REVIEW OF S02 CONTROL ALTERNATIVES FOR COLSTRIP UNITS #3 AND #4 Pacific Environmental Services, INC. ------- EPA CONTRACT NO. 68-01-4140 TASK ORDER NO. 17 REVIEW OF S02 CONTROL ALTERNATIVES FOR COLSTRIP UNITS #3 AND J. C. Serne - Project Manager January 1978 Prepared for the: U.S. Environmental Protection Agency Region VIII Air and Hazardous Material Division 1860 Lincoln Street Denver, Colorado, 80295 Norman A. Huey, Task Manager PACIFIC ENVIRONMENTAL SERVICES, INC. 1930 - 14th Street Santa Monica, California, 90404 (213) 393-9449 ------- TABLE OF CONTENTS 5.3 6.0 SUMMARY . Section Page 1.0 INTRODUCTION 1-1 2.0 COLSTRIP UNITS #1 AND #2 SCRUBBER DESIGN AND PERFORMANCE 2-1 2.1 Scrubber Description 2-1 2.2 Operational History 2-6 2.3 Scrubber Test Data and Performance 2-11 2.4 Scrubber Costs 2-13 3.0 PLANNED SCRUBBER SYSTEM FOR COLSTRIP UNITS #3 AND #4 . . 3-1 3.1 Scrubber Description 3-1 3.2 Emission Estimates 3-2 3.3 Scrubber Costs 3-5 3.2.1 Worst Case Emission Rates 3-3 3.2.2 Typical Emission Rates 3-3 4.0 MODIFICATION OF PLANNED SCRUBBERS 4-1 4.1 Increased L/G Ratio or Additional Sprays 4-2 4.2 Increased Lime Addition 4-3 4.3 Pilot Plant Program 4-5 5.0 ALTERNATIVE SO 2 CONTROL SYSTEMS 5-1 5.1 Colstrip SO 2 Control System Constraints 5-2 5.2 Operational FGD Systems 5-3 5.2.1 Limestone Scrubbing Systems 5-5 5.2.2 Sodium Carbonate Scrubbing 5-7 5.2.3 Lime Scrubbing 5-8 5.2.4 Sumary of Performance 5-9 FGD System Economics 5-10 6-1 1 ------- LIST OF ILLUSTRATIONS Figure Page 2-1 Coistrip Units 1 & 2 Simplified Flow Diagram 2-3 2-2 Typical FGD Scrubber, Colstrip Unit 1 & 2 2-4 LIST OF TABLES Table ____ 2-1 Scrubber Availability Versus Plant Load. 2-2 Emission Test Results 2-3 Coistrip SO 2 Control System Performance. 2—4 FGD System Costs - Two Generating Units. 3-1 Worst Case Emission Rates 3-2 Typical Emission Rates 5-1 Sumary of Low Sulfur Coal Operational FGD of September 1977 5-2 FGD System Performance Sunriary Page 2-7 2-12 2-14 2-15 3-4 3-4 Systems as 5-4 5-9 11 ------- 1.0 INTRODUCTION The Montana Power Company currently operates two 360 MW (gross) coal-fired electric generating units at Coistrip, Montana. These existing units, #1 and #2, are equipped with scrubbers designed to remove both particulates and sulfur dioxide from the flue gas. Montana Power Company is planning construction of Units #3 and #4 at Coistrip, each with a 700 MW capacity. Coistrip Units #3 and #4 will be equipped with scrubbers to remove particulates and sulfur dioxide, as required to meet New Source Performance Standards (NSPS) and Class I Prevention of Significant Deterioration (PSD) regula- tions. The objective of this study is to evaluate the SO 2 control alternatives for Coistrip Units #3 and #4 The design and performance of the scrubbers serving Coistrip Units #1 and #2 are described in Section 2. Sulfur dioxide emission rates from Units #3 and #4 are predicted in Section 3, assuming a similar scrubber design and performance as reported for the existing units. Section 4 describes potential modifications to the planned Coistrip scrubber design expected to improve SO 2 collection efficiencies. A brief sunii ary of alternative SO 2 control systems potentially avail- able for Coistrip Units #3 and #4 is presented in Section 5 along with cost performance information and associated environmental and engineering sacrifices. 1—1 ------- 2.0 COLSTRIP UNITS #1 and #2 SCRUBBER DESIGN AND PERFORMANCE An excellent description of the design and perfonitance of the scrub- bing system on Coistrip Units #1 and #2 is provided in a paper re- cently presented at the Fourth Symposium of Flue Gas Desulfurization. A sunui ary of “Status and Performance of the Montana Power Company’s Flue Gas Desulfurization System” by D. T. Berube and C. D. Grinnii of Montana Power Company is provided in this section along with a discussion of the SO 2 collection efficiencies calculated by PES. 2.1 Scrubber Description The flue gas cleaning system now in operation on Coistrip Units #1 and #2 consists of three scrubber modules operating in parallel per unit. Each 33 1/3% nominal scrubber module is capable of treating up to 40% of the flue gas flow for short periods of time. No scrub- ber bypass capability is installed. Each scrubber module consists of a variable throat venturi for particulate and sulfur dioxide re- moval and a spray absorption section for additional sulfur dioxide removal. This system, which was piloted for approximately one and a half years, uses the alkalinity present in the captured ash from the Rosebud seam coal for the SO 2 removal. Supplemental lime is added for pH control. The vendor for the scrubber installation was Combustion Equipment Associates. Bechtel Power Corporation was the architect-engineer for the power plants and personnel from its Re- search Division were involved in the devlopment of the Coistrip scrubbers. Unit #1 has been operational since September 1975 and Unit #2 since May 1976. The design parameters of the GD system are as follows: 1. Liquid to gas ratio: L/G 33 split L/G 15 to venturi, L/G 18 to absorption sprays. 2. Suspended Solids in Recycle Loop: 12%. 2—1 ------- 3. Venturi Pressure Drop: 17.0 in. W. S. 4. Recycle Retention Time: 8 minutes. 5. Recycle Slurry pH: 4.5 to 5.6. 6. Particulate Emission Guarantee: Outlet grain loading not to ex- ceed 0.018 grains per actual cubic foot as measured at the reheater outlet. 7. Sulfur Dioxide Guarantee: SO 2 emission not to exceed 1.0 lb SO 2 per million BTIJ heat input. 8. Closed Loop Operation: Liquid can leave the system by evapora- tion in the process, up through the stack, evaporation from the pond surfaces, or be purged with the sludge resulting from the scrubber operation. The coal characteristics used in the scrubber specification are sumarized below: Coal: Average As Received Moisture 23.87% Volatile Matter 28.59% Fixed Carbon 38.96% Ash 8.59% (Max 12.58%, t4in 6.1%) Heating Value 8500 BTU/lb (Max 8,843 BTU/lb, Mm 8,162 BTU/lb) Sulfur .77% (Max 1.0%, Mm 0.4%) A simplified flow diagram of the Coistrip scrubber train is shown on Figure 2-1. Figure 2—2 presents a detailed view of the scrubber in- ternals. Combustion gas exits the air heater at about 290°F, trav- els through a duct containing several 90° turns and enters the scrubber module. The gas then passes through the variable throat venturi where it is contacted with the slurry which flows over both the venturi bowl surface and the plumb bob. Next, it passes through the absorption zone where it is contacted with recycle liquor sprayed from the absorption nozzles. The wash tray is next in line to con- tact the gas. Its function is to remove entrained solids from the cleaned flue gas prior to the mist eliminators. Both the bottom of the mist eliminator and the bottom of the wash tray are sprayed continuously. The mist eliminator is sprayed with a blend of wash 2-2 ------- .COLSTRIP UNiTS 1 & 2 SIMPL IfIED FLOW DIAGRAM FLYASH PONO WASH TRAY POND Figure 2 -1 ------- IAWCtI TIAL P DZ7LIS PLUMB BOB VEP TURI BOWL WtSl LLIMII A1DR lOP SPRAY W!ST ILIMINA1OR V1ST IL TYPICAL FGD SCRUBBIR COLSTRIP UNIT 1 & 2 TRAY UhDER SPRAYS %ASH TRAY VISCii&R01 ABSORPHON SPRAYS ABSORPTION SICTID Figure 2-2 LUERCINCY SPRAYS PLUMB BOB i:O2zu VL! TURI !ICTIDU TRAY RORMAL LIDUID LEVEL BLURRY OUTLET MANHOLE ACCESS DOOR * ITA1DR IJIdIT 2-4 ------- tray pond return liquid and river water. This area and the pump and agitator seals are the only places where fresh water enters the system. A liquid level is maintained on the top of the wash