Reservoir Formation Damage Episode 3 Part 5 pdf

582 Reservoir Formation Damage 0 15 30km Figure 17-14. Areal distribution of Aux Vases formation waters resistivities (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Acid Treatment of Wells Demir (1995) simulated the treatment of the Morgan Coal no. 3 well in Energy Field, Williamson County, Illinois using mud-cleaning acids (MCA). Table 17-5 presents the reservoir mineralogy data from a nearby well, the Morgan Coal no. 2 well, used by Demir (1995) for the Morgan Coal no. 3 well. Figure 17-16 by Demir (1995) describes the hypothetical zones around the well considered for simulation of the MCA treatment of the near wellbore formation. Considered for simulation were 7.5 and 15% HCL-MCA solutions containing 0.1 molal KCL (clay stabilizer) and Model Assisted Analysis and Interpretation of Laboratory Field Tests 583 -0.7 r 2 = 0.992 -O.B-] \" -0.9- f 01- -1.3 • Aux Vases o Cypress 4.6 4.7 4.8 4.9 5.0 logTDS(mg/L) 5.1 5.2 Figure 17-15. Relationship between Aux Vases and Cypress formation water resistivities and IDS. The r 2 is the square of the correlation coefficient (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Table 17-4 Saturation Indexes (SI) a of Minerals that have the Potential for Formation Damage in Five Aux Vases and Five Cypress Formation Water Samples* Saturation indexes Sample Formation Field Calcite Gypsum Celestite Barite Fe-su!fide b EOR-B17 EOR-B36 EOR-B52 EOR-B73 EOR-B101 EOR-B9 EOR-B35 EOR-B70 EOR-B93 EOR-B99 Cypress Bartelso Mattoon Clay City New Harmony Dale Cons. Aux Vases King Mattoon Carmi North Clay City Eldorado 0.4 0.3 0.8 -0.7 -0.5 0.3 0.5 -1.0 0.1 0.1 -3.3 -0.5 -0.3 -1.8 -0.3 -0.4 -2.0 -0.7 -0.2 -0.7 -2.8 -0.5 -0.4 -1.5 -0.3 -0.3 -1.6 -0.5 -0.3 -0.3 0.8 0.2 0.0 1.3 0.0 0.3 0.4 0.3 0.5 0.1 2.1, 2.1, 2.5, 2.0, 2.5, 1.5, 2.2, 2.0, 2.1, 2.5, 2.2, 2.2, 2.6, 2.1, 2.7, 1.6, 2.3, 2.1, 2.2, 2.6, 11.0 11.5 11.1 11.4 12.1 10.6 10.7 11.5 11.3 11.7 a Sl>0, supersaturated; Sl=0, equilibrium; Sl<0, undersaturated. b The first, second, and third numbers belong to pyrothite, troilite, and pyrite, respectively. * See Table 17-1 for detailed information on the samples and text for computation of reservoir temperature and pressure. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. 584 Reservoir Formation Damage Table 17-5 Mineralogical Composition and Porosity of the Producing Sandstone Interval in the Morgan Coal No. 2 Well, Energy Field Minerals (wt. %, except the last row) Porosity Depth (ft) Illite Illite/smectite Chlorite Quartz K-feldspar Plagioclase Calcite Other (%) -387.6 1.6 -388.4 1.2 -390.1 1.4 -392.7 0.8 -394.7 1.0 -395.2 1 .6 Average (wt.%) 1 .3 Average (vol.%)1.3 0.9 1.1 0.7 0.3 0.5 0.9 0.7 0.8 2.4 1.9 2.5 1.7 3.0 4.1 2.6 2.3 81 57 85 73 76 63 73 71 0.0 0.2 0.6 0.2 0.4 0.0 0.2 0.3 8.2 8.2 2.6 7.8 6.3 2.5 5.9 6.0 6.0 31.0 6.7 17.0 13.0 27.0 16.8 16.1 4.7 5.7 0.6 0.4 0.0 tr 1.9 1.8 21.3 21.7 23.6 23.3 20.6 13.6 - 22.0 a a 22.1 was rounded to 22 in geochemical modeling computations. tr = trace. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. MCA injection 1 — ,, well bore zone 1 5 parts MCA 1 part brine ' / ' " • ' * . r . 9 ' '•'.".••• .' zone 2 • .' flush ' . pore ' . volume - 1 0x with ' . MCA • i . ' • • • 1 • " * * * "^•J • r t ese rvo i -,'' •' '^'\ '• zone 3 '.» ; 90% MCA ; .' 10% brine . / mixture . *, . • t * '•'•'.•''.'. — t '''••!*' . r ".*.'. • • . ' . .'' zone 4 \ • 10% MCA , '-90% brine 1 mixture • / * • ' • i i ii* ' . « .