Technical and Managerial Development for Raising Efficiency in Dr

UNIVERSITY OF KHARTOUM THE GRADUATE COLLEGE

“TECHNICAL AND MANAGERIAL DEVELOPMENT FOR RAISING EFFICIENCY IN DR. SHARIF POWER STATION”

BY OMAR MOHAMED SALEH BADAY ( B.Sc, M.Sc )

A THESIS SUBMITTED IN FULFILLMENT OF THE REQUIREMENTS FOR THE DEGREE OF Ph.D

2004

Supervisor: Dr. ELSHEIKH ELMAGZOUB

ACKNOWLEDGEMENTS

Acknowledgement and appreciations are due to professor El-Sheikh Elmagzoub for his kind supervision. Also my acknowledgement and appreciations to the staff members, in Dr. Sharif Power Station and other power stations abroad, who gave me enough zeal and gusto to carry out this research.

2 CONTENTS

Page Acknowledgements i Contents ii Summary (English) iv Summary (Arabic) vi List of figures viii List of tables ix Notation x

Chapter

1. Introduction 1 1.1: The objectives of this research 4

2. Conversion of the existing gas turbines’ Simple Cycles in Dr. Sharif Power Station 6 to Combined Cycle. 2.1: Introduction 6 2.1.1: Description of the Power Station Concerned G.Ts. 7 2.1.2: G.Ts Data Specification 7 2.2: Gas-Steam Turbines Combined (Hybrid) Cycle. 8 2.3: Burmeister & Wain Scandinavian Contractor (BWSC) offer for Combined Cycle 9 to the existing gas turbines. 2.3.1: Parts of the Project Work to be done by BWSC 11 2.3.2: Parts of the Project Work to be done by NEC 13 2.4: Study, Modification and Adaptation of BWSC offer, in accordance to Power Station 13 Technical Data. 2.4.1: Additional Supplementary Firing 13 2.4.2: Arrangement for enough Feed Water 14 2.4.3: Arrangement for enough Cooling Water 14 2.4.4: Arrangement for Cooling the Cooling Water 16 2.4.5: NOX Reduction Facility 16 2.5: Combined Cycle Efficiency Estimation by Simulation of Modules 18 2.6: Advantages of Combined Cycle Power Generation. 21

3. Combined Cycle Reliability, Availability and Performance Test. 22 3.1: Introduction 22 3.2: Reliability 23 3.3: Availability 24 3.4: Combined Cycle Performance Test 25 3.4.1: Performance Specifications 26 3.4.2: Responsibilities 27 3.4.3: Test Set-up 27 3.4.4: Measurements 28 3.4.5: Preparations 28 3.4.6: Conduct of Test 29 3.4.7: Combined Cycle Performance Evaluation 31 3.4.8: Acceptance Criteria 35

4. Exploitation of Sudan Refined Fuel Oil In Dr. Sharif Power Station 36 4.1: Introduction 36 4.2: Brief History of Petroleum Survey, Discovery and Production in the Sudan 37 4.3: Type of Sudan Crude Oils According to International Standards. 39 4.4: Refineries Functionalism and Productivity 39 4.5: Specifications of Produced Fuel Oil, Compared to International Specifications. 40 4.6: Evaluation of Refined Fuel Oil usage in the Power Station. 41

3 5. Transfer of New Technologies to Dr. Sharif Power Station For Raising the Efficiency 42 5.1: Introduction 42 5.2: Gas Turbine Air Inlet Chillers. 43 5.2.1: Vapour – Compression Refrigeration 44 5.2.2: Description of the Air Inlet Chillers 47 5.2.3: Effect of the Air Inlet Chillers 49 5.2.4: advantages of the Air Inlet Chillers 50 5.3: Steam Turbine Air-Cooled Condenser 50 5.3.1: Description of the Air Cooled Condenser 51 5.3.2: Performance of the Air-Cooled Condenser 53 5.3.3: Advantages of the Air-Cooled Condenser 53 5.4: Steam Turbine Steam Re-Heating 53 5.4.1: Steam Turbine Unit Operating Data 54 5.4.2: Advantages of Steam Reheating 58 5.5: Steam Turbine Condensate Polishing 58 5.5.1: Actual Operating Conditions & Data 59 5.5.2: Effect of Condensate Polishing 60 5.5.3: Exhausted Resin Regeneration 62 5.5.4: Advantages of Condensate Polishing 64 5.6: Steam Turbine Unit with Flue Gas Electrostatic Precipitator. 64 5.6.1: ESP Components 65 5.6.2: Effect of ESP 66 5.6.3: Advantages of ESP 70

6. Development of Power Station Management 71 6.1:Introduction 71 6.2: Objectives of Power Station Manager 72 6.3: Ways of Leading to be Adopted by Power Station Manager 79 6.3.1: Leading through Motivation 79 6.3.2: Leading through Communication 79 6.3.3: Leading through Interpersonal Skills 80 6.3.4: Leading through group Dynamics and Team work 81 6.3.5: Leading through Innovation and Planned Change 81 6.4: The Warehouse Management 81 6.4.1: Present Warehouse Management. 82 6.4.2: Upgrading of Warehouse Management 82

7. Discussion, Conclusion and Recommendation for future work. 92 7.1: Discussion. 92 7.2: Conclusion. 100 7.3: Recommendation for Future Work 102 References 104 Appendix (A) I

4 SUMMARY

This Ph.D thesis is considered as an extension to the author’s M.Sc thesis “Performance promotion and efficiency improvement in Dr. Sharif Power Station”, which was presented in University of Khartoum in 1997. The M.Sc thesis covered the period from 1994 to 1996, when most of the technical problems appeared in Dr. Sharif Power Station, specially after the commercial run of Phase II Units Nos 3 & 4. The author dealt with scientific methods to solve the power station standing problems in order to promote the deteriorated performance and to raise the already degraded efficiency. The M.Sc thesis showed all the technical and managerial studies that had been carried out by the author in this regard. Those studies are now shown briefly in chapter 1 ‘Introduction” of this Ph.D thesis.

The title of the Ph.D thesis is “ Technical and Managerial Development for raising efficiency in Dr. Sharif Power Station”. While the M.Sc thesis dealt with Remedial studies for promoting the performance, and hence improving the efficiency, the Ph.D thesis is now dealing with development studies for raising the efficiency to higher levels through using modern sophisticated technologies in power generation. The author, in order to fulfill the research objectives stated at the end of chapter 1, has divided his research into four main studies and many subordinate studies, which are all shown under seven chapters, in addition to an appendix covering one technical study been done by the author. At the beginning of each chapter a short summary is written as an introduction to it.

The first main field of study is dealing with conversion of the existing gas turbines’ simple cycles in Dr. Sharif Power Station to combined cycle. This main study represents the most important part of this research. It starts with explaining the gas-steam turbines combined (Hybrid) cycle. It shows the power station GTs data specification. Then it describes in detail the Burmeister & Wain Scandinavian Contractor (BWSC) offer to NEC to convert KNPS simple cycle gas turbines to combined cycle. It shows the parts of the project works to be done by BWSC and by NEC, with all the field research carried out in Dr. Sharif power station (formerly KNPS) to modify and adapt BWSC offer in accordance to the power station technical data. This mainly covers the need for supplementary firing, for enough feed water, for enough cooling water and for enough cooling of the cooling water. A sub-study for NOx reduction facility is also done. The author shows that an estimation has been done to the proposed combined cycle overall efficiency by simulation of modules, where genuine data were fed to a computerized program prepared by the author to identify the raise in efficiency from the simple cycle to the Combined Cycle. A conclusion to the first study shows the advantages of the combined cycle power generation, and a related sub-study has been prepared for proving reliability, availability and performance test of combined cycle.

The second field of study is dealing with exploitation of Sudan refined fuel oil in Dr. Sharif power station. It is divided into the following parts or sub-studies: Brief history of petroleum survey, discovery and production in the Sudan, type of Sudan crude oils according to international standards, refineries functionalism and productivity, specifications of produced fuel oil compared to international specifications, and evaluation of refined fuel oil usage in the power station. A

5 complete field research has been carried out in Dr. Sharif power station covering the exploitation of Al Obeid refinery fuel oil stating all problems and remedies arose from some differences in specifications, but which are in general much less than the first problems arose from Abu Jabra refinery fuel oil.

The third field of study, is dealing with usage of new technologies in Dr. Sharif power station for raising the efficiency. The author in this chapter has got use of his 20 years experience in power generation in the Arabian Gulf Countries, dealing with modern sophisticated technologies. His aim is to introduce them to engineers and planners to use them for development of power generation in the Sudan. Five sophisticated technologies are being field studied with comparison results and are all shown in details as: Gas turbine air inlet chillers, steam turbine air-cooled condenser, steam turbine steam re-heating, steam turbine condensate polishing, and steam turbine unit with flue gas electrostatic precipitator. The advantages of each of these modern sophisticated technologies are included at the end of each field study of them accordingly.

The fourth field of study is dealing with development of power station management. The study stresses on the role of the power station manager, the objectives he has to fulfill and the ways of leadership he has to adopt. The objectives are mostly to reduce costs, to keep good housekeeping, to improve plant performance, to develop the plant, to save money as a result of above techniques and safety techniques. The ways of leadership could be through motivation, communication, interpersonal skills, group dynamics and teamwork, and through innovation and planned change. A part of the fourth study also deals with the warehouse management, where its present situation is shown, then a special sub-study has been carried out for upgrading it to international standard of centralization of supplies department to include in its organization all of the purchasing, stock, and warehouse managements.

The final chapter is divided into discussion, conclusion and recommendation for future work. In discussion the author explains all his contributions in the study works he did in this research. In conclusion the author shows that the objectives of this research have all been fulfilled. In the recommendation for future work the author points out that it remains to carry out revised studies in power planning, covering the power market survey, power forecast for annual demand growth, short-term and long- term power plans, correlation of hydro and thermal power generations, correlation of NEC with Independent Power Plants (IPP) of refineries, cement and sugar factories for buying their surplus generated power, privatization in power generation and role of investments in power generation through the Build, Own and Operate for agreed Time (BOOT) regime after breaking electricity monopoly of NEC, and lastly endeavor to reduce cost of generated power by using sophisticated power technologies.

8 LIST OF FIGURES

Sl# Fig Description Page #

1. Fig (2.1)- Schematic flow diagram of a combined cycle. 10 2. Fig (2.2)- Gas-steam turbines combined (or Hybrid) cycle with 10 supplementary firing. 3. Fig (2.3)- Schematic diagram of BWSC combined cycle offer 12 4. Fig (2.4)- Proposed C.W design of combined cycle unit 17 5. Fig (2.5)- C.S. Power output versus fuel flow 21 6. Fig (5.1)- Schematic diagram of refrigeration system 45 7. Fig (5.2)- Vapour compression refrigeration cycle 45 8. Fig (5.3)- Inlet air cooling system (TESTIAC)- 48 9. Fig (5.4)- Air Cooled Condenser 52 10. Fig (5.5)- Rankine cycle with different steam pressures 55 11. Fig (5.6)- Rankine cycle with stem re-heating 55 12. Fig (5.7)- Heat balance of the condensate/steam cycle 57 13. Fig (5.8)- CPP operation relevant to three CPUs. 61 14. Fig (5.9)- Step No.1 Receive exhausted resin charge from M.B. 63 15. Fig (5.10)- ESP internal parts for dust removal 67 16. Fig (5.11)- Dust collection from flue gas 69 17. Fig (6.1)- Typical electric power utility organization structure 89

LIST OF TABLES

Sl# Table Description Page #

1. Table (4.1)- Al Obeid refinery fuel oil specification. 40

2. Table (5.1)- The effect of the air inlet chillers 49

3. Table (5.2)- Raw condensate analysis 60

4. Table (5.3)- Treated condensate analysis 60

5. Table (5.4)- HFO Specs. And resultant data 66

6. Table (5.5)- HFO sampling and test results 68

7. Table (6.1)- Stores requisition/return 91

NOTATION

A/H Air Heater ACC Air Cooled Condenser ARR Accounting Rate of Return ARV Anion Regeneration Vessel BMCR Boiler Maximum Continuous Rate BOOT Build, Own and Operate for agreed Time BTU British Thermal Unit BWC Boiler Water Circulation BWSC Burmeister & Wain Scandinavian Contractor C.W. PUMPS Cooling Water Pumps CCR Central Control Room CHP Combined Heat & Power CPD Compressor Discharge Pressure CPP Condensate Polishing Plant CPS Condensate Polishing System CPU Condensate Polishing Unit CRV Cation Regeneration Vessel CST Cent stock ERS External Regeneration System ESP Electro-static Precipitator F.D.FAN Forced Draught fan G.R.FAN Gas recirculation fan G.T Gas Turbine GCV Gross Calorific Value GHR Gross Heat Rate GJ Gega Joule GOR Gained Output Ratio H.P High Pressure HPV High Pressure Vessel HR Heat Rate HRSG Heat Recovery Steam Generator HVAC Heat, Ventilating & Air Conditioning I.D.FAN Induced Draught fan IPP Independent Power Plant KNPS Khartoum North Power Station

11 kVA Kilo Volt Ampere kW Kilowatt kWh Kilowatt hour L.P Low Pressure LMTD Log Mean Temperature Difference LPV Low Pressure Vessel MCR Maximum Continuous Rate M&HV Mixing & Holding Vessel M.B Mixed Bed MEPA Meteorological Environmental Protection Association MJ Mega Joule NEC National Electricity Corporation P.O Pass Out ppm Parts per million PR Performance Ratio RTD Resistance Temperature Detectors RW Redwood S.G Specific Gravity S.T Steam Turbine SR Saudi Riyal T/h Ton per hour TBT Top Brine Temperature TDS Total Dissolved Solids TMCR Turbine Maximum Continuous Rate U.V Ultraviolet W Power Output XLPE Cross-link Poly-Ethylene µg Microgram µS Microsimens Η Efficiency

12 Chapter 1

INTRODUCTION

The present thesis is a research in the power generation field, specially in Dr. Sharif Power Station. The author in the present research has got use of his long experience in this field in the Sudan as well as abroad, where ultimately he dared to cope with modern sophisticated technologies in power generation.

The author targeted from this thesis to reduce the generated power cost, and in the same time, to raise the efficiency of the generating units to higher levels – through practicing modern sophisticated technology that he aimed to introduce and transfer to the Sudan.

As a product of a large number of processes, the electrical power generation represents about 30% of the initial energy of the primary fuel used. This is a very low figure, and partly explains the high cost of electricity compared with other sources of energy

The electrical power generation is a result of processes of energy conversion. The chemical energy of fuels is converted to heat energy in the furnace or combustion chamber, which in its turn is converted to mechanical energy in the prime mover (e.g. gas turbine, steam turbine or diesel engine) which rotates the rotor of the generator, where it is converted to electrical power. During this process a large number of energy is dissipated as heat in the cooling water and in the exhaust gases, as we will see later.

In the early 1970s an oil crisis took place due to the Middle East war of 1973. The prices of oil shot up from US$ 3 per barrel of oil to US$ 30 per barrel. Due to high cost of fuel, which represents at present 70% of the total electrical power generation cost, the energy conversion in power generation process has become more essential for efficient operations. The modern technology in power generation has led to efficiency improvement, and hence has led to running cost saving, e.g. using energy recovery methods leads to financial gain by reducing the cost of electricity production, and mainly by reducing fuel consumption. Through history the thermal efficiency has increased from 5% for the old steam engine to 30% for the gas turbine and to 33% for the steam turbine and finally to 52.5% for the combined cycle. The gas turbine and steam turbine efficiencies can be more raised by utilizing sophisticated technologies, e.g. air inlet chillers for gas turbines, and steam reheating for steam turbines, as we see later.

The electrical energy consumed by a nation is directly proportional to its standard of living or its Gross National Product. For example, the under-developed countries use about 0.5 kW per person, compared with a rate in the developed world of between 5 and 10 kW per person (ref. 5).

The subject matter of the authors M.Sc also dealt with Dr. Sharif Power Station, but from different aspects other than what will appear in the present Ph.D thesis. It is beneficial to show briefly herewith, the aspects of the M.Sc thesis in order to create a general concept to the reader about Dr. Sharif power station progress.

In the author’s M.Sc thesis “Performance Promotion and Efficiency Improvement in Dr. Sharif Power Station”, which was presented in the University of Khartoum in 1997, the author stated that in large power stations, the power plant performance and efficiently control have become very important. In order to promote the operation staff performance, reference was made to the instruction manuals of Phase I & Phase II, and all the procedures of plant operation were extracted, then more points were added from the author’s previous experience to stress on checking and monitoring. The result was the preparation of operating procedures for Phase I boiler cold start and shut down, Phase I turbine cold start and shutdown, Phase II units (boiler + turbine) cold start and shut down, units auxiliaries operating procedures, Phase I units isolation procedures and Phase II units isolation procedures. All these operating procedures were distributed to all shift engineers and operators and were very helpful to them. In order to evaluate the plant performance and to endeavor for its improvement, a standard module of results is to be used as targets. These optimized results were gained at the time of initial performance tests when the plant units were new.

The power plant troubles and modifications were given a full chapter in the M.Sc thesis. Actually, this part of the research showed in statistical methods all the operational and maintenance main troubles that took place and analysed these methods in a scientific way, drawing towards the causes, and investigating about the faults, in order to reach the solutions and to prevent the faults to repeat again. The incidents of the units major breakdowns were taken in details from the operational and maintenance sides, and the modifications –if any-were also stated. All the data collections, analysis, studies were mostly done by the author.

A part of the M.Sc research dealt with the usage of Sudan fuel oil from Abu Jabra refinery in Dr. Sharif Power Station, which was formerly, using the imported furnace fuel with specifications close to the boilers’ fuel specifications. Abu Jabra furnace fuel has some deviations from the contractual specifications. This made the power station authority to conduct some studies and practical tests and to carry out some modifications.

Some unloading problems faced the usage of Abu Jabra fuel oil, mainly because of the high wax content, which represents about 20% by weight of fuel oil, and made the viscosity to be high. This problem of unloading from the railway and road tankers was temporarily solved by direct steam heating through hose connection. The direct steam heating created many problems in the fuel oil tanks, as water draining from time to time was required. This water sometimes reached the burners and caused flame troubles and trips. Later, Sudan railways were directed to fix steam coils for all the fuel tankers they deliver to the power station. Also they were directed to standardize their flange sizes of the steam coils, as they have different tankers with different flange sizes according to their manufacturers. The electric trace (or surface) heating was provided to the common fuel headers, to fuel filters, to transfer pumps, to the interceptor and to the fuel line to the fuel oil tanks. The fuel tanks were supplied with steam coil heaters. Other problems in this area continued to exist, like the fuel filters frequent blockage because of wax, and fuel pumps mechanical seal erosion due to impure deliveries.

14 In order to fire Abu Jabra fuel oil through the burners, its viscosity has to be close to the imported fuel viscosity of 68 R. W, as mentioned before. This imported fuel viscosity was reached when it was heated by steam to a temperature of 105 0C. The maximum auxiliary steam temperature (heating steam) is 130 0C. So, the viscosity of Abu Jabra fuel had to be experimented with various steam heating temperatures up to 130oC. This was experimented in the chemical laboratory in the power station. According to the temperature/viscosity graphs, the results proved to be positive when blending Abu Jabra fuel oil with imported fuel oil. It was proved that there was no harm appeared from burning large quantities of wax, as all of it is burnt out without deposits, only the quantity of ash became more. This required to operate soot blowing frequently. The erosion of fuel pumps mechanical seals and burners tips were quite noticeable, and maintenance/replacement of these parts were taking place.

The technical information and statistics chapter dealt with records discipline and management, along a period representing the life of the power station, say along 20- 40 years. Any long-term business will be influenced by its own history (as records) and the expected future (as statistical plan). In a large power station, it is necessary to plan and progress about 2,500 items, of work per month. In order to do this effectively, in 1995 the station management succeeded to enter a computerized system and immediately started using it.

The cost of electric power generation was dealt with in a separate chapter in the M.Sc thesis. The kWh cost in a power station is known by the overall calculations of the fixed and variable costs for a specific period of time, to add them together, and then to divide the total by the total units generated at the same specific period of time.

The fixed (or capital) cost is the total cost of land, buildings, machines, equipment, and installation, designing and planning. This cost was divided by the stipulated period, which represented the depreciation of the plant, where after a certain period of useful life, the plant loses its efficiency or becomes obsolete and needs replacement. For example, for steam units the stipulated period is given as 20 years, for gas turbines it is 10 years, for diesel generators it is 15 years. Out of this period, the cost per month could be obtained. The fixed cost also included the insurance, which was calculated as agreed percentage from the capital cost, after considering the depreciation. Taxes on land and property have to be considered, but in this case, and due to government rules, the land and property are tax-free.

The variable (or running) cost includes the cost of fuel used, cost of spare parts, cost of chemicals, cost of salaries & wages, cost of transportation & garage, cost of electric power used by auxiliaries, and make up water cost, which in this case, is considered negligible. In steam power stations, the depreciation is taken as 4.5% to 5% annually. The insurance is taken as 1.0% to 2.0% annually. In large power systems, the cost of distribution and the overhead lines plus the expenditure of the office and sales organization may increase the charge to the consumer per kilowatt hour to about 2.5 to 3.0 times the cost at the power station. The method of charging consumers is known as tariff, or rate of payment for the consumption of electricity.

The kWh cost calculation method was introduced by the author in 1992 in Khartoum North power station and in other large power stations of N.E.C. Formerly the kWh cost was calculated by the fuel consumption cost divided by the total units generated, which gave inaccurate result. In April 1996, when the cost of electricity generated was calculated, the kWh cost came to be equal to 61.0 LS/kWh or 0.055 US Dollar/kWh, according to the exchange rate at that time of 1 US$ = 1,100 LS.

The management development in the plant was dealt with in a separate chapter. According to many managerial problems that took place in the power station, and made the re-organization task as a national demand, the station manager selected a performance promotion committee headed by the author, in March 1994. The objectives of the committee were to study all the problems and drawbacks, and to create a system for solving these problems. An annual plan for the staff training was prepared, and the required co-ordinations with Um-Haraz training center were done. The author also prepared a course in the above training center on “Power Plant Performance and Efficiency Control”, and started teaching it to many groups of generation engineers, inside and outside NEC.

1.1 The Objectives of The Research

The objectives of the present Ph.D thesis, according to its title, are stated as follows:

1- To reduce the power generation cost in Dr. Sharif power station and to raise the efficiency in the same time by using the modern sophisticated technology in power generation .

2- To economize the fuel consumption and to gain money saving in Dr. Sharif power station .

3- To look forward for a continuous uniform flow of power generation in Dr. Sharif power station through engineering management

17 Chapter 2

CONVERSION OF THE EXISTING GAS TURBINES’ SIMPLE CYCLE IN Dr. SHARIF POWER STATION TO COMBINED CYCLE.

2.1 Introduction

The author, in order to be cognizant with the combined cycle theory and technology, made many contacts through the book shops and internet system to get the text books that deal with this subject. He also subscribed in the Gas Turbine magazine and in the Power magazine in addition to the British Institution of Mechanical Engineers (I. Mech. E) magazine, as he is a member of this international institution. The author gained huge experience during his work as a consulting engineer in the combined cycle power plant No. 9 project in the kingdom of Saudi Arabia, for a period of five years. The author believes that the combined cycle system is an ideal method of power generation, due to its sophisticated modern technology, that deals mainly with power generation economy, accompanied by high power outputs and resultant high overall thermal efficiencies.

When the author prepared his proposal for his Ph.D thesis to the university of Khartoum in October 2000, he tended to include the combined cycle technology for the above positive reasons and to introduce it and eventually transfer it to the Sudan in building new power plants. Before the time of commencing the presentation of this thesis, two new blocks of combined cycle units were installed and commissioned in Garie power station. Each block consists of two gas turbines plus one steam turbine with capacities equal to 2 x 41 MW + 40MW. The first block came in service in November 2003, while the second block came in service in December 2003. Garie is a new power station and is still under the contractor’s warranty. The new existence of the Combined Cycle in the Sudan will be enhanced by the information in this chapter and will not by any means degrade its anticipation and importance.

Dr. Sharif power station started as a pure steam (turbine) power plant, then in 1992 two gas turbines were installed in the power station by the Burmeister & Wain Scandinavian Contractor (BWSC). When the work completed, BWSC submitted an offer to NEC to supply and install two Heat Recovery Steam Generators (HRSG’s) and one Steam Turbine and other auxiliaries to convert the gas turbines simple cycle to combined cycle, while the rest of the combined cycle work was left to be provided by NEC.

The author took this offer for its low cost, and carried out a comprehensive research for fulfilling the requirements of NEC part in the Combined Cycle Construction from the available power station capabilities in fuel and cooling water supplies and in cooling facilities for the cooling water. The result was positive and hence, was more economical to NEC. The author had worked for five years in Dr. Sharif power station as efficiency and planning chief engineer and was quite aware of the power station layout and technical details.

18 The methodology that the author followed in preparing this chapter could be configurated as describing the existing two simple cycle gas turbines to be converted to combined cycle, to state their technical specifications and data. Then to describe the BWSC offer to NEC for the Combined cycle conversion, showing the parts of work to be done by BWSC and by NEC. Then comes the main part of studying, modifying and adapting the BWSC offer in accordance to Dr. Sharif power station technical data, a study work which is virtually deserving to be considered as a field design and construction research. The effect of the combined cycle in power generation economy, and hence, in raising the overall efficiency to high levels was shown in this chapter through a computer program prepared by the author for simulating the variable data according to the gas turbines loading and equivalent fuel consumption as well as steam turbine loading, in order to calculate the efficiencies. The author showed in the methodology he followed how to reduce the adverse effect of the exhaust gases in the environment through the injection of steam from the steam turbine to the gas turbines Combustion chambers. Then lastly the author ended this chapter by stating the advantages of the combined cycle power generation.

Combined cycle power plants are those, which have both gas and steam turbines supplying power to the network. The idea of combined cycle has grown out of the need to improve the simple Brayton cycle efficiency by utilizing the waste heat in the turbine exhaust gases. The large quantity of energy leaving with the G. T exhaust is used to generate steam for a steam turbine operation.