tray. The wash tray/mist eliminator loop works independently of the scrub- ber slurry recycle loop. The gas exits the scrubber module and passes through a reheat section consisting of two banks of plate- coil reheaters. The reheaters are cleaned by soot blowers placed above and between the two banks. The dry induced draft fans are last in line to contact the gas 1 then It passes isolation dampers and out the stack. Two scrubber recycle pumps are needed to provide the required slurry flow to the venturi and absorption sections. The third pump is a spare that can be valved in to either the venturi or the absorption sprays. A bottom entry agitator in the main recycle tank provides necessary agitation to extract alkali values from the ash and re- suspension capability for the slurry should the module be shut down. The wash tray tank is also agitated and a set of pumps, one opera- ting and one spare, is used in that loop. The three scrubber mod- ules of one generating plant rely on one tray recycle tank. Solids are bled from the scrubber recycle loop to the effluent tank, then pumped to the settling ponds Inmediately behind the plant. The wash tray cycle”rejects its solids to a separate pond at the same location. Oecanted liquid is brought back to the wash tray and scrubber recycle loops. Materials of construction include unlined carbon steel for the scrubber inlet ducts, glass flake polyester lined carbon steel for the internal surfaces of the scrubber vessels, abrasion resistant bricks In the venturi throat, 316 stainless steel on certain areas of the plumb bob, a Norel plastic for the four pass chevron mist elIminators, 316 stainless steel In the wash tray, flakelining In the duct exiting from the scrubber through to the chimney opening, 2-5 ------- Hastalloy G and Inconel 625 for the reheat surfaces with 316 stain- less forming the duct walls around the reheater and rubber lining in the fan casing. The large recycle pumps are all rubber lined. Piping four inches and greater in diameter is rubber lined carbon steel and piping less than four inches is 316 stainless steel. The dry induced draft fan is of carbon steel construction. The lime system consisting of storage silos for the pebble lime slakers, transfer and holding tanks, and the associated pumps and piping provides for lime slurry addition to the scrubber recycle tank for pH control. Inlet and outlet sulfur dioxide monitors are provided on the scrubber trains. The testing station placed in the stack also is the loca- tion for the SO 2 , NOR. CO 2 and opacity monitors. 2.2 Operational History Unit #1 has been in operation since September 1975 and Unit #2 since May 1976. The overall performance of the scrubber system has been quite good. The scrubbers have been free of massive scale formations that have been reported at other scrubber installations. The system has operated in a closed loop mode. Table 2-1 contains scrubber availability data from September 1975 through July 1977. The defi- nition of scrubber availability below the table should be noted. The average availability for the Unit 41 scrubbers was 87% and for Unit 42 scrubbers was 91.3%. Modifications and improvements have been made in the scrubber system to correct problems and increase availability. A description of the problem areas and the solutions or corrective measures taken by MPC are provided in the following pages of this section. Deposits occurred at the wet-dry interface located at the entrance to the scrubber modules which reduced availability to an jnacceptab1e 2-6 ------- Table 2-1. SCRUBBER AVAILABILITY VS PLANT LOAD Monthly Capacity Factor Percent Number Days On Line Average MW For Days On Line Scrubber Avail- ability Percent Unit *1 Unit #2 Unit #1 Unit #2 Unit #1 Unit *2 Unit #1 Unit *2 1975 Sep 0.5 3 50 Oct 19.4 19 139 Nov 42.2 24 203 Dec 59.9 30 239 1976 Jan 63.8 28 265 90.0 Feb 65.4 26 273 98.0 Mar 57.0 24 277 97.6 Apr 49.9 28 219 74.2 May 26.0 1.3 14 3 210 66 96.8 100.0 Jun 0.0 23.2 0 16 0 171 - 99.7 Jul 28.0 19.5 20 13 167 180 93.2 98.7 Aug 37.8 13.0 23 10 194 162 94.7 95.8 Sep 64.5 64.6 30 30 239 232 88.6 98.3 Oct 73.1 77.0 30 31 281 298 79.9 90.3 Nov 55.6 79.7 30 30 225 303 62.7 94.1 Dec 67.2 82.3 31 31 249 297 73.8 92.5 1977 Jan 72.9 68.2 31 30 270 258 92.5 83.4 Feb 3.0 75.3 2 27 161 285 95.4 93.8 Mar 0.0 71.3 0 28 0 293 - 96.7 Apr 49.9 68.2 25 29 236 264 83.0 84.5 May 64.1 23.3 26 13 286 209 85.4 63.0 Jun 68.6 61.4 28 28 284 249 87.4 87.8 Jul 71.8 57.5 29 28 284 238 85.1 90.6 Ave- rage 87.0 91.3 Note: Scrubber availability = total module hours available i (hours in month) except May through August 1976 base is days in operation because of extended scheduled outages. 2-7 ------- degree. These are not to be confused with calcium sulfate or calcium sulfite scale formation. Gas flow tests were run on a model that duplicated the configuration of the duct from the air heater exit to the top of the scrubber module and the upper portion of the scrubber module itself. These tests found there was a maldistribu- tion of the dust entering the scrubber module along with extreme velocity variation from one side of the duct exit to the other. In addition, a model study was made of the liquid flow on the tan- gential shelf above the venturi. Prom those studies, it was con- cluded that gas flow turning vanes in the duct elbow above the scrubber module and liquid guiding vanes and baffles on the tan- gential shelf would be required to reduce the wet-dry interface buildup. One module was modified and operation gave encouraging results. These modifications were then made during the spring and suniner of 1977 to the remaining five modules and the construction time is reflected in the scrubber availability figures in Table 2-1. Actual operating experience from the modules equipped shows a sig- nificant reduction in cleaning time and has Increased the time in- crement between inspection and cleanings. Instrumentation in slurry and flue gas service has not been trouble free. The stack opacity, SO 2 and NO monitors along with the SO 2 monitors on the inlet and outlet of the scrubber modules have exhib- ited unstable and erratic behavior. A corrective program has shown progressive Improvement in the data retrieved by these monitors during the past six months. The in line pH probes either erode away or lose sensitivity due to deposits on the elements. Slurry density monitors have given erratic and unstable operation too and a test program is in progress to isol te these devices from vibra- tion. Both slurry density and pH, key operating parameters, are taken manually and monitored on a frequent basis. 