplied to consumers passes through the MV network, and that there are losses in the transmission of reactive energy between the various voltage levels (VHIV-HV-MV). 7. To quantify the reduction in losses resulting from compensation we will use the cost hypotheses fom Annex 2. ANNUAL COST Of I kW OF PEAK LO LOSSES (Hours of Use: S,900) L:L NV IV/NV NV NV/LV LV C ost in TDOW 216.9 |236.5 |306.8 350.9 4U1.4 8. The aim is to examine the benefit to be gained from installing compensation resources on the transmission network and the MV networks. This requires a base compensation cost, i.e., banks of capacitors and reactors, of TD 10,000/Mvar, entailing annual investment costs of TD 1,000/Mvar. Operation of the Ghanmouch ractr 9. All the reactors are disconnected 16 hours a day. The Ghaninouch reactor (6 Mvar), which is pemanently connected to the network, is therefore in service for 16 hours too many each day, or during the 5,840 heaviest loaded hours of the year. The additional losses that this entails for the network (in addition to the internal losses due to its resistance) can be calculated as follows: - 125 - Annex12 Page 3 of 4 10. The simulations showed that 170 Mvar of compensation produced a gain of 1,2 MW (morning peak) and 0.4 MW (evening peak), or 0.8 MW on average. The annual gain can therefore be obtned from: 6 Mvar x 0.8 MW x TID 216,900/MW = TD 6,120 170 Mvar The cost of a breaker being estimated at 0.25 x TID 10, it does not seem ecWnomically justified to attach a breake to the reactor. InsaWlation of gcapaitrs on the tranmissionetsgod5 11. Using the same procedure as above produces a gain per Mvar of: ) 216.90l/MW x 0.8 MW a TD 1 x 103/Mvar 170 Mvar or exactly the annual cost of installing compensation. Consequently, at the level of precision of our calcuations, It is, economically speaking, immaterial whether or not capacitors are installed on the HV network. Only the advantages of increased network reliability in relation to a voltage collapse would justify installing capacitors at this voltage level. Intllaion of capac idosa the MV leVel 12. The preceding arguments only apply, of course, to the capacitors that would be installed in the VHV/HV or VHV/MV substations, in other words to the capacitors "seen" directly from VH.V The number of capacitors required to make tan ph equal to 0.5 (170 Mvar in 1989 and 218 Mvar in 1993) must clearly be allocaed over the entire network (VHV, HV, MV). From a technical and economic point of view it is more beneficial to install them close to the demand. 13. Installation of capacitors on MV would reduce losses not only on the VHV and HV networks, but also on the MV networks, and in much greater proportions. This ratio was put at 2 (see para. 6 of this annex), which leads to a gain per Mvar of: 0.8 MW x 2 x 306.800 TDIMW = 2.9 X 10' TD/Mvar 170 Mvar a figure that suggests an internal rate of return for the investment of about 30%. -126 - Annex1Z Page 4 of 4 Conclusion of tdh econo study on the Is__tinof comesan 14. This brief study has shown that It would be economically justifiable, in order to reduce network losses, to install capacitors. These should be placed as close to the load as possible, In other words, preferably on the MV network. 15. Tbis study is only a first approximation of the expected orders of mgnitude of the benefits. It used a minimum nunber of network operating hypotheses and assumed that the gains achieved were a linear function of the numbers of capacitors installed. These gains could thus only be calculated by using two extreme hypotheses: no compensation, and compensation producing a tan phi of loads equal to 0.5. In practice, the gains are a parabolic function of the compensation. To obtain a more accurate idea of their magnitude, one would need to undertake a more precise analysis, incorporating a larger number of hypotheses to permit better modeling of the load curve, and to calculate actual network losses for each load level considered, rather than accepting a global evaluation that assumes that these losses are merely proportional to the square of the energy consumed. It is also necessary to calculate these losses for more realistic installations of capacitors, taking local conditions into account (space in the substations, minimal size of each capacitor), and evaluate more precisely, either using statistical surveys or by making calculations for "representative' networks, the losses on the MV and RV networks and the Impact on these of a "realistic" installation of capacitors in the MV and HV substations. 16. This would reveal that the marginal gain (gain per Mvar Installed) declines as a funcdon of the overall amount of compensaion. Knowledge of these "marginal gains" would enable optimum use to be made of the funds tha may be allocated for reactive energy compensation. - 127 -Am13 Page 1 of 1S SELECON OF NETWORK SAPLE Peseton of Disribution Qeneral descripion of the network 1. The STEG distribution network operates at four voltage levels: 30 kV, 15 kV and 10 kV in the medium voltage range (MV); 400 V1230 V in the low voltage range (V). 2. The Distribution Direcoorate receives energy from the transmission network hroug 41 master stations with primary voltages of 225 kV, 150 kV and 90 kV. 3. The MV network has a radial structure and consists of: 13,000 km of three-phase overhead lines, and 4,000 km of single-phae spurs at 17.3 kV. The neutral of the three-phase overhead network is distributed and grounded; it is therefore a 'four-wireu system. 1,000 km of mostly underground 10-kV network supplying cities in the north like Tunis and Bizerte. - 354 km of 15-kV lk>.s supplying large towns in the south: Gab0s, Gafa. 4. The tot length of the MV network is 18,400 km, 1500 km of which is undergund. This MV network supplies power to 30,600 km of LV lines (97% of which are overhead) through 17,000 MV/LV transforming substations, 6,700 of which are customer substations. Following a major campaign to change voltage levels, 98% of these MV/LV substations supply a secondary voltage of 400 V. Of the MV/LV substations providing a 230 V secondary voltage, 70% are conceatd in the Tunis region, particularly in the Tunis City distict. 5. The following tables give a breakdown by district of the MV and LV networks and the MVALV substations. I - 128 - Page 2 of 1S TabIe A13.1: 1V/LV DISTRtWPTION NETWORK (1988) futro substat1on Network beIgMth ib ) Districts T Prvate u vott Totat ~~~~~~~Low LI L2 B1 B Tono- Tr- Total vottage I~~ _ I phase_ _pes __ Tunis Cfty 168 259 37 497 961 454 454 753 Arinam 383 . 245 628 458 458 1020 Exahra 9 346 . 619 974 12 493 505 896 La Kram 158 5 93 256 189 189 535 Le Bardo 319 24 565 3 381 38 1800 Zaghioum - 1377 138 275 6 346 352 295 Stierte 10 357 14 391 m 27 779 806 1659 Nabut e 849 l 629 1478 140 1088 1228 2715 Baja 266 228 494 109 SS0 659 664 Jendouba , 525 . 233 758 244 559 803 1163 Le Ket 501 S 133 634 339 631 970 1131 silana 339 123 462 237 445 682 694 sousee 26 490 13 467 996 156 643 799 1698 Notwstir . 200 . 256 456 19 315 334 664 N1oknlne . 205 . 148 353 56 171 227 800 Nabdifa 379 . 122 501 162 490 652 849 Koroua 435 1 242 678 205 810 101S 1261 Kauserine 305 . 139 444 254 515 769 729 Sidi ouS id 464 . 149 613 4S7 479 936 904 Gaefs . 