The first combined cycle plant was installed in 1950, and then this technology took a great development with many installations in the 1970s, when the generation economy became important. This appeared to be the result of October 1973 war in the Middle East, which made the oil price to shoot up from $3/ barrel to $30/ barrel.

2.1.1 Description of The Concerned G.Ts

In 1984/85 the National Electricity Corporation (N.E.C.) was granted a gas turbine plant for an extension of Khartoum North Power Station (presently Dr. Sharif Power Station) as a gift from the Italian government. The gift consisted of two production units each with a gas turbine connected to a generator through a reduction gear and related auxiliaries, such as coolers, filters, transformers etc.

In 1986 the equipment started to arrive. In 1991 N.E.C. signed a contract with Burmeister and Wain Scandinavian Contractor (BWSC), the Danish contractor. BWSC was assigned to perform the supervision of the installation and commissioning of the gas turbine power station. The immediate need for power made BWSC to expedite implementation of the project in approximately nine months. In the summer of 1992 the two new gas turbines were connected to the grid in Khartoum.

2.1.2 G.Ts Data Specifications:

Total output- 2 x 21 MW on base-load. Gas turbine – General Electric (GE) MS5001 (known as frame5)

License builder, NUOVO PIGNONE.

Fuel, gas oil

Generator- Ansaldo T-2, 22,963 kVA 50 HZ, 11kV Power factor 0.8

Reduction gear – Parallel shaft gear unit type VF63R Max. Power transfer, 35,000 kW Speed turbine side, 5,100 rpm Speed generator side, 3,000 rpm

Fuel oil tank- 2,000 m3

Line transformer-

OEL Italy 33/11 kV 22,963 kVA

Air filters- Donaldson 498 numbers of single filter elements per Unit.

DC-System Seira Electronic Industrial 110VDC

2.2 Gas-Steam Turbines Combined (Hybrid) Cycle:

A schematic diagram of a combined cycle with supplementary firing is shown in Figure (2.1). In correlation to the schematic diagram, a Gas-Steam turbines combined (or Hybrid) cycle is also shown in figure (2-2). These both figures have been modified by the author to include the supplementary firing as shown in section (2-4).

A gas turbine cycle, consisting of air compressor (AC), and combustion chamber (CC), and gas turbine (GT) is used with the turbine exhaust gas going to a Heat Recovery Steam Generator (HRSG) to generate superheated steam. This steam is used in a steam cycle, which consists of steam turbine (ST), condenser (C), condensate pump (CP) and feed water heaters (FWHs). The HRSG consists of economizer (EC), evaporator (EV), steam drum (SD), and superheater (SU). Both steam and gas turbines drive electric generators (G). The gas turbine is operated with a high air/fuel ratio in order to keep sufficient air for supplementary firing. The gas turbine is assumed to be running continuously. If the GT load is high, then the exhaust

20 gas temperature will be high, and hence through the HRSG, the heat transferred to water/steam will be more, and load on the ST will be more, without requiring supplementary firing. During medium and low loading of GT, the ST generating capacity will drop. To avoid such ST capacity drop during GT. low loading or during shut downs, supplementary firing will be required. The type of fuel for the supplementary burners, for economy, may be heavy fuel oil (HFO).

Referring to figure (2.2) T-S diagram, the combined cycle efficiency will be equal to (h3-h4) – (h2-h1) + (h7-h8) – (h10-h9) ηc = (h3-h2) + (h5-h4)

2.3 Burmeister & Wain Scandinavian Contractor (BWSC) Offer for Combined Cycle to the Existing G.Ts:

BWSC offer for combined cycle to the existing G.Ts in Khartoum North power station (presently Dr. Sharif Power Station) was issued to N.E.C. on 17/1/1992. This budget proposal was made for turn Key delivery of a combined cycle plant of 27,820 kW, built as addition to the existing 2 gas turbines of approximately 21,000 kW per each. The budget prices were based on delivery of hardware C.I.P. Khartoum, incoterms 1990. Harbour fees, taxes fees, custom duties and any other duties in the Sudan are assumed covered by N.E.C.

All the electrical system, including a 34.8 MVA, 11kV alternator, 35MVA, 11/33 kV step up transformer, switch gear, control panels---are included in this proposal.

The proposal also includes the erection and commissioning. The budget price was DKK 122,125,000 (say Danish Kroner one hundred twenty-two million one hundred twenty-five thousand), which at present currency exchange is equal to 19,881,950 US Dollars.

According to the above proposal, some part of the work will be done by BWSC, while some other part has to be done by NEC.

The validity of this proposal is 90 days from the date of issuing it, while the guarantee period is given by BWSC as 12 months from the date of commissioning, or maximum 18 months from the date of delivery.

The author’s remarks on BWSC above offer are that, Firstly, the budget price is quite reasonable. Normally, contract prices are measured in the range of 0.8 – 1.2 million US Dollars for every MW, depending mostly on generating Units size, type of origin and competition as well as the size of the plant infrastructure. In this case we have to consider of course, that some part of the installation work has been left to NEC, as we will see later in details. Secondly, the validity of this offer, as we saw, is 90 days from the date of issuing it, i.e. from 17/1/1992. Hence, it is required to extend this offer, and if possible, to keep the prices conditions unchanged. Thirdly, the guarantee period is given by BWSC as 12 months from the date of commissioning, or maximum 18 months from the date of delivery, but it would be better to change the

22 guarantee period to 12 months from the date of the provisional acceptance of the Unit, after completing the commissioning period. Fourthly, the 2 gas turbines are assumed to be running continuously at full loads, (100% MCR), in order to supply the 2 heat recovery steam generators (2 HRSGs) with exhaust gases having the following O parameters: Temperature 500 C, pressure 4 inch H2O, flow 443,630 kg/h, and speed 80ft/sec. The cooling water temperature is considered as 25OC. This means that the 2 G.Ts must be available and running at full loads all the time, in order to satisfy the steam turbine full generation, or otherwise, its generating capacity will drop. To avoid this problem during G.Ts lower loading or during shut downs, supplementary firing is required, i.e. to install 2 burners for each HRSG in order to raise the exhaust temperature to the required level. During normal operations of both G.Ts at high loads, the supplementary burners will be out of service. During lower loads of both GTs one burner for each HRSG may be enough for operation. During shut downs of both GTs both burners will be in service. The type of fuel for the supplementary burners will be the same like the existing fuel for steam Units, i.e. furnace fuel with provision of heaters. One F.D fan per HRSG will be required for supplying enough excess air for combustion, specially during GTs low loads and shut downs. Normally GTs have got excess air due to high air/fuel ratio, and hence, during GTs moderate and high loads, supplementary burner may operate without F.D fan operation.

2.3.1 Parts of The Project Work to be done by BWSC

According to BWSC offer and referring to its schematic diagram on figure (2.3) BWSC should provide and install the following parts:

1- Two diverter dampers at the GTs exhaust gases stacks, to divert the exhaust gases either to the HRSGs during combined cycle operation or to the GTs stacks during the simple cycle operation.

2- Two exhaust gases ducts joining the GTs stacks through the diverter dampers to the HRSGs inlets.

3- Two HRSGs with two L.P drums (economizers), two H.P evaporators, two L.P evaporators, two H.P superheaters, two L.P superheaters, two H.P drums, two exhaust gases stacks, one F.W tank/de-aerator, four feed water pumps, four H.P drums circulating pumps, 4 L.P drums, circulating pumps, both HRSGs steam safety valves, H.P & L.P steam lines and main headers to H.P & L.P turbines.

4- Two H.P & L.P main steam dump lines to L.P condenser.

5- One H.P turbine cylinder, with steam extraction to GTs combustion chambers to reduce NOx.

6- One L.P. tandom turbine cylinder.

7- One turbine generator reduction gear.

8- One generator with exciter and coolers.

24 9- Two air ejectors with complete system.

10- Two gland steam exhausters with complete system.

11- Two condensers. 12- Two condensate extraction pumps.

13- One 11/33 kV step up transformer. 14- Switch gears. 15- Control panels.

As shown in figure (2.3) BWSC have not provided supplementary firing or feed water heaters. The commissioning of the combined cycle is also a part of the project work to be done by BWSC. This includes the pre commissioning and commissioning of the combined cycle components, in addition to the performance test of the combined cycle as a whole to trig the project’s output and heat rate guarantees.

2.3.2 Parts of The Project Work to be done by NEC.

As per the above proposal, the NEC duties are:

1- To carry out the civil work for installation.

2- To arrange for enough treated demineralized feed water for the steam production.

3- To arrange for enough cooling water for both condensers, alternator, lube oil cooler and auxiliaries sealing and cooling water.

4- To arrange for cooling the cooling water.

2.4 Study, Modification and Adaptation of BWSC Offer, in Accordance to Dr. Sharif Power Station Technical Data:

The author has carried out a practical field study for BWSC above offer, with all technical aspects being included. The author’s comprehensive research in this matter has led to a final result that the offered combined cycle could be installed and utilized with the existing capabilities and resources in the power station, but with some slight modifications, as we will see below. This feasibility study includes the following:

2.4.1 Additional Supplementary Firing.

It has been discussed in chapter (2.3) that during G.Ts lower loading or during shut downs, Supplementary firing is required, i.e. to install two burners for each HRSG in order to raise the exhaust temperature to the required level to operate the steam turbine at full load. During normal operations of both G.Ts at high loads, there will be no need for supplementary firing, so both the burners in each HRSG will be

25 out of service. Practically the operation of supplementary burners will be only during abnormal operation or shut down of G.Ts. A fuel line will be connected from the fuel transfer pumps discharge header to Phase I Units. The fuel flow to the supplementary burners is expected to be intermittent with short time durations. A fuel heater will be installed upstream the supplementary burners to create proper viscosity for perfect combustion. The new Phase I fuel transfer pumps can maintain fuel flow of 20 T/h with 2 pumps in service to the fuel oil header for both Units No.1 & 2, while the third pump remains standby. This fuel flow is more than the maximum flow needed for both Phase I Units, i.e. more than 16.8 T/h. So, a fuel flow margin can be easily utilized for the combined cycle. Even when more fuel flow is required during G.Ts shut downs, the third pump can be started. The fuel oil header pressure can be controlled to the optimum pressure of 26 bar through the pressure control valve and fuel oil return line. It is expected that the cost of fuel to be used will be much less than the cost of the extra power gained from the steam turbine, when converted to money through electricity tariff. It is suggested by the author to install one F.D fan for each HRSG to blow in air for fuel combustion at the supplementary burners. Actually, G.Ts have always got enough excess air, as they have high air/fuel ratios (15: 1 as shown before) and about 60% of the compressed air goes as secondary air for cooling turbine blades and hot gas path, and after that it joins the hot gas at the exhaust diffuser. Hence, the F.D fan will be started only during the G.Ts low loading or during their shutdowns.

Therefore, there will be enough fuel oil flow from the power station resources, to supply the supplementary firing of the combined cycle.

2.4.2 Arrangement for Enough Feed Water.

A new demineralized water plant has been installed in Dr. Sharif Power Station for supplying both Phase I and Phase II with make up water. The demin plant consists of two units, with capacity 2 x 50 m3/h.

Let us calculate the make up water consumption for Phase I and Phase II Units:

Phase I steam unit make up water consumption is 5m3/h, while the same for Phase II steam Unit is 10 m3/h so, the total Phase I and Phase II Units make up water consumption is 2 x 5 + 2 x 10 = 30 m3/h The combined cycle expected make up water consumption, according to steam flow is < 5m3/h.

The total plant make up water consumption will be = 35 m3/h, while the make up water produced by the demin plant is 100 m3/h. Therefore, there will be enough make up water from the power station resources, to supply the proposed combined cycle Unit.

2.4.3 Arrangement for Enough Cooling Water.

In Phase I, four cooling water pumps were installed for both steam units Nos. 1 & 2. During units Nos. 1& 2 operation, two pumps will be enough in service for

26 both units, while the other two pumps will be standby. The four C.W pumps are connected to one discharge header with interconnecting isolating valve to enable each unit C.W pumps to run independently, or to enable the four pumps to run jointly. Each C.W pump flow is 7,310 m3/h. So, when two C.W pumps are running during normal operation, the C.W discharge header flow will be 14,620 m3/h. The condenser C.W flow in each unit is 6,500 m3/h. So,

3 C.W flow in units Nos.1 & 2 Condensers = 13,000 m /h C.W flow in units Nos.1 & 2 Generators’ Coolers, lube oil coolers & CCW Coolers = 1,000 m3/h Total Phase I C.W flow =14,000 m3/h

In Phase II, four C.W pumps were installed at the same order like Phase I. Each C.W pump flow is 9,964 m3/h. So, when two C.W pumps are running during normal operation; the C.W discharge header flow will be 19,928 m3/h. The condenser C.W flow in each unit is 8,640 m3/h. So,

3 C.W flow in units Nos3 & 4 Condensers = 17,280 m /h C.W flow in units Nos3 & 4 Generators’ Coolers, lube oil coolers & CCW coolers = 2,000 m3/h Total Phase II C.W flow = 19,280 m3/h

Let us calculate the proposed combined cycle C.W flow:

C.W flow in Condenser given by BWSC = 10,000 m3/h C.W flow in Combined cycle generators’ Coolers, lube oil coolers & CCW coolers = 1,000 m3/h Total Combined cycle C.W flow = 11,000 m3/h

The expected total C.W flow = 14,000 + 19,280 + 11,000 = 44,280 m3/h

Now, to satisfy this amount of C.W flow, the author suggests that a separate C.W header is to be installed for the combined cycle unit, with two C.W lines connecting this header to Phase I and phase II C.W headers, with all required isolating valves installed as shown in figure (2.4). Then a similar design will be installed to connect back the C.W to Phase I & Phase II cooling towers.

During all Units of Phase I, Phase II and combined cycle operations, it is suggested to run three C.W pumps on each phase and to keep one C.W pump on each phase as standby. In this case the total C.W. flow in both phases I & Phase II headers will be 3 x 7,310 + 3 x 9,964 = 51,822 m3/h

While, the expected total C.W flow = 44,280 m3/h

The C.W headers pressure is controlled to the optimum pressure of 2 bar, through the dump valves to Phase I and Phase II cooling towers’ sumps.

Therefore, there will be enough C.W flow from the power station resources, to supply the proposed combined cycle Unit.

27 2.4.4 Arrangement for Cooling The Cooling Water

The cooling water, when passing through the condensers and other coolers, gains more heat and hence, it is cooled in the cooling water towers, so as to repeat its cooling cycle. The cooling towers inlet C.W temperature is about 34oC, while the cooling towers outlet C.W temperature is about 29oC. There are six fans installed in phase I cooling tower to cool the cooling water for units Nos. 1 & 2. Normally four cooling fans are in service, while the remaining two fans are standby. The same number of cooling fans were installed in Phase II cooling tower but of course, with larger sizes. Also four cooling fans are normally in service for both Units Nos. 3 & 4, while two fans are standby. When connecting cooling water to the combined cycle Unit, and according to the extra flow, one more fan from each phase is to be started, making ten fans to be in service, five from each phase, while one cooling fan from each phase will remain standby. The Combined cycle C.W flow could be adjusted between Phase I & Phase II cooling towers.

Therefore, here also, there will be enough cooling fans from the power stations resources, to cool the cooling water for the proposed combined cycle unit.

2.4.5 NOX Reduction Facility

The BWSC offer on figure (2.3) includes a steam extraction from steam turbine H.P cylinder to both gas turbines combustion chambers. This steam will be used for NOX reduction. NOX is recognized as a major source of environmental pollution.

During combustion of fuel in a gas turbine combustion chamber, nitrogen oxides (NO) form within the immediate vicinity of the flame zone by oxidation of both atmospheric nitrogen and any nitrogen contained in the fuel. These sources of nitrogen produce two distinct types of NOX known respectively as Thermal NOX and Fuel NOX.

In thermal NOX the formation of nitrogen oxide via the thermal fixation of atmospheric nitrogen, is produced by a highly temperature sensitive reaction. The rate of formation is dependent on the reaction temperature and is proportional to the square root of oxygen concentration. For low nitrogen content fuels, such as gas oil and natural gas, thermal NOX is the major contributor to overall NOX emission. The thermal NOX fixation rate can be reduced by limiting the amount of oxygen available to the fuel, or by reducing the combustion temperature. For this reason intermediate pressure (IP) steam or hot condensate is used to reduce the amount of secondary air and to reduce combustion temperature, and hence, NOX emission will be reduced. The oxygen in air will be used mostly for carbon dioxide (CO2) formation, while a limited part of it will react with Nitrogen to form NO, which in its turn when exhausted to atmosphere it reacts with air and humidity to form nitric acid and Acid Rain. NO2 + H2 O Î HNO3

Analysis for NOX and O2 content will be done by using an electronic test gas analyser that provides continuous output.

29 The specifications of the pollutant emissions, as per the Meteorological and Environmental Protection Associations’ (MEPA) standards are limited as follows:

1. Nitrogen Oxide, NOX = 130 nanogram/Joule (for F.O) and NOX = 80 nanogram/Joule (for Gas)

2. Sulphur dioxide, SO2 = 1000 nanogram/Joule Sulfer is limited by fuel refining while SOx emission is directly equivalent to the sulphur content in the fuel. To reduce SOx if required, a flue gas desulphurization system (FGDS) to be installed before the stack.

3. Total Sticking Particles (TPS) = 43 nanogram/Joule

2.5 Combined Cycle Efficiency Estimation by Simulation of Modules:

In the combined cycle units operation, any change in the gas turbines loading from base loads to part loads will result in equivalent change in the steam turbine loading and consequently in the fuel consumption. These three variables are the constituents of the efficiency calculation for the combined cycle. In many cases due to load requirements, most of the efficiency and protection tests are being carried out by simulation through computer programs.

The computer simulated process is described by means of modules. A module represents a well defined part or component in a physical process. The modules consist of arrangements of calculation level elements and their mutual connections mapped onto a computational network, and the process model can be simulated and modified without any program recompilations. The combined cycle plant simulation can be divided into two types according to the requirements.

1. Design simulator application for process automation testing by the designer.

2. Analysis simulator application for operations training, performance testing and efficiency controlling. It could be used in some special cases to investigate the behavior of the cycle during abnormal operations, such as alarms, trips sequence monitoring , curves, logs.

Some international programs (software) are being used for the combined cycle simulation, but all of them are protected by copy rights. The author shows in this regard two internationally reputed programs:

1. The Advanced Process Simulator (APROS) is a general purpose simulator environment with a highly developed user interface and tools for model development. It is used to simulate nuclear, conventional power, combined cycle plants, distillation, recovery boiler, district heating and natural gas grid plants.

2. The American Society of Mechanical Engineers (ASME) simulator is a special program for combined cycle plants.

30 The working process and terminologies of these international programs can be concisely stated as:

CP – The calculation process is the program that executes all user – written applications.

GT ETD’s – The gas turbine enthalpy temperature detectors are including the following components.

i) GT Gas, This module computes the thermodynamic variables around the G.T (Compressor & Turbine) ii) GT EFF, The GT Gas Thermal efficiency. iii) GT EXP, the expected thermal efficiency which is computed with a design curve in function of the GT load.

HRSG ETD’s – They compute the thermal efficiency of the HRSG and its constituent components and compare it to the expected efficiency based on a design curve with the GT exhaust temperature and the ambient temperature as a parameter.

ST ETD’s –They do the performance monitoring for the major components of the steam cycle, such as the steam turbine, the condenser, the cooling tower, etc.

Plant ETD’s – They perform the plant – wide efficiency calculation.

These international programs are well equipped with design curves, correction curves and degradation curves, in order to draw the test conditions to the reference conditions.

As we know, the simple cycle base load efficiency of a gas turbine is about 30%, while the same of a steam turbine is about 33%. When both GT & ST are combined together, the combined cycle efficiency will raise to about 45%. Actually a record for a combined cycle efficiency reaching 52.5% has been achieved in the United Kingdom in Drakelow power plant. (ref. 11).

The efficiency of the combined cycle without supplementary firing is equal to

3600 (WGT + WST) ηcc = x 100% QF x Gcv

The efficiency of the combined cycle with supplementary firing is equal to

3600 (WGT + WST) ηcc = x 100% QF1 x GCV1 + QF2 x GCV2

Where

WGT - G.T output, in kw. WST - Steam turbine output, in kw QF1 - Fuel flow of gas turbine, in kg/hr QF2 - Fuel flow of supplementary firing, in kg/hr

31 GCV1 & GCV2 -Gross calorific values of each type of fuel, in kJ/kg.

The author, in order to monitor the expected efficiency in the proposed combined cycle in Dr. Sharif power station, he logged some actual parameters of the gas turbines on variable loads as follows:

1 The G.T. fuel consumption on Full Speed No Load (FSNL). 2 The G.T. fuel consumption on half load. 3 The G.T. fuel consumption on full (base) load.

The GT full load is 21 MW, and half load is 10.5MW. The fuel flow at G.T full load is 7.2 T/h, and at half load is 3.89 T/h, while at FSNL is 2.0 T/h. The fuel type is gas oil, with calorific value equal to 44,000 kJ/kg.

The steam turbine design load is equal to 50% of the block G.Ts loading. In some cases this percentage will be more than 50%, when the steam turbine is having more stages and is divided into H.P and L.P cylinders or with tandom L.P. turbine. The proposed steam turbine full (base) load is given by BWSC as 27.820MW, while its design as shown in figure (2.3) is H.P, L.P cylinders type with tandom L.P turbine. For this reason its loading percentage to the block G.Ts loading is more than 50% and is equal to: 27.820 X 100% = 66.2% 21X2

The author prepared a computer simulated program for the efficiency calculation, using the main three variables that have been stated as the gas turbines loading, the steam turbine loading and the fuel consumption. This will be shown in details in chapter 3.

The author omitted from his calculation all the correction factors that are liable for an existing plant efficiency calculation, and made his efficiencies estimates according to the following 3 cases:

Case No. 1 – Both G.Ts on full loads, the S.T load is 27.820 MW, the fuel consumption is 14.4 T/h, and the overall efficiency = 39.67%

Case No. 2 – One G.T on full load, one G.T on half load, the S.T load is 20.865MW, the fuel consumption is 11.09 T/h, and the overall efficiency = 38.63%

Case No. 3 – One G.T on full load, one G.T shutdown, the S.T load is 13.63 MW, the fuel consumption is 7.2 T/h, and the overall efficiency = 39.35% Here, in case No. 3 it is estimated that the equivalent steam turbine power at half steam flow is 49% of the full steam turbine load, due to mechanical and electrical losses.

Using the above relationship between the fuel flow and the equivalent generated power, a curve can be drawn by the results of the above three cases, as shown in figure (2.5). Then, from this graph the overall efficiency can be calculated at any combined cycle load by knowing the equivalent fuel flow.

Comparative results with other combined cycle power stations show that in the Kingdom of Saudi Arabia, in Riyadh combined Cycle power plant No. 9 , the overall efficiency is 42.5%, while in Rabigh Combined cycle Plant the overall efficiency is 43.4%. The effect of aging in Dr. Sharif power station’s gas turbines has increased the fuel consumption, and hence reduced the overall efficiency of the simple cycle to 23.86%. Adequate operational adjustments in the air/ fuel ratio, and intensive maintenance and leaks elimination will be required.

As a modern sophisticated power generation technology, it is advantageous to use the combined cycle in Dr. Sharif power station.

The disadvantages of combined cycle, if there are, may be related to the operational complexity leading to loss of flexibility and smoothness. But, actually modern control technology and staff high capabilities through training could eliminate these disadvantages.

2.6 Advantages of Combined Cycle Power Generation:

1- There is gain of extra FREE (as said) power from steam turbine by utilizing GT exhaust heat, which was otherwise dissipated to the atmosphere as waste. 2- The cost of installation per megawatt power is less. There are no requirements for boiler complications, extra fuel storage tanks, and extra pumps, even if supplementary burners are used. 3- The erection time is less than usual due to above non-required equipment.

4- There is economy in running cost, especially fuel cost, even when using supplementary firing. The fuel cost represents about 75-80% of the total kwh cost generated by GT. 5- Reliability of combined cycle can be maintained, even steam turbine output, during GTs low loads or off-loads, by installation of supplementary burners. 6- The thermal efficiency is raised to higher levels.

33 Chapter 3

COMBINED CYCLE RELIABILITY, AVAILABILITY AND PERFORMANCE TEST.

3.1 Introduction

In this chapter, the author started his research by collecting the required information mainly from the international standards that are concerned with the subject matter.

Along with the above international standards, the author depended also on his general knowledge in the generating units commissioning field.

The author put a definition to reliability and how it could be improved and developed. The same he did for availability and showed technically what it means in the Combined Cycle technology, where the steam turbine generated power depends mainly upon the block gas turbines outputs. The author showed what impact will result in the steam turbine if one gas turbine was operated on part load or was completely shutdown, and what impact will result if the preparation for maintenance or maintenance itself was exceeded. For such cases of probabilities ASME prepared an equivalent availability method of calculation.

The performance test is defined as the most important test to be carried out for accepting the new generating unit, if it fulfills mostly two guarantee conditions.

1. To generate net power equal to or greater than the contract guaranteed power. 2. To maintain heat rate equal to or less than the contract guaranteed heat rate.

The heat rate is an inverse proportion to the efficiency. If one or both of these conditions is not fulfilled, then the owner has the right to reject the generating unit, or to claim for penalties to the contractor.

The author prepared a methodology for performance test calculation as per the above international standards for calibrating the test instruments and equipment and for the test set-up and the conduct of the test. The test procedure seems long but it could not be shortened, as many correction factors and curves are used in order to draw the test conditions to the guarantee conditions. All the calculations of the performance test results are mostly dealing with two main equations:

1. The combined cycle plant corrected net power output. 2. The combined cycle plant corrected heat rate.

A computer program has been prepared by the author for calculating the corrected net power output and the corrected heat rate, following the performance test method of calculation, by feeding in the program the actual data that were collected during the combined cycle performance test. An example of the combined cycle performance test calculation is shown by the author in appendix A, where he used his computerized program to calculate the performance test results in Riyadh power plant No. 9

34 combined cycle, kingdom of Saudi Arabia, where he worked as consulting engineer and conducted the performance test and used the results data in his calculation.