2-8 ------- The supplementary alkali feed system has been difficult to use due to line plugging and equipment failure. The lime system is being modified so that it will be simpler to use and less prone to plug- ging. Pinch valves are being placed next to the scrubber vessel on each feed line so any solid accumulation will slough off as these valves are regularly stroked. The alkaline ash captured by the scrubber has generally been adequate to keep the scrubber pH within the control range. Better control of the lime system will keep the pH more constant and allow SD 2 removal to be optimized. Failures of the protective glass flakelining on the carbon steel vessel walls and ducts have occurred. These failures were evident prior to a major temperature excursion that occurred in Unit l in October 1976 but were then aggravated. The excursion followed a complete station power blackout and the failure of the emergency scrubber quench water supply system to operate. The glass flake- lining along with the plastic mist eliminators were seriously dam- aged at that time in Unit #1 and account for low scrubber availab- ility during November and December 1976. A failure of an ID fan motor during the same time period, independent of the temperature. excursion, also contributed to the Tower availability figures. If the ID fan motor was not considered in compiling the availability numbers, the scrubber availabilities would have been 88.5%, 94.0% and 81.6% for Unit #1 during the months of October, November and December 1976. Subsequent problems with other ID fan motors early in 1977 have reduced scrubber availabilities. The availability given for May 1977 for Unit 12 reflects another fan motor repair and the modifications for the wet-dry interface. Inspection of an ID fan rotor during the spring of 1977 resulted in the finding of cracks in the center plate next to the blades. Each fan was then cleaned and critically Inspected. If cracks were found or If there was a suspicion a crack might form, it was Isolated and ground out. Then that portion was welded and a stiffener plate was 2-9 ------- added. Availabilities during the suniner of 1977 and the modifica- tions carried out for the wet-dry interface show this activity. Quick clean basket strainers were added to the suction piping of the two main recycle pumps of each vessel in place of the original start-up strainers contained in a pipe spool. This has allowed de- posits and foreign materials to be removed before they clog spray nozzles and has also decreased maintenance and downtime on the vessels. A program is under way to evaluate abrasion resistant protective lining materials that could be used where the flue gas makes its 180° turn following the venturi down-corner and passes by the ab- sorption sprays. Impingement on the wall by the absorption spray slurry erodes the glas flakelining and this lining has been re- placed at least once in each module since unit start-up. Similarly, a program for evaluating corrosion, temperature resistant and abrasion resistant materials in other areas of the scrubber is in progress. Small test patches and full scale application of various linings are in place on several of the scrubber modules and are subject to different environments. Plugging of the wash tray underspray nozzles on scrubber modules of both units occurred during May of 1977 and forced the plants to shut down. The major cause of the problem was traced to piping in the wash tray pond which had broken and allowed some of the pond dike material to be ingested. A parallel pipeline and pumping system was installed, the units brought on line and modification and repair made to the original piping system. The scrubber ponds are reclaimed by a dredge system which transfers the scrubber sludge to a disposal pond approximately three miles from the plant site. Liquid from the disposal pond is returned to the scrubber ponds imediately behind the plant when the dredge is not operating. The scrubber sludge deposits in deltas in the 2-10 ------- ponds and contain 55% — 60% solids. The material hardens very well and the dredge has had some difficulty in reslurrying the sludge. Residual alkalinity remains in the sludge deposited in these ponds and this results in the sludge taking on a cement-like nature. Improved cutters for the dredge and a delumper ahead of the dredge pump are expected to increase the solids handling capacity. More rapid filling of the wash tray pond with solids than had been ex- pected has presented a problem in the method of removal of these materials. Each of the plant ponds has its own chemical identity due to water balance considerations. A dredge cannot be used pres- ently to reclaim the wash tray pond volume without adversely affect- ing either the plant operation or the pond water balance, so a less efficient clamshell operation is now in use. Plans are being de- veloped for the addition of another wash tray pond so that one may be dewatered and then cleaned while the other is in operation. 2.3 Scrubber Test Data And Performance A large number of emission tests have been conducted on the Coistrip units over the 1 — 1/2 year period. EPA compliance tests for par- ticulate, sulfur dioxide and N0 were completed during the spring of 1977 on both plants. Also, emission monitor certification test- ing has been conducted following the conclusion of the NSPS emission tests. Table 2-2 shows the results of the tests. The NSPS require- ments, the scrubber guarantee, the projected results from pilot plant experience and the actual tests on Units fl and •2 are re- ported. The results of the operation of the full scale units agree well with the pilot plant data. The data also shows the plant emissions are well below the guarantee and the NSPS standards. Al- though scrubber inlet data has not been taken and efficiency per se is not available, it appears sulfur dioxide and particulate re- moval efficiencies predicted from the pilot plant data are being achieved. 2—11 ------- Table 2-2. EMISSION TEST RESULTS 502 PartIculate ;NO Lb/hr Lb/mBTU Lb/hr Lb/mBTU % Opac Lb/hr Lb/mBTIJ Required by NSPS (358 MW) 4,063 510 1.2 339 .10 20 2,370 .7 Scrubber Guarantee (358 *1) 3,386 425 1.0 207 .06 — 2,370 Projected from Pilot Plant (358 MW) a) 0.78% S (760 PPM), 8.19% Ash 1,394 185 .41 130 .038 20 2,370 .7 b) 1.0% S (965 PPM), 12.58% Ash 2.071 260 .61 184 .054 20 2,370 .7 Unit #1 Tests: Coal As Received 4 Date Gr MW S Sul S Ash Btu/lb 2/76 353 .83 9.03 8,638 1,587 197 .48 95.8 .029 10 (3) 954 .29 4/76 210 .71 7.79 8,861 456 87 .23 60.9 .030 12 (3) 800 .41 7/76 184(6) .64 8.49 8,807 258 53 .15 57.1 .031 15 (2) 740 .42 9/76 186(6) .62 7.93 8,633 275 56 .15 64.4 .037 11 (2) 687 .39 12/76 223(6) 94 8.54 8,394 898 154 .43 67,2 .032 15 (2) 662 .31 1/77 354 .77 8.17 8,719 770 (5) 133 (5) 123.5 .037 13 (2) 1,459 .43 5/77 331 .61 8.41 8,851 552 72 .16 109.6 .032 14 (2) 1,029 .29 6/77 340 .91 8.96 8,888 1,164 122 .325 89.5 .039 18.4(2) 1,296 .36 Unit •2 Tests: Coal As Received Date Gr MW S Sul % Ash Btu/lb 10/76 331 .56 7.96 8,368 1,309 178 .42 88.6 .029 11 (2) 917 .30 11/76 327 .59 7.86 8,484 696 83 .23 91.4 .029 10 (2) 993 .32 12/76 324 .64 7.87 8,690 780 98 .25 105.7 .034 16 (2) 784 .25 3/77 335 .63 7.96 8,739 684 84 .20 91.9 .029 8 (2) 1,399 .38 6/77 305(8) .72 8.48 8,929 596.5 67 .189 104.2 .051 8.4(2) 1,261.4 .403 1. N0 emissions guaranteed by boiler supplier equal to NSPS. 2. Average EDC monitor opacity. 3. QualIfied observer, EPA Method 9. 4. Based on percent moisture of coal for periOd prior to test. S. SO 2 test done at 230 MW (two scrubbers on line). 6. Two scrubber modules on line, all other tests done with three modules on line. . so 21 tio tests 340 MW, particulate tests 260 MW. 8. 502. tests 305 MW, particulate tests 198.5 MW. 2-12 ------- Calculations of the scrubber inlet SO 2 rate were made using the coal characteristics and plant load. From these inlet SO 2 rates an estimate was made of the SO 2 collection efficiency during each emission test. Table 2-3 sumarizes these calculations. Note that it was assumed for calculation purposes that all of the sulfur in the fuel reports to the flue gas. In fact, it has been reported in the literature that from 5 to 20% of the sulfur in the Western coals is contained in ash. Of the sulfur contained in the coal an average of 83.5% was removed according to the 13 emission tests. For Units #1 and #2 the first emission test indicates significantly lower SO 2 control efficiencies than subsequent tests. If these two tests are excluded the average SO 2 control efficiency is 85.6%. All but the initial Unit #1 and #2 tests indicate SO 2 removal efficiencies of greater than 80%. 