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HomeMy WebLinkAboutSP 144B; SDG&E Wastewater Facility; Specific Plan (SP) (12)I 1 I I I I 1 I 1 i FIRST ANNUAL REPORT T OTY €< ^y» I I I I I 1 I I Presented by San Diego Gas & Electric NOVEMBER 22, 1977 I I In compliance with City of Carlsbad Ordinance 9456, • Section 314(k), San Diego Gas & Electric is submitting this first annual report to the Carlsbad City Council. This • report will describe improvements in plant and operating tt procedures during the preceding year which reduce the emission of air pollutants resulting from the operation of Encina I Units 1, 2, 3 and 4. The following are areas of improvement that were If accomplished in the last year. These improvements result • in increased efficiency, reduced fuel consumption, and a corresponding decrease in emissions. • I. Major Turbine Overhaul Encina Units 1 and 3 underwent major turbine over- | hauls in September 1976 and January 1977, respectively (see « Attachments 1 and 2). During a major overhaul, the entire turbine is dismantled, useable parts are cleaned and worn I parts replaced or repaired. The turbine is then reassembled and put back in operation. The goal of a major overhaul is jj to return the turbine efficiency to as close to design level — as possible and to insure reliable operation for the next ™ four years. Major turbine overhauls are normally done every II four years. II. Boiler Overhaul I The boilers for Units 1, 2, 3 and 4 were overhauled _ during the past year. By cleaning and repairing burners, air • registers, heat transfer surfaces and structural components, • air leakage is minimized. In this way, boiler efficiency is I I I returned to design conditions. • III. Condenser Tube Scraping The tubes in the condenser of all four units were • scraped to remove marine growth and other deposits. In ft this process, spring loaded metal scrapers are inserted into the 1-inch tubes (each condenser has 6,000 to 10,000 tubes) • and a high pressure water stream pushes the scrapers through the individual tubes. Condenser heat transfer is thus improved, reducing each unit's turbine back pressure. This • results in improved unit efficiency. IV. Electric Production Performance Monitoring Program I Since mid-1975, a special SDG&E team has been working to find new ways of improving plant efficiency and | to cut fuel oil consumption. The Performance Monitoring _ Program is one of several developments that resulted from ™ those efforts, flj The aim of this program is to provide a method of monitoring performance of each unit so that it can be | operated at its most efficient level under various loading _ conditions. This increased efficiency leads to reduced oil ™ consumption and corresponding emission reduction. Operators • make hourly comparisons of actual unit performance to the best attainable standards and then take corrective action | when appropriate. The operator can either adjust the _ control setting of the unit or request that maintenance be ™ performed (see Attachment 3). i i I 1 V. Encina Fallout Test Program | Since mid- 197 6, SDG&E has been conducting this ^ program to determine and correct the cause of damage resulting • from acidic particulate emissions from Encina Power Plant. • The test program had its beginnings in June 1976, at which time SDG&E accepted the allegations and provisions • of the Abatement Petition sought by the Air Pollution Control District. At that time it was established by both SDG&E » and the APCD that "SDG&E was responsible for at least some • of the corrosive spotting" around the Encina Power Plant. We subsequently hired an independent consultant, York I Research Corporation, as specified in the Abatement Order, to conduct a comprehensive study to determine the source of I the damaging particles , and develop a method to control • these particles. Results of the test program and recommendations • for acid-fallout abatement at Encina are as follows: 1. Reaffirming our original findings, the four I boilers situated at Encina Power Plant do M contribute to local corrosive spotting problems. Acidified particles formed in the boilers I are emitted, and some have sufficient weight to fall within close proximity of the plant | and cause damage if they land on a susceptible _ surface such as a car, or a patio awning. The ™ majority of particles emitted from the unit are • extremely small, dust-like, and non-corrosive I I I in nature. The acidic fallout particles are I very few in number and small in size. ™ 2. Acid fallout particles are composed of two key • parts, a carrier