413 180 593 129 909 1038 990 Tozeur 104 . 170 274 35 375 410 35S Sfax 43 1094 21 560 1718 604 1000 1604 4016 GstAs - 451 216 667 314 666 980 979 Kbitl . 143 , 102 245 52 325 377 860 Zaruis . 684 196 880 236 774 1010 2495 Tataoulne , 247 , 29 276 145 360 505 616 Total 256 10053 91 6551 16951 3941 14205 18146 30561 129 - AmJ 13 Page 3 of 1S tabte, A1.3: TECHNICAL DISTRIDUTION RATIOS Data for 1968 Share of total Cd Reions Networks (km) No. of No. of Networks Substations Customers NV LV STEC Custo NV BW NV BV STEC Custo _ LV mers mere Tunis 1990 5004 1642 1742 2043 334980 11 17 16 26 30 28 North 2386 4669 1353 1l1n 1240 169960 13 15 13 18 18 14 Northwest 3114 3672 1631 717 651 121220 17 12 16 1l 9 10 conter 3027 5272 1M 1249 1264 211020 17 17 17 19 18 18 southwest 3153 2975 1286 638 582 101530 17 10 12 9 9 a South 86 8966 2662 1124 1098 261610 25 29 26 17 16 22 Totat 18146 30561 10309 6642 6878 1200313 100 100 100 100 100 100 Tunisia -- --- - -Ratio No. of km of NV No. of km of LV No. of meters of No. of LV customers per substation per STEC LV per LV per STEI substation (STEI + substation customer ___ _ r customers) _ _ Tunis 0.589 3.045 15 204 North 0.945 3.450 27 126 Northwest 1.326 2.250 30 76 Center 1.016 3.039 25 121 Southwest 1.639 2.315 29 79 South 1.607 3.368 34 98 Total Tunisia 1.070 2.965 25116 -130- Page 4 of 15 Power ionldD azm 6. The following table gives the 1989 regional breakdown of power supplied for distribution and billed by this Directorate. Tlbte A13.h: BREAKDOWN BY REGION Regfon Enerry supplied X Energy billed X .____ CGWh) (GAh) Tunis 1240.63 28.25 1125.40 28.22 North 852.64 19.42 776.90 19.48 Northwest 333.90 7.60 320.60 8.04 Center 832.32 18.96 740.70 18.58 South 730.03 16.63 635.40 15.94 Southwest 401.24 9.14 388.40 9.74 Tota l 4390.76 100.00 3987.40 100.00 7. TIbs breakdown shows an area of high consumption comprising the neighboring regions of Tunis and the north, which account for 47.70% of total domestic consumption, and some centes with an average level of consumption around Sousse and Gabbs. The city of Tunis and its suburbs account for 28.22% of national power consumption. l. eof PoW= o g distriution netorks 8. The pattern of developmen of the MV and LV networks is greatly influenced by the expansion of rural electriflcation, which Is one of the key elements in the Distribution Directorate's maser plan, the goal of which is to achieve a 75% electrification rate in 1991 (the rate for 1976 wa 13%, and that for 1987 was 58%). The following table shows changes in the network from 1976 to 1988. Tabte A13A: DEVELOPMENT OF THE NETWORKS _ _ _ 1961 j 1987 18 I WV network (la) 660 11000 14872 16163 16955 17529 18146 LV network (km) 7700 15100 22234 25016 27118 29234 30561 No. NV/LY substations Pubtic 7354 8001 8500 9759 10309 Private 4804 5477 5562 6229 6642 Total 3900 9030 12158 13478 14062 15988 16951 . - --- -- ............ _ - 131 - Page 5 of 1S 9. The breakdown of sales by sector shows the importance of the construction Industries (principally the cement works), which account for 19.30% of the energy billed; the cement works alone accounted for 64.5% of the HV energy consumed. Tabte A13.S: KV/IIW POE SALES BY SECTOR (1989) AVerage Difference Turnover price Consuvption beteen 198 (tD 000) per kWh Sector OWN and 1989 (total) (t) Totat Share (TO) Extractive industries 209.0 3.1 8813 7.3 42.2 Food and tobacco 195.8 2.0 9506 7.8 48.5 Textiles amd clothing 172.7 10.5 8680 7.1 50.3 Paper and pubtishing 77.3 -4.2 3251 20.7 42.0 Chemical ad petroleum Industries 118.4 -4.2 6350 5.2 53.6 Construction 769.6 8.4 30056 24.8 39.0 Basic engineering 144.9 14.3 5810 4.8 40.1 Niscellaneom 182.9 9.6 9632 7.9 53.7 Total 1 1870.6 6.3 82098 67.6 43.9 Purping: agricultural 154.5 0.0 6646 55.5 43.0 Pusping: water supply and sanitation 166.8 10.5 7530 6.2 45.1 Transportation and coimmuications 91.2 3.6 4715 3.9 51.7 Tourism 157.2 9.7 8097 6.7 51.5 Services 216.7 3.5 12294 10.1 56.7 Total 2 786.4 5.4 39282 32.4 49.9 GRAND TOTAL 2657.0 6.0 121380 100.0 45.7 Table A13.6: POWER SALES TO NV CUSTOMERS Consmption (VAh) Turnover (TO 000) Average AE Pcier price Customer Code (NW) Total Differ- Total Differ- per klh ence o_ _ ence (TD) Nine de Cafsa 300 26 131.3 0.9 4801 16.6 36.6 Collulose Kasserine 25 10 37.8 *15.0 1364 4.7 36.1 El P. (act6rie) 220 9 76.3 4.7 2724 9.4 35.7 El F. (fours a arc) 220 7 29.4 18.1 1057 3.6 35.9 Cimenterie de Bizerte 211 10-16.5 70.4 8.3 2391 8.3 34.0 Cimanterie de Gabls 211 15 89.2 16.7 3045 10.5 34.1 Cienterie de Kef 211 19-21 114.4 13.5 4092 14.1 35.8 Cimanterfe Soussm 211 22.5-23.5 116.3 6.5 4279 14.8 36.8 Cimnterfe de Zaghouen 211 23-26 102.9 14.6 3745 12.9 36.4 Nitro Idger Sousse 400 1.2 2.4 20.0 108 0.4 45.0 Ciment Blanc K. 211 6.6 26.8 5.9 944 3.2 35.2 SIAPE, Sfax 230 8 9.1 -9.0 429 1.5 47.1 169.8 806.3 7.3 28979 100.0 35.9 - 132 A na 13 Page 6 of 1S Tcnical AlgoM¢ Seefio2n of rernce netw,o 10. IThi study examines the various areas in which losses on the STEG distribution network have been detected. The loss rate at each of these points is demhied by an "overall method, and short, medium or long-term recommendations will be made, matching the type of problesa Identified. 11. Given the extent and diversity of STEG distribution networks and the time available to this mission, an exhaustive analysis of the networks was not possible. It was therefore decided to concentrate on the networks in zones where consumption was homogeneous and representative of the distribution system as a whole. 12. An initial analysis identified three major zones with a homogeneous pattern of consumption. As Table A13.17 indicates, the various regions of Tunisia can be divided into the foUowing three categories: - the first consists of regions characterized by a poor ratio of energy biled to energy supplied, and a ratio of about 0.5 between number of mMV and mber of mLV. This category consists of the North, Center and South; the second is characterized by a high ratio of energy billed to energy supplied, despite a high ratio between number of mMV and number of mLV per consumer, the reason being that the network is more recent and therefore certainy more efficient. It consists of the Northwest and Southwest; and finally, Tunis is a special case, with a low ratio of energy billed to energy supplied, and also a low ratio between number of mMV and number of mLV per customer. Ibis in itself suggests that nontechnical losses in this zone will be high. -133 - Page 7 of 15 Table A13.7: IDENTIFICATION OF ZONES Zone Ratio A/ No. of mLV per LV No. of mlV ir LV Ratio .______________ ._________ customer and NV customner nWNMLV Tunls 0.907 1S 6 0.40 North 0.911 27 14 0.52 Northwest 0.960 30 26 0.87 Canter 0.890 25 14 0.56 SCuth 0.870 34 17 0.10 Southwest 0.970 29 31 1.07 Iv Ratio u Rnergy billed/Energy supplied. 13. One typical district was selected from each category: Nabeul, where agculture, tourim and industry are major activities; Sillana, a rural district, Is representative of the seond, ad two districts (the city of Tuni, an urban district, and Bzzahr, a suburban district) were slected as represeative of the region of Tunis, which alone consumes over 28% of the energy supplied In Tunisia. 