2.4 Scrubber Costs Actual construction costs for Colstrip Units #1 and #2 with some portion estimated through June 1977 are listed in Table 2-4. The emission control system alone costs $63.98 per net kW. When the scrubber sludge disposal system is added, the cost rises to $83.74 per net kW. The bottom ash and other disposal ponds are not included in these costs. Work is still proceeding on the Installation and these costs will increase. These costs describe a combined par- ticulate-sulfur dioxide removal system requiring minimal chemical addition, installed as a new unit and ordered in 1972. It was reported by MPC that the first cost (capital cost) of’the scrubbers for the first two Colstrip units was approximately 30% of the entire plant first cost. 2-13 ------- Table 2—3. COLSTRIP SO 2 CONTROL SYSTEM PERFORMANCE Date MW %S Btu/lb Lb S0 2 /Hr* Lb S0 2 /Hr SO 2 Removal Efficiency Unit 1 In Out 2/76 353 0.83 8,638 6,416 1,587 75.3 4/76 210** 071 8,861 3,183 456 85.7 7/76 184** 0.64 8,807 2,529 258 89.8 9/76 186** 0.62 8,633 2,527 275 89.1 12/76 223** 0.94 8,394 4,724 898 81.0 84.7% Average 1/77 354 0.77 8,719 5,914 770 87.0 5/77 331 0.61 8,851 4,315 552 87.2 6/77 340 0.91 8,888 6,585 1,164 82.3 Unit 2 10/76 331 0.56 8,368 4,190 1,309 68.8 11/76 327 0.59 8,484 4,302 696 83.8 12/76 324 0.64 8,690 4,514 780 82.7 81.6% Average 3/77 335 0.63 8,739 4,568 664 85.5 6/77 305 0.72 8,929 4,6 2 596.5 87.2 (Average 83.5%) * Calculated by PES assuming all fuel sulfur reports as SO 2 in the flue gas to scrubbers. ** Two scrubber modules operating. Coal datawere adjusted byMPC to “as received basis.” 2-14 ------- Table 2-4. FGD SYSTEM COSTS — TWO GENERATING UNITS Dollars $/Net kW* 1. Scrubber subcontract and out of scope additions by prime contractor (in- cludes foundation, field wiring, insulation, heat tracing, painting, piping to ponds, piping between mod- ules and field distributables in addition to the scrubber modules, ductwork, equipment supply and erection) $33,677,261 $51.02 2. Owners’ cost including interest at $2,792,000 4,374,000 6.62 3. Subtotal as of December 1976 38,051,261 57.65 4. Estimated cost for work in progress (cost responsibility under dispute) 4,178,499 6.33 5. Fly ash ponds (temporary storage), fly ash slurry transport system and evaporation pond 12,722,131 19.29 6. Incremental costs (auxiliary boiler, FD fans, start-up and auxiliary transformer) 317,520 0.48 7. TOTAL $55,269,411 $83.74 *This cost does not include an additional claim submitted by the subcontractor. It also does not include a value for reduced plant capacity, although for many purposes, it should. **Net rating 330 MW/unit; gross rating 358.4 MW/unit. 2-15 ------- 3.0 PLANNED SCRUBBER SYSTEM FOR COLSTRIP UNITS #3 AND #4 Information and data regarding the planned scrubber system for Co1 strip Units #3 and #4 were obtained at meetings and during dis- cussions with D. T. Berube and C. D. Grimm of Montana Power Company. 3.1 Scrubber Description Montana Power Company has indicated that the scrubber system design planned for Colstrip Units #3 and #4 will make use of identical scrubber modules as are installed on the first two units. MPC feels that Coistrip Units #1 and #2 have demonstrated successful develop- ment of a scrubber system suited for the particular characteristics of Coistrip coal, achieving low emissions, zero water discharge and efficient use of resources such as chemicals, water, land and money. No other power plant equipped with scrubbers is operating with per unit emissions less than Coistrip in a closed loop node. The high scrubber availability and SO 2 control efficiency described in Section 2.3 are cited as factors in deciding to utilize a similar scrubber design for Coistrip Units #3 and #4. It is planned to install eight scrubber (seven plus one spare) mod- ules on each of the new Coistrip units. The improvements and field modifications developed during the first years of operating the existing Coistrip Units #1 and #2 scrubbers are expected to be incorporated into the planned scrubbers. Improved scrubber avail- ability is anticipated due to these design changes, as well as the use of a spare scrubber module per unit. For a description of the scrubber module design and system improvements the reader should review Sections 2.1 and 22. 3-1 ------- 3.2 Emission Estimates Estimates of the SO 2 emissions for worst case and an average or typical case are presented in this section, assuming various SO 2 removal efficiencies. Throughout the calculations all of the sulfur contained in the fuel is assumed to appear as SO 2 in the flue gas. The SO 2 control efficiencies discussed are therefore system control efficiencies rather than actual scrubber SO 2 removal efficiencies. Coal is a heterogeneous material containing organic combustible matter and mineral matter. Sulfur exists in coal in two principal forms; organic and inorganic. Organic sulfur is chemically bound to the coal and cannot be removed by physical or mechanical proc- esses. On the other hand, inorganic sulfur (pyritic sulfur) is not bound chemically and may be physically removed to varying de- grees from the coal. The coal at Coistrip is pulverized and par- tially dried before firing. A portion of the pyrites (and pyritic sulfur) are removed from the coal during the coal preparation and not combusted. Also a portion of the sulfur in combusted coal is retained in the ash after combustion. From 5 to 40% of the sulfur may be retained in the ash for Western coals. As a result of these factors (the removal of a portion of the pyritic sulfur prior to combustion and the retention of a portion of the combusted coal sulfur in the ash) the sulfur dioxide load at the inlet of the scrubbers is not twice (2 lb SO 2 / 1 lb S in coal) the sulfur content of the “as received” coal. The percent or amount of pyritic sulfur removed and sulfur retained in ash are not known for Coistrip. For this reason an SO 2 removal or control efficiency for the system has been used rather than a control efficiency for the scrubbers. No adjustments were made to account for removal of pyritic sulfur and sulfur retention in the ash. All calculations were performed for and all results are reported for each individual unit. Since Coistrip Units #3 and #4 are identical in size and design the 3-2 ------- total emission rate for the combined units would be twice the values cited in the remainder of this chapter. 3.2.1 Worst Case Emission Rates A sulfur content of 1.0% and heating value of 8,162 Btu/lb along with a plant load of 100% (7,573 x io6 Btu/hr heat input) were as- sumed as representative of worst case conditions. Worst case con- ditions, by definition, mean the conditions resulting in the maxi- mum SO 2 emission rate. These worst case conditions represent a rare or unlikely short-term event. An uncontrolled SO 2 emission rate (from each unit) of 18,557 lb/hr (222.7 TPD) was calculated. With an SO 2 control efficiency of 73.7% (the removal efficiency projected under worst coal conditions by MPC from the pilot plant data for Colstrip Units #1 and #2) a per unit SO 2 emission rate of 4,880 lb/ hr or 58.6 TPD is predicted. Four other SO 2 control efficiencies were used in the 502 emission rate projections. A control efficiency of 80% was selected as representative of a value achieved or surpassed in all but the first weeks of scrubber operation on Units #1 and #2. The average 502 control efficiency, measured to date for Units #1 and #2, of 83.5% (see Table 2-3) was used to compute SO 2 emission rates. Control efficiencies of 85 and 90% were also used. The 90% value represents the approximate limit of proven scrubber technology. The SO 2 emission rates calculated for the worst case conditions assuming the various control efficien- cies are presented in a variety of units in Table 3-1. 