3.2 Reliability

In general, Reliability is the probability that the equipment, or system, can fulfill its function for the planned period of need. In power generation, Reliability is the probability of having the generating unit on line when it is expected to be so. It is measured in terms of forced outage factor. The period for measuring reliability is defined as the specific time that the unit is able to provide service and is taken normally as a month or a year.

Reliability can be defined mathematically as follows:

Period hours – Forced outage hours Reliability = x 100% Period hours

Along with the evaluation of gas turbine models, starting with the MS300 series in 1949, is the continuous reliability improvement process that results from refined design standards, advanced analytical techniques and field data feedback. The new gas turbine models have benefited from that process and also incorporated advanced materials and cooling designs proven in aircraft engines that operate at high temperatures. The gas turbine manufacturers e.g. G.E guarantee an average reliability for the modern gas turbines to be close to 99%.

The controls of the new gas turbine models are also contributing to high reliability. G.E’s SPEEDTRONIC Mark V control system is dominating in most of the new gas turbine technologies. It employs triple – redundant microprocessor controllers designed to fulfill all gas turbine control requirements such as fuel, speed, load, temperature, injections, start up, shutdown, etc. This new advanced electronic Mark V control is a derivative of the earlier, highly successful Mark IV control system.

The combined cycle steam turbine control during plant start-ups and shutdowns is utilized by the main steam Inlet Pressure Control (IPC), while its control during normal operation will be utilized by the main steam sliding pressure mode. When the steam turbine protections are functioning properly, its reliability will be in correlation with the combined cycle gas turbines reliabilities.

35 3.3 Availability

Availability is the ability of the generating unit to be on line when it is expected to be so. It considers both forced and planned outages and measures the overall net percentage of time (normally a month or a year) that the unit is able to provide service.

Availability can be defined mathematically as follows:

Period hours – (forced outage hours + Planned outage hours) Availability = x 100% Period hours

The evolution of turbine technology has also raised availability to levels close to 96%.

Using the time based outage definitions and concepts of ANSI/IEEE international standard No.762-1987, availability shall be expressed in terms of the ratio of actual available hours to planned available hours on a plant equivalent basis. Planned outage periods are excluded from the measurement. The plant equivalent availability is to average not less than 90% for the combined cycle plant over the full measurement period.

In order to reflect plant capacity reductions due to partial plant outages and deal with non-chargeable outage time, the equivalent availability formula shall be as follows:

AH - EDH – EAOH Equiv. Avail = PH-POH-EPDH-AOH-EAOH

Where,

AH- Available hours, which is equal, by the conventional time-based IEEE 762 definitions, to AH = PH- FOH- MOH- POH- AOH

EDH- Equivalent derated hours, which is equal to EDH= EUDH + EPDH

EAOH- Equivalent administrative outage hours (partial plant outage, non-chargeable hours)

PH- Period hours.

FOH- Chargeable forced outage hours

MOH- Chargeable maintenance outage hours.

POH- Chargeable planned outage hours (periodic planned inspections plus scheduled shutdowns for turbine cleaning)

AOH- Administrative outage hours (full plant outage, non-chargeable hours)

EUDH- Equivalent unplanned derated hours.

36 EPDH- Equivalent planned derated hours

The equivalent derated hours are determined by multiplying the derated operating time by the nominal (block loss) of capacity. For example, if one gas turbine generator set is unavailable due to a chargeable forced outage for a period of 100 hours, the combined cycle plant (2 G.Ts + 1 S.T) would suffer a nominal block loss of 50% of capacity. This 50% (derating) multiplied by the 100 hour period would accumulate (0.5 x 100) = 50 equivalent unplanned derated hours. The plant is still considered to be available since the other gas turbine and the steam turbine are able to continue producing electricity. The (block loss) method simply extends the traditional time-based availability measurement to a more complex plant.

A rigorous and explicit operating log shall be maintained, from which the equivalent availability measurement is to be determined. The log shall clearly identify the cause, the block capacity reduction and the amount of waiting time and/or idle maintenance time associated with each and every outage event.

On an annual basis the plant equivalent availability shall be calculated collectively as a single average measurement of all the contract units that are within the availability measurement period. If the calculated average plant equivalent availability falls below the expected level, the log of outage events and causes shall be reviewed to determine if corrective action should be taken. At the end of the measurement period the full plant equivalent availability shall be calculated as a single collective measurement, for purposes of the measurement, inspections, maintenance and repair shall be gauged on a high priority, high need basis. To achieve this, waiting time and inactive maintenance time in excess of four hours per outage event shall be considered as administrative outage hours (AOH), either full or equivalent as applicable. As such, they shall have (stop-the-clock) treatment and effectively not be counted as outage hours, derated hours included in the period hours base. Outage hours associated with the equipment furnished but not directly chargeable to equipment failure, shall be considered administrative outage hours either full or equivalent, as applicable.

The planned outage inspections, such as gas turbine combustion inspection which takes place in the low demand (off season), and the shutdowns for turbine cleaning, are categorized planned outages, and are effectively removed from the availability measurement.

3.4 Combined Cycle Performance Test

The purpose of performance test is to demonstrate performance guarantees for the generating unit. Performance tests are carried out while operating these units as near as possible to the performance reference (optimum) conditions. The measured performance data are corrected according to deviations of actual test conditions from the performance reference for guarantee comparison.

The combined cycle test procedure is prepared in accordance with the international standards ANSI/ASME, PTC 46-1996, PTC 22-1985, AND ISO 2314 (ref. 13, 14, 15 & 18). The combined cycle block, in our case, includes two gas turbine generators with their associated inlet and exhaust systems, two HRSGs (without using

37 supplementary firing) a condenser, and a steam turbine generator. Testing should be initiated as soon as the block is checked out and ready for operation. The performance test shall be performed no later than 45 days from the initial loading of the steam turbine generator. The performance test procedure specifies the test set-up, including special test instrumentation, and outline of the test points, data to be taken and a calculation procedure by which results will be evaluated. Correction factors are included and will be the basis for determining performance at rated conditions. A full calculation of performance test data to demonstrate performance guarantees has been done by the author and is attached in Appendix (A).

3.4.1 Performance Specifications

The performance for the combined cycle block has been guaranteed for base load operation on specified fuel. The performance guarantee is referenced to the high side of the step up transformer. The terms of contractual guarantees alone generally stated (in this study ) to be as follows:

Fuel Gasoline Ambient temperature (°C) 50 Load Base Net Plant Power – kw 69,820 Net plant Heat Rate kj/kwh, LHV 8,500

Guarantees are based upon the following operating conditions:

1. Ambient pressures = 937 mbar.a

2. Relative humidity = 60%

3. Compressor inlet temperature 50 0C

4. Gas turbine extraction air = 0

5. Power factor = 0.80

6. HRSG drum blow down = 0

7. HRSG sootblowers are off-line -

8. Steam make – up = 0

9. Gas oil LCV = 44,600 kj/kg

10. Steam/condensate leaks = 0

11. Steam/condensate passing valves 0

12. HRSG LP steam header-interconnecting valve to other LP header is closed.

The test results for the combined cycle will be corrected to account for differences between test operating conditions and conditions of guarantee for compressor inlet temperature, barometric pressure, specific humidity, and power factor. Additional corrections will be made when:

a) Speed differs more than 0.5% of the design turbine speed.

b) Fuel differs from guarantee.

c) The gas turbine exhaust temperature differs from the specified value determined by the control specification.

d) The average of the fired hours on the two gas turbines is greater than the specified time (e.g 5000 hours)

3.4.2 Responsibilities

Specific responsibilities for this test program are as follows:

Contractor − Confirm proper operation of test set-up − Conduct the test program − Provide special instrumentation as specified herein − Provide all documentation, calculation results and official test report. − Provide guidance for the installation and removal of special test instruments. − Provide suitable containers to collect samples of fuel obtained during tests. − Prove detergent for turbine water wash. − Arrange for analysis of gas oil fuel samples obtained during testing. − Install and remove temporary test instrumentation.

Customer − Perform compressor off-line water wash immediately prior to the test. − Provide test assistants for data logging − Provide water for the off-line water wash − Provide load and fuel for the test program − Provide qualified operators for cycle isolation − Make combined cycles block available for testing program.

Independent Third Party − Analyze gas oil fuel samples, taken during testing − Witness/verify calibration of temporary test instruments at contractor facility.

3.4.3 Test Set-up

39 The test set-up will consist of combined cycle block, specified station instruments and special instruments supplied for the test. The purpose of these instruments is to provide precise determination of key test parameters in accordance with the requirements for overall test accuracy. The measurements of interest which are taken with special instrumentation are: − Barometric pressure − Dry bulb ambient temperature − Wet bulb ambient temperature − Compressor inlet air temperature − Compressor discharge air pressure − Precision power per phase (steam and gas turbine generators) − Gas turbine exhaust pressure − Steam turbine exhaust pressure − Condenser inlet water cooling temperature

3.4.4 Measurements

Instrumentation for the test will consist of selected station instruments and special instruments provided by the contractor on a temporary basis. Special instruments will be calibrated by the contractor while being witnessed by a third party prior to the test. Calibration certificates will be provided to the customer. Calibration standards will be traceable to National Institute of Standards and Technology (NIST). The calibrations will be concluded within 12 months prior to the test date. Special instruments will be removed from the entire block immediately after testing.

3.4.5 Preparations

1- Special instruments required for test purposes will be provided and installed by the contractor.

2- Station instruments which will be used for the test, which are part of the installation, will be loop checked.

3- Each gas turbine will be cleaned to the satisfaction of the contractor performance engineer. The compressor inlet and plenum will be inspected before and after the wash. It may be necessary to hand wash certain areas of the inlet system in addition to the off-line water wash.

4- After each gas turbine compressor is cleaned, the contractor will measure the inlet guide vane angle in the full open position with a machinist’s protractor, near the pitch line, on sixteen vanes equally spaced around the inlet circumference. The average of these measurements should be within ± 0.5 degree of the IGVs full open position and will define the correct position of the IGVs. All values are to be recorded.

5- The gas turbine exhaust thermocouple read out system will be confirmed to be operating per specification using a thermocouple indicator/calibrator provided by the contractor.

6- The speedtronic control devices and recording system for the compressor discharge pressure transducer will be calibrated by the contractor prior to

40 the test using the precision test gauge as the standard instrument.

7- All on site calibrations and operational test conducted by the performance engineer personnel may be monitored by customer’s representatives provided that the personnel is available at the time these tasks are under taken. Prior notice will be given to the customer/representatives to show the time when calibrations or operational tests will begin.

8- The liquid fuel flow meter will be removed and calibrated by the contractor.

9- Each HRSG should be soot blown before testing begins.

10- Prior to testing, all combined cycle plant equipment directly associated with cycle performance shall be correctly adjusted and in excellent working condition and shall function within normal range.

11- Controls and instrumentation to be used for obtaining test and operating information or for functional control of combined cycle plant equipment shall be operating according to specification.

12- The steam cycle isolation list of the valves will be finalized after the on site cycle walkdown.

13- Each gas turbine exhaust shall be directed through the HRSGs and the turbines shall be run on the combined cycle exhaust temperature control curve.

3.4.6 Conduct of Test

1. The combined cycle tests will be started after the combined cycle block has been in a thermally stable condition, with gas turbines operating at base loads with exhaust directed through the HRSGs, and steam turbine operating at valves wide open, for a period of at least one hour. The criteria for combined cycle stable operation is as follows:

a) The gas turbine will be considered in a steady – state condition when the turbine wheel space temperatures change no more than 2.8 0C in 15 minutes.

b) The system will be considered in steady – state when variations from the average value during the test period do not exceed the following values:

Compressor inlet temperature ± 2.2 0C Barometric pressure ±0.5% Net power output ± 2.0% Turbine exhaust temperature (TTXM) ± 2.8 0C Turbine speed ± 1.0%

41 c) The steam turbine will be considered in steady-state condition if the electrical output remains within ± 2.0% and condenser pressure does not vary more than ± 5mm HgA. These values represent maximum permissible variations which if exceeded render the test run invalid unless the contractor and the customer mutually agree otherwise.

2. One combined cycle test run will be conducted for comparison with contractual guarantees. The test run will be 2 hours in duration and is defined as follows:

a) 2 gas turbines and one steam turbine operating at base load combined cycle operation with gas oil fuel.

3. Three additional combined cycle test runs may be conducted for information purposes only and will not be corrected to guarantee ambient conditions. Each of these test runs will be one hour in duration as follows:

a) 2 gas turbines and one steam turbine operating at 85% part load combined cycle operation.

b) One gas turbine and one steam turbine operating at base load combined cycle operation.

c) One gas turbine and one steam turbine operating at 85% part load combined cycle operation.

4. Complete sets of instrument readings will be taken at five-minute intervals. The most consistent data over a minimum thirty minute period will be selected for the main 2 hour test run, and will be mutually agreed to by the contractor and the customer for the purpose of evaluating the performance of the combined cycle plant.

5. Four fuel samples per guarantee test point will be taken. Two will be taken right before the beginning of the test point, and two will be taken immediately following the end of the test point. The two samples before or after the test point will be taken from each of the two gas turbine fuel lines. Two of the fuel sample per test point shall be shipped to a third party laboratory abroad for analysis. The remaining fuel samples per test point shall be kept at site, for future use as backup, and for analysis if questions arise regarding fuel properties.

6. Data will be recorded on data sheets at the following data stations: − Station A- Outside measurements (dry bulb, wet bulb, barometer) − Station B- Compressor inlet RTD’s and CPD pressure GT No.1 − Station C- Compressor inlet RTD’s and CPD pressure GT No.2 − Station D- Steam turbine data. − Station E- Condenser C.W temperatures − Station F- Station watt-hour meter - GT No.1 − Station G-Station watt-hour meter – GT No.2 − Station H- Station watt-hour meter – ST − Station I- Fuel sample taking

42 − Station J- Auxiliary power measurements The speedtronic control short-term trend file will also be utilized to record data.

7. The customer’s engineer and contractor representatives shall sign all data sheets at the completion of testing. Any discrepancies or questionable items shall be noted at this time. The originals of all data sheets shall be retained by the contractor for use in preparing the official test report, the customer shall be provided with copies of data sheets at the completion of each performance-testing day.

8. A preliminary test point may be run for the purpose of:

a) Determining whether the gas turbine and associated plant are in a condition suitable for conducting an official test.

b) Checking instrumentation and gas turbine control settings.

c) Familiarization with test procedure

d) Training customer data takers.

9. After the performance testing is completed all temporary test instrumentation will be removed.

3.4.7 Combined Cycle Performance Evaluation

Evaluation of the combined cycle block performance will be based on the combined test data from the 2 gas turbines and the steam turbine corrected to contract guarantee conditions.

1. Combined cycle unit performance Combined cycle plant net output, corrected (kWCC (Corr))

kWCC (corr) = (kWNGT.KW + kWSST.KW) X [F(Ie)xF(2e)xF(3e)xF(4e)] -AUX block [F(If)xF(2f)xF(3f)xF(4f) ]

Note, suffix (e) refers to guarantee condition. suffix (f) refers to test condition,

Where: kWCC(corr) =Combined cycle plant net output corrected to contract guarantee conditions. kWNGT.KW = Net gas turbine generator output, total of 2 gas turbines, corrected to guarantee power factor. kWSST.KW = Steam turbine generator net output (kW) at the generator terminals corrected to guarantee power factor.

43 AUX block = Measured auxiliary power of the block consistent with the contractor heat balance list of equipment.

F(1e), F(1f) = Correction factor for barometric pressure. F(2e), F(2f) = Correction factor for compressor inlet temperature. F(3e), F(3f) = Correction factor for ambient specific humidity. F(4e), F(4f) =Output correction factor for combined cycle degradation if the average fired hours of the 2 gas turbines is greater than 5000 hours.

a) Gas turbine gross power output Gas turbine gross generator power output will be calculated by summing the 2 individual gas turbine gross outputs measured with precision load equipment.

kW/ф = (Meter rdg.) X CFM x PTR x PTRCFxCTRx0.06 Time Where:

kW/ф = Power output of each phase

(Meter redg.) = watt-hours Time = Test time in minutes CFM = Meter Correction factor PTR = Potential transformer ratio. CTR = Current transformer ratio PTRCF = Potential transformer ratio correction factor 0.6 = 60 minutes/hour/1000 watts/kW

n kWNGTn = ∑ (kW/ф) = Gross generated power for n gas turbines. 1

2 kWNGT.kW = ∑ (kWNGTn –EPGTn) x FPFGTn n=1 Where: kWNGT.KW = Net gas turbine generator output corrected to guarantee power factor, total of 2 gas turbines.

EPGTn = Gas turbine generator excitation, kW FV x FA EP = GTn 0.975X1000 Where:

FV = Field excitation volts FA = Field excitation amps 0.975 = Factor for losses in AC to DC conversion elements. 1000 = 1000W/kW FPF = Power factor correction (curve IPS7824D-6A) – Attached

Note: All the correction curves are attached in Appendix (A).

[ (loss less windageguar.PF – loss less windageTest PF) ] FPF =1- [ kWNGTn ]

b) Steam turbine output

The steam turbine generator gross output kWS (P) is measured at the generator terminals. Generator gross power output will be calculated from the precision test instruments. The power output for each phase will be calculated individually and the results summed.

kW/Ф = (Meter rdg.)xCFM xPTRxPTRCFxCTRx0.06 Time

kWS(P) = ∑ KW/Ф = steam turbine generator gross power, precision Basis, measured at generator terminals, kW kW/Ф = power output of each phase

(Meter rdg.) = watt-hours Time = Test time in minutes CFM = Meter correction factor PTR = Potential transformer ratio CTR = Current transformer ratio PTRCF = Potential transformer ratio correction factor 0.06 = 60 minutes/hour/1000 watts/kW

kWSst.kW = [kWS (P) – EP] x FPF

Where:

kWSST.KW = Steam turbine generator net output (kW) at the generator terminals Corrected to guarantee power factor.

kWS(P) = As measured steam turbine generator gross power, precision basis, measured at generator terminals, kW

EP = Steam turbine generator excitation, kW

EP = FV x FA 0.975 X 1000 Where:

FV = Field excitation volts

45 FA = Field excitation amps. 0.975 = Factor for losses in AC to DC conversion elements 1000 = 1000 W/kW FPF = Power factor correction, (curve F297T04-5A) – Attached.

[ (loss less windage – loss less windage ) ] FPF =1- guar.PF Test PF [ kWS(P) ]

2. Combined cycle plant heat rate

Combined cycle generator net heat rate, corrected to guarantee conditions will be obtained by dividing total plant generator net heat consumption by the total plant generator net output and then correcting to guarantee conditions.

F(1m)xF(2m)xF(3m)xF(4m) AUX block HRPGCC(Corr) = HRPGCC x x 1 + [ F(1n)xF(2n)xF(3n)xF(4n) ] [ kWcc(corr) ]

Note: suffix (m) refers to guarantee conditions Suffix (n) refers to test conditions

Where:

HRPGcc(corr) = Combined cycle block heat rate corrected to guarantee conditions. HRPGCC = Combined cycle block heat rate at test conditions. F(1m), F(1n) = Correction factor for barometric pressure. Drawing No.519HA137 – Attached. F(2m), F(2n) = Correction factor for compressor inlet temperature. Drawing No. 519HA135 – Attached. F(3m), F(3n) = Correction factor for ambient specific humidity. Drawing No. 519HA136 – Attached. F(4m), F(4n) = Heat rate correction of the average fired hours of the 2 gas turbines is greater than 5000 hours. GE curve 519HA752 – Attached. F(4m)=1, F(4n)= 1+derate %/100

AUXblock = Measured auxiliary power of the combined cycle block. kWcc(corr) = Combined cycle block net output corrected to guarantee conditions, kW.

Plant heat rate [HCGGT1 + HCGGT2 ] HRPGcc = [kWNGT.KW + kWSST.KW]

Where:

HRPGcc = Combined cycle block heat rate at test condition.

HCGGT1+2 = Gas turbine generator heat consumption for each gas turbine.

46 Gas turbine heat consumption rate will be calculated from the measured fuel flow rate and the fuel lower heating value (LHV) as determined from laboratory analysis of the fuel samples.

HCGGT = WF x LHV

Where:

HCGGT = Gas turbine heat consumption rate WF = Fuel flow rate LHV =Fuel lower heating value

3.4.8 Acceptance Criteria

Performance of the combined cycle block will be considered acceptable when:

1. The corrected net unit power from the block is equal to or greater than the guaranteed power.

2. The corrected block heat rate from the block is less than or equal to the guaranteed heat rate.

47 Chapter 4

Exploitation of Sudan Refined Fuel Oil in Dr. SHARIF POWER STATION

4.1 Introduction

The author in this chapter intended to show his contribution in exploiting Al- Obeid refinery fuel oil in firing the boilers in Dr. Sharif power station. The usage of Al-Obeid refinery fuel oil in Dr. Sharif power station started in 1996 and is still in progress. Before that and starting from 1992 Dr. Sharif power station was using Abu- Jabra refinery fuel oil. The usage of Abu-Jabra fuel oil with all its problems and remedies was included in the author’s M.Sc thesis, which was concisely highlighted in chapter 1 of the present thesis.

The adequate information for this chapter were collected by the author from different sources, that include the ministry of energy and mining_petroleum department publications and reports, as well as its executives’ televised interviews. An important book, written in Arabic language was published by the ministry of energy and mining in 2002 with a name of “From Higleeg to Bashayer” was considered as good reference by the author, in addition to the ministry's "Petroleum and Gas " monthly magazine in 2004. Beside the above references the author got more information from the University of Khartoum chemical engineering department. Lastly and as in general cases, the author collected more information from his free readings in news papers and magazines.

After his transfer from Dr. Sharif power station, the author retained his communications continuing with the power station staff, specially with the engineers of his efficiency and planning department. His contacts continued through the visits, telephone calls, facsimile and internet electronic mails. The author contributed in solving the power plant problems, including the Al-Obeid fuel oil usage by exchanging thoughts and ideas with the power station engineers and by advising them with correct solutions from his own point of view, according to his long experience in the power generation field.

The methodology that the author followed in setting up this chapter attempts to furnish complete information to the reader regarding the Sudan petroleum, covering all the aspects of its historical review from the time of the early geo-physical surveys up todate. This includes the details of the type of Sudan crude oil, refineries and their progress, with special concentration to Al-Obeid refinery product of fuel oil and comparing its specifications with the boilers fuel specifications in Dr. Sharif power station. Then the author stated his contribution in solving the problems, that arose from the deviations in fuel properties between the standard boilers fuel oil and Al- Obeid refinery fuel oil, that had affected the flame patterns. As a historical review, the oil fields had been discovered for the first time in the world in the year 1858, simultaneously in Poland and in Canada(ref. 41). Then, in 1859 oil was discovered in the United States of America, when a well in Pennsylvania started pumping out crude oil successfully. From that time the oil field technology started its progress. The Sudan started exploiting its petroleum in 1992. At present it

48 is self-satisfied in fuels from its own refineries, and even it is now exporting fuels to Ethiopia and to overseas countries. The exported crude oil from port Bashayer is now reaching 300,000 barrels/day.

A tour in Sudan petroleum discoveries, exploitation, refining, and usage in Dr. Sharif Power Station is shown in details underneath.

4.2 Brief History of Petroleum Survey, Discovery and Production in The Sudan.

In the Sudan, the Italian oil company Ajiip started its geo-physical survey for oil discoveries in 1950 in the red sea region. Then, in 1964 Ajiip declared the availability of petroleum in two under-water wells, named Dorwar 1 and Dorwar 2 in the Red Sea offshore(ref. 41). Unfortunately, the work in this area was abandoned, may be due to the requirement of heavy finance. In 1976 the American oil company Chevron announced its oil discovery in the eastern part of the Sudan near the Ethiopian borders, then again in 1978 Chevron announced its oil discovery in the red sea region. Due to some intelligential information, probably acquired from the American satellites surveys, Chevron shifted to the inland, where in 1979 it declared its success in finding oil in Abu Jabra well in Al Wahda oil field, then in 1980 it discovered oil in Al Wahda. 2. Chevron moved further to the south and in 1982 it completed digging two wells named Higleeg and Adariel, where oil discoveries continued. Chevron announced at that time that the oil production from both the wells was commercially unprofitable. It attributed its statement to the far distance of the oil field from the sea ports, and also to the comparative international oil prices at that time. A third reason might not had been declared by Chevron, which was the political instability in the Sudan and its reflection in the Sudan-American relations. In 1983 when the civil war again started in the southern part of the Sudan, Chevron took serious reservations on the act of oil discoveries and escalated the matter by suspending its oil operations in the region in 1984, accompanied by the withdrawal of the French oil company Total and some other companies, infracting by that their agreement with the Sudan government, then it back-filled its discovered wells with concrete and withdrew totally in 1990.

In the 1980’s the Sudan continued facing shortages and crisis in oil supplies from abroad, due to its high cost of 400 million U.S. Dollars annually, that curtailed 80% of the country’s annual export budget. The Sudan government targeted to go out of the impasse and solve the acute shortage in fuel supplies by exploiting the Sudan petroleum. In 1992 the Sudan government purchased back from Chevron the concessions of oil exploitation in the areas that were granted to it. Exploitation of Sudan petroleum started from Abu Jabra well in August 1992 through Abu-Jabra refinery. Then the Sudan government determined to divide the areas in sub-sections and sold them to the Canadian State Petroleum Company in a joint venture agreement. In 1996 State Petroleum started leading the process of Sudan oil exploitation. In 22 July 1996 it inaugurated the Higleeg oil field and Al Obeid refinery. Later State Petroleum became a part of Arakis Company. Arakis incorporated a partnership consortium with the Chinese National Petroleum Company and the Malaysian Petronas company, as more money was needed to finance the oil discovery projects in the Sudan. The Sudan government shared in the consortium with Sudapet Company. Later Arakis sold its share in the consortium to the Canadian Talisman Company. The

49 consortium appeared in July 1997 under the name of the Grand Nile Petroleum Company(ref. 4). Later, Talisman sold its share to India.