14. In addition, these districts also meet the following criteria of representativity: voltage levels: 10 kV and 30 kV; network structure: overhead and underground; distribution system: three-phase and single-phase; energy utilization: at medium and low voltage. Tables A13.8 to A13.18 present the technical specifications for these districts. -134- Ann1 Page 8 of IS Jn dent Criteri 15. A reprseave sample of the MV network In a given district is selected by meam of the following three Interdependent criteria: Criterion 1 = rt P pmax Criterion 2 = EP (kVA/m) Outgoing feeder length Criterion 3 = E P max (kVA/m) Outgoing feeder length 16. For each outgoing feeder in the zone, the value of each criterion is calculated, together with E P inst x outgoing feeder length, in order to identify those feeders assumed to have a high loss rate. Tbis provides the data for Tables A13.7 to A13.12 for the City of Tunis district and A13.13 through A13.15 for the district of Siliana. From these tables can be detemined the distribution of feeders according to the value of each criterion. This provides the materi for Tables A13.16 to A13.18. This provides a "predominant interval* for each criterion; this is the interval defined by the lagest number of feeders. All feeders are then identified and the predominant intrval for the three criteria is also detrmined. This selection is weighted by taking one feeder in each interval adjacent to the predominant interval, up to a maximum of six additional feeders selected so as to provide feeders connected to most main substations. -135- Annex13 Page 9 of 1S ii I B I NhI n H 01~~~~ Cy l Sees ~~~~~~~~...... . _ §I . @0 Na oa- ,-X; CyV.. Ii~~~~~~~~~~~~~~~~~~4 l}} R ,$g qsO ,a _ - 00. . 0 0-_.0000** -~~ ~ ~ ~ t -- ERnU- ~~~~~~~~~~~~~~~~~~~~~- tlbte DA1X9. DISTItICt: CITY OF IUIS MaIN UBSTATIr: TUNIS WIIU Feeer .M.A. Lenth Winst p _ vim n8l mpIt*Leuth SLibstatoms (kC) CkA) (WA) P Lmmb Lle th (kVAI) t. brine 1 0,S00 1 T. Nwins 0 0.500 0 Gare 1 9,48 7 antfleury 1 5,700 UITIK 0 0 H. Cmlrees 1 2.300 1450 0.63 5 R. Conrew$ 0 0 T. Nerine 1S 5.960 4530 1957 334 1.10 O03 38919 Soreti6 ? 5,640 751S 3585 2no 1.33 0.6 42385 a Biat 16 5,S27 6SS 3723 173 1.17 0.67 3M677 TurquSe 11 3.42S 3370 1818 185 0.98 0.53 1S142 ojeaui 10 3,227 3761 1818 207 1.17 0.56 1213 Aorfcultor 11 3.460 5200 1784 291 1.50 0.52 17992 BCT 16 5,57 10905 3256 335 1.96 0.58 60795 Ctaridge 16 S,640 9910 4676 212 1.76 0.83 SS892 Africa 9 2,615 5393 2234 241 2.06 0.8S 14103 ICrfe 27 7,500 10525 4676 225 1.40 0.62 8 Total 152 67.049 7114 01 I IL Ibt& A1LI9: DISOtICT* CITV OF 1?US PlAIN SUBSTATIU: TUNIS WEST I Feeder NV(LV Length Winat P mx metiN Smt LU P f,nstLertih Suhstaet o C (kYw) CkVA) P mx Length Lngth (kVAflt) (ItVA/ft- CIMAm) Karoun 19 5,060 5313 1.05 26886 UTTI 1 1,650 3400 2.06 5610 schtel 2 1,430 3630 2.54 5191 BSwricho 37 9,145 10065 4728 2.13 1.10 0.52 92044 Dasuat 30 11.915 100l9 3585 2.81 0.85 0.30 120091 Francevilte 26 12,335 7315 4469 1.6 0.59 0.36 90231 Kitatn 17 6,755 7245 4468 1.62 1.07 0.66 48940 Ben MarfI 29 12,010 10800 2511 4.30 0.90 0.21 129708 Plantation 19 5,740 7993 3793 2.11 1.39 0.66 4S880 El Nef ir 17 7,175 6755 3308 2.04 0.94 0.46 48467 SSSUT 3 6,170 8178 2909 2.81 1.33 0.47 50458 STIT 26 7,350 12685 3983 3.18 1.73 0.54 93235 Uettoiemnt 14 5.150 721S 3983 1.81 1.40 0.77 37157 Berthelot 10 3,590 4565 1766 2.58 1.27 0.49 16388 Riot 11 3,395 4360 3256 1.34 1.28 0.96 14802 Total 261 98,870 109598 'I II tae A1jS1: DISTRICT: CIT OF TUNIS _AIN SUBSTATIO I: Tt131 WEST 2 _ _ Feeder NY/LV Length Vfinst P Max sPinmt fPwM P & Pinstftwigth subsetation Cb) (WA) (OA) P mx Length LenIthMkV (kVA*im) MA/mJ AJm RTT 0 1.550 0 0.00 0 Kartoum 2 1,380 1260 0.91 1739 CEN I 0,085 1000 11.76 85 Fi let 19 7,905 10945 1.38 86520 SiT 18 7,035 4420 0.63 31095 Carrwud 22 12,790 13880 1.09 17752S B. Seed 25 18,485 8395 0.45 155182 Banana 35 18,446 11850 0.64 218585 Frigori f fque 22 9,895 6630 0.67 656C4 Sidi Assfca 14 8,665 Au90 0.56 42372 Beaux Arts 5 3,430 2655 0.77 91o7 Vetwart 25 13,275 7610 0.57 101023 Nutrition 16 10.495 4180 0.40 43869 Total 204 113,436 60090 Tabte A13.12: DISTRICT: CITY OF TUNIS PAIW SUBSTATION: TNItS NORTH Feeder WVfLV Lenoth )Pinst P max _SP Pnnst*Length Substations (km) (MA) CkVA) P mx Length Lenth CkVAtkm) Palestfne 27 8,990 8600 1957 4.39 0.96 0.22 77314 Chebbf 15 4,385 6310 1212 5.21 1."4 0.28 27669 Syrie 7 0,520 2060 207 9.95 3.96 0.40 1071 Avnf r 11 19 7,620 6340 2523 2.51 0.83 0.33 48311 Avenir 12 21 10,810 9090 3377 2.69 0.84 0.31 98263 Avenir 16 8 5,390 3255 2840 1.15 0.60 0.53 17544 Ibn Roch 12 3,958 3695 1090 3.39 0.93 0.28 14625 Pexfque 44 22,060 15278 4607 3.32 0.69 0.21 337033 Chargufa 41 14,650 10938 4797 2.28 0.75 0.33 160242 TuLipes 14 6.660 4505 3256 1.38 0.68 0.49 30003 Total 208 85,043 70071 ELR TableA131: DISTRICT: CITY OF lIIIS MAIN SLSTATTION: ZANIRUN Feeel e r uP Length imnst P mx 3 t Zimnst Lt Pinst*Laength Sustattemn Cb) (WVA) CkVA) P max Legh- Length CWAMM) __ ___- c ) Raf 28 14,919 10645 2979 3.57 0.71 0.20 158813 Noubltfe 19 13,770 7385 2z02 2.73 0.54 0.20 101691 Msrabou 21 13,080 6685 4538 1.47 0.51 0.35 87440 Total 68 41,769 2471S TsbtlAI3.14: DISTRICT: MADItL NAIN SUBSTATION: WHAMET Fewer NVLV Length DInst P am >"t Pinst*Length Substatiom (ktm) (kVA) CkVA) P max Length Length (VA*km) (kYA/m) (kVAIM) S. Argoub (1201) 120 88,384 18002 13302 1.35 0.20 0.1S 1591 Enf dia (1202) 90 S1,890 1973 7205 2.74 0.38 0.14 1026 Nabeul (1203) 156 72,425 50240 - 0.69 - 3639 Elkoutn (1204) 19 _ 8213 3948 2.08 Sultan (1205) 20 10,398 8313 3525 2.3S 0.80 0.34 86 R. Jannet (1206) 19 10,469 9375 2950 3.17 0.89 0.28 98 Total 424 233,566 113916 Teble A13.15s: DISTRICT: MASL FAIN SUSSTATION: GR0NLIA Feder NVtV Length Winst P max Wjns winst LMX Pflst*Length Substatians Cki) CkVA) (WA) P m Length Length CkVA'kr) Ck_AWM (kWA/r) 1e.l1 (5001) 87 70,954 19464 9222 2.11 0.27 0.13 1381 E. Nord (5002) 58 43,266 16420 9260 1.77 0.38 0.21 710 Solinan (5003) 136 112,085 23419 12153 1.92 0.21 0.11 2625 Z1 Grme (5004) 66 34,211 19710 392 2.35 0.58 0.25 674 N. SoueL. (5005) 138 88,384 22765 8504 1.77 0.26 0.10 2012 Total 485 388,900 101778 Table A13.16: DISTRICT: NASEULL MAIN SUBATIOU: * KOM Feeder NV/LV Length ZPinst P max xpirt ZPinst P x Ptnst*Length Substatiom (kn) (kVA) (kVA) P mx Length Length (kVAnm) _______________ ________ ____ _________ (VA/rA ) (W AM) Dressen (1301) 70 79,834 953 2161 4.41 0.12 0.03 761 nIzraa (1302) 90 62,465 14697 10195 1.4 0.23 0.16 918 Korba (1303) 25 11,510 6275 2838 2.21 0.54 0.25 72 Kelibia (1304) 229 227,157 22265 7074 3.14 0.09 0.03 5058 llauaria C1305) 190 246,518 20944 6625 3.16 0.08 0.03 5163 Total 604 388,900 101778 a ILt; - 141 - A 1 Page iS of iS Tsble AILjZI INTERDEPENDENT CRITERIA DISTRICT: CITY OF TUNIS Criterion I (0.11 (1.22 t2.31 t3.41 £4.51 15.3£ Numer of feeders 0 10 20 7 3 3 Criterion 2 [O;0.51 [O.5;11 t1;1.53 t1.5:2J 121t Number of feeders 0 22 1S 4 2 Criterion 3 CO;0.251 tO.25;0.5l IM.5A0.M5 1O.75;[ . Number of feeders 9 18 12 4 Table A13.18: INTERDEPENDENT CRITERIA DISTRICT: NASEUL CrIterion 1 [0.11 [1.21 £2.31 C3.41 14."t Number of feeders 0 4 I 3 2 Criterion 2 CO;0.251 [O.25;0.51 10.5;0.751 [O.75;11 Murber of feeders 6 4 3 2 Criterion 3 t00.1251 EO.12;0.251 CO.25;0.371 Number of feeders 6 7 2 17. This gives the following feeders for the diricts In question: Ditrict: City of Tunis: Tanit - Imer - B.Miled - BCT - Agricultor - Turquie - El hafir - Daudet - Avenir 1 - Avenir 12 - Charguia. D41ria: Nabeu: : B.Argoub - Mazzraa - Kelibia - Haouaria - Belli. 