3.2.2 Typical Emission Rates A sulfur content of 0.77% and a heating value of 8,500 Btu/lb with a 70% plant load (5,301 x Btu/hr heat input) were selected as representative of typical or average conditions. Typical or average conditions, and the predicted SO 2 emission rates, are useful for 3-3 ------- long—term impact assessments. An uncontrolled SO 2 emission rate (per unit) of 9,604 lb/hr (115.3 TPD) was computed. The SO 2 emission rates resulting from application of the various levels of SO 2 control are provided in Table 3-2. - Table 3-1. WORST CASE EMISSION RATES (1.0% S 8,162 Btu/lb 100% Plant Load) SO 2 Control Efficiency SO 2 Emission Rate lb/hr TPD lb/10 6 Btu g/sec Uncontrolled 73.7% 80 % 83.5% 85 % 90 % 18,557 4,880 3,711 3,062 2,784 1,856 222.7 58.6 44.5 36.7 33.4 22.3 2.45 .64 .49 .40 .37 .25 2,343 615 468 386 351 234 Table 3-2. TYPICAL EMISSION RATES (.77% S 8,500 Btu/lb 70% Plant Load) SO 2 Control Efficiency SO 2 Emission Rate lb/hr TPD lb/l0 6 Btu g/sec Uncontrolled 73.7% 80 % 83.5% 85 % 90 % 9,604 2,526 1,921 1,585 1,441 960 115.3 30.3 23.1 19.0 17.3 11.5 1.81 .48 .36 .30 .27 .18 1,211 319 242 200 182 121 3-4 ------- 3.3 Scrubber Costs The cost data reported by MPC for the scrubber system installed on Colstrip Units #1 and #2 were escalated and adjusted to reflect the larger unit size and later installation date. Start-up dates in 1981 and 1982 were projected for Units #3 and #4, respectively. It was assumed that the $83.74 per net kW value reported for Units #1 and #2 (see Section 2.4) was in terms of 1977 dollars. Assuming an escalation rate of 7% per year over the 4 years, a cost of $109.77 per net kW is estimated. The total cost of the scrubber system for Units 113 and #4 is computed as $153,678,000. In a memo to Walter C. Barber, Director of EPA ’s Office of Air Qual- ity Planning and Standards dated June 10, 1977, MPG provided a cost estimate for the scrubbers at Coistrip Units #3 and #4. Starting with a $80/kW figure for Coistrip Units #1 and #2, and escalating at 8% per year to 1981 (6 years) gives 80 x 1.59 or $127.2/kW. To account for the additional redundancy (a spare scrubber) required on Units #3 and #4 a factor of 8/7 was applied raising the scrubber system cost to $145.4/kW. A total cost for the Units #3 and #4 scrubber system is therefore $203,560,000. MPG also performed an Order of Magnitude gross cost estimate based on Colstrip Units #1 and 112 plant costs, with a percentage allocation for the scrubbers. These computations project a total scrubber system cost of in the range of $180 — $200 million. Stated another way, the scrubber system cost for Units #3 and #4 is estimated to be about $128 to $1 421kw. 3-5 ------- 4.0 MODIFICATION OF PLANNED SCRUBBERS Modifications or improvements in the planned Colstrip Units #3 and #4 scrubber system design with the objective of increasing the SO 2 control efficiency might be possible, but several inter- related factors must be considered. Field modifications, which have lowered scrubber maintenance requirements and increased scrubber reliability or availability, have been made on the Coistrip Units #1 and #2 scrubbers. The objective of these improvements has not been to increase SO 2 control efficiency, per Se. Since no scrubber bypass capability was provided for at Coistrip Units #1 and #2, the relation between increased scrub- ber reliability and annual SO 2 emissions would be difficult to quantify. When adequate scrubbing capacity is not available to handle Unit #1 or #2 flue gases, the boiler(s) must be operated at a reduced load(s) or shut-down. The planned scrubber system for Coistrip Units #3 and #4 will utilize eight scrubbers per unit (seven operating and a spare) to minimize the occurrence of scrubber caused reductions in plant load. A list of factors to be considered or evaluated before adopting any design modification includes: water usage and balance waste disposal — quantity and characteristics chemical consL nptiOn reliability energy requIrements maintenance requirements operating experience The evaluation of the impacts on these factors of scrubber design modifications to improve SO 2 removal could necessitate a pilot program. In this section, potential scrubber modifications aimed 4-1 ------- at improved SO 2 control efficiency are identified. A comprehen- sive evaluation of the impacts on the factors listed above could not be performed within the scope of this study. Potential im- pacts have been identified and are noted briefly. 4.1 Increased L/G Ratio or Additional Sprays The redesign 0 f the scrubbers to operate at a higher L/G ratio or with additional sprays is a potential method of improving SO 2 removal efficiency. The relationship between the L/G ratio and SO 2 control efficiency( SO 2 ) is not known precisely, but generally, as hG is increased SO 2 also increases. Several methods 0 f increasing the L/G ratio are possible. Increasing the liquid pump- ing rate and amount of spray per nozzle is one option. Increased pumping costs (larger pumps and more energy consumption) as well as more rapid nozzle wear and more frequent shut-down for nozzle replacement would be expected. A second, and possible better method of raising the L/G ratio,is to increase the number of absorption sprays while maintaining the rate of spray from each nozzle. The placement of the additional sprays within the scrub- ber vessel could affect the SO 2 control efficiency and other scrubber system parameters. The most significant increase in SO 2 control efficiency might be achieved by incorporating an additional absorption spray section operated on a separate water loop. The operation of a separate water loop would be required if a two-stage absorption system was needed. The scrubber system design modifications to achieve a second SO 2 absorption stage would be significant and worthy of pilot plant testing. The incorporation of an increased L/G ratio or additional sprays would affect the scrubber system design and operation. Extensive scrubber vessel arrangement and size modifications, such as 4-2 ------- increasing the scrubber height and/or diameter to maintain sufficient slurry recycle retention time. Larger pumps would be required with an increased L/G ratio, and if a separate, additional spray section were incorporated, additional pumps, nozzles and piping would be required. The increased hG ratio would impact the water balance. Water consumption would be higher and it is uncertain if a closed loop water balance could be maintained. These modifications might also adversely affect the scrubber system reliability. Maintenance requirements would be increased due to the additional sprays and pumps or nozzle wear. Energy consumption would increase due to the higher liquid pumping requirements. As with all modifications resulting in a higher SO 2 removal efficiency, the quantity of solid wastes to be disposed of would increase. Handling and disposal of greater quantities of scrubber sludge or wastes would add to the capital and operating costs. 