The Consortium constructed a pipe line for exporting the petroleum from Al Wahda and Higleeg oil fields to the new oil port of Bashayer at the red sea coast, a distance of 1610 kilometers. The line was completed in 24 May 1999. The cross- sectional diameter of the pipe line is 28 inches, with flow capacity of 280,000 barrels/day.

This pipeline was constructed by German and Chinese Companies, with overall cost of one billion U. S. Dollars. In 30 August 1999 the first ship loaded with Sudan crude oil left Bashayer port on its way to Malaysia. The exported oil from Bashayer started with 100,000 barrels/day, and increased gradually till it reached the full capacity of the pip line. Then at this time a new pipe line will be needed.

In November 1999 the oil production increased to 160,000 barrels/day, then it continued increasing at a brisk pace till it reached 280,000 barrels/day at present, being exploited from 99 wells in Al Wahda and Higleeg oil fields. The estimated oil reserves in these two fields is about 800 million barrels. At present Bashayer port has got five storage tanks with each tank capacity 400,000 barrels, and total storage capacity equal to 2 million barrels. Recently during the fourth anniversary of oil exporting from Bashayer, a contract has been signed to construct a new pipeline from Al-Foola new oil field to Khartoum refinery. Another agreement has been signed to reverse operate the old Port Sudan – Khartoum fuel pipeline which was constructed in 1976 with diameter 8 inches, and to establish a new refined oil sea port of Al-Khair. Recently, a new agreement has been signed to construct an eastern pipeline for exporting petroleum from Mallut oil field to Al-Salam new oil port in the red sea coast, a distance of 1370 kilometers. The cross-sectional diameter of the pipeline is 32 inches, with five pumping stations, while the flow capacity is 350,000 barrels/day, and the total cost is 1.7 billion U.S Dollars. The oil discoveries are continuing in Al- Jazeera square 9 and in some other areas, which will make the Sudan in the near future a prominent producer and exporter of petroleum.

The Sudan crude oil has been given a commercial name as ‘the Nile blend’. This reflects the international prominence of the Nile as the longest river in the world and also reflects its importance to the Sudan as the ‘vein ‘ of life.

It was agreed among the consortium partners, that the stipulated share of the Sudan government will be 40% of the aggregate oil production, in the first 5 years, then will increase till it reaches 80%, when the investors receive the capital pay back. It was also agreed that the share of the Sudan Petroleum company (Sudapet) will be 5% of the aggregate oil production.

50 4.3 Type of Sudan Crude Oils According to International Standards

The characteristics of the Sudan crude oil are categorized internationally as a part and identical to the African crude oil sources. It provides more light fractions and less residuum than do the main bulk of crudes obtained from Middle East sources. The Sudan crude oil yields low sulphur content but, as it contains a high proportion of waxes (20%) the pour point of the heavy residual fuel is higher, therefore, the crude oil needs to be stored and handled at higher temperature than that produced from Middle East sources. The lower sulphur content of the Sudan crude oil is advantageous in connection with the drive towards clear air from pollution, and towards reducing acid corrosion in the cooler parts of the boiler.

4.4 Refineries Functionalism and Productivity

As the Sudan had been depending ultimately upon imported petroleum for running its machines since a long time till recently, the first refinery in the country was installed in Port Sudan to refine the imported crude oil prior distributing it in the whole country, for the purpose of saving the extra transportation cost.

Since the Sudan started exploiting its petroleum in 1992 till now, many refineries came to exist and are now functioning properly. The refining capacities of these refineries exceed the need of the country, and since 30 January 2003 the Sudan started exporting its refined products of fuels to the neibouring countries, especially to Ethiopia. A concise briefing for the Sudan oil refineries which are in service will be stated chronologically as follows(ref. 4):

1. Port Sudan refinery- It was established in 1963 to refine the imported Middle East crude, with refining capacity of 1,000 barrels/day. It produces all kinds of fuels. It has been developed and extended recently to produce 25,000 up to 70,000 barrels/day.

2. Abu Jabra refinery- It was established in 1992 to refine the first crude oil exploited from Abu Jabra well, with refining capacity ranging from 1,500 to 2,000 barrels/day. It is a small re-conditioned rudimentary refinery. It consists of a distillation Unit which separates gas oils, while naphtha and kerosene are added to the residual oil. No vacuum distillation is provided to separate lubricating oil, and also no dewaxing is provided to separate wax.

3. Al obeid refinery- It was established in 1996 to refine crude oil from Higleeg and Adareil wells, with refining capacity of 10,000 barrels/day. It produces all kinds of fuels. It has been developed recently to produce 15,000 barrels/day.

4. Concorp refinery- It was established in 1999 in the southern part of Khartoum to refine Adareil crude. It is a private refinery owned by the business man Mr. Mohamed Abdulla Jar-Elnabi with capacity of 10,000 barrels/day. It worked once with some imported crude oil, then stopped due to financial problems.

51 5. Khartoum refinery- It was established in 1999 in Al Jaily area and was inaugurated in 30 June 2000. It refines crude oil from Al Wahda and Higleeg oil fields, with refining capacity of 50,000 barrels/day. It produces all kinds of fuels. A new extension has been sanctioned, which will raise its capacity to 100,000 barrels/day.

Beside the above running refineries, a small refinery had been planned to be constructed at Kosti, but it was abandoned.

4.5 Specification of Produced Fuel Oil, Compared to International Specifications.

In the beginning, from 1992 to 1996, Dr. Sharif Power Station was using Abu Jabra refinery fuel oil, which was out of specification due to the refinery deficiency and mal-functioning. All the efforts that were done to draw Abu Jabra fuel oil specifications closer to the international specifications are now included in the author’s M.Sc thesis, and are also included in Chapter 1 “Introduction” of this thesis. From 1996 and onwards, Dr. Sharif Power Station moved to use Al Obeid refinery fuel oil when it became available. The refinery itself is modern, and so its fuel oil is much closer in specifications to the power station specified fuel oil with international standards. The specifications of the fuel oil from Al Obeid refinery(ref. 38) are shown in table (4.1)

Table (4.1) Al Obeid Refinery Fuel Oil Specifications

Items Units Results

Viscosity R.W. Sec 1100 Density kg/m3 0.87 Pour Point 0C 40 <….> 45 Flash point 0C 62<……>71 Ash Content % 0.01 Sulphur Content % 0.12 Sediment % 0.03 Water Content Volume % 0.06 Gross Calorific value kj/kg 43,224

Source: Al Obeid refinery.

The above specifications of Al Obeid fuel oil were analysed in Al Obeid refinery itself. Some other samples of the same refinery fuel oil were analysed in Port Sudan and Khartoum refineries and also some other sample was analysed by ABB combustion services. The results of the analysis had some deviations, that were derived to the fuel oils been delivered by unclean road tankers that caused their contamination.

The power station contract specifications shows that the fuel oil to be used for firing the boilers is categorized to the international furnace fuel type Redwood R. W. 3,500 class G (bunker C). This fuel oil content analysis by weight is as follows:

Carbon 85.2% Nitrogen 0.5% Sulphur 4.5% Hydrogen 9.59% Moisture 0.2% Ash 0.01% Gross calorific value 42,580 kj/kg. The source of these results is the generating units contractor.

More analysis were made for this fuel oil in the Power Station chemical laboratory (ref. 22). The results were:

Viscosity (at 37 0C) 2000 RW (Standard 3,500 RW) Specific gravity (or density) 0.953 kg/m3 Flash Point 110 0C Gross calorific value 42,572 kj/kg.

The source of these results is Dr. Sharif power station chemical laboratory.

Comparing Al Obeid specifications with the international fuel oil specifications, it appears, that the Sudan fuel oil is better in its characteristics of having less density (light) and less sulphur content and high gross calorific value than the international one.

4.6 Evaluation of Refined Fuel Oil usage in the Power Station

In Chapter 1, (summary to the author’s M.Sc thesis),the modifications that were carried out in Dr. Sharif Power Station in order to facilitate the liability of firing Abu Jabra fuel oil were shown in details.

When the power station moved to use Al Obeid refinery fuel Oil, some problems arose from the deviation in viscosity and contaminants, that had an adverse effect on the performance of the pumping system in Phase I. The burner header pressure was low, which resulted in short irregular flames with gases at burner atomizer.

Some modifications were put forward for solving these problems. The high- pressure fuel oil pumps with flow 8.4 T/h per each were dismantled from the system in Phase I and a new pumping system was installed with bigger fuel transfer pumps to feed fuel oil directly to the burners header. The transfer pumps are 3 in number, 2 of them will be running for both phase I Units while the third pump will be standby. The flow of each pump is 10T/h. The pumps were commissioned in December 2002 and the fuel combustion was observed, which proved that the burner flame is having a regular shape, while the burner fuel oil header pressure has raised from 20 bar to 26 bar. The minimum fuel oil header pressure was set to 20 bar as alarm, and to 12 bar as trip. There is a tendency to replace the oil burner tips to cope with the modifications but so far this has not been commenced.

53 Chapter 5

TRANSFER OF NEW TECHNOLOGIES TO DR. SHARIF POWER STATION FOR RAISING THE EFFICIENCY

5.1 Introduction

The author opinion is to use this chapter as an outlook to the worlds modern sophisticated technologies in power generation. The author has got chances to familiarize himself with these new technologies during his work as a consulting engineer in the kingdom of Saudi Arabia, and is intending to transfer them to the Sudan and to install them in Dr. Sharif power station for raising the overall power plant efficiency to higher levels.

Actually there is enough vacant land inside Dr. Sharif power station fencing, plus a surplus bare land between the power station and the staff accommodation colony, that can be used for building these modern sophisticated generating units.

It is inevitable to state here, that the modern sophisticated technologies are considered by the manufacturers as firm secrets, and nowhere, detailed descriptions are liable to be furnished in the manufacturers manuals, beyond the operation and maintenance procedures. However, the author succeeded to collect all the adequate supporting information that are forthcoming in each type of a modern technology, from his own diligence and contacts with the contractor’s engineers.

Some of the schematic diagrams and sketches were drawn by the author on Autocad, while some others were extracted from the performance test procedures. The sources of all schematic diagrams and sketches were shown in details by the author. As the author is a member of the British Institution of Mechanical Engineers (I. Mech. E), he got more information about these modern technologies from the institution magazine and from other commercial gas turbine and power magazines.

The Sudan, as one of the under-developed countries, had faced a lot of troubles due to scarcity of resources. This fact led its people, in one way or

54 another, to the drastic margin of poverty. The above statement contradicts the abundance of natural resources granted by God to the country, that though they are rich, they have not yet been exploited properly. The shortage in electric power generation is one of the major troubles that face the Sudan. The globalization effect in addition to other regional and internal political and economical changes created an atmosphere of openness, and this in turn encouraged and still encouraging foreign and local investments in all economical fields, specially the petro-chemical and power generation fields. An optimistic short-term plan of three large power plants projects are now due to commence.

As a guidance to Sudanese planners for constructing sophisticated thermal power stations, and according to the author’s humble experience in the field of power generation during his 20 years working in the same field in the United Arab Emirates and the Kingdom of Saudi Arabia, the author feels that he could serve his country by furnishing his experience for improving the performance of the thermal power plants to increase their output, efficiency and reliability.

Some new technologies are being utilized in sophisticated power stations as latest inventions and innovations. It would be a great gain to Sudanese engineers to cope with these technologies for their future career.

This chapter will cover the following technological descriptions and studies:

5.1 Introduction. 5.2 Gas turbine air inlet chillers. 5.3 Steam turbine air-cooled condenser. 5.4 Steam turbine steam re-heating. 5.5 Steam turbine condensate polishing. 5.6 Steam turbine unit with flue gas electrostatic precipitator.

A new technology of gas turbines exhaust gases utilization by a Heat Recovery Steam Generator (HRSG) to generate low pressure (L.P) steam for a desalination plant in a cogeneration system for producing combined heat and power (CHP), is a well known technology in coast lands away from rivers. Hence, this new technology is not fit for Dr. Sharif power station, and therefore it will be omitted.

5.2 The Gas Turbine Air Inlet Chiller

The author could not find any text books dealing with the gas turbine air inlet chiller. This technology is completely modern and sophisticated. Even the operation and maintenance manuals were not ready to be provided by the contractor during the commissioning and performance test of the gas turbines in Al Qaseem power station, Kingdom of Saudi Arabia. The author carried out these tests, as he was deputed by the Saudi Electricity Company from his station in power plant No. 9 in Riyadh, where he worked at that time as a consulting engineer.

The author depended ultimately on studying the air inlet chiller with gas turbines air intake compartments as they were built. The author got some enhancement from the Contractor’s performance engineer in answering his queries about the functions of some constituents of the chiller system. The performance test procedure, though it was short, gave some help to the author to explain the effect of the air inlet chiller in raising the generated power output and the efficiency of the gas turbine. The author himself drew the schematic diagram of the air inlet chiller as per the contractor (testiac) construction.

The author noticed that the air inlet chiller construction follows theoretically the vapour compression refrigeration method of technology. Hence, he collected some information about the said refrigeration method from some thermodynamics and energy text books and added them to this part for the sake of the reader. At the end of this description, the author stated the advantages of the gas turbine air inlet chillers.

The gas turbine air inlet chiller technology is still considered as a new sophisticated technology in power generation to reduce the gas turbine air inlet temperature. It is an act, as said by gas turbine manufacturers, of (deceiving) the gas turbine that it is located in a cold weather. When the air temperature reduces, its density increases, and hence the air mass flow increases. This in turn will lead to increase the fuel flow to burn the added amount of air to preserve the air/fuel ratio. So, the resultant heat will increase and the turbine power output will increase(ref. 5). This kind of new technology has been tried recently in Qaseem power station in the Kingdom of Saudi Arabia, in the desert, north-west of Riyadh. The author, who had been working in Riyadh Power Plant Project No.9, was asked by the Saudi Electricity Company in 2001 to carry out performance tests

56 for the newly commissioned six gas turbines with air inlet chillers in Qaseem power station. The test has been done for the gas turbine with chillers ‘on’, and with chillers ‘off’. The result was amazing, when the chillers ‘On’, the G.T unit power output increases 35%! Before getting to the details, it is worth to explain in the beginning the refrigeration system in use, which is categorized as Vapour-compression refrigeration.

5.2.1 Vapour-Compression Refrigeration

This type of refrigeration, which is using a reversed heat engine cycle with a wet vapour, is the most common refrigeration system in current use. The schematic diagram of such refrigeration system is shown in figure (5.1), while the refrigeration cycle is shown in the T-S diagram in figure (5.2). The system cycle consists of the following:

1. The refrigerant

The working fluid which circulates continuously through the refrigeration cycle process is called the refrigerant. It is preferable to be a liquefiable vapour. The evaporation and condensation processes take place when the fluid is receiving and rejecting the specific enthalpy of vaporization, and these processes are constant temperature and constant pressure processes.

Ammonia is used as primary refrigerant, though it is toxic and can create a fire and explosion risk should leaks occur in the piping or evaporator system. The toxity of ammonia is practically reduced by using water as a secondary refrigerant in the refrigeration system. Ammonia has some other positive characteristics such as:

a. Its cost is low.

b. The saturation pressure at the desired low temperature is above atmospheric, but not too high, to eliminate leaks.

c. The specific enthalpy of vaporization at the low temperatures is high and hence gives a reasonable low mass flow rate.

d. The specific volume at compressor suction is not high, which enables usage of small size compressors.

e. The latent heat of vaporization is very high.

Many other refrigerants are used or have been used such as sulphur dioxide, methyl Chloride, hydrocarbons (e.g. methane, ethane, propane) and halocarbons.

The first two named refrigerants were discontinued because of their toxicity and odourlessness; the hydrocarbons are seldom used because of their flammability. The halocarbon compound was invented in the 1930s; it was nontoxic with a zero fire and explosion risk and has ideal thermodynamic properties. Chemical companies developed similar compounds containing carbon, fluorine and chlorine under the names of Freon and Arcton and are now familiarly called CFCs. The CFCs are now under threat and restrictions because of the discovery that, due to the chlorine content, their release into the earth’s atmosphere is damaging the ozone layer. Under an international agreement effective from January 1989 the use of most CFCs will be phased out and safe alternative fluids developed (ref. 6 ).

Sources of chlorine in the atmosphere include CFCs, from refrigeration plant, from aerosols where they are used as a propellant, and from foam blowing for insulation materials.

2. The Evaporator

There are two main designs of evaporators, depending on the application and the type of compressor and refrigerant. In a direct expansion or dry expansion shell-and-tube type the refrigerant flows through the tubes leaving with a slight degree of superheat. In a flooded evaporator the refrigerant is on the shell side and the liquid covers the tubes with the vapour drawn off the top of the shell. Heat transfer is improved when liquid refrigerant wets the heat transfer surface and hence a flooded coil is sometimes used in which the refrigerant flows to an accumulator where the

59 vapour separates and goes direct to the compressor with the liquid flowing through the tubes within the shell.

Evaporative cooling takes place when ammonia is exposed to water flow, and on vaporization, the enthalpy of vaporization is supplied from water by tube surface heat transfer, thus reducing the water temperature

3. The Compressor

Centrifugal compressors are widely used for larger plants in the range above 300KW up to 15MW. The reciprocating compressors are widely used in the range up to 600 kw, while the screw type compressors compete with both other types of compressors covering the range 300KW to 3MW.

4. The Condenser

Condensers can be of three main types, water-cooled, air-cooled or evaporative. Water-cooled condensers can be of the shell-and-tube type or the double pipe type. The air-cooled type would generally be used with a higher condensing temperature since air is not available normally at as low a temperature as water. In the evaporative type the refrigerant is supplied to a cooling tower where water is sprayed over the coil and cooled by counter airflow drawn by fans.

5. The throttle valve

The throttle valve is installed as a replacement to the expansion cylinder (expansion engine), which had been in use formerly. A flow of fluid is said to be throttled when there is some restriction to the flow. The restriction to flow can be a partially open valve, an orifice, or any other sudden reduction in the cross-section of the flow. The process occurs such that the initial enthalpy equals the final enthalpy. The process is highly irreversible so that the whole cycle becomes irreversible. The process is represented by the dotted line 3-4 on figure (5.2).

The main function of the throttle valve is to reduce the liquid temperature and pressure, from the values at the condenser outlet to the values at the evaporator inlet.

5.2.2 Description of The Air Inlet Chillers

60 The gas turbines air inlet cooling system in Qaseem power station, is shown by TESTIAC schematic diagram in figure (5.3), which was drawn by the author himself in view of the installed components. The following description of TESTIAC components was compiled by the author according to his understanding of the system work. 1- Ammonia refrigerant, with one High-Pressure Vessel (HPV), and one Low-Pressure Vessel (LPV), and four refrigerant recirculation pumps. 2- One ice storage tank with capacity 13,000 M3, and height about 12 meters, consisting of water spray pipes and chilled water with ice. Four chilled water pumps circulate the chilled water through the chilled water header to all G.Ts air intake compartments and then back to the water spray pipes. Two-evaporator supply pumps circulate the chilled water through the evaporators for further cooling. 3- Eight evaporators located on the top of the ice storage tank, to make ice by heat exchanging of ammonia and chilled water, as was described before,. Four refrigerant recirculation pumps drive the liquid refrigerant with low pressure and temperature through the evaporators to absorb heat from the chilled water to become vapour and then to flow back to the LPV. A part from the compressed ammonia vapour with high pressure and temperature by-passes the air condenser and flows to the evaporators tubes to be used only for releasing the hanging ice on the tubes to make it fall in the chilled water storage tank.

4- Four refrigerant compressors with common discharge line, two of them draw ammonia vapour from the HPV, while the other two draw saturated ammonia vapour from the LPV.

5- One air condenser is located above ground to admit clean cooling air flow. It condenses most of the compressed ammonia vapour, with some ammonia remain as vapour with high pressure in the HPV. Air-cooling of the condenser is the most suitable media in the desert, due to scarcity of water.

6- One throttle valve is located after the condenser between the HPV and LPV. It reduces the ammonia temperature and pressure from the values that in the HPV to the values in the LPV.

5.2.3 Effect of the Air Inlet Chillers

A practical experiment for the air inlet chillers has been done for the first time in a tropical desert in Qaseem power station, Kingdom of Saudi Arabia. Chilled water coils have been installed in the air inlet compartments of six frame 7EA, GE gas turbines. The ambient air temperature and humidity during the test are 50 0C and 10% respectively. The conditions of the test are:

1. The gas turbines are new and clean 2. The fuel in use is crude oil 3. The gas turbines are on base loads 4. The exhaust gases are in simple cycle

The inlet air-cooling system (TESTIAC) was kept in service with its full capacity, with chilled water circulating through the chilled water header to all the six gas turbines air-cooling coils.

The effect of the air inlet chillers is clearly shown in table (5.1), which shows the results of the gas turbines parameters with chiller-off and with chiller-on, for comparison.

Table (5.1) The effect of the air inlet chillers Item Chiller-off Chiller-on

Inlet air temperature 50 0C 10 0C

Inlet air humidity 10% 100%

Barometric pressure 0.93895 bar 0.93895 bar

G.Ts power output (6 Units) 342,420 kw 462,540 kw

Heat Rate 12,180 kj/kwh, LHV 11,390 kj/kwh, LHV Source: Al-Qaseem power station performance test report. The remarkable effect of the air inlet chillers is that the air inlet temperature to the compressor has reduced to 10 0C only, while the humidity has increased to 100%. The dense, heavy air with more oxygen and hydrogen will lead to more combustion, and hence to more power output, which shows that with chiller-on the power output has increased 120,120 kw!. i.e each gas turbine power output has increased 20,020 kw! The heat rate has dropped from 12,180 kj/kwh with chillers-off, to 11,390 kj/kwh with chillers-on.

5.2.4 Advantages of The Air Inlet Chillers

1. The average power output of each gas turbine has increased from 57.07 MW on base load, to 77,09 MW. The extra power output has been gained by the air inlet chillers operation. This gain in power output represents 35.1% of the gas turbine base load.

2. The efficiency of the gas turbine has increased as follows:

1 3600 With chiller-off η = = X 100%= 29.56% eg HR 12180

1 3600 With chiller-on η = = X 100%= 31.61% eg HR 11390 The raise in efficiency = 2.05%

5.3 Steam Turbine Air-cooled Condenser

64 As mentioned in the previous type of modern technology, here also the author could not find any text books dealing with the steam turbine air-cooled condenser. This technology is also considered as modern and sophisticated. The operations and maintenance manuals were not ready to be provided during the commissioning and performance tests of the plant combined cycle units. The author worked as a consulting engineer in the same power project in power plant No. 9 in the Kingdom of Saudi Arabia. He contributed in all the commissioning tests and performance tests of the generating units, including the air_cooled condensers. He succeeded to collect all the information he required about the air cooled condensers from the as-built drawings and the construction configurations. He also collected some data from the performance test of the air cooled condensers, which he carried out himself.

In order to make his description of the air-cooled condenser more clear to the reader, the author drew a sketch showing the contents of the air-cooled condenser and its layout. Then at the end of this description, the author stated the advantages of the air cooled condenser.

The air-cooled condenser, as a sophisticated technology in the power generation field, has put an end to the general opinion, that steam power stations must always be constructed near rivers or seas. The condenser cooling requires great amount of cooling water. If this cooling water flows in an open circuit, as is normally the case with seawater, the flow will be continuous from the sea and back to the sea. In the case of river water, water is kept flowing in a closed circuit to conserve its purity and treatment and to preserve river life. Some more water from the river will be used to compensate the lost water during evaporation in the cooling water towers, with flow representing about 1.5% of the total cooling water flow. The cooling water flow, as an example, for a steam turbine unit generating 400 MW, is equal to 62,000 M3/hr (ref. 40).

The advanced technology of air-cooled condenser, made it possible to build steam power plants right in the middle of the desert! A good practical example for this assumption is the power plant No.9 (PP9), been constructed in 2001 in Riyadh, Kingdom of Saudi Arabia. Actually PP9 is considered as the first power station outside North America and Europe where the air-cooled condenser technology is used, especially in a tropical area. The following are some information about PP9:

The contract was signed with General Electric (GE) Company in 1995 to construct a combined cycle power plant in Riyadh, with generating power of 1,200 MW. The cost of the contract is SR. 5,128,000,000 (US$ 1,367,466,000). The plant consists of 16 gas turbines (50 MW per unit) and 16 HRSGs (111 T/h of steam per unit) and 4 steam turbines (100 MW per unit).

65 The fuel in use is crude oil and natural gas. The source of water is from 2 deep wells inside the power plant with depth equal 2,400 meters for each. The temperature of water when pumped out is 70 0C, so it is kept in 3 raw water storage tanks open to atmosphere, with capacity 10,000 M3 per each, to cool down to 50 0C. The water is then taken through a cooling water tower to reduce its temperature to 35 0C. Afterwards it is directed to the reverse osmosis units and raw water treatment units to prepare demineralized make-up water, drinking water and softened water (used mainly for HVAC, heat exchangers and fire fighting). A back-up water source is trucked in by road tankers. Recently when the underground water table (or water level) started to drop due to scarcity of rains, a pipe line has been constructed to feed water to the power station from a nearby terminal water station receiving desalinated water by a pipe line from Dammam at the east coast. The work in the project has come to its end, as a turnkey project, at the end of 2001.

5.3.1 Description of the Air Cooled Condenser (ACC)

In order to economize water losses, the design of the steam/condensate system was targeted to ensure the minimum practical loss of water by leakage or by blow down requirements, and whenever possible, drains are recovered for re-treatment and re-injection into the system. There is no steam taken from the turbine casing as extraction, and hence, no L.P or H.P. heaters are installed. The exhaust steam is directed through pipe work of a tapered annulus style to the ACC, which is located outdoor as close as practicable to the steam turbine exhaust. The condensing surfaces and cooling air fans are elevated to about 30 meters above ground level to allow access and reduce ingestion of local sand into the cooling air streams. The dimensions of the horizontal surface with 20 cooling air fans is 45 meters x 37 meters. The height of the condenser tubes above the fans is about 10 meters. Four riser pipes take the exhaust steam from the exhaust duct up to 4 headers in the ACC, which are connected to the condensing tubes in a reversed V-shape, to create a zigzagging configuration. The condensate headers at each bunch of tubes outlets are collected in one main header, which goes down to the condensate receiver below the ACC at the ground level. The condensate receiver plays the role of the hot well in the water-cooled condenser. The vacuum in the condenser is sustained by two vacuum pumps and two steam air ejectors, which are located below the ACC on the ground level.