called a "cenosphere," and an acid. The cenosphere is a carbon particle £ formed during the combustion of oil, which looks and acts like a sponge. It has an affinity • for liquids, so the many holes in its structure • become filled with water and acid formed during combustion. As combustion efficiency increases, • production of cenospheres decreases. Therefore, efforts to improve combustion efficiency are • extremely worthwhile. Sulfuric acid is formed I when a small fraction of sulfur in the fuel combines with oxygen during combustion and • then with water formed from combustion or available in the atmosphere. When a particle • lands on a cloth, painted, or metal surface, •j the acid is strong enough to corrode or stain the surface. Fortunately, the acid-fallout • particles are small and few in number so that the damage caused is not extensive.i • 3. Fallout damage was determined to be primarily caused by acidic particles and not by iron ft rust, as was originally speculated. i I I 4. The majority of acid-fallout emitted occurs I during and immediately after each unit's soot • blow, an operation to clean the heat transfer surfaces of the boiler. However, fallout is • emitted from each boiler at varying levels throughout the day. « 5. Local meteorological conditions surrounding Encina Power Plant are such that the impact of • fallout cannot be accurately forecasted based on surface wind speed and direction information. £ This is because an unpredictable upper-air _ layer exists above approximately 250 feet • altitude that has no relationship with the • surface wind conditions. When the stack plumes enter this layer, the problem of determining • fallout impact and intensity are complicated. • Based on these findings and York's recommendations, • SDG&E implemented the following control measures to sub- stantially eliminate the damaging acidic fallout from the • Encina Power Plant: 1. Magnesium based fuel oil additive is being • injected into the fuel system of each boiler • at Encina on a continuous basis. All Encina boilers have been using an additive since t -5- I I I May 6, 1977. Test data based on ambient fallout • monitoring devices indicates a typical monthly average reduction exceeds 95% in the number of m acidic particles emitted from the power plant. • The additive reduces acid-fallout by both inhibiting the formation of 803, and thus sulfuric • acid, and by neutralizing any acid that is formed. The rate of additive injection will be | maintained at a level just sufficient to ^ substantially reduce acid-fallout, which will ™ then minimize any increase in particulates • from the boilers. With the additive, we are currently in compliance with Rule 52 which • sets the maximum source particulate levels at _ 0.1 grains/SCF. • 2. Soot blowing on each boiler has been rescheduled from present 5:00 p,m. start time to 11:00 a.m. • in order to take advantage of favorable wind conditions existing from mid-day through early W afternoon. Surface winds during this period • are generally at or near their maximum speed with high persistence and apparently, from • ambient emission data, the upper winds tend to follow the surface winds during this time period. • This has the effect of limiting the dispersion m of fallout to a narrow corridor, east to south-east I I I of the plant, which is essentially unpopulated. I 3. Automatic fuel oil viscosity controls will be " installed on each boiler to assure that oil • combustion is optimized so as to reduce the carbonaceous acid carriers, "cenospheres . " • Combustion equipment is designed to operate at certain fuel oil viscosities in order to • produce the best flame possible and minimize • the amount of unburned carbon. This project is currently in the engineering phase, with • two consultants handling the engineering. The current schedule calls for completion of the I project in 1979. Based on the trends exhibited by the data during • limited test periods, the first two control methods, addi- tives and soot blow changes will provide the Encina Power | Plant with substantial elimination of damaging fallout • while installation of viscosity controls will just enhance the effectiveness of the other control methods. The cost H of these control methods will amount to about $30,000 per month for the purchase of the fuel oil additive. | At the recommendation of the San Diego Air • Pollution Control Officer, a new test program was initiated to study the proposed solution to the fallout program. This • test program will continue until December 31, 1977. I I I The following activities are