4.2 Increased Lime Addition A design concept used in the Coistrip Units #1 and 2 scrubbers is the utilization of the alkalinity of the fly-ash for SO 2 removal. Lime is added to the existing scrubbers for pH control and not for SO 2 absorption purposes. The use of additional lime as a method of increasing the SO 2 removal efficiency could be considered an alternative scrubbing technique rather than a modification to the planned scrubber system. The amount and role played by the lime in the scrubbers would determine whether increased lime addition were a modification or an alternative SO 2 control method. For the case where lime is added to enhance SO 2 absorption while relying primarily on the fly-ash alkalinity, a discussion of the impacts of increased lime addition on other scrubber system parameters is appropriate in this section. 4-3 ------- The redesign to allow for the use of additional lime could result in several adverse scrubber system impacts. The scrubber chemistry, recognized as very complex, could be altered significantly and would require pilot plant investigation. Changes in the scrubber chemistry could affect the slurry recycle retention time. Scrubber vessel size and arrangement modifications might be required to provide adequate retention time. Scrubber scaling problems might become a significant problem and result in higher maintenance requirements and decreased scrubber availability. If hard deposits or scaling resulted, difficult operating and maintenance problems would have to be overcome. Metals in the captured fly-ash are thought to act as a catalyst, aiding in the oxidation of SO 2 to SO 4 . Calcium sul- fate (CaSO 4 ), a scrubber product, is more readily decanted and forms a more stable disposal material. If increased lime addition altered the scrubber chemistry and resulted in greater sulfite formation, the system design would require several modifications. More diffi- cult water separation and increased disposal problems would result. The increased usage of lime would increase chemical consumption and costs. Lime handling and storage facilities would have to be en- larged and capital costs and operating expenses would rise. The handling of larger quantities of lime would result in greater energy consumption. Lime is obtained from limestone which must be mined and processed. The impact of increased lime addition on water usage and the water balance is uncertain. The ability to maintain a closed loop water balance would have to be tested. The higher SO 2 collection efficiency combined with greater lime usage would result in larger quantities of scrubber sludge for dis- posal. As a result, waste handling and disposal requirements and costs would increase. The dewatering and disposability of the 4-4 ------- scrubber waste might also be affected. A less stable scrubber waste product would raise disposal costs and/or result in greater potential envi ronmental impacts. 4.3 Pilot Plant Program Any substantial change in the scrubber system design would require a pilot plant program to verify process parameters, perform- ance and to evaluate the impacts on all related factors. Reliabil- ity and operating experience are considered essential by MPC before committing to a modified scrubber system design. According to MPC, nine months to two years would be required to verify and evaluate scrubber design modifications. The cost of delaying Colstrip Units #3 and #4 and the impact of delays on the needs of MPG customers could be significant. Any scrubber system changes which sacrificed the closed loop water balance or reliability; or caused increased consumption of energy, chemicals, water or land for disposal, would require comprehensive evaluation. 4-5 ------- 5.0 ALTERNATIVE SO 2 CONTROL SYSTEMS Several factors must be considered before selecting an SO 2 control system. A scrubber system cannot be selected solely on the basis of SO 2 removal efficiency. Likewise, the performance of a scrubbing system cannot be summarized and reported entirely in terms of SO 2 removal efficiency. Governing air quality standards and emissIon regulations generally establish the required level of SO 2 control system operation. An emission limitation for a given power plant is typically determined by air quality or dispersion modeling which utilizes site specific meteorological, plant and emission data. Once an emission limit is established based on the applicable emis- sion regulations and air quality impact constraints, the optimum SO 2 control system can be selected after consideration and evalua- tion of the following factors: governing water quality standards and effluent limitations fuel characteristics and composition water requirements — quality and quantity needed chemical consumption and availability particulate removal equipment requirements quantity and characteristics of wastes to be disposed of energy cons umpti on maintenance requirements auxiliary facilities required reliability operating experience capital and operating costs 5-1 ------- The fuel characteristics and composition can be used to calculate the overall SO 2 control efficiency required to achieve the required emission limitation. ‘The availability of water plays an important role in scrubber system design. Suitable space and waste disposal facilities are also needed. Favorable reliability and operating experience are demanded of all comercial control systems. The best SO 2 control system must be determined for each specific power plant in accordance with avail- able conditions and resources. The constraints or factors listed above can vary widely between plants, limiting the applicability of an SO 2 control system. This chapter describes the Coistrip Units #3 and #4 SO 2 control system requirements and discusses the avail- ability of alternative SO 2 control systems. Information regarding flue gas desulfurization (FGD) systems operating at other domestic power plants and potentially usable at Colstrip are sumarized. Well over 50 FGD processes have been invented; many have undergone testing in laboratory or pilot plant operations. Relatively few have been operated on full-scale utility boilers. A tremendous volume of material has appeared in the literature regarding FGD systems. This is a reflection of the large number of FGD processes tested and the controversy between industry and the environmental comunity. Only a cursory review of alternative FGD systems could be performed within the scope of this study. 5.1 Coistrip SO 2 Control System Constraints In addition to the SO 2 emission limitation required to meet the Class I PSD increment, other important site specific parameters must be incorporated into the design of the Colstrip SO 2 control system. Due to the scarcity of water in the Colstrip area and water pollution effluent limitations, a closed loop water balance 5-2 ------- with minimum water consumption is called for. The coal character-. istics of low-sulfur content and high fly-ash alkalinity also in- fluence the scrubber system design. The utilization of the fly-ash alkalinity for SO 2 absorption, rather than a chemical brought from offsite is desirable. The availability of solid waste disposal sites and difficulties in obtaining a marketable byproduct from low sulfur coal flue gases limit consideration to only nonregener- able FGD processes. Since a readily disposable scrubber waste is desired a process yielding an easily dewatered and stable waste product is advantageous. 