Normally one vacuum pump and one air ejector are in use, while the other vacuum pump and air ejector are considered as standby. When starting the steam turbine, the vacuum pump is used to pull the vacuum quickly down to a certain level, and then the main air ejector will be used to pull the vacuum further to the design level. The other vacuum pump and main air ejector are kept as standby units. For starting the vacuum pulling it is possible to use pilot (or hogging) ejectors instead of the vacuum pump. The air-cooled condenser in order to be separated from the water-cooled condenser, it is abbreviated in drawings as a pair of fan blades holding an 8-shape being drawn inside the condenser configuration. A sketch of the air cooled condenser as described above, is shown in figure (5.4).

5.3.2 Performance of the ACC

Normally the cooling air fans run on low speed of 54 rpm. The high speed of 109 rpm is used when more cooling is required, when the ambient temperature exceeds the design temperature of 55 0C, or when more than 2 fans are out of order. Motor high speed sometimes leads to fan’s tip rubbing with shroud, specially in rough weathers. The total cooling airflow for the 20 fans is equal 11,516 M3/S, while the ACC cooling surface is equal 4,023 M2. The ACC cooling capacity of exhaust steam to condensate is 446T/h. The exhaust steam temperature is about 70 0C, while the condensate temperature is about 60 0C with vacuum about 0.55 bara (8.1 psia). The large area under vacuum, e.g. the whole ACC, exhaust duct, condensate receiver, condensate drain tank, condensate flash tank, air ejectors, and all concerned pipe works from the exhaust duct to the suction of the condensate extraction pumps, makes it possible to have air ingress sometimes, from joints or punctured tubes. In this regard good monitoring and maintenance is required.

5.3.3 Advantages of the ACC

1. This modern technology made the steam power plants possibly be located away from rivers or seas, e.g. even in the middle of the desert.

68 2. The steam power plant, by the ACC technology, can be located in the areas of power requirement . This will save the cost of power transmission lines to these areas. 3. The air is a free media for the ACC. In this case the cooling water and its treatment costs will be saved.

4. The cost of constructing the ACC is much less than the cost of constructing the cooling tower with the intake and circulating pumps and pipe works to the condensers and back. 5. The availability of the steam turbine will increase with the ACC, and hence, the efficiency will increase.

5.4 Steam Turbine Unit Steam Reheating

The author in this new technology, which is known in large power generating units, depended upon his own experience and his contribution as a consulting engineer for commissioning the same units in Shoaiba power plant in the Kingdom of Saudi Arabia, where he works at present. Actually , the steam reheat technology has been practiced in conventional boilers to replace the nuclear reactors in generating high capacities of steam to generate power in the turbo alternators. The author returned to some text books in thermodynamics, from where he studied the theory of the steam reheat and drew some schematic diagrams. He also got some supporting information from the generating units performance test procedure and the resultant data, as shown in the generating units heat balance diagram. In addition to the above adequate information, the author depended upon his own concept in describing this type of new technology. At the end of this study, the author stated the advantages of the steam reheat technology.

Steam reheating is used in power generation to raise the steam turbine unit power output. It is desirable to increase the average temperature at which heat is supplied to the steam, and also to keep the steam as dry as possible in the lower pressure stages of the turbine. The wetness at exhaust should be no greater than 10%. The presence of water during the expansion is undesirable, since the droplets are denser than the remainder of the working fluid and therefore have different flow characteristics. The result is the physical erosion of the turbine blades and a reduction in isentropic efficiency; the modern tendency is to use higher boiler pressures, to increase the heat work in the turbine to generate more power.

In figure (5.5) a T-S diagram for Rankine cycle is shown, in order to prove, that for a given steam temperature at turbine inlet, the higher steam

69 pressure is used, the wetter the steam formation will be at turbine exhaust, (P1 > P2).

The exhaust steam condition can be improved most effectively by reheating the steam. Referring to figure (5.6), the steam expansions in the turbine are carried out in two stages. 1.2 represents isentropic expansion in the high-pressure turbine after steam superheating, and 6-7 represents isentropic expansion in the intermediate and low-pressure turbines after steam reheating. The steam is reheated at constant pressure in process 2-6. The reheat is carried out by returning the steam to the boiler, and passing it through a special bank of tubes being situated in the proximity of the superheat tubes. Heavy pipe work is required for cold reheat – hot reheat process.

5.4.1 Steam Turbine Unit Operating Data

In Shoaiba power project, Kingdom of Saudi Arabia, reheat system was utilized in the boilers. Figure (5.7) shows the heat balance of the condensate/steam cycle of one of the identical steam turbine Units of the above power project. The steam turbine unit’s major components are (ref. 40):-

1. Boiler: CE, drum type, controlled circulation, with reheater, oil fired (crude + HFO), including 2 x 50% ID/GR/FD fans, air heater, sootblowers, ESP, ash-handling plant.

2. Steam turbine: ABB, condensing steam turbine consisting of HP cylinder, IP cylinder and L.P cylinder.

3. Bypass Steam: HP/LP bypass system to divert the steam around the turbine, if required.

4. Generator: ABB, H2 cooled.

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5. Major electrical equipment: Generator transformer, unit auxiliary transformer, 6.9 kV switchboards, 480V switchboards, and DC system.

6. Condenser: ABB, seawater cooled, generates the necessary vacuum for the ST and serves as water/steam cycle heat sink.

7. Feed water heating system: Seven F.W. heaters including one combined deaerator/condensate preheater and F.W. tank works as water storage facility and preheats/deaerates the main condensate.

8. Main circulating water system: The circulating water is taken from the sea and led through the condenser and then along with the dissipated heat is discharged back to the sea.

9. Make up water supply: Water needed for the boiler is produced by seawater desalination units within the plant. The distillate is then treated in the demineralized system to remove the minerals.

10. Hydrogen production system: One common package produces H2 to compensate the leakage of the generators.

The unit boiler specifications at 100% BMCR are:

a. Main steam pressure 206 bar

b. Main steam temperature 541oC

c. Main steam flow 348 kg/Sec (1252.8 T/h)

d. Boiler heating surface 2,778 M2

The Unit turbine specifications at 100% TMCR as per figure (5.7) are:

a. Generated power output 393MW b. Superheated steam pressure 167.7 bar c. Superheated steam temperature 538oC d. Superheated steam flow 317.3 kg/Sec e. Condenser vacuum 0.085 bar (a) f. Steam to reheater temperature 334.7oC g. Reheated steam pressure 39 bar h. Reheated steam temperature 538oC i. Reheated steam flow 292.7 kg/Sec

At the outlet of the turbine H.P cylinder, the steam is diverted to the boiler as cold reheat to be reheated in the reheater tubes, then to be directed as hot reheat to the turbine I.P cylinder and then to the L.P cylinder.

5.4.2 Advantages of Steam Reheating

1. It increases the average temperature at which heat is added, thereby increasing the power output and hence the cycle efficiency, as shown in figure ( 5.6).

2. It raises the unit efficiency. As per the performance test, the boiler efficiency is 91% and the unit heat rate is 9418 kj/kwh, so the unit overall thermal efficiency is 1 3600 η = = x 100% = 38.22% HR 9418 Normally, the overall thermal efficiency of a steam turbine unit with BWC pumps and GR fans is equal to about 34%. The raise in efficiency = 4.22% .

3. It results in an operating condition which involves less moisture in the turbine expansion process. A major source of wear on turbine blades is the erosion caused by liquid droplets. The reheat process is more effective in preventing moisture from entering the turbine.

5.5 Steam Turbine Unit Condensate Polishing

The author met this modern sophisticated technology in Shoaiba power plant in the Kingdom of Saudi Arabia, where he works at present as a consulting engineer. He attended the construction and installation of the condensate polishing plant, and he himself did the commissioning and the performance test of the condensate polishing plant. He studied this plant as it was built, then he got more supporting information from the commissioning and performance tests procedures. As it is known in power projects, the operation and maintenance manuals are the last to be handed over to the client at the end of the project.

The author has got previous experience in the demineralization plant mixed bed units, which functions are similar to the condensate polishing plant in removing the minerals and salts from the make-up water / condensate, but their locations in the plant are different.

At the end of this description, the author stated the advantages of the condensate polishing plant.

Condensate polishing is the process of removing mineral salts from condensate by ion exchange. The condensate polishing plant (CPP) function is

75 to ensure and re-establish the condensate quality for the water/steam cycle of the power plant. It is composed of two sub-systems:

1. The Condensate Polishing Units (CPU), which have both the purpose of mechanical cleaning and the removal of foreign ion substances of the condensate.

2. The External Regeneration System (ERS), in which the exhausted mixed bed resin is periodically sent and mechanically and chemically processed in order to supply a cleaned and regenerated ion exchange resin charge for the consecutive service cycle of the CPP.

The CPP is installed downstream of the condensate extraction pumps discharge header. In Shoaiba Power Project Phase I, CPP consists of three Condensate Polishing Units (CPU), i.e. each CPU for a steam power unit, and one common condensate polishing External Regeneration System (ERS). Each CPU includes 2x50% ion exchange polishers (Mixed Beds). Each M.B consists of a cylindrical vertical pressure vessel in stainless steel with hard rubber internal lining, condensate distribution and discharge system, ion exchange resins, sight glasses, manholes, all flanged connection nozzles, internal strainers, outlet resin trap, interface piping and valves, supports and hangers, instruments and control equipment (ref. 40).

The condensate polishing process involves two ion exchange reactions: cations, such as calcium, magnesium and mainly sodium and ammonium can be removed by cation exchange resin, while anions, such as chlorides and silica can be removed by anion exchange resin.

Condensate polishing by ion exchange can be conveniently accomplished by passing the water to be processed through a vessel containing a bed of mixed cation and anion resins. When condensate containing a solute (for example a neutral salt) passes through an intimately mixed resin bed (of strong acid and strong base resin), the cations and anions of the salt are retained by the two resins and the hydrogen and hydroxyl ions, released by the ion exchange, react to form water. The specific reaction rates are quite fast.

Figure (5.10) shows the condensate polishing plant operation relevant to the three condensate polishing Units of Phase I in Shoaiba Power Plant.

Each M.B unit is further equipped with 2 x 100% recirculation pumps (to permit operation at low condensate flow rates and to be used during rinse

76 phases) and the resin transfer system, complete with interface piping, isolating valves, I&C equipment and sight glasses.

The ERS includes one resin separation and Anion Regeneration Vessel (ARV), one Cation Regeneration Vessel (CRV) and one Mixing & Holding Vessel (M&HV).

5.5.1 Actual Operating Conditions and Data

1. Condensate polishing units installed – 3 in number, each for a 350 MW steam power unit.

2. Number of mixed beds per condensate polishing unit 2x50%.

3. Total condensate flow rate to be treated at normal operating conditions:- Minimum = 350 m3/h Maximum = 1220 m3/h

4. Operating Pressure at normal operating conditions Minimum = 33.0 bar Maximum =39.0 bar

5. Operating condensate temperature = 45 0C

6. Mixed bed operating time between 2 consecutive regeneration sequences ≥ 15 days

7. Instrument air operating pressure = 5.9-8.6 bar

8. Service air operating pressure ≥ 8 bar.

5.5.2 Effect of Condensate Polishing

The condensate, collected in the condenser, is pumped by the condensate extraction pumps to the feed water/steam cycle. The condensate after the condensate extraction pumps enters the condensate polishing plant as raw condensate. Table (5.2) shows the raw condensate analysis upstream the polishing plant during normal operation of steam unit.

Table (5.2) Raw Condensate Analysis

77 Unit Normal Operation Item Analysed PH - 9.0 – 9.1 Ammonia (as NH3) µg/l 400 Silica (as siO2) µg/l < 20 Sodium (as Na) µg/l 10 Total iron, copper, nickel µg/l 20 Chloride (as cl) µg/l 20 Calcium µg/l Nil Suspended solids µg/l < 50 Total Dissolved Solids (TDS) µg/l <250 Source: Shoaiba power plant CPP commissioning test document, 2003.

The condensate polishing process takes place in the condensate polishing plant. Whereas, at the end of the process the analysis of the treated condensate downstream the polishing plant will be as shown in table (5.3).

Table (5.3) Treated condensate analysis Item analysed Unit Normal operation Total hardness Nil Cation conductivity at 25 OC µs/cm <0.1 Silica (as siO2) µg/l <10 Total iron, copper, nickel µg/l <10 Sodium (as Na) µg/l <1 Chloride (as cl) µg/l <5 Suspended solids µg/l <10 Total Dissolved Solids (TDS) µg/l <25 Source: Shoaiba power plant CPP commissioning test document, 2003.

As shown from the two tables of the raw condensate and treated condensate analysis, the effect of the condensate polishing is mostly clear in reducing the concentration of salts, measured normally by Conductivity or Total Dissolved Solids (TDS).

TDS= Conductivity x 0.5 TDS unit is mg/l or ppm

Where, mg/l = 1 ppm and 1 µg/l = 1000 ppm or 1 ppb So, TDS has been reduced from <250 µg/l to <25 µg/l, i.e from <0.25 ppm to <0.025 ppmWhile, conductivity has been reduced from <0.5 µs/cm to <0.05 µs/cm. 5.5.3 Exhausted Resin Regeneration

When regeneration becomes necessary, the metallic cations are displaced by the high hydrogen ion concentration of the regenerant (sulphuric acid in this case). While, the anions are displaced by the high hydroxide ion concentration of the regenerant (Sodium hydroxide). Figure (5.9) shows the ERS with a sequence of operation, while other sequences could be followed easily.

The sequences of the regeneration process are as follows:

1. The exhausted mixed resin is transferred from the CPU to the ERS, where it collects in the ARV, as shown in figure (5.9).

2. The regenerated resin is transferred from the M& HV of the ERS to the empty CPU.

3. Start separating the cation and anion resins by passing up-flow water through the backwash inlet to the ARV. The higher specific gravity cation resin settles to the bottom of the ARV and the anion resin settles on top.

4. After the two resins are separated, the cation resin is transferred (from the vessel bottom) to the CRV.

5. The cation and anion resins in the CRV and ARV are separately regenerated and rinsed.

6. The cation resin is transferred from the CRV to the M&HV.

80 7. When process No.6 completes, then the anion resin is transferred from the ARV to the M&HV.

8. The regenerated anion & cation resins in the M&HV are mixed together by air. By the end of the last process, the regenerated resin will be ready for transfer to the service CPU.

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5.5.4 Advantages of Condensate Polishing

The main function of the CPP is to reduce condensate conductivity (or TDS). So, the advantages of this function are:

1. The steam unit will continue in operation generating power even if the raw condensate conductivity is high, and need not be shut down as usually is done during the absence of the CPP. The conductivity rise may be due to condenser tube leak or contaminated make up water or contaminated condensate drains to system. 2. Saving of money by saving of the feed and condensate water, which if contaminated, during the absence of the CPP, is drained to waste and replaced by demin make up water.

3. The steam unit Reliability will be more, and hence, its efficiency will increase.

5.6 The Flue Gas Electrostatic Precipitator

The author met this modern sophisticated technology in Shoaiba power plant, in the Kingdom of Saudi Arabia, where he works at present as a consulting engineer. This technology appeared recently as an environmental requirement to reduce the adverse effect of the power stations exhaust flue gases on the environment. As known, the flue gases contain CO2 which increases the greenhouse effect and results in an increase in the worlds average temperature and rises the oceans levels. The flue gases also contain SOx and NOx that react with air and humidity to produce sulphuric acid and nitric acid and cause the acid rains and corrosion.

The manufacturer still considers most of the design and functionality of the electrostatic precipitator are firm secrets. No operation and maintenance manuals have been provided yet in the power station. The author got his information for compiling this description from his study of the as-built configurations and from the contractors’ commissioning procedure.

At the end of this study, the author stated the advantages of the flue gas electrostatic precipitator.

It is defined as follows:

“ The electrostatic precipitator (ESP) is a device where dust particles can be separated from a flue gas stream by action of electrostatic forces.”

The most important function of the ESP is that it reduces the environmental pollution by the exhaust gases. The location of ESP in the power plant is between the rotary air preheater and the I.D. fan. The size of the ESP in Shoaiba Power Project, Kingdom of Saudi Arabia, is about 30% of the boiler size, with ash collection surface area equal to 21,600 m2 (ref. 24). From the construction point of view an ESP can be seen as steel casing, internally subdivided into channels where the gas can pass through. The channels are delimited by plate curtains, supported over the internal structure of the ESP. A frame with secured spiral wires is located within each gas passage. All the frames are then linked to each other to form a rigid framework. The entire framework is held in place by four support insulators that seat over the ESP roof.

During operation and due to the presence of insulators, the spiral wires framework is electrically insulated from the other parts of the ESP, which in addition are all connected to earth (grounded). A high voltage direct current rectifier, typically 70kV negative voltage, is connected between the framework and the ground, thereby creating a strong electrical field between the wires in the framework and the steel curtains. The schematic diagram of the ESP internal parts is shown in figure (5.10).

The process inside the ESP continues as follows. The electrical field becomes so strong near the surface of the wires that an electrical discharge (corona discharge) develops along the wires. The gas is ionized in the corona and large quantities of positive and negative ions are formed and start to travel towards the opposite sign electrodes. Negative ions, in their travel to the nearest positive curtain, collide with and adhere to the particles in the gas. The particles thereby become electrically charged and also migrate in the same direction of the ions. Dust is collected on the curtain (collecting electrodes) and then removed from there during periodic rapping. This process of dust collection from flue gas is shown in figure (5.11).

5.6.1 ESP Components

1- Ash collecting system. It is composed of:

- Two primary support structures. - Two independent casings from both air preheaters.

84 - One set of access facilities (stairs, walkways,…) - Two inlet funnels, with related set of gas screens. - Eighteen pyramidal hoppers. - Two ESP inlet guillotine dampers. - Two ESP outlet guillotine dampers. - Four expansion joints. - Two warm purging air production systems. - Six high voltage power units (transformer/rectifier). - Eighteen ash discharge assemblies. - Two gas screen rapping system - Twelve discharge electrodes rapping system. - Six collecting plates rapping system. - Twelve emitting system, each composed off:

• 4 support insulators • One bushing insulator • One rigid frame • 720 spiral type electrodes 2- Ash handling unit. It is composed of a storage silo, a truck and 6 bin trolleys.

5.6.2 Effect of ESP

The effect of ESP is shown in two ways, one in the removing rate of dust from the flue gas stream by the de-dusting equipment; and the other in measuring the emission at the unit flue gas stack.

The testing met-hod and equipment are according to ASME D3685/3685M-Standard test method for sampling and determination of particulate matter in stack gases (ref. 16).

In order to identify the effect of the ESP, flue gas samples are collected and analysed at the ESP inlet ducts as well as at the stack. Since the flue gas velocity and particulate concentration may vary from point to point in the duct, the code requires that sampling be performed over the whole cross- section of the duct, not at just one point. For each casing or duct of the ESP one sampling section upstream the de-dusting equipment has to be identified and equipped according to geometrical and flow dynamic considerations suggested by the Code. Sampling is conducted in the ducts by introducing a probe through five ports covering the cross-sectional area, with eight readings from top to bottom of each port, i.e. with 40 readings for each inlet duct. The sampling section at the precipitator outlet will be located into the stack and will sample the mixed flue gas stream, and due to the stack

85 circular symmetry, the velocity distribution profile is likely to be the same. The probe is inserted into one port to read 3 readings to the centerline, and then it is removed to the other port at the opposite side to do the same, i.e with 6 readings.

The samples are treated in a so called “sampling train”, that is an assembly of equipment suitable to analyse and calculate the flue gas data, i.e temperature, pressure, water content, velocity, flow, and particulate concentration. The test is normally done with the boiler operating on 100% BMCR, with crude oil or HFO. For easiness of comparison due to its international standard, HFO will be used for the boiler during conducting the ESP performance test.

The HFO specifications and the resultant flue gas data are shown in table (5.4)

Table (5.4) HFO Specs. And Resultant Data Unit power output 426 MW Fuel Oil Type HFO Boiler firing rate 100% BMCR Fuel oil burn rate (kg/s) 23.89 HHV (kj/kg) 43,031 Heat input (kj/s) 1,028,011 Flue gas flow rate (g/s) 409.5 Avg. molecular wt (g/gmole) 28.91 Gas density (g/Nm3) 1.291 Flue gas flow rate (Nm3/S) 317.2 Max. Particulate Conc. At ESP inlet (mg/Nm3) 500 Source: Shoaiba power plant ESP performance test document, 2003.

The actual data calculations are to be corrected to the design conditions of flue gas flow, temperature, humidity, and dust concentration.

86 87

1. The particulate (or dust) removed by the ESP is equal to its concentration at the ESP inlet minus its concentration at the stack.

The particulate removal efficiency is defined as the ratio of mass flow rate of dust removed from the flue gas stream over mass flow rate of dust at precipitator inlet, i.e.

W -W η= in out Win Where:

Win = Mass flow rate of dust at precipitator inlet (kg/h) Wout = Mass flow rate of dust at precipitator outlet (kg/h) The same parameters can also be evaluated as:

C -C η= in out Cin Where:

Cin = dust concentration at precipitator inlet (mg/Nm3) Cout = dust concentration at precipitator outlet (mg/Nm3)

Particulate removal efficiency guaranteed value to be targeted is: η=85%

At such ESP efficiency and when firing HFO, the smoke opacity (rate of blackness) at the stack, as per MEPA standard, is to be targeted < 15%.

The sampling and measurement results at 100% BMCR with HFO in the ESP inlet and the stack are shown in table (5.5)

Table (5.5) HFO sampling and test results Item ESP inlet Stack Flue gas flow rate (g/s) 204.8 44.09 Flue gas temp. at ESP inlet (0C) 144 - Flue gas pressure at ESP inlet (mm w.g) -459 - Flue gas density (g/Nm3) 1.291 0.139 Actual flue gas flow rate (Nm3/s) 158.6 317.2 Internal dimensions at sampling section (mm) 3400 x 4620 D4880 Cross-sectional area at sampling section (m2) 15.71 18.70

88 Flue gas velocity (m/s) 16.1 25.9 Number of sampling points 40x2 6 Standard probe internal diameter (mm) 4.5 4.5 Expected dust concentration (mg/Nm3) 500 75 Inlet/outlet dust concentration (mg/Nm³) 190.3 28.5 Source: Shoaiba power plant ESP performance test document, 2003.

Therefore, the particulate (dust) removal efficiency is equal to:

190.3 – 28.5 η = x 100% = 85.02% 190.3

2. The particulate matter emission is determined as the ratio of the particulate mass flow rate at the stack over the heat input of the boiler (fuel rate times the fuel high heating value).

Particulate mass flow rate Particulate matter emission = Heat consumption

Where,

Heat consumption = fuel flow rate x fuel HHV

The particulate matter emission guaranteed value to be targeted, according to the MEPA requirement is ≤ 43ng/j.

The stack flue gas sampling and measurement results at 100% BMCR with HFO are used to identify the particulate matter emission, as follows:

Fuel oil burn rate = 23.89 kg/s HHV = 43,031 kj/kg Heat input = 23.89 x 43,031 = 1,028,011 kj/s Particulate mass flow rate = 44.09g/s

44.09 x 109 Particulate matter emission = = 42.89 ng/j 1,028,011

5.6.3 Advantages of ESP

1. It is well known that power stations are having great effect on spoiling the environment by exhausting flue gases to the atmosphere. The ESP reduces this adverse effect to the minimum. The measurement of particulate matter and collected residue emission rate is an important test widely used for environmental pollution control. Particulate matter measurement after control devices are necessary to determine total emission rates to the atmosphere and the opacity of the flue gas. These

91 measurements, when approved by federal and state agencies, are often required for the purpose of determining compliance with regulations.

2. The generating unit control for perfect combustion at the boiler will reduce the CO2 percentage at the ESP and will lead to economise fuel consumption and hence, will raise the efficiency.

Chapter 6

DEVELOPMENT OF POWER STATION MANAGEMENT

6.1 Introduction

The Author in this chapter dealt with the engineering management, which became as important in the power generation field as the engineering technicalities. For preparing this chapter the author relied on his background and long experience in the power generation field, in addition to relying on many references in the engineering management and supplies management.

The author’s opinion is that any engineer, who might become a manager one day, must equip himself with the engineering management. He himself, during his work progress in power station, felt the importance of the management awareness to engineers.

The target of the author from this thesis, as was shown in chapter 1, is to reduce the generated power cost, and in the same time, to raise the efficiency of the generating units to higher levels. The objectives of the power station manager and his ways of leading will help to reach the author’s targets by a managerial way, as highlighted in this chapter.

92 The scope of the Power Station Management includes the staff organization chart, job descriptions, duties and rights, reasons of performance inefficiency and remedies, types and categories of maintenance planning, regular management meetings, the annual budget, staff training, and warehouse management. Most of these aspects of power station management had been dealt within the author’s M.Sc. thesis.

In this chapter the Author will deal with the modern role of the power station manager in a sophisticated power station, as well as the development of warehouse management towards centralization, with upgrading studies from the author’s own point of view, by using modern technology of computer system and special warehouse programs, e.g. by using a locally adapted international program from the American Software Institution – Material System (ASI System).

The modern role of the power station manager, as will be shown, is categorized in two aspects: a) the objectives he tends to fulfill, and b)the ways of leading he tends to follow.

6.2 Objectives of Power Station Manager

1. Same Usage: Reduce Costs by Tariff negotiation.

The procedure of electric power generation cost calculation was dealt within details in the author’s M.Sc thesis, where the kWh cost was shown to be calculated through the overall calculation of the fixed and variable costs for a specific period of time, then by adding them together, and dividing the total by the total units generated at the same specific period of time. The cost of transmission and distribution lines plus the expenditure of the head quarter will be added to kWh cost to reach the actual electricity cost and the profitable electricity tariffs. Concise details of this matter are shown in the ‘introduction’ in chapter 1 of this thesis

As a manager of electric power plant, the power station manager may not bother about electricity tariff negotiation, but he should do so. The power station auxiliary consumption is a part of kWh cost calculation. In some areas in the Sudan the power station manager is designated simultaneously as the area manager, with responsibilities to deal with tariffs.