underway as part of P this new test program: _ 1. At the request of the State Department of Health, ™ tests are being conducted to assess if any adverse • side effects may result from use of the additive. SDG&E has initiated a program to determine £ emission and dispersive characteristics of respirable-sized particles, with qualitative and • quantitative identification. Information will • be submitted to APCD and the Department of Health. • 2. SDG&E and APCD are jointly conducting a series of source tests on each boiler to determine any • net increase or decrease in particulate emissions. • APCD Rules 20.1, 20.2, 53 (b) and Subpart A of Regulation X limit an increase of total particu- • late emissions to 10 Ib/hr or 100 Ib/hr, as compared to emission levels prior to any modifi- • cation of operations or equipment. In conclusion, SDG&E has an aggressive and efficient • overhaul and maintenance program to maintain the most efficient power plants possible. Additionally, we have I been successful in finding new ways to improve plant eff ici- • ency in many areas. Regarding the Fallout Abatement Program, SDG&E I began over a year ago to solve a problem others had not I I — solved, and sought to find a solution others had not yet • found. All valid claims made by residents affected by tt this problem have been acknowledged and settled. Through an extensive test program utilizing York Research Corp., P and an expenditure to date of $1,620,000, we have developed — a Control Plan that will substantially eliminate the fallout ™ problem. Evidence of this is the fact that demand claims by • Carlsbad residents have dropped dramatically. We are con- tinuing our testing through December 1977 to verify that in • fact this Control Plan will meet all applicable regulatory standards. I I I I I I I I I Q I c2 irr ELECTRIC PRODUCTION DEPARTMENT 1976 OVERHAUL SCHEDULE REVISION 'C JANUARY 5 1O 15 2O 25 ooo a<o MARCH 5 IO 15 2O 25 5 IO 15 2O 25 5 10 15 2O 25 5 IO 15 2O 25 5 IO 15 2O 25 5 IO 15 2O 25 5 IO 15 2O 25 5 1O 15 2O 25 5 IO 15 2O 25 S IO 15 2O 25 ooo •5 IO 15 2O 25 JANUARY 5 1O 15 2O 25 5 IO 15 2O 25 FEBRUARY MARCH 5 1O 15 2O 25 APRIL 5 IO 15 2O 25 MAY 5 IO 15 2O 25 JUNE 5 IO 15 20 25 JULY 5 10 15 ?O 25 AUGUST 5 1O 15 2O 25 SEPTEMBER 5 IO 15 2O 25 OCTOBER 5 IO 15 2O 25 NOVEMBER 5 IO 15 2O 25 DECEMBER ATTACHMENT 2 GENERATING UNIT OVERHAUL SCHEDULE 1977, REVISION 'D' CAPACITY RESOURCES (Mw) NUCLEAR UNIT SCHEDULED MAINTENANCE (Mw) GAS TURBINE TEMPERATURE DERATING (Mw) LARGEST CONTINGENCY (Mw) CAPACITY BEFORE SCHEDULED MAINT. (Mw) PREDICTED MONTHLY PEAK DEMAND (Mw) ALLOWANCE FOR EXTREME WEATHER (Mw) EXTREME MONTHLY PEAK DEMAND (Mw) MARGIN BEFORE SCHEDULED MAINT. (Mw) MAINT WEEK STARTS ON (SUNDAY) CAPACITY SCHEDULED OFF (Mw) UNIT MARGIN AFTER SCHEDULED MAINT. (Mw) JANUARY 2248 86 287 1875 1626 85 1711 164 2 9 16 23 102 102 102 EA3 EA3 EA3 164 62 62 62 FEBRUARY 2249 86 287 1876 1560 83 1643 233 30 6 13 20 102 102 102 EA3 EA3 EA3 131 131 131 233 MARCH 2257 86 287 1884 1543 66 1609 275 27 6 13 20 27 102 102 102 102 EA2 EA2 EA2 EA2 173 173 173 173 275 APRIL 2257 43 287 1927 1509 78 1587 340 3 10 17 24 142 142 220 220 SB2 SB2 SB4 SB4 198 198 120 120 MAY 2257 2257 43 43 287 220 1927 1994 1438 1438 98 98 1536 1536 391 458 1 8 15 22 287 287 EA4 EA4 391 171 171 391 JUNE 2255 34 287 1934 1617 146 1763 171 29 5 12 19 26 64 64 64 38 SG4 SG4SG3SG1 171 107 107 107 133 CAPACITY RESOURCES (Mw) NUCLEAR UNIT SCHEDULED MAINTENANCE (Mw) GAS TURBINE TEMPERATURE DERATING (Mw) LARGEST CONTINGENCY (Mw) CAPACITY BEFORE SCHEDULED MAINT. (Mw) PREDICTED MONTHLY PEAK DEMAND (Mw) ALLOWANCE FOR EXTREME WEATHER (Mw) EXTREME MONTHLY PEAK DEMAND (Mw) MARGIN BEFORE SCHEDULED MAINT. (Mw) MAINT. WEEK STARTS ON (SUNDAY) CAPACITY SCHEDULED OFF (Mw) UNIT MARGIN AFTER SCHEDULED MAINT. (Mw) JULY 2252 40 287 1925 1707 65 1772 153 3 10 17 24 100 100 100 EA1 EA1 EA1 53 53 53 153 AUGUST 2187 42 287 1858 1797 114 1911 •53 31 7 14 21 28 -53 -53 -53 -53 -53 SEPTEMBER 2185 76 287 1822 1761 210 1971 -149 4 11 18 25 -149-149-149 -149 OCTOBER 2185 67 287 1831 1603 125 1728 103 2 9 16 23 198 198 198 198 SB3 SB3 SB3 SB3 -95 -95 -95 -95 NOVEMBER 2185 3 287 1895 1638 83 1721 174 30 6 13 20 27 198 198 198 198 SB3 SB3 SB3 SB3 -24 -24 -24 -24 174 DECEMBER 2187 287 1900 1724 86 1810 90 4 11 18 25 140 140 SB1 SB1 90 -50 -50 90 NOTES: CAPACITY RESOURCES BASED ON FIGURES SHOWN IN "CALIFORNIA POWER POOL LOAD RESOURCES REPORT" DATED 5/4/77. MONTHLY PEAK DEMAND BASED ON FIGURES SHOWN IN "LONG TERM DEMAND FORE- CAST" - 5/5/77. UNIT ENCINA4 ENCINA3 ENCINA2 ENCINA 1 SOUTH BAY 4 SOUTH BAY 3 SOUTH BAY 2 SOUTH