18. It should be noted that in the cas of the District of Nabeul the intersection of the thee criteria produces an empty set. Consequently priority has been given to those feeders assumed to have a high loss rate. -142- 1 Page 1 of 12 CROSS-SECTION CHANGE 1. Installing a cable with a larger cross section, and thus lower resistance per unit length, reduces losses per unit of power transmitted. The loss reduction, in kW, is given by the following formula: gain = 1000 x L x (rl - r2) S2/V2 where: ri = resistance per unit length of conductor i, in 0/km S apparent power in kVA U = inteIphase voltage, in kV A section should be upgraded when the following is true: Annual capital investment cost _________________< Annual cost of one kW loss Reduction of Losses [kWV This ratio can be used to establish a threshold output S, beyond which investment is profitable. NO: since the eimated discount rate is 10%, the annual cost of the works is 10% of the total investment cost. 2. For the overhead network, the total investment cost is the sum of the following costs: installation of cable with cross section S2 + removal of cable with cross section SI + insalling new poles W/ WU/ On awrag, own doirf &# eing poks wuW be replacea - 143 - A= 14 Page 2 of 12 3. for the underground network, the total investment cost is broken down as follows: laying of cable with cross section S2 + accessories junctions and ends) + repairs + cable trenches 4. In the underground networks, removal of the original cable with cross section SI is not financially worthwhile, even taking into consideration the possible recovery of copper from the conductors. 5. The following table shows the total investment cost for the various types of network and conductors: tabte A14.1: INVESTENT COSTS FOR THE VARICUS CONDUCTOR TPES New cable Inestment Lost Low voltage rntwork 3i5' Au 7.12 TD/i 70' Alu 8.67 TDIm Wedium voltage network Overhead tines 54.6 Alm 5805 TO/km 148.1 Atm 9670 TO/km Underground cables 240' Alu 64592 To/km 6. When the diameter of the cable Is doubled, the strength of the current in any given section is halved, the losses for each line are divided by four, and total losses are therefore divided by two. lhe wcrren strength corresponding to the economic break-even point for thbis operation is determined by the following formula: Loss reduction > annual investment/annual cost of one kW of losses, from which we obtain: 12 > (AnnUal InveStmenta cost of one kW of loss) * 2 3000 r r = linear resistance of the cable, in 0/km 7. From the total number of feeders studied, we select those segments which convey current at a level of intensity greater han, or equal to, the threshold level for reconductoring the secdon. In each case, the total savings in Tunisian Dinars (ID) can be calculated, since a loss reduction of 1 kW produce an annual saving of TD 360.5 for the medium voltage network (see Annex 2, 'Calculation of Loes). - 144- MM 14 Page 3 of 12 I'us, for eah segment, and then for each outgoing feeder, the immediate rate of return RR) can be calculated. It Is defined as foliows: Discouned annual savings in TD TRI = Total investment cost in TD For each outgoing feeder, the results are as follows: Jghle AUJ: RECONIOCT0RING OF THE HACURIA OUTGOING N FEEDER (DISTRICT OF NASEUL) P (IdE) Length Loss Total cost (m) sect I Sect 2 reduction (TO) in 2596 80 22 Cu 148.1 Atm 386 774 18 2557 80 22 Cu 148.1 Atm 376 M74 1lx 2557 520 22 Cu 148.1 Alm 245 5028 18o 2492 810 22 Cu 148.1 Alm 3617 7833 17g 2285 1540 22 Cu 148.1 Atm 5782 14892 14X 2235 900 22 Cu 148.1 Atm 3233 8703 132 2026 430 22 Cu 148.1 Atm 1269 4158 11X 4360 17111 42161 15X - 145 - AnuI Pago 4 of 12 table A4t3: RECOUCTORING OF THE RELLI OUTGOING NV FEEDER (DISTRICT Of NASIUL) P &Id) Length Loss totol cost (m) sect 1 sect 2 re uctton (TD) IRR - (") . . .. .~~~~~~-(W 4573 80 1 Cu 148.1 At 1607 774 75X 450? 130 17 Cu 148.1 Al 2536 125? 73n 4446 140 17 Cu 148.1 At 265 1354 n 446 670 17 Cu 148.1 Al 1270 6479 7T12 4427 280 17Cu 148.1 Al 5270 2708 702 4349 260 17 Cu 148.1 Al 4723 2514 682 4310 610 I7 Cu 148.1 Al 10883 S"9 67X 4271 310 1? Cu 148.1 Al 5431 2998 652 4232 230 17 Cu 148. Al 3956 2224 642 3533 80 7 Cu 148.1 Al 959 74 45X 353 370 17 Cu 148.1 Al 4436 3578 452 3494 670 7 Cu 148.1 Al 7856 6479 4 3302 270 17 Cu 148.1 At 2827 2611 3 3263 310 l7 Cu 148.1 Al 3170 2998 382 3244 220 I? Cu 148.1 At 2224 2127 382 3205 410 l7 Cu 148.i Al 4045 3965 372 3205 200 17 Cu 148. Al 1973 1934 372 3168 7o 17 Cu 148.1 Al 6940 6942 36 3149 400 l7 Cu 148. Al 3810 386 362 2843 550 29 Cu 148.1 Al 2136 59 142 2715 840 29 Cu 148.1 Al 2975 8123 142 25S9 810 lT Cu 148.1 At 5094 7833 232 2438 140 29 Cu 148.1 Al 400 1354 11X 2316 280 29 Cu 148.1 Al 2708 102 8980 99351 86837 412 - 146- &= 14 Page 5 of 12 Jlbtg A14.4: RECONODUCTORING OF THE LAKCES OUTGOING NV FEEDER (DISTRICT OF SILIANA) r (d) Lenth Loss Total cost (M) Sect I Sect 2 reduction (TO) IRN 6168 2430 54 Atm 148.1 ALm 42855 23498 66X 6045 450 54 Alm 148.1 Al. 7623 4352 63X 5807 860 7S Alm 148.1 Alm 7588 8316 33X 485S 280 75 Alm 148.1 Alm 1734 208 23X 4855 1000 75 Alm 148.1 Alm 6168 9670 23X 4836 750 75 Alm 148.1 Alm 4590 7253 23X 4797 540 75 Alm 148.1 ALm 3251 5222 22X 4782 860 75 Alm 148.1 Alm 5146 8316 22X 4M 1390 75 Atm 148.1 Alm 8283 13441 2,3 4741 80 75 Atm 148.1 Al. 471 774 22'3 4739 1790 75 Atm 148.1 Alm 10519 17309 223 4711 80 75 Alm 148.1 Alm 46S 774 22X 4708 660 75 Atm 148.1 Alm 3828 6882 22X 4708 140 75 Alm 148.1 Alm 812 1354 22X 4708 90 75 Atm 148.1 Alm 522 870 22X 4439 1150 75 Alm 148.1 Alm 5929 11121 19X 4210 S00 75 Alm 148.1 Alm 2319 4835 17X 4190 650 75 ALm 148.1 ALm 2986 6266 17X 4115 150 75 Alm 148.1 Alt 665 1451 17X 4112 440 75 Alm 148.1 Alm 1770 3868 16X 2775 130 22 Cu 148.1 Alm 720 1257 213 2760 390 22 Cu 148.1 Alm 2136 3771 203 2663 160 22 Cu 148.1 Alm 816 1547 19X 2563 80 22 Cu 148.1 AL 378 774 18X 254 300 22 Cu 148.1 ALM 1396 2901 173 2544 600 22 Cu 148.1 Alm 2792 5802 17X 2396 S580 22 Cu 148.1 Alm 23036 539S9 153 2296 7800 22 Cu 148.1 Alm 2569 75426 143 2296 200 22 Cu 148.1 Alm 758 1934 14X 29490 121572 145147 303 -147 - Anna 14 Page 6 of 12 8. In order to evaluate the rate of technical losses on STEG's low voltage disibution network, losses were calculated for a number of low voltage outgoing feeders that were representative of the networks in each district selected for the study. As these districts themselves were charcteic and represenative of Tunisian distribution networks, one can then determine the overall loss rate on the low voltage network. Calculation of Losses on an Outgoing LV Feeder: 9. For these calculations, the following assumptions were made: the load is evenly distributed over the length of the outgoing feeder; losses in consumer connections were not taken into account. 