5.2 Operational FGD Systems The review of alternative SO 2 control methods was limited to FGD systems which have been installed and operated on domestic power plants. The sumary of FGD system operating experience provided in the Suninary Report - Flue Gas Desulfurization Systems - August - September 1977 indicates that there are currently 29 operating FGD systems in the United States. Of these 29 FGD systems, 12 are operated on plants burning coal with a sulfur content of 1.0 per- cent or less, similar to Coistrip. A sumary of these operational low-sulfur coal FGD systems is presented in Table 5-1. The 12 systems can be classified into four FGD processes as follows: Number Number of years of Capacity Exper- FGD Process Units MW lence Limestone scrubbing 5 1 ,910 81 Sodium carbonate scrubbing 3 375 96 Lime scrubbing 2 240 119 Alkaline fly-ash scrubbing 2 720 37 TOTAL 12 3,245 333 5-3 ------- Table 5-1. SUMMARY OF LOW SULFUR COAL OPERATIONAL FGD SYSTEMS AS OF SEPTEMBER 1977 AOL / Combustion Alkaline Fly-Ash AOL / Combustion Alkaline Fly-Ash AOL / Combustion Sodium Carbonate AOL / Combustion Sodium Carbonate AOL / Combustion Sodium Carbonate Equi pment Scrubbing Equipment Scrubbing Equipment Scrubbing Equipment Scrubbing Equipment Scrubbing 7/77 47 58 61 9 23 14 41 41 14 18 5 2 Si ze New Of Coal Char- Start- Utility Company Power Station Or Ret- rofit FGO Unit (MW) Process / Vendor acteristics (Percent Sulfur) Up (Month! Year) Exper- ience (Months) Research Cottrell Limestone Scrubbing Combustion Engineering Lime Scrubbing Combustion Engineering Lime Scrubbing Combustion Engineering Limestone Scrubbing Arizona Public Service Cholla No. 1 Kansas City Power And Light Hawthorn No. 3 Kansas City Power And Light Hawthorn No. 4 Kansas Power And Light Lawrence No. 4 Montana Power Company Coistrip No. 1 Montana Power Company Colstrip No. 2 Nevada Power Company Reid Gardner No. 1 Nevada Power Company Reid Gardner No. 2 Nevada Power Company Reid Gardner No. 3 Northern States Power Company Sherburne County Station No. 1 Northern States Power Company Sherburne County Station No. 2 South Carolina Public Service Winyah No. 2 R R R R N N R R N N N N 115 140 100 125 360 360 125 125 125 710 680 280 .44 - 1. - 3.5 * .5 - 3.5 * .5 .8 .8 .5 — 1. .5 - 1. .5 - 1. .8 .8 Associate Associate Associate Associate Associ ate 10/73 11/72 8/72 1/77 10/75 7/76 4/74 4/74 7/76 3/76 4/77 Combustion Engineering Limestone Scrubbing Combustion Engineering Limestone Scrubbing Babcock And Wilcox Limestone Scrubbing 1 Note: * Two grades of coal are burned; a low sulfur coal with typical sulfur content of .5% and a high sulfur coal with a typical sulfur content of 3.5%. The FGO system was converted to a tail-end wet lime scrubber system in early 1977. ------- The two alkaline fly-ash scrubbing systems are Coistrip Units #1 and #2 which were described in Section 2. The three other FGD proc- esses operated at plants burning low-sulfur coalare described in the following subsections. 5.2.1 Limestone Scrubbing Systems Five limestone scrubbing systems are operating on power plants burning low-sulfur coal. At the Cholla #1 unit (115 MW) operated by Arizona Public Service a Research Cottrell limestone scrubbing system has been operated since October 1973. The average coal characteristics are 0.52% sulfur, 10,150 BTU/lb heat content and 13.5% ash. Two parallel trains (Modules A and B), each designed to handle 50% of the boiler’s flue gas load, are designed to have a combined 502 removal efficiency of 58.5%. Either one or both of the scrubbers can be bypassed. The A-side consists of a variable throat flooded disk scrubber followed by a packed tower. The A-side SO 2 removal is reported to be about 90%. The B-side is similar in design except that the tower is not packed and limestone slurry is not circulated through it. The B-side has a low degree of SO 2 re- inoval (25%). The open loop water system uses 1.04 GPM/MW. The un- stabilized scrubber sludge is disposed of in unlined solar evapora- tion ponds. No pond water is recycled to the FGD system. Corrosion, erosion, scaling and plugging problems have been encountered with the scrubber system. Scrubber availability has been about 90%. No 502 removal efficiency or emission rate data were available to verify the design efficiency of 58.5%. A new limestone Combustion Engineering scrubbing system has replaced a previously operated limestone injection FGD System at the Kansas Power and Light Lawrence #4 unit. The new FGD system which corn- menced operations in January 1977 consists of a rod scrubber fol- lowed by a spray tower for SO 2 absorption. The rod scrubber, designed to remove particulates. is fed overflow from the spray 5-5 ------- tower recirculation tank and a significant portion of SO 2 is re- moved also. The plant can burn either natural gas or coal. Con- tinuous SO 2 monitors have recorded SO 2 removal efficiencies of better than 85%. Limited scrubber operating experience is avail- able as the plant has operated on coal only about 10 days to date. Combustion Engineering also designed the limestone scrubbing sys- tems operated on Northern States Power Company’s Sherburne County Stations #1 and #2. Colstrip coal is burned in both units. Simul- taneous particulate and SO 2 removal are achieved in the scrubber system. At each unit 12 scrubbing modules, 11 of which are required for full load capacity, are operated. The scrubbing system is comprised of a first stage fixed-rod venturi scrubber for partic- ulate removal and a marble bed absorber to complete particulate removal and achieve the necessary SO 2 removal. The design SO 2 control efficiency is based upon the removal of 50% of the sulfur in the fuel (maximum fuel sulfur content of 1.2%) or a 200 ppm SO 2 emission concentration, whichever outlet value is greater. The scrubbing systems at Sherburne County Stations #1 and #2 both operate with an open loop water system with a water consumption rate of 1.13 GPM/MW. Unstabilized sludge is disposed in lined ponds. Water from the ponds is recycled back to the process. Unit #1 (710 MW) has been in operation since March 1976 and Unit #2 (680 MW) began operation in April 1977. The availability of the scrubber systems have been about 90%. The South Carolina Public Service Winyah No. 2 plant (280 MW) recently began operation. A Babcock & Wilcox designed limestone scrubbing system is installed. Medium sulfur Virginia coal with a maximum 1.9% sulfur and a 11,200 BTU/lb heat content is burned. An ESP to remove 99% of the inlet fly-ash is installed ahead of the scrubber. The scrubber is designed to remove 69% of the SO 2 5-6 ------- from 50% of the flue gas. The remaining half of the boiler flue gas is bypassed around the FGD system and recombined with the scrubbed portion for reheat purposes. The FGD system consists of one scrubber-absorber train, including a venturi scrubber and a tray tower absorber. The overall SO 2 removal efficiency is 25% (935 ppm inlet and 294 ppm outl et). The water system is open- loop and the scrubbing wastes are discharged to an unlined pond. No availability or operating experience data are provided yet. 5.2.2 Sodium Carbonate Scrubbing Nevada Power operates the Reid Gardner Station consisting of three (125 MW) units burning coal with from 0.5 to 1.0% sulfur and a heat content of 12,450 BTU/lb. Units #1 and #2 were retrofitted with sodium carbonate scrubber systems. Unit #3 is a new installation also equipped with a sodium carbonate based FGD system. Combustion Equipment Associates in association with A. D. Little designed and installed the FGD systems. Each unit is equipped with a single FGD module consisting of a twin variable-throat venturi scrubber, followed by a single-stage wash tray. Bypassing of the module is possible. Primary particulate removal is accomplished by mechanical collectors (75% efficient) installed upstream of the scrubber. A comon facility for sodium carbonate ore (trona) storage and proc- essing serves all three FGD systems. A sulfur dioxide removal ef- ficiency of 85% is reported. There are two sources of liquid ef- fluent from the scrubbers; a slip stream discharged from the recirculation tank and the underflow from the clarifier. The FGD system operates on an open water loop with no liquid recycled to the modules from the ponds. A water consumption rate of 1.52 GPM/ MW is reported. Unstabilized sludge is disposed in solar evaporation ponds. Plugging problems in several areas of the scrubber systems have been encountered. Scrubber reliability has been about 80% 5-7 ------- for Units #1 and #2 and 60% for Unit #3. 