Electricity cost is related to tariffs with different structures, and it is a matter of negotiation with the area board as to which is the most advantageous structure to adopt. The tariff structure will not of itself alter the total

93 consumption of electricity but may suggest a different pattern of usage to reduce costs. The forthcoming examples of electricity costs are related to U.K tariffs for comparison. Tariff structures are categorized (ref. 5) as:

a) Domestic electricity tariffs.

Domestic tariffs are available to private residences where the maximum demand for power does not exceed 25kw, as internationally stated. The standard tariff for domestic consumers deals with a fixed quantity standing charge and a rate per kWh consumed. The fixed quarterly standing charge is used as a rental charge to the power connection and metering equipment that joins the load to the supply system. In U.K. all domestic consumers can apt for an ‘Economy 7’tariff where consumption is separately metered during the day (17 hours) and night (7 hours), the night time consumption is charged at a lower rate than the day time. The seven hours of night period are not necessarily a single continuous period but any seven hours between 2200 and 0900 hours. Referring also to U.K. tariff, the typical figures for such tariffs are shown as:

General domestic tariff - Quarterly fixed charge = £ 7.50 Unit charge = 5.94 p/kWh

‘Economy 7’ domestic tariff- Quarterly fixed charge = £ 9.80 Unit charge = 2.07 p/kWh for the night period = 6.26 p/kWh for day time.

b) Block electricity tariffs

For non-domestic loads of up to 50kVA the normal tariff is a block tariff, which deals with a fixed quarterly charge, a unit charge for the first 1,000 kWh and a lesser charge for additional unit consumed. There are variations on this tariff with ‘economy 7’ rate and other arrangements involving weekend / evening rates. Typical figures for such tariffs are shown as:

General block tariff- Quarterly fixed charge = £ 7.90 Unit charge = 8.13 p/kWh for the first 1,000 kWh. = 6.09 p/kWh for additional kWh

‘Economy 7’ tariff- Quarterly fixed charge = £ 10.20 Unit charge (day time) = 8.13 p/kWh for the first 1,000 kWh. = 6.41 p/kWh for additional kWh Unit charge (night time) = 2.07 p/kWh

c) Maximum demand electricity tariffs. Maximum demand electricity tariffs are used for large premises. These tariffs are controlled by four items: The availability charge, the demand charge, fuel price adjustment, and unit charges.

The availability charge is the cost of providing the local distribution network to each consumer, and is expressed as £ / kVA of chargeable capacity. Thee demand charge is based on the highest demand (kVA) recorded in a month. The maximum demand is defined as the highest average rate of consumption in any half-hour period, or twice the number of units metered in any half-hour period.

The maximum demand is identified by a device which meters consumption for a given half-hour, resets to zero at the beginning of each new half-hour and indicates the maximum reading of all previous half-hour periods. The fuel price adjustment is a small correction supplied to the unit charge related to the replacement price of fuel burned at power stations from price of fuel. The unit charges is the cost identified by three scales:

Scale 1- Separate charges for day and night units apply. Availability charges and demand charges related to demands at any time.

Scale 2- Separate charges for day and night units apply. Availability charges and demand charges only apply to demands outside the seven-hour night period.

95 Scale 3- all units are charged at one rate only (for low voltage, less than 1,000 V only). Availability charges and demand charges relate to demands at any time.

Availability Charges-

Low voltage supplies (scales 1,2, & 3) For the first 50 kVA of chargeable capacity =£ 0.96/kVA For additional kVA of chargeable capacity =£ 0.79/kVA

High voltage supplies (scales 1 & 2) For the first 500 kVA of chargeable capacity = £ 0.72/kVA For additional kVA of chargeable capacity = £ 0.60/kVA

Demand charge- The following charges apply each month to each kVA of maximum demand recorded in that month.

Low voltage supplies (Scales 1,2 & 3) In each of the months March to October inclusive = Nil In each of the months November and February = £ 2.10 In each of the month December and January = £ 6.70

High voltage supplies (scales 1 & 2) In each of the months March to October inclusive = Nil In each of the months November and February = £ 2.05 In each of the months December and January = £ 6.45

Unit charges- Scale 1 Low voltage High voltage

For units supplied during the 7 hour night period 2.06 p/kWh 1.95 p/kWh For units supplied outside the 7 hour night period 4.62 p/kWh 4.28 p/kWh Scale 2 For units supplied during the 7 hour night period 2.18 p/kWh 2.07 p/kWh

96 For units supplied outside the 7 hour night period 4.62 p/kWh 4.28 p/kWh

Scale 3 For units supplied at any time 4.59 p/kWh - It is important to note here, that the above months of low and high demands will reverse for tropical regions, e.g. the Sudan.

Apart from tariff negotiation, electricity cost can be reduced by:

Load factor- An improvement in the load factor will lead to the demand charge being distributed over greater number of units and hence, lead to a lower average price. The maximum demand can often be reduced by energy recovery schemes, or by the careful sizing of equipment such as heating elements, or by the use of modern methods of lighting and heating buildings.

Annual consumption in kWh Load factor = Max. Demand (kWh) x hours in year8760

In order to improve load factor, special technique is used, which is known as demand management, a system which will reduce electricity consumption if the metered demand looks likely to exceed some pre-set limit, after maximum demand study. Systems in use normally employ microprocessors-based units to predict the half-hour demand and compares this to a reference level. If the forecast demand exceeds the reference level then the management system will either sound a warning alarm or take action by disconnecting the supply from non-essential usage and later reconnecting it when the total demand has reduced.

Power factor-

useful (active) power (kW) Power factor = Apparent (reactive) power (kVA)

The power factor decreases with reduction in load when using too large motors for the duties required or when running motors on part loads. Also slow speed machines have a lower power factor due to the greater leakage and other losses caused by the large number of stator poles. There are three ways of improving the power factor: (a) Connect in a capacitor or bank of capacitors, (b) using a synchronous (induction) motor for part of the load and running it at a leading power factor, (c) using a synchronous motor on no load as a synchronous capacitor.

The customer will be billed for the apparent power because it is his responsibility to make best use of the energy on his own premises. There is extra tariff if the power factor falls below about 0.8.

2. Less usage: Good housekeeping by running existing plant in a more effective way.

Housekeeping generally refers to the situation where all staff within the power station are aware of the cost of energy and adopt simple measures to save energy. An example of good housekeeping could be simply as staff switching off equipment when it is not being used e.g. lights, space heaters, ventilation, air conditioning system. It could also be a constant awareness of leaks of steam, oil or compressed air. This aspect of the power station manager’s job is more to do with the education of staff. The success in ‘good housekeeping’ is matter of good staff management. Let us take in details some of the above-mentioned examples, where some checks for good housekeeping have to be done by the power station staff:

a- Lighting -

- Make the best use of daylight by keeping windows and roof lights clean, also by suitable arrangement of working places near windows. - Keep lamps and fittings clean - Replace lamps when their efficiency drops through ageing. - Use suitable reflectors and diffusers, which transmit light in the desired direction. - Avoid dark background colors, which absorb light. - Have separate switches to control lights near windows. - Consider automatic switching of lighting. - Use fluorescent or discharge lamps rather than filament lamps. - Make sure to switch off light when not required.

b. Space Heater-

- Do not heat unoccupied working areas. - -Limit maximum temperature to the limit of 19 0C, and check the accuracy of temperature control.

c- Heating, ventilation & air conditioning (HVAC)-

98 - Avoid draughts by a properly sealed system, sealing doors, windows etc. - Doors and windows should normally be closed in cold weather. - Air heating is to be used during cold weather only. - In air-conditioned buildings ensure that the controls for moisture content, temperature and direction of airflow are effective. - Switch off air-conditioning controls in unused rooms. - After working hours keep air-conditioning system only working for control rooms, electronic rooms and shift staff rooms. - Avoid air leaks in ducts by sealing them.

3. Less usage: Improve plant performance by retrofitting energy- saving measures.

This technique will mostly deal with energy Monitoring, energy Auditing and energy Targeting. When the power station manager collects data about the overall energy consumption, it can be said that energy consumption is being monitored. When the data is analyzed to show the pattern and efficiency of energy usage, it can be said that energy data is being audited. The result of auditing will help the power station manager to evaluate targeting the objectives.

In a power station the electricity consumption will effectively be monitored by the sum-meter installed, but if the manager requires having a more detailed knowledge of consumption, then he will install separate meters at a number of locations of major use. This information can be recorded and analyzed to indicate trends in areas of major demand. A similar system can be used to meter the detailed consumption of other consumables such as fuel, oil and water. After monitoring the next step is to analyze the data and carry out an energy audit. The aim of the audit is to determine according to targets how well the power station uses the energy, and how this will affect the energy cost contained in the price of electricity produced (kWh cost).

4. Less usage: New equipment/new process development with energy conservation in mind.

With the poor condition of a specific plant within the power station negates the effectiveness of retro-fitting, then it is the power station manager to decide to replace it by a new plant. The new type of plant has to be more appropriate for energy saving and hence, cost saving. The new equipment or new process development may lead to install a combined cycle unit instead of a simple cycle unit, or install a co-generation unit with Combined Heat and Power (CHP) production, where a same amount of fuel could be exploited

99 through HRSGs to generate more power or heat, and hence, energy saving will be fulfilled.

The process of investing capital in energy saving projects is controlled by two main methods: the Accounting Rate of Return (ARR), and the payback.

a- The ARR method –

This method is defined as follows:

ARR = Average net annual savings (after depreciation) Capital cost

This method indicates to the power station manager what level of return will be obtained by the investment of capital into energy-saving schemes. Normally ARR targets to 8.0 %.

b- Payback-

The payback period is the length of time required for the running total of net savings, before depreciation, to equal the capital cost of the project. The shorter the payback time, the more attractive the investment will be. The depreciation, as shown in chapter 1 ‘ Introduction’ is the stipulated period of the plant, where after a certain period of useful life it loses its efficiency or becomes obsolete and needs replacement.

The method is simple to apply and favors projects with a short payback time, which reduces the uncertainty of calculating savings for periods a long time in the future. The effects of changing technology and energy prices for example, are then reduced. The method does not consider savings produced after the payback time and therefore does not assess the overall value of the project.

5. Less usage/same usage: Money saving as a result of above techniques, and safety technique.

As we have seen, the four above techniques are directly helping the power station manager to fulfill his objectives of saving money. Now, there is another technique, which started drawing more attention to its importance in indirectly helping the power station manager to improve his act of saving money. This technique is safety technique. Strict compliance to safety measures will reduce/eliminate accidents that lead to destruction of buildings,

100 equipment, machines, and disability or loss of life of staff. The consequence of accidents is always loss of money in reconstruction, reinstallation and compensations. Plant safety has become in modern management a direct responsibility to the plant manager (power station manager). Accident prevention in a power station can be studied as follows:

a- Definition of accident-

“An accident can be described as an unplanned event in a sequence of planned events which can lead to physical harm, damage to equipment or property or a combination of these factors.”

Figures of accidents differ from one phase in industry to another e.g. construction phase of a power station records more numbers of ‘persons falling’ and ‘falling materials’ than commercial running phase. This may be due to the difficult working conditions experienced on construction sites, where the environment of the workplace is continually changing as work progresses.

b. Causes of accidents

Accidents can be caused by unsafe acts and attitudes of people at work, which result in unsafe conditions being created. The most frequent known causes of accidents on a power station are:

- Lack of knowledge of good safety techniques. - Lack of safety awareness through training courses in safety rules, risk assessments, hazardous substances assessments. - Incorrect use of working platforms, scaffolding towers and ladders without using safety belts, helmets and safety shoes. - Incorrect use of machinery, equipment, tools and electrical installations.

c) The cost of accidents -

Cost to the victim: - Pain and suffering - Loss of earnings - Extra expenses - Continuity disability - Incapacity for the same job - Incapacity for activities outside the job. - Consequent effect on dependants and relatives

101 Cost to the power station: - Work time lost by the victim - Time lost by other staff out of sympathy, curiosity, and discussion. - Time lost by engineers and others investigating the accident. - Possible damage to machines, equipment, materials - Idle time (re-plan, repair and reinstate the job) - Rise in insurance costs - Prosecution by the legal procedure and claims for compensation. - Damage to the power station reputation. Cost to the engineer directly responsible: - Worry and stress - Guilt - Extra work e.g. reports, training and recruitment - Loss of credibility Cost to the working group: - Shock - Personal grief - Low morale - Effects on production Cost to the Sudan: - In social and economic terms, accidents are an unwanted expense. - Many thousands of person days production are lost each year. - Many hospital beds are occupied. - Billions of Dinars are paid in pensions and compensations. - Many lives are changed for the worse.

6.3 Ways of leading to be adopted by Power Station Manager

The power station manager must have a quality of leading, although leading as well as organizing and delegating work are all considered as non- engineering activities/responsibilities.

Leadership is defined as: ‘the ability to enthuse, to inspire and guide subordinates.’ A manager is generally defined as: ‘a person who gets things done by working with people and other resources to achieve the objectives.’ Both the above definitions when related to the power station manager will apparently reflect the ways he has to adopt for his leadership. These ways of leading are shown as:

1. Leading through motivation

102 Motivation means encouraging subordinates to work with zeal and gusto and cooperate for achieving the objectives of the organization (power station). The manager must motivate his work force to peak performance. The motivational system must satisfy the ego needs of the group besides being flexible, competitive, comprehensive and productive.

Motivation can be more effective if it is inspired through the inter- relationship between the manager and his work force by trust, honesty, transparence, justice and fairness. Motivation can be controlled by meetings, publications, supervision and follow-up.

Experience in the field of motivation proved that it can be practiced through religion, morals, conscience and patriotism, as well as through material rewarding, which could be promises for bonus, for upgrading or for promotion, in order to secure efficiency of the staff to achieve the objectives. In this regard grants of ‘praising certificates’ to the successful staff are by themselves not enough.

The staff evaluation in the motivational process is done through staff performance measuring. It is an act of practicing fairness and nonbias in granting the right reward to the right person. The power station manager’s supervision and close follow-up are required.

2. Leading through communication

Communication is defined as: ‘the interchange of thought or information to bring about mutual understanding and confidence or good human relations.’ Thus communication forms the basis of understanding between the various members of organization (or power station in our case). Communication is particularly important in the function of direction, by which people are linked together in the power station in order to achieve a central purpose.

Communication is the means by which behavior is modified, change is affected, and goals are achieved. In general, there are two types of communication in a power station: internal communication and external communication. a. Internal Communication.

It is concerned with communication inside the power station. It is classified as follows:

- Oral communication; it may be a face-to-face conversation or through telephone or radio (walky talky) within the power station.

103 - Written communication; it takes the shape of a letter, circular, manual, bulletin, office memo. A centralized computer system helps a lot in this regards. - Formal communication; it is the transmission of direction or information in the power station formal structure. - Informal communication; it is the transmission of messages between the members of the staff on the basis of informal relations. - Upward communication; it is the flow of information from the lower level to the higher level e.g. suggestions, complaints and reports. - Downward communication; it is the flow of information from the higher level to the lower level e.g. objectives, plans, manuals, instructions, circulars. b. External communication

It is the transmission of information to the people outside the power station and its receipt from outsiders. It is classified as follows:

- Oral communication; it is a face-to-face conversation with others outside the power station during visits and meetings. Also it can be an external telephone call, a videophone call or a conference call. - Written communication; it can be carried out through mail, telex, facsimile and Internet.

The power station manager during his leading has to regard to the above internal and external communications in order to understand his staff, to declare his directions and to achieve his objectives.

3. Leading through interpersonal skills.

Skill can be a talent. It can also be gained through education and necessary training. A talented person can be more skilled than an ordinary person if he gets a chance to develop his talent through education and necessary training.

The power station manager, in order to ensure that his staff is skilled, has to stress on recruitment interviews to select from the beginning the best persons out of the applicants to fill the vacancies. On-job training is always considered as preliminary training; then comes the specialized training in training institutes either inside the country or abroad. The allocation and re- allocation of staff members or what is called’ staff movement’ is the manager’s job. In this case work measuring, reporting and performance assessments have to be supervised by the manager, to put the suitable person in the suitable position.

104 Skill makes a person to do his job accurately and quickly, so it raises the efficiency and reduces the time duration of the job.

Skill can be developed through personal recognition, rewarding and promotion; a skilled person is an intelligent person who can learn new things easily. Hence, such a person has to be upraised in order to raise up the performance level in the power station.

4. Leading through group dynamics and teamwork.

Group dynamics and team work can be organized by determining what activities are necessary for any plan and what arrangements are assigned to individuals. In this regard coordination is required among the members to ensure homogeneous performance of activities to accomplish group goals. Coordination is required because different people have different ideas as how group goals can be attained.

Teamwork needs flexibility, transparence and harmony. The group inter- relations must be systematic and trustworthy, with all the work done to relate to the group, not to individuals.

The power station manager during his leading can study the internal structure of the group and can encourage the group dynamics and team work through motivation to achieve his objectives.

5. Leading through innovation and planned change.

Innovation and planned change are mental processes based on available mass of facts and future possibilities. Thus they require the use of trained knowledge, imagination, foresight and sound judgment. Innovation and planned change are to be practiced with reference to the overall objectives of the power station.

The aim of innovation is to change the present situation to a more accurate and productive one, and hence, to raise the power station efficiency.

Innovation requires courage, non-hesitance and decision making from one side, as well as recognition, care and motivation from another side. The power station manager during his leading can look after the innovators, study their plans and needs and direct them towards achieving his objectives.

6.4 The Warehouse Management

105 This part of the thesis had been recommended by the author in his M.Sc’s thesis, to be kept as a future work.

The warehouse management in Dr. Sharif power station has been subjected to some amendments, which are still in progress. The decentralization which was dominating the warehouses managements has now merged to some kind of centralization. The author in the following pages will show the present warehouse management in Dr. Sharif power station, then he will inspire his own concepts for upgrading it.

6.4.1 Present warehouse management

In the past, before the recent amendments, the warehouse controller in Dr. Sharif power station along with his staff, were administratively in a direct reporting relationship to the power station manager, while the warehouse controller was technically in a joint reporting relationship to the power station manager as well as to the supplies manager in the head quarter. During decentralization of warehouses allocated in separate power stations, the role of the power station manager in the stock handling, preservation and exchanging among other power station warehouses is considerably great. Any misallocation of spare parts could be a loss to the power station as well as to any other power station that needed them. Borrowing of spare parts between power stations during acute needs could be dealt with according to interpersonal relationships among managers, which sometimes could be negative and contradict the power generation interests.

Recently when changes to centralization start taking place, the warehouse management has shifted to become under the supplies department in the NEC’s head quarter. The present vast growth of the supplies department makes it to face many complications due to its wide range of coverages, e.g. diversity of materials and services involved, diversity of end users, variety of demand patterns, large number of warehouses in different locations, different purchasing procedures for different goods and services.

The wide range of coverages of the supplies department as shown above can be categorized to make the supplies organization dealing mainly with the purchasing, planning and control of material stocks, and storage and transport of materials. It may also include a central quality control organization. The supplies manager is in a direct reporting relationship to the general manager. The purchasing officer (or manager) reports directly to the general manager on purchasing matters, even though, administratively, he is under the control of the supplies manager.

6.4.2 Upgrading of Warehouse Management

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The supplies organization in the new concept of the supplies department is consisting of three main parts: (1) Purchasing, (2) Stock management, and (3) warehouse management. A senior manager will be incharge of each part, and all the three managers will be reporting to a single supplies manager. In some organization charts the supplies manager is placed as well to be a purchasing manager. The supplies manager in his turn reports directly to the chief executive (or general manager in the case of NEC). This new concept of supplies department is shown in a typical electric power utility organization structure in figure (6.1)

The Main responsibilities of the supplies manager are:

- To assure that the adequate supplies are available as required throughout the NEC warehouses. - The competition level among reputable suppliers is satisfactory. - The fairness and integrity of the purchasing system is followed strictly and is acknowledged by the suppliers. - Home supplies provide the maximum practical portion of the materials than the foreign, whenever possible. - Approved policies and plans exist for necessary expansion of storage and storekeeping facilities and are being progressed in relation to needs. - Comprehensive procedures and standards have been defined for operation of the warehouse system and are being implemented effectively.

The above three consisting parts of the supplies department will now be dealt with as:

1. Purchasing Management

NEC has normally got a monopoly position in fixing electricity tariffs to customers, who may be exposed to unfair pricing, either directly by the corporation itself, or indirectly by the corporation’s suppliers of materials.

Unfair pricing by the corporation may be prevented by public control of the government which is responsible to ensure this, whether the electricity utility is publicly owned or not. The unfair pricing by the corporation’s suppliers passes on to the customers in the form of higher prices for electrical energy, which could be prevented by ensuring that there is open and fair competition between the NEC’s suppliers. This is achieved by applying effective procurement policies and procedure. Establishing and enforcing policies is a responsibility of the NEC’s general management.

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The purchasing manger’s signature on an order document certifies that all purchasing procedures have been correctly followed, and the purchase has been approved at the correct level.

The range of services provided by the purchasing management is:

a- Worldwide sourcing of quality supplies of materials at competitive costs. b- Dealing directly with key suppliers of materials. c- Bearing attention to standards and quality of materials. d- Monitoring market trends for price changes.

The responsibility of the purchasing manager is to maintain the visible integrity of the purchasing organization, but his role is normally extended to assure the following:

- The competition level among reputable suppliers is satisfactory. - The standard bidding procedures are understood, and purchasing security requirements are fulfilled. - Suppliers are satisfied with the integrity and fairness of the purchasing procedures. - Home products of acceptable quality and price are in use to the maximum practical extent. - Cash flow is optimized through effective planning of payment terms, delivery schedules, etc. - A comprehensive register of reputable and dependable suppliers exists.

Some words have come on the above purchasing statement and need to be defined for general understanding and accuracy in meaning.

a- Specification.

A formal statement of the corporation’s technical requirement. A good specification will leave potential tenderness, and after ordering, the manufacturer, in no doubt about what is needed.

b- Standard.

The international and reputable national standards are important instruments of communication between the buyer and the seller.

108 c- Quality assurance.

Failure to follow up specifications and standards of materials will lead to disastrous consequences to the client and relatively to the contractor by non- achieving quality. Due to this, additional effort must be made by the client to supervise the contractor’s activities, e.g. by using consultants when having insufficient in-house expertise to handle the activities.

Quality- The totality of features and characteristics of a product or service that bear on its ability to satisfy a given need.

Assurance-All the planned and systematic actions necessary to provide adequate confidence.

d- Control.

The operational techniques and activities and their use that sustain the product or service quality to the specified requirements.

2. Stock Management

It involves both planning and control. The stock management organization is often split into two sections, one to plan procurement of stock items, and the other to monitor and control levels of stocks.

The concept of the stock management organization is as follows:

- A long-term purchasing plan for defined materials acceptable to users, and to the finance department. - To ensure that the key materials covered by the long-term purchasing plan become available as programmed. - Stock review procedures are in operation for all user areas. - A management information system covering key aspects of stock planning and control is operational and servicing the needs of general management and user departments. - Effective working relationships are operating between the stock planning organization and the purchasing and finance organization.

For upgrading the system, new approaches, such as the ‘just-in-time’ philosophy of stock management, and the development of advanced computer- based information system are also important. The career development of the stock management include extensive experience of both the electric power business, and the stock management itself. Formal training in the more

109 theoretical aspects of stock control would be essential, but must be tempered by an awareness of the special needs of the business.

3. Warehouse Management.

The main function of the warehouse management organization is to store the stock items and to deliver them to users as and when required. It also includes, in most cases, its own transport and particularly any specialized vehicles e.g. forklifts, cranes, and heavy trucks.

The concept of the warehouse management organization is as follows:

- All the staff accept and understand the standards and discipline of the warehouse systems and co-operate in implementing the requirements. - To ensure that transportation of supplies is safe, economical and efficient. - The incidence of stock discrepancies (physical stock compared with records balance) is maintained at the minimum level. - Stock items are stored neatly, efficiently, and securely in identified locations that are readily accessible. - Breaches of warehouse discipline and security are at a minimum level. - Warehouses are adequately equipped with appropriate handling devices. - The NEC’s safety rules and appropriate awareness and follow-up by the staff are required.

Most of the skills and understanding required to manage the warehouse organization are common to many other management jobs of equal importance. Some items require special methods for handling and storage e.g. oil filled equipment, inflammable and hazardous materials, and electronic instruments. The value of the stocks is high, and many high-value items are readily portable, so security is a major consideration. Many warehouses operations involve the use of lifting gear and hoist, and the handling of dangerous items, so the warehouse management must promote a high level of safety consciousness.

The Warehouse Catalogue and Coding System:

A catalogue is needed for every warehouse. When catalogues become extensive and in order to make their usage easier, a method of coding the items stored will be used. Normally the electric power utilities maintain very large ranges of highly standardized items, and in this situation, a coding system is essential. The supplies organization requires a catalogue and coding

110 unit. The function of the coding unit is to maintain and update the catalogue. Every item in stock is assigned a number, with which is associated a brief description in the catalogue. Coding systems may be designed according to a number of different principles, but many utilities have adopted ‘Nature of the item Code’ systems. The principle is that items which have similar natures and functions should have similar coding numbers.

The following typical coding procedure describes the function of a catalogue unit: 1- All requests to the unit to take material under control as stock must be Investigated to determine what exactly the item is. Consider the following: a- Purchasing requisitions and orders, the packing documentation and suppliers invoice if available. b- Corporation specifications, drawings and technical instructions. c- Manufacturers catalogue, drawings, spare parts lists and service manuals. d- Consultations with other departments on common classification if necessary. e- Physical examination of the items, if appropriate. 2. After determining that the material is to be held as stock, consider the following Before alloting a new code:

a- Ensure that the item is classified correctly in the main group and section. Check if there is an existing code covering a similar item (for example where the item is totally interchangeable with the existing coded item)

b- Check if the description on an existing code can be amended to suit the new item (for example replacement of an existing item by a new one which supersedes it)

c- if the item to be coded may be broken down into its component parts and each part coded under existing or new code.

d- if the reinstatement of a cancelled code can cover the item.