10. If we know the power demand in the outgoing feeder and the distribution mode (three phase or single-phase, LI or L2, i.e, 380 V or 220 V), the following values can be detennined successively: peak load percentage (i,,); intenity of current transmitted (LW); - losses (Loss.) for each segment; then loss rate for the outgoing feeder (% Loss) by means of the following equations: i,, = (I/L) x '"S Loss.,. = r,^ I,,, vL, % Loss= 5 Loss.,/P. in which: I current intensity in the outgoing feeder, recorded at the MVALV substation (A) - 148 - ADDM.14 Page 7 of 12 L = total length of outgoing feeder (km) L." = length of segment (km) r,, = resistance per unit length of the segment (0/km) P,,Sx, = power demand recorded at the outgoing feeder bay (kW). X = Cost of network losses in TD/kW Y = Annual investment cost in TD/km And thus: y S 2 UVj X 1000(rl-r2) 11. This value is called the "threshold power," since it marks the break-even point for k 2 x 702: I threshold = 41.41 A 15. Ihe mission observed that in rural areas like Siliana the monophase network is geneally correctly structured and has a low loss rate. Consequently, no reinforcement Is planned for the single- phase work in this area 16. From the sample of feeders studied, those segments of outgoing feeders transmitting power equal to or greater than the most cost-effective threshold level for reinforcement are selected. Likewise, in each case, the savings in TD to be derived from this reinforcement are calculated, on the assumption that a 1 kW reduction in losses corresponds to a saving of TD 471.4 (see "Calculation of Losses"). The immediate rate of return (IRR) is then calculated for each section and feeder, in accordance with the following: Projected savings in TD IRR = _ _ _ _ _ _ _ _ _ _- Total inlvestment cost in TD -150 - Am14 Page 9 of 12 Thus, once the break-even point has been reached for the two cross sections (352 al and 702 al), the option providing the higher IRR for the section is selected. Moreover, by classifying the outgoing fiedes in descending order of IRR, a schedule of work can be prepared that spaces the work to bedoneovertime. In effect, prioritywillbegivento the feeders with thehighestlRls. Thismediod of calculation also enables the loss re subsequent to reinforcement to be determined for each outgoing feeder,, together with the new loss rate for the district as a whole. 17. The results per outgoing feeder for the low voltage network are as follows, when we apply the method and calculations defined in Annex 3: Tabte AWf RECONDUCTORING OF THE EL DJAZIRA OUTGOING LV FEEDER (TUNIS CITY DISTRICT) Length Loss Total cost I (A) (a) sect 1 Sect 2 reduction (TO) hR 63.00 90 710' ALu 2'0* Atu 287 780 17% 27.9f 10 6V Atu 35' Atu 54 71 36% 100 1 851 19% Tkbl A14.i8: RECOIiDXCYORING Of THE EZZITOUJA OLTCOING LV FEEDER (TUNIS CITY DISTRICT) Lenoth Loss Total cost I (A) tm) Sect I sect 2 reduction (TO) IRS 235.00 10 70' 2*700 497 87 27ox 47.50 50 70' 2*70' 80 434 12% 60 577 521 52X - 151 - Am 14 Page 10 of 12 tableiauAIL.% RECONDUCTORING OF THE ONAS OUTGOING LV FEEDER (DISTRICT OF E22AHRA) Length Loss Total cost I (A) (i) Sect I Sect 2 reductfon (TO) IRR _ _ _ _ _ _ _ _.. _ _ _ _ _ _ _ . _ _ _ _ _ _ ( U _ _ _ _ _ _- _ _, _- _ _ _ _ _ . _ _ 76.00' 60 70 Alu 2*70# Atu 279 520 25% 68.92 45 70' Atu 708 ALu 230 390 28% 17.47 20 30/10 Cu 352 AMu 33 142 11% 125 542 1052 24S Lblj Ali4 l: RECONDUCTORING OF THE INDEPENDANCE OUTGOING LV FEEDER (DISTRICT OF EZZAHRA) Le.gth Loss Total cost I (A) Cm) Sect I Sect 2 reduction (TO) IRR 116.00 75 70 Atu 2*701 AMu 812 650 59% 59.07 25 16' Alu 70' Atu 425 217 93% 51.86 30 16' ALu 70' AMu 394 260 71% 43.22 35 16' Alu 70' Alu 319 303 5OX 33.14 45 16' AMu 70' AMu 241 390 29% 20.07 30 16# Alu 70' AlU 59 260 11% 240 2250 2080 51% Euahre DOstriet, Ghandf outgoing feeder: no reconductorlng. lTae A14,11: RECONDtWCTORING OF THE KAHENA OUTGOING FEEDER (DISTRICT OF EZZANRA) Length Loss Total cost I (A) (__ ) Sect I Sect 2 reduction (TO) tRR 38.48 20 3S5 AMu 70' Atu 42 173 12% 59.00 20 70' Alu 2*70' Alu 56 173 15% 40 98 346 13% -152- Afh Page 11 of 12 Tabt A14l12: RECONDUCTORING OF THE ECART NMRD Al OUTGOING LV FEEDER (DISTRICT OF NABEUL) Length Loss Total cost I (A) (i) sect I sect 2 reductIon (TO) IRn 80.48 125 386 AMu 70 Atu 975 1084 421 65.8B 110 38' Atu 701 AMu 575 954 281 47.85 270 38' AMu 70' Alu 744 2341 15X 31.07 1SO 17.8' AMu 708 Alu 276 1301 101 655 2570 5680 21X TXbt A14.13s: RECONDUCTORING OF THE ECART NORD A2 OUTGOING LV FEEDER (DISTRICT OF NABEUL) Lenoth Loss Total cost I (A) cm) Sect I Sect 2 reduction (TO) IRR 84.52 90 50' Alu 70' Atu 367 780 22X 72.09 220 50' AMu 708 AMu 653 1907 16 37.29 50 40/10 Cu 70' Alu 224 43 24 360 1244 3121 19X Tabte A14.14: RECONDUCTORING OF THE ECART NORD A3 OUTGOING LV FEEDER (DISTRICT OF NABEUL) Length Loss Total cost I (A) Cm) Sect I sect 2 reductfon (TO) IRR 53.12 370 29' Alu 70' Alu 2109 3208 31X 31.52 160 298 Alu 70' Alu 361 1561 11M 550 2470 4769 24X *153 - Page 12 of 12 taettM AHs.15s RECONDUCMING OF TNE ECART NORD A4 OUTGOING FlEDE0 (DISTRICT OF AEUL) Lnogth Loss Totat cost I CA) (m) Sect 1 Sect 2 rodtwtlon (TO) 1R3 _________tO _ _ _ _ _ _ _ _ _ _ _ _ _C )_ _ _ _ __ ___ _ _ _ _ 96.88 120 70' Alu 2*70' Atu 906 1040 41% 82.8 160 70' Alu 2*70' Atu 884 1387 30% 26.02 480 40/10 Cu 70' Alu d212 4162 14% 760 3002 658 212 Ilhtg A14h6A: RECONDUCTORING OF THE KAWNIA LV OUTGOING FEEDER (DISTRICT OF NAUUL) Length Loss Total cost I CA) tm) sect I Sect 2 rduction (TO) IRR 122.00 35 70' AMu 2*70' AMu 419 303 65X 106.60 50 35' Atu 70' Alu 812 434 88X 101.38 90 29' Atu 70' AMu 1869 780 1132 44.45 60 29' Atu 70' Alu 239 520 22X 51.70 40 40/10 Cu 70' AMu 344 347 4?7 43.57 40 40/10 Cu 70' Alu 244 347 33m 29.05 110 40/10 Cu 70' AMu 2S} 954 15S 425 4226 3685 542 TWO( A14.17s RECONDUCTORING OF THE ARSOLINE OUTGOING SINGLE-PHASE LV FEEDER (DISTRICT OF NABEUL) Lenth Loss Total cost I (A) Cm) sect I Sect 2 reduction (TO) 133 95.00 100 351 70' 430 867 23X 73.88 120 35' 70' 312 1040 13X 34.01 70 6' 35' 186 496 18n 290 928 2405 182 - 154 - Annexi1 Page 1 of 1 TllANSFORMOR OPRATION IN TIHE IV/MV SBTATIONS ±bA15.1t LIST OF SUISTATIONS FOR WHICH IT IS NORE ECONMI4CAL TO PUT ONLY ONE NV/NV TRANSFORMER INTO SERVICE, SWITCHING OFF THE SECOND TRANSFORER (1989 DATA) Annual Anna NVA NW NVA Pcore PJoute Saving Gain _ vlalegmnt peal -pPk kV kV To INh 0Nralte 2°40 16.0 My.7 25.3 195 4670 140 N. jaml 240 19.S 21.6 25.3 195 2460 100 0. zerm 2*40 16.0 1T.? 25.3 195 4670 140 Jaidoub 2*40 17.0 18.8 25.3 195 4080 130 Oeseletfi 230 15.0 16.6 25.0 160 3280 113 Zahroui 2*30 13.5 15.0 21.0 160 2890 98 90/O kV Sfdf Nwrour 2*40 16.0 17.7 26.6 195 5130 151 Zarafa 240 13.0 14.4 34.0 195 9350 243 Zbrouni 2*40 19.5 21.6 26.0 195 2700 128 9030 kV Karomua 2*40 11.0 12.2 25.3 195 7030 182 Tunis Center 2*40 21.0 23.3 25.3 195 1340 80 sono kV Tunis Nord 2*30 19.5 21.6 29.0 160 720 76 90/10 kV NdRutt 2*40 16.0 17.7 34.0 195 7820 215 Totat 56140 1796 - 155 -16 Page 1 of 7 GUIDEf FOR PREPARiNG MAINTEIANCE PROCEDURES gneal: usfation for maintenance ogerations in an electricit system 1. The purpose of maintenance operations is to maintain the power system in good condition so as to guarantee: the safety of personnel; proper operation of the equipment. 2. The aim here Is to reduce the possibility of exposing the public and the operating pesonnel to electrical risks. Electrical equipment is initially designed to confonm to safety regations; it is up to the distributor to ensure that it continues to do so throughout its usefid life. 3. TIbs consists of reducing the risks of equipment breakdowns that could lead to fteuptions In supply. These failures could be the result of: equipment working improperly as a result of age, wear, etc.; specific environmental conditions: pollution, corrosion, animals; - exceptional circumstances (atmospheric conditions, damage caused by third parties, vandalism). 