5.2.3 Lime Scrubbing The only lime scrubbing FGD process operating on low sulfur coal flue gases is installed at the Kansas City Power and Light Hawthorn Units #3 and #4. Both units are designed to burn either (1) a low sulfur Wyoming coal typically containing 0.5% sulfur and having a heat content of 9,800 BTU/lb; or (2) a high sulfur Oklahoma coal with 35% (average) sulfur and 11,500 BTU/lb heat content. The original FGD system consisted of limestone injection and Combustion Engineering designed scrubbers. Dry limestone was injected directly into the furnace box and calcined to lime. The furnace calcined lime and boiler flue gas were then discharged to a tail-end wet scrubbing system consisting of two marble-bed absorbers where particulates and SO 2 were removed. The spent lime and other scrub- bing wastes were then discharged into a comon clarifier tank and the underfiow was pumped, untreated and unstabilized, to an unlined disposal pond. Boiler tube plugging problems attributed to the limestone injection forced changes in the mode of operation. The scrubbing system was modified in early 1977 and now operates as a tail-end wet lime scrubbing system. Two marble-bed scrubbers are installed on each boiler. The fresh water make-up requirement is approximately 7.0 GPM/MW to maintain the open loop water balance. The SO 2 removal efficiency is estimated at 50 to 60% for both modules although no tests have been run. 5-8 ------- 5.2.4 Summary of Performance A summary is presented in Table 5—2 of important design and perform- ance parameters for the FGD systems operated at power plants burning low—sulfur coal. Only Coistrip Units #1 nd #2 currently operate on a closed loop water balance. The scrubber availability and SO 2 re- moval efficiency of the Colstrip FGD system are comparable or better than the other low sulfur coal FGD systems. Comparing the Coistrip Units l and .#2 performance data with other FGD systems reported in the Sumary Report — Flue Gas Desulfurization Systems August—September, 1977 , it appears that lower SO 2 emissions, in terms of lb/l0 6 BTU or ppm, are achieved at Coistrip than with other scrubber systems. Sul- fur dioxide removal efficiencies of 90% or greater reported in the Summary Report and elsewhere in the. literature are for plants burning high. sulfur coal. The lb/10 6 BTU, ppm or TPD SO 2 emissions at these plants would exceed the emission level achieved at Coistrip. It must be pointed out that the FGD systems included in Table 5-2 were not designed solely for maximum 502 removal efficiency; but, as in the Coistrip design, site specific criteria or restraints were incorporated into the individual system designs. Water Avail- SO 2 Removal Water Usage abil- FGD System Efficiency Balance GPMJM ity Limestone Cholla #1 58.5% open 1 04 90% loop Lawrence #4 85% open loop Sherburne 50% open 1 13 90% #1 and #2 (or 200 ppm) loop 69% from 1/2 of flue open Winyah #2 gas (25% overall) loop Lime Hawthorn #3 & #4 50 to 60% open loop 5-9 ------- Table 5-2. FGD SYSTEM PERFORMANCE SUMMARY (Continued) Water Avail- .)u2 emova Water Usage abil- FGD System Efficiency Balance GPM/MW itY Sodium Carbonate Reid Gardner 85 open 60 to 111, 2, and 3 loop 1.52 80% Alkaline Fly-ash Colstrip 73.7% guarantee closed #1 and #2 (83.5% actual) loop 90% 5.3 FGD System Economics The costs of an SO 2 control system consist of the capital costs of purchasing and installing the system and the annual costs of owner- ship, operation and maintenance of the system. Capital costs can be further categorized as direct and indirect costs. Direct costs are defined as those for purchase of the items of equipment and the labor and material required to install and interconnect the equip- ment. Indirect costs are those not attributed to specific equipment items such as freight, interest, taxes, spare parts, engineering, overhead, shakedown, and contingencies. Annual costs are categorized as operation and maintenance costs and fixed costs. Operation and maintenance costs include those expenditures for raw materials, utilities, direct labor, maintenance, and supervision. Fixed costs include depreciation, taxes, insurance, and costs of borrowed capital. Scrubber system costs are generally reported in $/kW for capital costs and mills/kWh for operating costs. Before attempting to com- pare the costs from one plant or system to another one should de- termine what has been included or excluded from the figures and the base year for costs are reported. Appendix A of the Suninary Report 5-10 ------- Flue Gas Desulfurization Systems August-September 1977 contains cost data for 47 FGD systems. Capital costs range from less than $lO/kW to $189/kW. Operating costs range from about .25 mills/kWh to over 17 mills/kWh. Differences in the reported cost data caused by including or exclud- ing the costs of particulate removal, sludge disposal, lime or lime- stone preparation, indirect costs and other items make comparison FGD system economics difficult and inconclusive without further information. Insufficient data were available at this time to compare the costs of the alternative SO 2 control systems for Coistrip. 5-11 ------- 6.0 SUMMARY A review of the design, performance and operating experience at Coistrip Units #1 arid #2 and other FGD systems operating on domestic power plants burning low-sulfur coal was performed. According to the results of 13 emission tests at Coistrip Units #1 and #2 the scrubbers have consistently reduced SO emissions to less than 0.5 ib/lO BTU. The average SO 2 emission rate is 0.274 ib/lO BTU and the average SO 2 removal efficiency is 83.5%. A scrubber system availability of approximately 90% has been maintained. This scrub- ber performance, combined with other important system design features (such as a closed loop water balance and use of alkaline fly-ash rather than purchased lime or limestone for SO 2 absorption) make the planned scrubber system design optimum for the Colstrip site. The SO 2 emissions for Colstrip Units #3 and #4 were predicted as- suming various levels of SO 2 removal. The expected performance of the planned alkaline fly-ash scrubbing system for Units #3 and #4 was described. Available scrubber cost information and estimates for Coistrip were reported. Potential modifications to improve SO 2 removal capabilities were discussed. A sumary was presented of FGD systems operating on domestic power plants burning low sulfur coal. 6-1 ------- |