BAY 1 SILVER GATE 4 SILVER GATE 3 SILVER GATE 2 SILVER GATE 1 STATION B 25 STATION B 24 STATION B 22 STATION B 21 STATION B HT GAS TURBINES CAPACITY 287 102 102 100 220 198 142 140 64 64 64 38 41 28 18 17 3 410 ATTACHMENT 3 I I I I I I I I I I I I I I I I I I I EFFICIENCY IMPROVEMENT PROGRAM AT SAN DIEGO GAS & ELECTRIC Presented at: EEI Prime Movers Committee Meeting October 4, 1976 by: Jon P. Hardway General Superintendent, Electric Production San Diego Gas & Electric Company INTRODUCTION Over the last year and a half, San Diego Gas & Electric Company has been concentrating on reducing its single largest operating expense—the cost of power plant fuel and purchased energy. A special team was set up to increase plant efficiency and to cut fuel oil consumption. According to 1974 data, SDG&E's system heat rate of 10945 Btu/kwhr ranked 70th in the survey of the Top 100 electric utilities. In 1975 we achieved a heat rate of 10481 Btu/kwhr which elevated us to 41st among the Top 100. That improvement of 29 steps is significant. It was exceeded only by one other company--Middle South Utilities, which ranked 56th in 1974 and 23rd in 1975. SDG&E's improvement in heat rate reduced operating expense in 1975 by approximately $7 million which, undoubtedly, had a significant effect in the Company's improved financial outlook. Just what did we do to achieve this savings? Many factors contributed, including a unit performance monitoring pro- gram, improved maintenance, cleaner condensers, and operational dispatch changes. PERFORMANCE MONITORING Our first approach to improve unit efficiencies was to develop a unit performance monitoring program, similar to Florida Power and Light's Energy Management Program.2 Special thanks go to Charlie Branning of FP&L and Joe Davis of Duke Power Company for their helpful assistance. 1. "The Top 100 Electric Utilities 1974--A Year of Zero Growth", Electric Light & Power. July 21, 1975 (1974 Data); August 16, 1976 (1975 Data). 2. "An Energy Management Program Helps This Utility Reduce Its Fuel Bill", 1975 Generation Planbook, Power Magazine, p. 41-45 I I I I I I I I I I I I I I I I I I I -2- The aim of our program is to provide a method of monitoring performance of each unit, so that it can be operated at its best efficiency under various loading conditions. Five key variables were selected as potentially having the greatest effect on heat rate. They are-. 1) Turbine back pressure, as a function of circulating water inlet temperatures. 2) Excess oxygen at the economizer outlet. 3) Air heater gas out temperature, as a function of air heater air in temperature. 4) Main steam temperature, and 5) Reheat steam temperature. A display chart containing these five variables, (as a function of Mw), for each generating unit has been placed in each plant control room. The charts graphically depict the "best attainable" performance standards so that the operator can evaluate the unit's performance. The best attainable approach was selected over design parameters to encourage operators to meet present realistic goals. Each operator makes hourly comparisons of actual performance to the best attainable standards and then takes corrective action when appropriate. The operator can either adjust the control setting of the unit or request that maintenance be performed. The operator then records actual operating performance on control room logs which are processed and compared by a digital computer to the best attainable standards. The difference between the actual measurement and the best attainable value is then used to calculate the influence on heat rate and a prediction of the theoretical fuel savings (loss) that is created by variance from optimum. Knowing the economic impact of the increased fuel costs, our engineers can then use the data to determine the best correc- tive action, such as optimum frequency and method of condenser cleaning, boiler wash, soot blowing and other maintenance item scheduling. The computer program summarizes daily and monthly values for the performance monitoring report. See Figure 1 for sample monthly printout, and Figure 2 for trend analysis. The performance monitoring report provides Company management with information on efficient plant operation. But just ay important - it requires the plant operators to participate directly in monitoring each unit's efficiency. I I I I I I I I I I I I I I I I I I I -3- OPERATIONAL CHANGES Operational changes have had a significant effect on our system heat rate improvement. Our first step was to set up an accurate set of current incremental heat rate