4. These objectives can be achieved through activities ranging from monitoring the equipment to replacing it, and encompasses all stages of mainece. S. It is not easy to define a mai ce policy since it basically involves selectig a series of measures in a context of multiple contradictory constraints. 6. It is obvious, for example, that a maintenance policy that guaranteed total service reliability by iminang all network ptoblems would be economically harmful, as would a very limited and tmid policy, due to its effects on service continuity. A maintenance policy is therefore a -156- Page 2 of 7 reasonable compromise between doing everythinga and "intervening only where and when necessay, just before the Incident." lTis compromise consists In finding a balance between the economic cost of the meaures taken and the cost for all equipment breakdowns. Bases of a maintenance poic 7. The establishment of an appropriate maintenance policy should follow the following theoretical diagram: Information -> choice of actions-> actions-> validation. B. An initial diagnostic analysis of the equipment should be made, to evaluate a priori the effectiveness of the policies selected, followed by an a posteriori validation of the actions that have been taken. However, this theoretical approach must be tempered by pragatism In light of the operators' experience, since very often it is hard to determine the qualitative improvement to equipment and It can take several years to evaluate a maintenance policy. 9. The prerequisite for all maintenance operations is the gathering of relevamt data. As a first step this requires a diagnostic analysis of the equipment to provide data on the physical characteistics of system components, their location and age, and the sequence of events that may have affected their operaton. It also involves preparing cartographic surveys of all or part of the electric pawer system, with permanent flagging of defects and incidents. 10. This information system must also make special provision for the upward flow of data from the operators: deficiencies detected during normal operations, searches for defects, emergency repairs, and maintenance work. In recording this information, duplication should be avoided; there must be one file, and only one, for each category of equipment - for example, one file for each MV feeder, and so on. 11. Another very importan source of data is comprehensive analysis of all incidents and defects that affect the components of the electric system, In order to understand their caus and, if possible, draw lessons for the future, especiaWly in regard to decisions to be taken in similar conditions or relating to identical components. - 157 A Page 3 of 7 12. A mntenance policy is based on observing a number of requirements. (a) R lg e. These generally involve observing safety regulations, for example, minimum distances to maittain between conductors and the ground, between conductors and buildings, and maximum grounding resistances. Verifying that equipment conforms to these safety regulations is an important part of maintenance acdvities. Ibis verification will be performed on a case-by-case basis as maintenance work is done. (b) Ser-vce continuit imperaie. These are expressed in the form of various indicators, such as the number of MV feeders, the number of permanent defects per 100 kin, amount of energy unsupplied s the result of a breakdown, etc. If the values of these indicators exceed predetermined thresholds, maintenance operations can be planned at the time the problems occur. (*c) Prweveive maintenance This is generally based on maintenance schedules recommended by equipment manufacturers, but also, and particularly, on the experience the operators acquire by opemting and mantining the equipment. (d) Ec L ens. Defining a maintenance policy, as already noted, is a compromise between "doing everything" and very selective intervention just before the failure or breakdown. This compromise reflects a priority ranking of the various actions (which the data colleted will suggest) using a cost/benefit method, in light of the savings to be expected from improvements in the continuity of supply and in productivity following a reduction in the number of failures and, hence, in the nmber of emergency repairs. - 158 - Page 4 of 7 Mantenance prgrm 13. A multiannual mainteance program, including actions by category, should be prepared in light of the preceding considerations and the resources available. 14. This program must also be consistent with investment programs that cover equipment rehabilitation and reinforcement, to avoid redundancy in maintenance actions or in the use of resources. 1S. The program will be established according to equipment type, since it is impossible to establish mantenance rules valid for all the components of an electricity system. In practice the frequency of incidents varies from one piece of equipment to another in light of: (a) the initial uneven quality of the equipment; (b) the variety of external constraints; (c) the uneven quality of previous maintenance work on the equipment. 6. The scope of the work to be planned will vary in light of the information available and the kind of equipment involved, ranging from occasional visits to routine maintenance, and including regular visits and light mainteance as and when necessary. MV!gxvbead netwQrJe t?. Maintenane opemrions on this category of structures should not be routine. They will be undertaken on the basis of the following information: (a) information supplied by oprators. These are the specific problems detected by operating personnel. These deficiencies should be located on a map and attended to very rapidly. When problems the operators have identified are attended to prompdy, the operators are encouraged to continue reporting problems and the informaton improves, both in quality and in quanity; (b) oeall analis of incident, which enables the detection of weak points to be monitored and, thus, helps detmine general maintenance guidelines for esh type of equipment; - 9 16 (c) routine Iiine inspec, as far as possible by helicopter at intvals of four yeas. The frequency of inspections could be adjusted in light of the number of failur per MV feeder. The inspections will serve to identify iregularities, locatiors where pruning is needed, and other weak spots so that the amount of work ned ca be quantified. Repairs should be begun immediately fllowing the npectIons, a should pruning; (d) casioal vi, at the request of the operators to confirm or deny ft e o of less obvious problems on the network. 