3. When new materials cannot be accommodated under existing sections of the catalogue, and having considered the following, a new code may be opened. Consider:

111 a- The classification of existing similar or associated items and the function of the item being coded.

b- Anticipated future stocking of similar or like materials and the order in which they will be stocked, so as to make proper provision for future codes.

4. When writing descriptions keep the following norms in mind:

a- includes only sufficient pertinent information to identify each item.

b- Use only language, which a cross-section of personnel using the catalogue will understand.

c- Ensure uniformity of presentation, the key characteristics to be placed in order of importance.

d- Use standard terms symbols and abbreviations.

5. After allocating a section to the material the next stage is the allocation of the item number, the final three digits. To prevent the same code being used for two or more nonidentical items, a code control register must be used.

Each coded item may be designated a three digit number between 001- 999. Care to be taken to leave ample room between codes for future codes, e.g. to accommodate additional sizes.

6. To facilitate computer storage of data each code is given a check digit, which will verify the code. The check digit is a number between 0-9 and the following formula is used.

Example: Code 1111012 Take 1st, 3rd, 5th, 7th digits, That is 1102 And multiply by 2, = 2 + 2 + 0 + 4 Then add total, = 8 ------( A) Next add remaining digits That is 1 + 1+ 1 = 3 ------(B) Add results (A) + (B) = 11 Now go to the next highest multiple of 10, in this case 20, and Subtract: 20 – 11 = 9 -: Check digit = 9

112 If the result of (A) + (B) = 10, or a multiple of 10, The check digit = 0 In the catalogue the check digit is shown against each code.

The following is an example of a catalogue entry in a typical system. The catalogue is arranged in four levels for easiness of access, as follows:

Group - One digit Sub-Group - Two further digits Section - One further digit Item - Three further digits

Level Number Catalogue Description Group 2 Underground cable material Sub-group 212 Underground cable Section 2129 33kV underground cable Item 2129605 Aluminum core, stranded, XLPE, Copper wire screened, PVC insulated.

The warehouse standard documentation:

The purchasing management and other supplies transactions can be more simplified by the use of well-designed standard forms for frequently recurring items of correspondence. The documents which are exchanged frequently in the procurement area are as follows:

1. Purchase Requisition

It represents a request from a user department to the purchasing manager to order some item. It is used for standard items, which are to be bought for stock, otherwise memorandum is used.

2. Request for Approval to Purchase

It is a memorandum, addressed to the officer who is authorized to approve the purchase of items of the stated value.

3. Orders for Materials Goods or Services.

Standard forms are used for writing the orders. They will be signed by the officer, whose signature gives them legal effect.

113 4. Goods Inward from Vendor

It is a notice from the person incharge of receiving goods that the items identified on it have arrived.

5. Goods returned to vendor

It documents the return of unacceptable goods to a vendor.

6. Stores Requisition/Return

It documents the movement of materials between warehouses and users, or between warehouses. A user department uses it to requisition materials for a job. When the job completes, the surplus material, or any material, which had been replaced but in serviceable condition, will be returned to the warehouse. The returned material will be also accompanied by this form.

Copies of the above forms and documents are retained by their senders, and most systems require that copies be sent to other locations as well. This facilitates accounting, stock control and other activities.

As this thesis deals mainly with the power station warehouse, it is logical to concentrate on the document of stores requisition/return, and to take it as an example out of the above six documents that are covering the process of supplies. Hence, table (6.1) shows a stores requisition/return document. The columns on this document are detailed briefly as follows:

Location- It initiates the requisition or return.

Date- Date of requisition or return

Week- Number of week in the company’s accounting year.

114 115

Voucher number- Every requisition should be numbered serially, and a permanent record kept. Reference/purposes- Concise explanation of the purpose of the material movement.

Dispatched to/received from- By: Name of despatcher or receiver.

On: Date on which the materials were dispatched or received. Transaction- Only one box from the three boxes to be ticked to indicate the nature of the transaction.

From stores location No: Job No:

To stores location No:

Item- All items are to be numbered. Quantity required – Description- A concise description, preferable the catalogue description is sufficient. Code No.- All stock items are coded. Goods checked- Initials of the person who checked the goods. Cards posted – Initials of the person who records the change in stock level in the two warehouses (dispatching and receiving) Signature authenticating transaction- It is the signature of the warehouse supervisor initiating the transaction. Signature for receipt of goods- It is the signature of the person who receives the goods. This copy – Copies are to be sent to the stock management organization and the stock recording unit.

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Chapter 7

DISCUSSION, CONCLUSIONS AND RECOMMENDATIONS FOR FUTURE WORK

The methodology the author followed in preparing this chapter consists of showing in discussion the importance of this thesis through its objectives and what aspects it tends to fulfill, and what contributions the author acquitted in the different studies of the thesis. Then comes the brief description of the technical and managerial studies and their role in fulfilling the objectives, and lastly comes the numerically stated conclusions and recommendations for future works.

7.1 DISCUSSION

The title of the present thesis is “Technical and Managerial development for raising efficiency in Dr. Sharif power station”. The objectives are accordingly stated as: to convert the gas turbines simple cycle in Dr. Sharif power station to combined cycle, to exploit the Sudan refined fuel oil in Dr. Sharif power station with remedies to all problems that arose from the deviation in fuel oil specification, to introduce and eventually transfer to the Sudan the modern sophisticated technologies in power generation to be installed in Dr. Sharif power station for raising the overall plant efficiency, to economise the fuel cost in Dr. Sharif power station by reducing its consumption by raising the efficiency through the combined cycle, to gain money saving in Dr. Sharif power station through the power station manager objectives and ways of leading, to develop the warehouse management in Dr. Sharif power station to a centralized supplies management, and to look forward for a continuous uniform flow of power generation in Dr. Sharif power station.

According to the objectives, the author aimed to fulfill his target of reducing the cost of the electric power generation and simultaneously to raise the efficiency of the generating units to high levels. This intention if fulfilled, will lead to extensive money saving in the process of electric power generation, which had tended to increase progressively from the 1970’s with the increase of fuel prices. Actually, the fuel cost represents 70% to 80% of

119 the total kWh cost in power generation. As a result of October 1973 war in the middle east, the oil prices started to shoot up from $ 3.0 per barrel to $30.00 per barrel. At present in 2004 and as a consequence to the Iraqi war and to other oil companies downfalls, the oil prices have reached $53 per barrel, a sealing which have never been predicted! It is inevitable in this case to ignore the economic effect in the process of electric power generation. Economy in fuel consumption is not beneficial by itself unless it is accompanied by more resultant work. The mechanical work in power generation is an indication of its convertible electric power generated, and hence, is reflected by the raise in efficiency.

In chapter 1 the author showed briefly the performance promotion that he carried out previously in Dr. Sharif power station in order to improve the efficiencies of the generating units. For a generating unit the efficiency can be improved by: adjusting the air/fuel ratio, cleaning the burners tips, cleaning the condenser tubes, improving the vacuum, cleaning the air heater, soot blowing the superheater tubes, proper insulating the steam pipes, using feed water free of scale formation, eliminating the air, fuel, steam and gas leaks, reducing steam vents and water drains and rectifying passing valves.

Now, technical development for raising the efficiency to higher levels means the usage of modern sophisticated technologies in power generation. The author tended to use these modern technologies specifically in Dr. Sharif power station to fulfill his objectives of the present thesis.

In the present thesis, the author divided his research into seven chapters that include four main studies. Three studies are of technical nature, while the fourth study is related to the managerial aspects of the question. The contribution of the author in each study will be shown along with the description of each study.

The first technical study relates to the conversion of the existing gas turbines’ simple cycle in Dr. Sharif power station to combined cycle. This study is considered by the author as the main field research practically conducted, pertaining respectively to gas-steam turbines combined Hybrid cycle, the Burmeister & Wain Scandinavian Contractor BWSC combined cycle offer to the existing gas turbines in Dr. Sharif power station, modification and adaptation of BWSC offer in accordance to power station technical data, combined cycle efficiency estimation by simulation of modules, combined cycle advantages, and combined cycle reliability, availability and performance test.

In order to be cognizant with combined cycle theory and technology, the author made many contacts through the book shops and internet system to

120 get the text books that deal with this subject. He also subscribed in the Gas Turbine magazine and in the Power magazine in addition to the British Institution of Mechanical Engineers (I. Mech. E) magazine, as he is a member of this international institution. The author gained huge experience during his work as a consulting engineer in the Combined cycle power plant No. 9 project in the kingdom of Saudi Arabia, for a period of five years. The author believes that the combined cycle system is an ideal method of power generation, due to its sophisticated modern technology, that deals mainly with power generation economy, accompanied by high power outputs and resultant high overall thermal efficiencies.

When the author prepared his proposal for his Ph.D thesis to the university of Khartoum in October 2000, he tended to include the combined cycle technology for the above positive reasons and to introduce it and eventually transfer it to the Sudan in building new power plants. Before the time of commencing the presentation of this thesis, two new blocks of combined cycle units were installed and commissioned in Garie power station, north of Khartoum. Each block consists of two gas turbines plus one steam turbine with capacities equal to 2x41 MW + 40MW. The first block came in service in November 2003, while the second block came in service in December 2003. Garie is a new power station and is still under the contractor’s warranty. The new existence of the Combined cycle in the Sudan will be enhanced by the information in this thesis and will not by any means degrade its anticipation and importance.

The effect of the combined cycle in power generation economy, and hence, in raising the overall efficiency to high levels was shown in this study through a computer program prepared by the author for simulating the variable data according to the gas turbines loading and equivalent fuel consumption as well as steam turbine loading, in order to calculate the efficiencies. The author stated that in many cases due to load requirements, most of the efficiency and protection tests are being carried out by simulation through special computer programs. The author succeeded to receive information through his contacts with the manufacturer about the two most reputable international programs (software) for combined cycle simulation, which are the Advance Process Simulator (APROS) and the ASME simulator, but both of them are under copy rights. The author collected actual data for the gas turbines in Dr. Sharif power station in different loads and equivalent fuel flows. He calculated the proposed steam turbine loads according to the given base load and percentages of gas turbines loads. Then he drew a curve for the fuel consumption versus the combined cycle loading. By this way the author dared to estimate the overall efficiencies of the combined cycle at different loads, and saw how much it is raised in comparison to simple cycle efficiencies.

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The author collected and used many international standards to calculate the reliability, availability and performance test of the combined cycle. He put a definition to reliability and how it could be improved and developed. The same he did for availability and showed technically what it means in the combined cycle, where the steam turbine generated power depends mainly upon the block gas turbines outputs. The performance test is defined as the most important test to be carried out for accepting the new generating unit, if it fulfills mostly two guarantee conditions, that are to generate new power equal to or greater than the contract guaranteed power, and to maintain heat rate equal to or less than the contract guaranteed heat rate. The author prepared a performance test computerized program and used it for the calculations.

Starting from the 1970s, the Sudan, same as many other countries all over the world, has suffered a lot from the effect of inflation as a result of the devaluation of its national currency. This could be attributed mainly to the Arab-Israel’s war of 1973, which created an international economic crisis, when the oil producing countries from the middle-east raised the oil prices to high levels, as a consequence for the war, when most of the western countries biased to the enemy and supported him. From that time the turnaround in the energy picture created a need for new solutions to be adopted to reduce the effect on the rising costs of production. This tendency for reducing the cost of production has actually become a must. It mainly concentrates in modern aspects of power generation on problems of energy supply, demand, conservation and economics. In the power generation field, it becomes very important to reduce the fuel consumption by raising the plant efficiency. The efficiency is mainly raised by utilizing the gas turbine exhaust gases, which otherwise are dissipated as waste, by a heat recovery steam generator (HRSG) to generate steam to a steam turbine through a combined cycle.

In addition to the economy of fuel for more power generation, another advantage could be recognized as the reduction of the greenhouse effect, which has been announced since 1980s as a serious environmental problem leading to an increase in the average temperature of the earth and hence to damaging changes to the world’s climate and ocean levels. The greenhouse effect is due to the fact that the sun’s short wave radiation passes freely through the gases, which make up the earth’s atmosphere but the long wave radiation, which reflects from the earth’s surface back to space is partially absorbed by the atmosphere. One of the gases which is an efficient absorber of long-wave radiation is carbon dioxide, the main product of combustion of any fossil fuel.

122 Although the first combined cycle plant was installed in the 1950s, it didn’t draw any attention as an economic modern technology, till the second half of the 1970s. The combined (hybrid) cycle indicates that the overall efficiency is much more than the efficiency of a separate gas turbine and steam turbine. These efficiencies can be shown as 30% for the gas turbine, 33% for the steam turbine, both as separate cycles, and as 45% for the combined cycle, which even reached a record of 52.5% in Drakelow power plant in the United Kingdom.

It is considered in the power plant construction that the average cost of constructing a new plant per its generated power in MW, is approximately equal to one million U.S Dollars per MW, which more or less depends on the size of the plant infrastructure, contractor’s country of origin and competition among contractors. Concerning the combined cycle plant, the cost of installation per MW power is less, as there are no requirements for boiler complications, extra fuel tanks, pumps and fuel lines, even if supplementary burners are used. Hence, the erection time of combined cycle plant is less.

In 1992 the Burmeister & Wain Scandinavian Contractor (BWSC) proposed an offer to the National Electricity Corporation (NEC) to install a combined cycle to the existing two gas turbines in Khartoum North power station (presently Dr. Sharif power station). The power output of this offer was about 28 MW, while its cost was about 20 million U.S Dollars. This offer didn’t receive the care and follow-up that it deserved and hence it remained without any action been taken. The author took this offer and studied it attentively and modified it to adapt the power station, in accordance to the project work to be done by NEC. An additional supplementary firing was suggested to keep the steam turbine running on base load even if one or both gas turbines’ loads were reduced or completely shutdown. The possibility of fuel supply to the supplementary burners was calculated according to phase I units header pressure and flow and the conclusion was that there will be enough fuel oil flow from the power station resources to supply the supplementary firing of the combined cycle. The arrangement for enough feed water to the combined cycle from the power station resources was calculated according to the demineralization plant production and the conclusion was that there will be enough make up water from the power station resources to supply the proposed combined cycle. This same possibility of extra supply to the combined cycle was calculated to the matters concerning the arrangement of enough cooling water and for cooling the cooling water. The proposed combined cycle overall efficiency was estimated by simulation of modules, as any change in the gas turbines loading from base loads to part loads will result in equivalent change in the steam turbine loading and consequently in the fuel consumption. These three variables are the constituents of the efficiency

123 calculation for the combined cycle. The results of the calculation showed that the maximum estimated overall efficiency will be during the base loads equal to 39.67%.

Contacting BWSC to update its offer after its acceptance by NEC is necessary to issue the “go on” instruction for starting the work. The combined cycle technology has recently been practiced in the Sudan, so it is a good chance for Sudanese planners and engineers to cope with this modern technology. In order to preserve more economy in the running cost, gas turbines can be operated with crude oil, instead of light fuel oil, with injection of fuel additives at the fuel skid to eliminate the deposition and corrosion effects of sulphur, sodium and potassium in the combustion chambers and hot gas pass. As the Sudan is now producing natural gas, this source of energy can be used for power generation after conducting the gas conversion requirements. It is advisable to convert the combined cycle to natural gas for more economy in fuel cost and more plant availability due to the clean nature of natural gas which will reduce the effect of deposition and clogging of the flow divider, check valves, nozzles and internal parts, without any need for atomization. This will reduce the routine and forced maintenance and will increase the life of the unit.

The second technical study in the present thesis attempts to examine the exploitation of Sudan refined fuel oil in Dr. Sharif power station. This study also consists of many sub-studies. The author in this study intended to show his contribution in exploiting Al-Obeid refinery fuel oil in firing the boilers in Dr. Sharif power station. The usage of Al-Obeid refinery fuel oil in Dr. Sharif power station started in 1996 and is still in progress. The adequate information for this study was collected by the author from different source, that include the ministry of energy and mining petroleum department publications and reports, as well as its executives televised interviews. An important book, written in Arabic language was published by the ministry of energy and mining in 2002 with a name of “From higleeg to Bashayer” was considered as a good reference by the author. Beside the above references the author got more information from the university of Khartoum chemical engineering department. Lastly and as in general cases, the author collected more information from his free readings in news papers and magazines.

After his transfer from Dr. Sharif power station, the author retained his communications continuing with the power station staff, specially with the engineers of his efficiency and planning department. His contacts continued through the visits, telephone calls, facsimile and internet electronic mails. The author contributed in solving the power plant problems, including the Al- Obeid fuel oil usage by exchanging thoughts and ideas with the power station

124 engineers and by advising them with correct solutions from his own point of view, according to his long experience in the power generation field. The methodology that the author followed in setting up this study attempts to furnish complete information to the reader regarding the Sudan petroleum covering all the aspects of its historical review from the time of the early geo- physical surveys upto date. This includes the details of the type of Sudan crude oil, refineries and their progress, with special concentration to Al-Obeid refinery product of fuel oil and comparing its specifications with the boilers fuel specifications in Dr. Sharif power station. Then the author stated his contribution in solving the problems, that arose from the deviations in fuel properties between the standard boilers fuel oil and Al-Obeid refinery oil, that had affected the flame patterns. Actually, this last sub-study with all problems and solutions involved, is considered as an important filed sub-study for fulfilling the objectives of raising efficiency in the power station and preserving a continuous and uniform flow of power generation.

Starting from 1996, Dr. Sharif power station became using Al-Obeid refinery fuel oil by rail tankers, which were equipped with coil heaters. In this regard the water and impurities contaminations reduced. The fuel oil specifications are close to the units specifications, only with some deviation in viscosity and contaminations, that created an adverse effect on the performance of the pumping system in phase I. The burner header pressure was low, which resulted in short irregular flames with gases at burner atomizer. In order to solve these problems, some modifications were made. The high-pressure fuel oil pumps with flow 8.4 T/h per each were dismantled from the system and a new pumping system was installed with bigger fuel transfer pumps to feed fuel oil directly to the burners header with flow 10 T/h per each. The pumps were commissioned in December 2002 and the fuel combustion was observed. The fuel header pressure was raised from 20 bar to 26 bar. The result was that the burner flame became regular and the combustion became normal. The minimum fuel oil header pressure was set to 20 bar as alarm, and to 12 bar as trip. There is a tendency to replace the oil burner tips to cope with the modifications but so far this has not been commenced.

The third technical study is about new technologies being utilized in sophisticated power stations to improve performance. The author opinion is to use this study as an outlook to the world’s modern sophisticated technologies in power generation. The author has got chances to familiarize himself with these new technologies during his work as a consulting engineer in the Kingdom of Saudi Arabia, and is intending to transfer them to the Sudan and to install them in Dr. Sharif power station for raising the overall power plant efficiency to higher levels. Actually there is enough vacant land inside Dr.

125 Sharif power station fencing, plus a surplus bare land between the power station and the staff accommodation colony, that can be used for building these modern sophisticated generating units.

At the beginning of each type of a modern technology, the author describes all what he did in that specific type of technology, regarding the research material and the role he played himself to prepare the research. It is inevitable to state here, that the modern sophisticated technologies are considered by the manufacturers as firm secrets, and nowhere, detailed descriptions are liable to be furnished in the manufacturers manuals, beyond the operation and maintenance procedures. However, the author succeeded to collect all the adequate supporting information that is forthcoming in each type of a modern technology, from his own diligence and contacts with the contractors engineers.

The author relied largely on his own background and professional experience of twenty years in United Arab Emirates and Saudi Arabia, all in sophisticated power stations. The sub-studies in this field are presented as five field studies in power and efficiency raising, covering the areas of gas turbine air inlet chillers, steam turbine air-cooled condenser, steam turbine steam reheating, steam turbine condensate polishing, and steam turbine flue gas electrostatic precipitator. Each of the above five sub-studies is treated as a separate complete field study with actual data and results.

The turbine air inlet chiller is a modern technology. The author could not find any text books dealing with the gas turbine air inlet chiller. This technology is completely modern and sophisticated. Even the operation and maintenance manuals were not ready to be provided by the contractor during the commissioning and performance test of the gas turbines in Al Qaseem power station, Kingdom of Saudi Arabia. The author carried out these tests, as he was deputed by the Saudi Electricity Company from his station in power plant No. 9 in Riyadh, where he worked at that time as a consulting engineer. The author depended ultimately on studying the air inlet chiller with gas turbines air intake compartments as they were built. The author got some enhancement from the contractor’s performance engineer in answering his queries about the functions of some constituents of the chiller system. The author himself drew the schematic diagram of the air inlet chiller as per the contractor (testiac) construction. The air inlet chiller is an act, as say the gas turbine manufacturers, of (deceiving) the gas turbine that it is located in a cold weather. Ammonia is used as refrigerant in the air inlet chiller instead of freon and chlorine content gases, as their release into the earth’s atmosphere is damaging the ozone layer. The effect of the air inlet chillers is that the inlet air temperature has reduced from 50o C to 10o C and the inlet air humidity has

126 increased from 10% to 100%. The dense, heavy air with more oxygen and hydrogen leads to more combustion, and hence to more power output. The average power output of each gas turbine has increased from 57.07 MW on base load to 77.09 MW, while the efficiency has increased from 29.56% to 31.61%. This modern technology can be used in the Sudan, specially with the abundance of water for the chillers.

The steam turbine air-cooled condenser (ACC) is a sophisticated technology. Here also the author could not find any text books dealing with the steam turbine air cooled condenser. This technology is also considered as modern and sophisticated. The operations and maintenance manuals were not ready to be provided during the commissioning and performance tests of the plant combined cycle units. The author worked as a consulting engineer in the same power project in power plant No. 9 in the Kingdom of Saudi Arabia. He contributed in all the commissioning tests and performance tests of the generating units, including the air cooled condensers. He succeeded to collect all the information he required about the air cooled condensers from the as- built drawings and the construction configurations. He also collected some data from the performance test of the air cooled condensers, which he carried out himself. In order to make his description of the air-cooled condenser more clear to the reader, the author drew a sketch showing the contents of the air- cooled condenser and its layout. The steam turbine air-cooled condenser made it possible for the steam power plant to be located away from rivers or seas, as what is always the case. Even by this technology the steam turbine plant can be built right in the middle of the desert. By the ACC technology, the steam power plant can be located in the area of power requirement. This will save the cost of power transmission lines to these areas. The air is a free media for the ACC, but of course its cooling effect is less than the water, but in this case the condensate temperature after the ACC can be designed to be near to 60o C, instead of 45o C for the water-cooled condenser. The ACC technology saves the cost of cooling water and its treatment. In the Sudan this modern technology can be used for its flexibility of power plant location and for its economy. The existence of blowing winds most of year will help in this regard.

The steam turbine unit steam reheating is a modern technology. The author depended upon his own experience and his contribution as a consulting engineer for commissioning the same units in Shoaiba power plant in the Kingdom of Saudi Arabia, where he works at present. Actually, the steam reheat technology has been practiced in conventional boilers to replace the nuclear reactors in generating high capacities of steam to generate power in the turbo alternators. The author returned to some text books in thermodynamics, from where he studied the theory of the steam reheat and

127 drew some schematic diagrams. He also got some supporting information from the generating units performance test procedure and the resultant data, as shown in the generating units heat balance diagram. In addition to the above adequate information the author depended upon his own concept in describing this type of new technology, which is used in large power units, where the superheated steam is raised to high pressure and temperature, then after its usage in the high pressure steam turbine, the steam flows as cold reheat to the boiler, where it reheats in the reheater tubes, then flows as hot reheat steam to the intermediate and low pressure turbines. The steam reheating increases the average temperature at which heat is added, thereby increasing the power output. In this case the moisture in the turbine expansion process is eliminated. A major source of wear on turbine blades is the erosion caused by liquid droplets. The thermal efficiency of the steam unit is raised by the steam reheat to 38.22%. The Sudan needs to start building large power generation units, e.g. above 200 MW per unit. The cost per MW is always less for large power generation units, while the running cost is also less, specially when using the steam reheat technology.

The steam turbine unit condensate polishing is a modern technology. The author met this modern sophisticated technology in Shoaiba power plant in the Kingdom of Saudi Arabia, where he works at present as Consulting engineer. He attended the construction and installation of the condensate polishing plant, and he himself did the commissioning and the performance test of the condensate polishing plant. He studied this plant as it was built, then he got more supporting information from the commissioning and performance tests procedures. As it is known in power projects, the operation and maintenance manuals are the last to be handed over to the client at the end of the project. The condensate polishing reduces the concentration of salts in the condensate, when the conductivity rises due to condenser tube leak or contaminated make up water or contaminated condensate drains to the system. The cation and anion ion exchange resins are used to remove the dissolved minerals and salts. The condensate polishing increases the reliability of the steam unit, as it can be used to reduce the condensate conductivity while the unit is in service and need not be shutdown. It is also economical in saving the cost of feed water which could be drained to waste and replaced by clean makeup water. In the Sudan this technology can be used for raising the reliability of the steam units and for its economy.

The flue gas electrostatic precipitator (ESP) is a modern sophisticated technology. The author met this modern sophisticated technology in Shoaiba power plant, in the kingdom of Saudi Arabia, where he works at present as a consulting engineer. The manufacturer still considers most of the design and functionality of the electrostatic precipitator are firm secrets. No operation and

128 maintenance manuals have been provided yet in the power station. The author got his information for compiling the description from his study of the as-built configurations and from the contractors commissioning procedure. The electrostatic precipitator separates the dust particles from a flue gas stream by the action of electrostatic forces. It is well known that power stations play a great role in spoiling the environment by exhausting flue gases to the atmosphere. The ESP reduces this adverse effect to the minimum, by making the particulate matter measurement and total emission rates to the atmosphere and opacity of the flue gases not exceeding the allowable measurements of the environmental pollution control. This technology can be used in the Sudan in power stations that are close to dense populated areas.