characteristics for all steam generating units. In some cases, we had previously been dispatching units on the basis of 10-year-old data. Since absolute heat rate changes can change the incremental heat rates significantly, accurate input-output tests are essential. A special team of SDG&E engineers was formed to make periodic tests of all steam generating units. Within 15 months, tests of every steam unit on the system had been completed. The results were twofold: First, accurate incremental heat rate curves were defined, and second, each unit's performance was compared to original or manufacture specifications. The incremental heat rate curves were then utilized by a new computer program, "Unit Commitment/Pro duct ion Cost". This program provides load dispatchers with an hour-by-hour model of our electric generating system. Now, the Load Supervisor can efficiently dispatch our generating units by considering incremental heat rates plus important plant operating conditions such as boiler/turbine startup, shutdown, and other operation data. This new computer program also enables our Electric Operations Department to more effectively schedule limited use of less efficient, quick-starting gas turbines. MAINTENANCE Our input-output testing program pointed out that some units no longer met the original manufacturer's guarantee. Thus, it became our goal on each unit's yearly overhaul to return our boiler/turbines to an "as new" condition. This goal, of course, could not be achieved on every unit without significant modifi- cations and expense. During 1975, several major unit overhauls corrected problems such as severe deposits on turbine blades, circulating pump impeller wear, turbine seal "rubout", and a condenser fouling. Another key maintenance development was a new computerized overhaul scheduling program. This program determines the optimum yearly schedule for overhauling each generating unit, thereby minimizing the system fuel cost and maximizing the system heat rate improvement. I I I I I I I I I I I I I I I I I I I -4- CONDENSERS Both the Performance Monitoring Program and our main- tenance programs concentrate on turbine back pressure as the most important variable influencing heat rates. Efforts in 1975 have significantly reduced each unit's back pressure. Our goal, in this case, is to reduce all units back pressure to the original manufacturer design specification. In the past, we cleaned our condensers each month with an air and water method, and each year with rubber plugs. However, these techniques cleaned primarily tube-sheet debris and did not remove mineral deposits. As indicated on Figure 3, the back pressure on our South Bay Unit 1 had been increasing since 1960. Stemming from our heat rate improvement program, we looked into different methods of condenser tube cleaning. We evaluated hydroblast (10,000 psi waterjet), acid cleaning, a "flocculent" material, plus the metal scraper technique. The metal scraper approach, provided by the Condenser Cleaners Manufacturing Co., Pittsburgh, Pennsylvania, was judged to be the superior method. The condenser tube wear was empirically determined to be less than 0.06 thousandths of an inch (.00006 inch) for each scraping. The results were dramatic! We flushed out more than one ton of "crud" from the condenser cleaning operation at South Bay Unit 1. The deposits were analyzed to be iron oxide, manganese oxide, silica, and organic growth. Figure 3 shows a 1.10" Hg improvement in back pressure — a return to original design back pressure. Our experience with the scrapers in 1976 indicated that, considering our specific fouling conditions and heat rate economics, a frequency of twice a year is optimum for our South Bay units and once per year for our Encina units. By cleaning condensers on seven units, we have lowered our system heat rate by 0.6670, gaining a fuel saving of more than $1.2 million per year. SUMMARY I have described some of the major parts of our program to reduce the net system heat rate. Many other factors contributed to improvement, but perhaps the most significant is the sincere interest our management has shown in heat rate improvement. We're still learning about efficiency projects, but we were encouraged by the first year results. Our goal for 1976 is to improve efficiency by an additional 1 to 3%. For this second stage efficiency effort we have retained the NUS Corporation of Rockville, Maryland as consulting engineers. This will put additional emphasis on specific programs that should further improve our position in the Top 100 electric utilities.