18. Overbed brk sWitC: maintenance will be perfrmed followinS line Inspecios. Tbis should as far as possible be hot-line maintenmce. LY overbead netorSc 19. No routine equipment inspection. Occasional inspections will be scheduled to vulnerable parts of the network known to the operators or identified by the statstical record on incidents. The resulting maintenance operations will be economically justified and assied a prior ranking according to the savings expected. IAdrgmY nd V/VI Lq=rk 20. No preventive maintenance is recommended. Me;emmCLof eartbing quality 21. The frequency of measurements will vary according to the zone and equipmen The following intervals could be envisaged: (a) HV/MV substations: annually (b) overhead MV network: . break switches: every 5 years * poles: every 10 years * surge arresters: every 10 years -160- Page 6 of 7 (c) MVILV substations: . grounding connections: every 5 years w neutral wire grounding: every 10 years. 22. The mission recommends: (a) a routine inspection every five years to take measurements of earthing quality. However, the inspection schedule should be adjusted to the schedule of other actions in the substations, such as redistribution of the transformers, replacement of equipment, and operating maneuvers; (b) occasional Inspections: -when problems occur; in specific cases known to the operators (substations along the coast, pollution, humidity). These visits will lead to two kinds of maintenance: light maintenance performed at the time of, or right after, the visit; pianned maintenmce following technical and economic justification. 23. Routine maintenance will be performed on these, firstly because of their sensidvity and the difficulty of calculating the probability of breakdowns, and secondly because of the disproportionate economic consequences of incidents that may affect them, when compared to the cost of mantning them. However, the mantace Intervals should change in light of equipment Improvements and operator eperience. One can expect: (a) a monthly Inspection to verify: the overall good condition of the equipment: HVIMV transformer, remote control equipment, capacitors, MV breakers; the overall good condition of the automatic devices; - 161 - An 16i Page 7 of 7 the operating records of the breakers and recloses; the indicator reading; lighting, heatig and air conditioning; the condition of the premises. (b) routne mainenan: breakers and fteir associated equipment, every 18 months for equipment at is insulated in oil; operation of capacitor banks, every 18 months: capacitors capacitor batteries, annually; c capacitor bank break switches, at the same time as the capactor breake,t in other words, every 18 months for equipment that is ilated In oil. - 162 - ENERGY SECTOR MANAGEMENT ASSANCE PROGRAMME COMPTED ACTIVITIES CounSq ActvIy Dae Number SUP-SAHARAN ARCA (APR) Africa Regional Anglophone Africa Household Energy Workhop 07/88 085/88 Regional Power Seminar an Reducing Electric Power Sytem Lose in Africa 08/88 087/88 Insitional Evaluation of EGL 02/89 098/89 Bioma Mapping Regional Workshops 05/89 - Francophone Household Es'ergy Wodshop 08/89 103/89 Interafrican Electrical Engiueering College: Proposals for Short- and Long-Term Developmnt 03/90 112/90 Biom As ssmet and Mapping 03190 - Angola Eme Asent 05/89 4708-ANG Power Rehabilitation and Technical Assistance 10/91 142/91 Benin EnergyAssent 06/85 5222-BEN Botswana Energy Asssment 09/84 4998-BT Pump Electrification Prefessibility Study 01/86 047/86 Review of Electricity Service Connection Policy 07/87 071'87 Tui Block Farms Electnfication Study 07/87 072/87 Household Energ Issues Study 02/88 - Urban Household Energy Strategy Study 05/91 132/91 Buwkia Faso Energy Asm mt 01/86 5730-BUR Technial Assistance Progm 03/86 052/86 Urban Household Energy Strategy Study 06/91 134/91 Burundi Energy 06/82 3778-BU Petroleum Supply Management 01/84 012/84 Status Report 02/84 011/84 Pesetation of Energy Projects for the FouLi Five-Year Plan (1983-1987) 05/85 036/85 Improved Charcoal Cookstove Strate 09185 042/85 Peat Utilization Project 11/85 046/85 Energy Amssesnt 01/92 9215-BU Capte Verde Enery Assmesst 08/84 5073-CV Household Energy Strategy Study 02/90 110/90 Comoros Enr Assmt 01/88 7104-COM Congo Energ A _t 01/88 6420-COB Power Development Plan 03/90 106/90 C6te d'Ivoire Energy A _t 04185 5250-IVC Improved Bioms Utilization 04/87 069/87 Power System Efficiency Study 1287 - Power Sector Efficiency Study (French) 02/92 141/91 Ethiopia Energy Asest 07/84 4741-ET Power Systen Efficiency Study 10/85 045/85 Agiculturl Residue Briquetting Pilot Project 12/86 062/86 Bagpsse Study 12186 063/86 Cooking Efficecy Project 1V87 - - 163- Couhy AcMv*y Date Number Gabon Ebq A meot 07/88 6915-GA lEe Gambia Eleq8y AtEeswnent 11/83 4743-GM Solr Watfr Heating Rebofit Project 02/8S 030/8S Solr Photovoltaic Applications 03/8S 032/85 Petroleum Supply Mlanagenet AEssista 04/85 035/85 Gbana Energy AuEent 11/86 6234-GH Energy Raionalzatin the Industrial Sector 06/88 084/88 Sawmill Residues Utilization Study 11/88 074/87 Guinea E=V A t 11/86 6137-GUI. GuineeBisms loery A _dnM 08/84 5083-GUB Reommended Technical Assistance Ptrects 04/85 033/85 Management Options for the Electric Power and Water Supply Subsectors 02/90 100/90 Power and Water Instittional Restmucting (French) 04191 118/91 Kenya Energy Assessnt 05/82 3800-KE Power System Efficiency Study 03/84 014/84 s Report 05/84 016/84 Coal Conversion Action Plan 02/87 - Solar Water Heating Study 02/87 066/87 Pni-Urban Woodfuel Development 10/87 076/87 Power Master Plan 11/87 - Lesotho EnerD Assemwent 01/84 4676-LSO Liberia E y Asessmt 12/84 5279-LBR Rwo_neded Techicd Al iam Projects 06/85 038/85 Power System Efficiency Study 12/87 081/87 Madagasar Energy Assmet 01/87 5700-MAG Power System Efficiency Study 12/87 07S/87 Malawi EnergyAsslt 08/82 3903-MAL Technical AsUsine to Tnprove the Efficiency of Fuelwood Use in the Tobacco Idy 11/83 009/83 Su"tw Rtport 01/84 013/84 Mali Energy A _ (Pch) 11191 8423-MU Islamic Republic of Maluitana Energy A _et 04/85 5224-MAU Household Energy Staty Study 07/90 123/90 Mauritius Energy As e 12/81 3S10-MAS Status Report 10/83 008/83 Power System Efficiency Audit 05/87 070/87 Bagasse Power Potetial 10/87 077/87 Moznibique Bnert A _mment 01/87 6128-MOZ Household Electricity Utilization Study 03/90 113/90 Niger EnergY ^_t 05/84 4642-NIR St Report 02/86 051/86 Improved Stoves Poect 12/87 080187 Housold Energy Consevaon and Substitution 01188 082/88 Nigeria Energy A08 O/83 4440-UNI Rwanda A 06/82 3779-RW hErgV A _essnt (lig and Fte-h) 07/91 8017-RW Stats Rot 05184 017/84 Imprved Ckpcoal Cooksto Strat 08/86 059/86 Improved Chao Podu Techiques 0287 065/87 -164 CoWry ActWty Date Numner Rwanda Commercialization of Improved Charcoal Stoves and Carbonization Techniques Mid-Term Progrers Report 12/91 141/91 SADCC SADCC Regional Sector: Regional Capacity-Building Program for Energy Sueys and Polcy Anayss 11/91 - Sao Tome and Principe Energy Assessment 10/85 5803-SP Senegal E0ey Assem t 07/83 4182-SE Status Rort 10/84 025/84 Industrial Energy Conservation Study OSl85 037/85 Preparatory Assistance for Donor Meeting 04/86 056/86 Urban Household Energy Strategy 02/89 0! '/89 Seychelles Eaer Aesst 01/84 4 *SEY Electric Power System Efficiency Study 08/84 021/84 Sierra Leone Energy Assesent 10/87 6597-SL Somalia Energy Asssment 12/85 5796-SO Sudan Management Assistance to the Ministry of Energy and Mining 05/83 003/83 Ene As 07/83 4511-SU Power System Efficiency Study 06/84 018/84 Status Report 11/84 026/84 Wood Energy/Foestry Fesibility 07/87 073/87 