The forth study, which is a managerial study, is concerned with development of power station management. The author in this study dealt with the engineering management, which became as important in the power generation field as the engineering technicalities. For preparing this study the author relied on his background and long experience in the power generation field, in addition to relying on many references in the engineering management and supplies management in the same subject, then he visited the Management Development Center in Khartoum, where he previously conducted a course in the production management, and used its library for his research. Then the author visited the ministry of foreign trade and used its library, specially for the import management, where he photocopied a book prepared by the American International Trade Center about the electricity utilities. He also visited the university of Khartoum library for the same purpose of collecting more adequate information about the subject. He also got use of the power magazines publications. The author’s opinion is that any engineer, who might become a manager one day, must equip himself with the engineering management. The forth study consists of three sub-studies, covering mainly the power station top management responsibilities. The first sub-study deals with the objectives of the power station manager, which are mainly to reduce costs, to preserve good housekeeping, to improve plant performance, to conserve station energy, and to generate saving. The second sub-study deals with the ways of leading to be adopted by the power station manager, which are leading through motivation, communication, interpersonal skills, group dynamics and team work, and through innovation and planned change. The third sub-study deals with warehouse management, where the present situation is described, and a concept for upgrading it towards centralization of supplies department in the head quarter, covering the purchasing management, stock management, and warehouse management.

In the Sudan, the power station manager is recommended to have the same objectives as the mentioned ones and to concentrate on energy saving

129 and money saving. His ways of leading is preferred to be similar to what has been stated, with more attention to be paid by him to understand his staff, to ensure homogenous performance of activities to accomplish group goals, to practice flexibility, transparence and harmony, to be imaginative and decisive, and to practice fairness and nonbias during staff movement in order to put the suitable person in the suitable place.

The author has upgraded the warehouse management by using and adapting an international program from the American Software Institution- material system, which is known as “ASI system”. The author offers this same program for upgrading the warehouse management in the Sudan.

7.2 CONCLUSIONS

1. The present thesis is a research in the power generation field, specially in Dr. Sharif Power station. The author targeted from this thesis to reduce the generated power cost, and in the same time, to raise the efficiency of the generating units to higher levels, through practicing modern sophisticated technologies.

2. The author is cognizant with the modern sophisticated technologies through his long experience abroad. He also got information about these technologies through his membership in the British Institution of Mechanical Engineers (I.Mech.E) and through the power magazines and internet system.

3. The modern sophisticated technologies are considered by the manufacturers as firm secrets, and nowhere, detailed descriptions are liable to be furnished in the manufacturers manuals, beyond the operation and maintenance procedures. However, the author succeeded to collect all the adequate supporting information from his own diligence and contacts with the contractor’s engineers.

4. The contributions that the author acquitted are shown in the beginning of each study and sub-study in this thesis. The modern sophisticated technologies obliged the author to draw himself many sketches for these technologies as they were built, due to non-availability of ready drawings.

5. The combined cycle offer of the Burneister & Wain Scandinavian Contractor (BWSC) to install a steam turbine with two heat recovery steam generators (HRSGs) to the existing gas turbines in Dr. Sharif power station, can be updated after its acceptance by NEC. The author

130 has studied this offer and has modified it to the power station capabilities. It represents a very economical way of putting extra 28 MW in the grid system. A new technology of combined cycle can be overwhelmed in the Sudan by this offer for the sake of Sudanese planners and engineers to cope with modern technology.

6. The proposed combined cycle overall efficiency was estimated by simulation of modules. Some international programs (software) are being used for the Combined Cycle simulation, but all of them are protected by copy rights. The author showed in this regard two internationally reputed programs. Then he himself drew a curve by the actual variable modules and prepared a computer program for calculating the Combined Cycle efficiency.

7. The advantages of the combined cycle are shown in details in this thesis, which are mainly gaining extra (free) power output by burning the same amount of fuel, which will result in raising the overall efficiency to higher levels.

8. The Sudan refined fuel oil is now in use in Dr. Sharif power station without major problems. All the problems that arose in the last few years have been solved. The author showed in the present thesis all the problems that took place and the solutions that were carried out and have recently proved to be effective.

9. The transfer of technology to the Sudan has gained great attention from the author, who has spent twenty years working in modern sophisticated power plants in the United Arab Emirates and the Kingdom of Saudi Arabia. Five sophisticated technologies, in addition to the combined cycle technology are shown in details in a form of sub-studies, which were carried out in the relevant power stations. The author believes that it is beneficial to use all these types of modern technologies in the Sudan, due to their low costs, high power outputs and high efficiencies.

10. The development of power station management can be practiced through the responsibilities of the top management. This statement depends mainly upon the role of the power station manager, who is obliged to fulfill his objectives and to lead his subordinates properly. The ideal objectives and ways of leading to be followed by the power station manager were shown by the author in this thesis. The new methods of upgrading the warehouse management by using the

131 international computerized programs, can help more in setting up a new method for the warehouse management in the Sudan.

11. The engineering management has become as important in the power generation field as the engineering technicalities. The author’s opinion is that any engineer, who might subsequently become a manager, must equip himself with the engineering management, as it helps him to reduce the generated power cost and to raise the efficiency of the plant.

12. The author is of the opinion that the various components of the studies dealt with in the present thesis could contribute significantly to the solution of the chronic problems falling in power generation in the Sudan.

13. Financial support in the respect of power generation development in the Sudan is instrumental to the success of any project towards its end.

14. The author for his part believes, or at least hopes, that the objectives of the thesis have been fulfilled in a manner conducive to their utilization as useful elements in any future venture to enhance power generation in the Sudan.

7.3 RECOMMENDATIONS FOR FUTURE WORK

The author recommends the following as future work in the power generation field: 1. To carry out revised studies in power planning, covering the power market survey, power forecast for annual demand growth, short-term and long-term power plants’ construction. 2. To correlate the hydro power generation with the thermal power generation, in order to eliminate power bottle necks during summer and winter. 3. To correlate the independent power plants (IPP) of refineries, cement and sugar factories with NEC, for the purchase of their surplus generated power. 4. To urge constructing Combined Heat and Power (CHP) plants in co-generation systems to produce both generated power and steam heat for different industrial and water desalination uses, due to the high overall efficiencies of such plants. 5. To cope with the world development in the power generation field by using the modern sophisticated technologies in constructing new power

132 stations, in order to begin the coming uplift from where the developed countries ended. 6. To plan to construct in future large generating units with high power outputs, e.g. more than 200MW per unit, in order to reduce the construction cost per MW and the running cost per MW. 7. To construct new thermal power plants as gas turbine or steam turbine units, due to their high power outputs, compared with diesel generators. 8. To plan to run the existing and future gas turbines on crude oil with additives , instead of distillate gas oil, due to the economy in fuel cost. 9. When the natural gas becomes abundant , it is more economical to convert and run the gas turbines on natural gas, due to its clean nature that leads to reduction in maintenance cost and in downtime , and hence, will increase the availability. 10. To concentrate in constructing combined gas turbine and steam turbine units in combined cycle, as it represents the latest technology in power generation in the world, for its economy, high power output and high overall efficiency. 11. To endeavor to achieve cost effectiveness and cost reduction of generated power by practicing technical and managerial development in power generation, in order to reduce electricity tariffs to consumers, after gaining adequate profit.

12. To enhance privatization in power generation and role of investments in power generation through the Build, Own and Operate for agreed time of Transfer (BOOT) regime, after breaking the electricity monopoly of NEC.

133

REFERENCES:

1. A. Ivanova, Smolensky, Electrical Machines 1, 2, 3 Mir Publishers, 2002. 2. A Morrison, Storage & Control of Stock, Pitman Publishers, 2002 3. ASME (American Society of Mechanical Engineers)Steam Tables, ASME Press, 1993 4. Bashir. M. Bashir, from Higleeq to Bashayer, Future Studies Center 2000. 5. Eastop & Croft, Energy Efficenicy, Longman, 1995 6. Eastop & Mcconkey, Applied Thermodynamics, Solutions Manual Longman, 1993. 7. Eckenfelder, Water Quality Engineering, B&N, New York, 2000. 8. G. Boxer, Engineering Thermodynamics, Macmillan Press, 1998 9. Gill, Power Plant Performance, Mc Graw – Hill 1987 10. I.T.C, Import Management (Electricity Utilities), 2000 11. I.Mech.E (Institution of Mechanical Engineers) Monthly Magazines & Publications, 2003. 12. Internet Power Webs, 2002 13. International ANSI (American National Standard Institute) book 2000.

134 14. International ASME, PTC 46, Standard book for performance test code 46, for gas turbine technology, 1996. 15. International ASME, PTC 22, standard book for performance test code 22, for steam turbine technology, 1985. 16. International ASME D3685/M3685 standard for sampling flue gases at stack, 92001. 17. International IEEE 762 (Institution of Electrical and Electronic Engineers) standard book, code 762, 2000. 18. ISO 2314 (International Standards Organization) book for generating units acceptance tests. Code 2314, 2000. 19. International NIST (National Institute of Standard Technology) book, 2001. 20. J.P. Holman, thermodynamics, Mc Graw – Hill, 1988. 21. J.W. Schroeter, Cogeneration & Combined Cycle Plants, ASME, 1991. 22. Kirilin, Sychev, Sheindlin, Engineering Thermodynamics, Mirr Publishers, 2001. 23. M. El-Wakil, Power Plant Technology, Mc Graw – Hill, 1988. 24. N. Afgan & E.U. Schlunder, Heat Exchangers Design & Theory Source Book, Mc Graw – Hill, 1999. 25. N. Deshpande, Elements of Electrical Power Station Design , Wheeler, 2002 26. Power CEGB, Modern Power Station Practice – Station Planning and Design, Pergamon Press, 1990 27. Power CEGB, Modern Power Station Practice – Boiler and Ancillary Plant, Pergamon press, 1990 28. Power CEGB, Modern Power Station Practice – Turbines / Generators & Associated Plant, Pergamon Press, 1990. 29. Power CEGB, Modern Power Station Practice – Electrical Systems & Equipment, Pergamon press, 1990. 30. Power CEGB, Modern Power Station Practice – Chemistry and Metallurgy, Pergamon Press 1990. 31. Power CEGB, Modern Power Station Practice – Controls Instrumentation, Pergamon Press, 1990. 32. Power CEGB, Modern Power Station Practice – Station Operation & Maintenance, Pergamon Press, 1990 33. Power CEGB, Modern Power Station Practice – Station Commissioning, Pergamon Press, 1990 34. Power Magazines, & Gas Turbine World Magazines, 2002. 35. Robert Stein & William Hunt, Electrical power System Components (Transformers & Rotating Machines), CBS, 1987. 36. Skrotzki & Vopat, Power Station Engineering & Economy, Mc Gaw – Hill 1996.

135 37. S.P. Arora, Office Organization and Management, Vikas Publishing house, 1999. 38. Dr. Sharif Power Station Fuel Oil Specifications reports, May 2001. 39. Riyadh Power Plant No. 9 Performance Test Manual, KSA, 2001. 40. Shoaiba Power Plant Performance Test Manual, KSA, 2002. 41. Sudan Petroleum Department Records, Ministry of Energy & Mining 2003. 42. Venikov, Zhuravlov & Filippova, Optimal Operation of Power Plant & Electric Systems, Mir Publishers, 2003.

136

APPENDIX “A”

137

RIYADH POWER PLANT # 9 Date July 22, 2001 Latest - dated August 30, 2001

Performance Calculation for Block ‘B2’ Combined Cycle Based on Performance Test Measurements taken on June 23, 2001

138 Performance Guarantee Reference:

1. Fuel Natural Gas 2. Ambient Temperature 50oC 3. Ambient Pressure 937 m bar (a) 4. Relative Humidity 60% 5. Power Factor 0.80 6. Load Base 7. Net Plant Power 331,720 kw 8. Net Plant Heat Rate (LHV) 8,484 kJ/kwh

Prepared by : Omar M. Baday EWR Engineers & Consultants PP-9

139

1) GTGs Gross Power. 3 KWG GTn = Σ KW / φ = (φ A, B, C) x CFM x PTR x PTRCF x CTR x 0.06 1 TIME

1.1) KWG GT13 = 1,178 x 1.0007 x 70 x 1.0 x 1600 x 0.06 = 66,014 KW 120

1.2) KWG GT14 = 1.162 x 1.0002 x 70 x 1.0 x 1600 x 0.06 = 65,085KW 120

1.3) KWG GT15 = 1,170 x 1.0002 x 70 x 1.0 x 1600 x 0.06 = 65,533 KW 120

1.4) KWG GT16 = 1,164 x 1.0005 x 70 x 1.0 x 1600 x 0.06 = 65,216 KW 120

2) GTs Excitation :

EP GTn = FVxFA KW 0.975 x 1000

2.1) EP GT13 = 123.21 x 521.1 = 65.85 KW 0.975 x 1000

2.2) EP GT 14 = 120 x 515 = 63.4 KW 0.975 x 1000

2.3) EP GT 15 = 120.8 x 521.4 = 64.6 KW 0.975 x 1000

2.4) EP GT 16 = 125 x 524 = 67.2 KW 0.975 x 1000

140

3) GTGs Net Power:

KWN GT KW = KWGGTN – EPGTN) x FPFGTN

Data power factors Correction Factor

GT 13 = 0.990 ------0.9974 GT 14 = 0.989 ------0.9975 GT 15 = 0.985 ------0.9975 GT 16 = 0.982 ------0.9973

3.1) KWNGT13 = 66,014 - 65.6 x 0.9974 = 65,777 KW

3.2) KWNGT14 65,085 - 63.4 x 0.9975 = 64,859 KW

3.3) KWNGT15 65,533- 64.6 x 0.9975 = 65,304 KW

3.4) KWNGT 16 65,216 – 67.2 x 0.9975 = 64,986 KW

Σ KWN GTKW = 65,777 + 64,859+65,304+64,986 = 260,926 KW

4) STG Gross Power: 3 KSW (p) = Σ KW / φ = (φ A, B, C) x CFM x PTR x PTRCF x CTR x 0.06 1 TIME

= 1,175 X 1.0002 X 120 X 1.0 X 1600 X 0.06 120 = 112,822 KW

5) STG Excitation:

141 EP STG = FV x FA 160 x 960 = = 157.5 KW 0.975 x 1000 0.975 x 1000

6) STG Net Power

KWN ST.KW = KWS (p) – EPSTG x FPF

Data power factor = 0.998

KWN ST.KW = 112,822 – 157.5 x 0.9972 = 112,349 KW

7) Combined Cycle Plant Net Output, corrected:

F(1e)xF(2e)xF(3e)xF(4e)xF(5e) KWCC (corr) = KWN GT KW + KWS ST KW x - Aux Plant

F(1f)xF(2f)xF(3f)xF(4f)xF(5f)

7.1) From Data

Dry bulb temperature = 98.42oF Wet bulb temperature = 63.2oF Barometric pr. = 13.505 psi a

iii

7.2) Plant Auxiliary Power :

142 See Attachment # 1 for detail

Aux. Plant = 480V, MCC of GT13 + GT14+ GT15+GT16 +

4.16 kV Board A + B + 480V STG4 Boards of A+B+C +

Tx losses of GTs 13 & 14 + GTs 15 & 16 + STG4 KW

Aux. Plant = 119+122.5+130.5+125.5 +1609.5+546.5+ 1228 + 1259.5+481.87 +

337 + 366 + 313 = 6639.03 KW

KWCC (corr) = (260,926 + 112,349) x 1 x 1 x 1 x 1 x 1 - 6,639.03

0.996x1.076x0.9966x0.983x0.984

= 354,677.47 KW

8) Plant Heat Rate:

HRPGCC = HCGGT13 + HCGGT14 + HCGGT15 + HCGGT16

KWNGT KW + KWS ST KW

2 WFG GT13 = 3600 x N1 x Cd x Ev x Y x d x ρtp x ∆ ρ

= 3600 x 0.0997424 x 0.604509 x 1.1019 x 0.995329238 x 3.93092 x 0.9552 x 112 = 38,048 lb / hr

143 WFGGT14 = 37722 lb / hr, while, d = 3.9317 inch, ∆ ρ = 110 in H20

WFGGT15 = 37894 lb / hr, while, d = 3.9317 inch, ∆ ρ = 111 in H20

WFGGT16 = 37535 lb / hr, while, d = 3.9309 inch, ∆ ρ = 109 in H20

HCGGTn = WFGGTn x LHV, while, LHV = 19215.9 BTU / lb = 44692 KJ/KG Guarantee LHV = 487.06 KJ/KG

HRPGCC = 731,126,563 + 724,862,179 + 728,167,314 + 721,268,806

260,926 + 112,349

= 7783.6 BTU / kwh

144 9) Plant Heat Rate Corrected to Guarantee Conditions:

HRPGCC (corr) = HRPGCC x F(1m)xF(2m)xF(3m)xF(4m)xF(5m) Aux plant x 1 + F(1n) x F(2n) x F(3n) x F(4n)xF(5n) KWCC (corr)

1 x 1 x 1 x 1 x 1 6639.03 = 7783.9 x 0.9999x 0.985x 0.996x1.002x1.004 x 1 +

354,677.47

= 8034.58 BTU / kwh

= 8475.2 KJ / kwh

F (5m) = Guarantee factor for fuel F (5n) = Correction factor for fuel

10) Plant Efficiency, according to Guarantee conditions:

1 3600 η = = x 100% = 42.47% HRPGCC (corr) 8475.2

Conclusion:

Comparing the performance test results with the guarantee reference, we conclude that Block ‘B2’ performance test results are acceptable.

Description Guarantee Reference Perf. Test Result

A. Net Plant Power 331,720 KW 354,677.47 KW B. Net Plant Heat Rate (LHV) 8484 KJ/KWH 8475.2 KJ/KWH

INPUT SUMMARY:

145 Guarantee Measured Correction Correction Description Values Values Factor Factor (Power) (Heat Rate)

Barometric 937 m bar 13.505 psia 0.996 0.9999 Press. Ambient 50oC 37oC 1.076 0.985 Temp. Humidity 60% 12% 0.9966 0.996 Degradation Less than > 11000 0.983 1.002 5000 hrs avg. Fuel Quality 48706 KJ/kg 44692 0.984 1.004 (Natural Gas) KJ/Kg Power Factor of • GT-13 0.8 .990 0.9974 -- • GT-14 0.8 .989 0.9975 -- • GT-15 0.8 .989 0.9975 -- • GT-16 0.8 .982 0.9974 -- • ST-4 0.8 .998 0.9972 --

146 ATTACHMENT # 1

Auxiliary Consumption

Block B2:

A) 4.16 kV Switchboards: ( BCA)

Bus # A – (298110 – 294891 = 3219 Bus # B – (291493 – 290400 = 1093 In two hrs = 2156 KWH/hr = 2156 KW

B) 480 V GT Unit Auxiliary Switchgear: ( BHA )

GT # 13 – (3248 – 3010) = 238 GT # 14 – (3147 – 2902) = 245 GT # 15 – (10394 – 10133) = 261 In two hours = 497.5 KWH/hour = GT # 16 – (11685 – 11434) = 251 497.5 KW

C) 480V Steam Turbine Condenser Switchgear (BFA, BFB & BFC)

B-20 BFA (Main-1) – (9734 – 8524) = 1210 In two hrs = 1228 KW / hr = 1228 KW B-20 BFA (Main-2) – (9356 – 8110) = 1246

B-20 BFB (Main-1) – (8984 – 7862) = 1122 In two hrs = 1259.5 KW / hr = 1259.5 B-20 BFB (Main-2) – (14541 – 13144) = 1397 KW

B-20 BFC (Main-1) – (7673 – 7217) = 456 In two hrs = 655.5 KW / hr = 655.5 KW B-20 BFC (Main-2) – (29745 – 28890)) = 855

TOTTAL = 3143 KW

D) 480V MCC B-20 BJA 2001 High Bay Ventilation

Average Current

147 Average Voltage Power Factor (Assumed)

P = √ 3 VI cas φ = √ 3 x 469.182 x 267.074 x 0.80 = 173.63 KWH

Net Aux. Consumption = (A+B+C–D) = 2156+497.5+3143–173.63 = 5622.87 KW

Transformer Losses ( Step up ) GT-13 / 14 = BAT 10

LV1 Current at N Top = 2629 A Iph = 2629 / √ 3 = 1519.65 A LV2 Current at N Top = 2671.22 A Iph = 2671.22 / √ 3 = 1544 A

vi LV1 Resistance at 75° C , N Top = 0.03173 Ω LV2 Resistance at 75° C , N Top = 0.03287 Ω LV1 I² R Losses = ( 1519.65 )² x 0.03173 = 73.27 KW ……………1 LV2 I² R Losses = ( 1544 )² x 0.03287 = 78.35 KW …………..2 HV Resistance at 75º C , N Top = 3.685 Ώ HV Current = ( LV1 I x LV2 I ) x 13.8 / 380 = 192.48 A HV I² R Loss = ( 192.48 )² x 3.685 = 136.52 KW …………………..3 Stray Loss at 75º C ,N Top = 48.5 KW …………………4

Total Load Losses = 1+2+3+4 = 73.27+78.35+136.52+48.5 = 336.64 KW

Transformer Losses ( Step up ) GT-15 / 16 = BAT 20

LV1 Current at N Top = 2809 A Iph = 2809 / √ 3 = 1623.69 A LV2 Current at N Top = 2750 A Iph = 2750 / √ 3 = 1589.59 A LV1 Resistance at 75° C , N Top = 0.03209 Ω

148 LV2 Resistance at 75° C , N Top = 0.03285 Ω LV1 I² R Losses = ( 1623.69 )² x 0.03209 = 84.6 KW ……………1 LV2 I² R Losses = ( 1589.59 )² x 0.03285 = 83 KW …………..2 HV Resistance at 75º C , N Top = 3.756 Ώ HV Current = ( LV1 I x LV2 I ) x 13.8 / 380 = 201.87 A HV I² R Loss = ( 201.87 )² x 3.756 = 153 KW …………………..3 Stray Loss at 75º C ,N Top = 45.46 KW ………………4

Total Load Losses = 1+2+3+4 = 84.6+83+153+45.46 = 366.06 KW

Transformer Losses ( Step up ) ST# 4 = BAT 30

LV Current = 3630 A Iph = 3630 / √ 3 = 2098 A HV Current = 3630 x18 / 380 = 172 A LV Resistance at 75° C , N Top = 0.027057 Ω HV Resistance at 75° C , N Top = 4.197 Ω LV I² R Losses = ( 2098 )² x 0.027057 = 119 KW ……………1 HV I² R Losses = ( 172 )² x 4.197 = 124.16 KW …………..2 Stray Loss at 75º C ,N Top = 70.3 KW ………………3 Total Load Losses = 1+2+3= 119 +124.16 + 70.3 = 313.46 KW

Transformer Losses = BAT10+BAT20+BAT30 = 336.64+366.06+313.46 = 1016.16 KW

Total = 6639.03 KW

vii

149

Auxiliary Consumption

Block A1:

A) 4.16 kV System:

Bus # 1 – (54766 – 52890) = 1876 Bus # 2 – (46621 – 44466) = 2155 In two hrs = 2015.5 KWH/hr

B) 480 V BHA GT Aux. Switchgear :

GT # 1 – (102369 – 102119) = 238 GT # 2 – (73917 – 73685) = 232 GT # 3 – (13419 – 13170) = 249 In two hours = 504 GT # 4 – (158656 – 158379) = 277 KWH/hour

C) 480V Steam Turbine Condenser Switchgear (BFA, BFB & BFC)

A-20 BFA (Main-1) – (60555 – 59362) = 1193 A-20 BFA (Main-2) – (55809 – 54802) = 1007

A-20 BFB (Main-1) – (59005 – 57708) = 1297 A-20 BFB (Main-2) – (85351 – 83767) = 1584 In two hours = 3325.5 KWH/hrs

A-20 BFC (Main-1) – (90355 – 89446) = 909 A-20 BFC (Main-2) – (107970 – 107309) = 661

D) 480V MCC A-20 BJA 2001 High Bay Ventilation:

Average Current = 326.2567 A Average Voltage = 457.0344 V Power Factor = 0.85 Assumed

150

P = √ 3 VI cas φ

P = √ 3 x 457.0344 x 326.2567 x 0.85 = 219.527 MWH In Two hrs = 219.527 MWH

= 109.764 KWH / hr

NET AUX. CONSUMPTION = A+B+C-D = 2015.5+504+3325.5 – 109.764

= 5735.236 KWH / hour = 5734.236 KW

viii

Transformer Losses ( Step up ) GT-13 / 14 = BAT 10

LV1 Current at N Top = 2629 A Iph = 2629 / √ 3 = 1519.65 A LV2 Current at N Top = 2671.22 A Iph = 2671.22 / √ 3 = 1544 A LV1 Resistance at 75° C , N Top = 0.03173 Ω LV2 Resistance at 75° C , N Top = 0.03287 Ω LV1 I² R Losses = ( 1519.65 )² x 0.03173 = 73.27 KW ……………1 LV2 I² R Losses = ( 1544 )² x 0.03287 = 78.35 KW …………..2 HV Resistance at 75º C , N Top = 3.685 Ώ HV Current = ( LV1 I x LV2 I ) x 13.8 / 380 = 192.48 A HV I² R Loss = ( 192.48 )² x 3.685 = 136.52 KW …………………..3 Stray Loss at 75º C ,N Top = 48.5 KW …………………4

Total Load Losses = 1+2+3+4 = 73.27+78.35+136.52+48.5 = 336.64 KW

Transformer Losses ( Step up ) GT-15 / 16 = BAT 20

151 LV1 Current at N Top = 2809 A Iph = 2809 / √ 3 = 1623.69 A LV2 Current at N Top = 2750 A Iph = 2750 / √ 3 = 1589.59 A LV1 Resistance at 75° C , N Top = 0.03209 Ω LV2 Resistance at 75° C , N Top = 0.03285 Ω LV1 I² R Losses = ( 1623.69 )² x 0.03209 = 84.6 KW ……………1 LV2 I² R Losses = ( 1589.59 )² x 0.03285 = 83 KW …………..2 HV Resistance at 75º C , N Top = 3.756 Ώ HV Current = ( LV1 I x LV2 I ) x 13.8 / 380 = 201.87 A HV I² R Loss = ( 201.87 )² x 3.756 = 153 KW …………………..3 Stray Loss at 75º C ,N Top = 45.46 KW ………………4

Total Load Losses = 1+2+3+4 = 84.6+83+153+45.46 = 366.06 KW

Transformer Losses ( Step up ) ST# 4 = BAT 30

152 153

154

155

156