Swauiland Energy Assessment 02/87 6262-SW Tania Energy Assessment 11/84 4969-TA Pei-Urban Woodfue Feasibility Study 08/88 086/88 Tobacco Cuing Efficiency Study 05/89 102/89 Remote Sensng and Mapping of Woodlands 06/90 - Industri Energy Efficiency Technical Assisance 08/90 122/90 Togo E06agy Asement 06/85 5221-TO Wood Recovery in the Nangbeto Lake 04/86 055/86 POWer Efficiency Impovenmt 12/87 078/87 *J8a4ta EBAtgy Ausesoment 07/83 4453-UG Status Report 08/84 020/84 Ibstitutional Review of the Eney Sector 01/8S 029/85 Energy Efficiency in Tobacco Curng Industry 02/86 049/86 Fuelwood/Forestry Feasibiliq Study 03/86 053/86 Power System Efficiency Study 12/88 092/88 Energy Efficiency Imprr- ement in the Brck and Tile Industry 02/89 097/89 Tobacco Curing Pilot Froject 03/89 UNDP Tenrinal Zaire Energy Assmet 05/86 5837-ZR Zambia EBnergy Assessmmt 01/83 4110-ZA Status Report 08/85 039/85 Eney Sector Institutional Reiew 11/86 060/86 Power Subsector Efficiency Study 02/89 093/88 Energy Statg Study 02/89 094/88 Urban Household Energy Sty Study 08/90 121/90 Ziubawe Enery Assest 06/82 3765-ZIM Power System Efficiency Study 06/83 005/83 Status Report 08/84 019/84 Pw Sector Management Assistance Project 04/85 034/85 Petoleum Management Asio 12189 109/89 -16S CoWY Acdv* Dats Nwumber Zimbabwe Power Sector Management Institution Building 09/89 - Cbarcoal Utizaon Preaibility Study 06/90 119/90 Iltrat Energy Stateg Evaluation 01/92 8768-ZM EASR ASIA AND PACIFIC (EAP) Asia Regional Pacific Household and Rural Energy Sem r 11/90 - Chna County-Level Rural Energy Assessments 05/89 101189 Fuelwood Forsty Preinveatment Study 12/89 105/89 Fiji Eiigy As rit 06/83 4462-PU Indonesda Enwg A sament 11/81 3543-IND Status Report 09/84 022/84 Power GCenation Efficiency Study 02/86 050/86 Energy Efficiency in the Brick, Tile and Lime Industries 04/87 067/87 Diesel Genting Plant Efficiency Study 12/88 09S/88 Urban Household Energy Strategy Study 02/90 107/90 Bioma Gafier Preinvetment Study Vols. I & U 12/90 124/90 Malaysia Sabah Power Sydem Efficiency Study 03/87 068/87 Gas UtDiztion Study 09/91 9645-MA Myannwr e Asset 06/85 5416-BA Papua New Guinea Ergy Asemmt 06/82 3882-PNG Status Report 07/83 006/83 Enery Stratgy Pae - - nstitutonal Review in the Energy Sectr 10/84 023/84 Power Tariff Study 10t84 024/84 Solomnan IWands Eb"gy Am##sument 06/83 4404-SOL South Pacific Petroleum Trnsport in the South Pacific 05/86 - Thailand Enegy A ment 09/85 5793-TH Rural Energy Iues and Options 09/85 044/85 Accleratd Diemination of Improved Stoves and Charcoal Knlns 09/87 079/87 Norteast Region Viage Forestry and Woodfuels Preinveatment Study 02/88 083/88 Impact of Lower Oil Prices 08/88 - Coal Development and Utihzation Study 10/89 - Tonga Energy Asuet 06/85 5498-TON Vanuan EnQ Agy esn 06/85 5577-VA Westrn Samoa Energy AuEent 06/85 5497-WSO SOUTH ASIA (SAS) Etang1slesh Enerqgy AJamu*east 10/82 3873-ED Priority lnvestnet Program 05/83 002/83 Stus Report 04/84 015/84 Power System Efficiency Study 02185 031/85 Small Scale Uses of Onas Prefiosibiity Study 12/88 - - 166- Corly Aed l& Di Nwnbr nia Oppoftunties for Commercialimation of Nonconventiona Enr Sysms 11/88 091/88 M_rashtm Bagass Enery Effiency Project 05/91 120/91 Mini-Hydro Devolopment on Irigaon Dams and Canal Drops Vols. I, II and m 07/v1 139191 Nepal lVA m 08/83 4474-NEP Status Report 01/85 028/84 Pakistan Houseold ery A OS/88 - - - - of Photovoltaic Proginms, Applications, and Markets 10/89 103/89 Sri Lanka E0ergy Assessmen OS/82 3792-CE Power System Loss Reduction Study 07/83 007/83 Stus Report 01/84 010/84 Industrial Energy Consevation Study 03/86 054/86 EUROPE AND CEN ARAL ASUI (ECA) Portugal Energy Ameant 04/84 4824-PO Turkey Ehg AEsnet 03/83 3877-TU MIDDLE EAST ANID NORTH AFRICA (MNA) Morneoo o Amomfmt 03/84 4157-MOR Stat"dus Report 01/86 048/86 Syria Energy Assma05/86 5822-SYR Electric Power Efficiency Study 09/88 089/88 Energy Efficency Iimpvent n the Cmnt Sector 04/89 099/89 Energy Effcimency Improvement i dte Fertilizer Sector 06/90 115/90 Tunisia Fuel Substitution 03/90 - Yemen EnergAy h mes t 12/84 4892-YAR Energy Investment Priorities 02/87 6376-YAR Household Energy Sfttegy Study Phase I 03/91 126/91 LATIN AMERICA AND TIRE CARIBBEAN (LAC) LAC Regional Regional Semiar on Elmec Power System Loss Reduction in the Caribbean 07/89 - Bolivia Enersy m 04183 4213-BO Natonal Energy Plan 12/87 - Nationdl Energy Pln (Spanish) 08/91 131/91 La Paz Privat Por Technical Asdstance 11/90 111/90 Natund Gas Disuibution: EBonomics and Reguaiton 01/92 125/92 Prefeadibility Evaluaton Rurt Elctnficcatin and Demand 04/91 129/91 Caie Enurgy Sectr Review 08/88 7129-CH Colombia y St12186 - Cota Rica E=V Asont 01/84 4655-CR ;n_I Tedrl AsWs_e Poftects 11184 027/84 Forst Reidues Utiliztion Study 02/90 108/90 - 167 - Couon AcdWy Dae Number Dominican E051gy Amsement OS/91 8234-DO Repubb Ecuador Eneg sment 12/85 5865-EC EkYay Stodqgy Fb"8e I 07/88 - EnaVgy Sbadegy 04/91 - dati E0e6g An"t 06/82 3672-HA Status Report 08/85 041/85 Honduras Energy Am M 08187 6476-HO Yetxdeum Supply Managernent 03/91 128/91 Jamaica Emr Ammum 04185 5466-JM Petroeum Pocurement, Refining, and Disribution Study 11/86 061/86 Energy Efficiency Building Code Phase I 03/88 - EneVgy Efficuocy Standards and Labels Phase I 03/88 - lla ye et bnmtion,nad System Phsse I 03/88 - Chaucoal Production Project 09/88 090/88 FIDCO Sawmill Residues Utilization Study 09/88 088/88 Mexico lImroved Carcol Production Within Forest f ofr ths Stat of Veracruz 08/91 138/91 Paunam Power System Efficiency Study 06/83 004/83 Paraguay Energy h mes t 10/84 5145-PA Recommended Technical Aistance Projects 09/85 - Status Reiport 09/85 043/85 P-eu Enwy AesncM 01/84 4677-PE Status Report . 08/85 040/85 Proposal for a Stove Disseinaion Prtogam in the Sierra 02187 064/87 Enegy Stra 12/90 - Saint Lucia Energy Ammmunt 09/84 5111-SLU St Vincent and the Grenadines Energy sessnt 09/84 5103-51W Triidad and Tobago Enfg Assesiat 12/85 5930-TR GLOBAL Energy End Use Efficiency: Research and Stategy 11/89 - Guideines for Utility Customer Mlaemet and Meteing (Englsis and Spanish) 07/91 - Women and Energy-A Resource Guide mm International Network: Policies and Experience 04/90 - Assessment of Pesonad Computer Modebs for Energy Plning in Developing Conties 10/91 - IBRD 23592 TUNISIA MAEDITFRRANtEAN Cienteler . iu/ IVNISIE s.- -> ibi POWER . wf Mh ouruiba foeh3 EFFICIENCY STUDY e-- - v Pan ETUDE DE LAMELIORATION ano e DE L'EFFICACITE .oqa.suI 5cul DU SYSTEME ELECTRIQUE < Zoeho L 4 TRANSMISSION NETWORK SoukIArSlla / OF ELECTRICAL POWER 36* 3z6f RESEAU DE TRANSPORT El Aouinet Tojeroulne / ( SMuue D'ENERGIE ELECTRIQUE _ Wa Cimenbrie nMd i r EN PltOJET ttrNt t Mih ^ei ELECTRIC UNES: LIGNES ELECTRIQUES: _J _- - _ 225kV - 35 KoA! 1 *SOrin, irJiZSidi B0t z\ 33 -~~ 150kV t Manwur --- 90 kVI /. SUBSTATIONS: jPSTES: * 225 W o U ~~~150 kV O i50kzV To 0 '2 \i0hiVGabes POWER PLANTS: CENTRALES Gae ELECTRIQUES: * THERMAL0 THERMIQUE Medenirm , ~J GAS TURBINE TURBINE A GAZ Tton. HYDRO \ fTataounine HYDRAULIQUE -32- 320- SALT LAKES 3 gILACS SAlES I NATIONAL CAPITAL - 31 fbqn0QpwwmeSww s 7 CAPITALE DU PAYS 0 a s v wa-INTRNATIONAL BOUNDARIES vwaWw"' ain'w FRON17ERES INTERNA7IONALE on LI nn n , | KILOMETERS ofayenba 9any0 M J~~~~~~~~ 8; 9 19 2 'VESURY19