* ' • ' ' 1 Figure 17-16. Hypothetical zones (not to scale) around an Energy Field well in which reactions were simulated (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Model Assisted Analysis and Interpretation of Laboratory Field Tests 585 the formation brine with the analysis given for sample EOR-B6 in Table 17-1. The reservoir temperature was taken as 36°C. The simulated changes of the mineral contents in various zones after 2 days of exposure to the treatment fluids are presented in Tables 17-6 and 17-7 by Demir (1995), respectively, for 15 and 7.5% HCL-MCA treatments. Table 17-8 by Demir (1995) shows the predicted pH, and the CO 2 gas and dissolved iron species produced by 7.5 and 15% HCL-MCA treatments. Figures 17-17 and 17-18 by Demir (1995) show the predicted changes in mineral compositions and the fugacity of the produced CO 2 gas, which dissolves in aqueous phase readily at elevated reservoir fluid pressure conditions, for 15% HCL-MCA treatment. The results of the simulations by Demir (1995) indicate an increase in porosity with either 15% or 7.5% HCL-MCA treatment. Demir (1995) concludes, however, that the probability of asphaltene precipitation is higher with 15% HCL-MCA treatment because of the higher acidity and dissolved iron concentrations in this case compared to 7.5% HCL- MCA treatment. Water/loading Demir (1995) simulated the consequences of waterflooding operations in the Dale consolidated field. Demir (1995) considered the injection and the Aux Vases formation brines with the analyses of samples EOR-B101 and EOR-B107, respectively, given in Table 17-1. The Aux Vases reservoir formation mineralogical composition and porosity were approximated by data obtained from a McCreery no. 1 well core, given in Table 17-9 by Demir (1995). The Aux Vases formation brine pH had to be adjusted to 5.85 to achieve convergence in the simulation, although the actual field measured value was 5.34. The reservoir temperature taken was 37°C. Demir (1995) simulated two different scenarios: (1) replacement of pore water by flushing, and (2) mixing of pore and injection waters. In the first case, a ten pore volume of injection water was injected to completely flush out the pore water and react with the formation minerals until thermodynamic equilibrium. As can be seen by the simulated results given in Table 17-10 by Demir (1995), the porosity is unaffected and remains constant at 20%, for all practical purposes, when compared with the values given in Table 17-9 by Demir (1995), in spite of the variation of the individual mineral constitutients of the formation, as shown in Figure 17-19 by Demir (1995). In the second case, Demir (1995) simulates the consequences of mixing the injection and pore waters at a ratio of 1:1 and the resultant reactions (text continued on page 590 586 Reservoir Formation Damage Table 17-6 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume Before and After Treatment of a Production Well in Energy Field with 15% HCI-MCA Original volume (cm 3 ) Mineral Measured Predicted Zone 2 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Kaolinite 0 49 Mordenite-K 0 0 Pyrite 0 tr Siderite 0 0 Net change in total mineral volume % Change in total pore volume" Final porosity (%) c Zone 3 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Kaolinite 0 49 Mordenite-K 0 0 Pyrite 0 tr Siderite 0 0 Net change in total mineral volume % Change in total pore volume" Final porosity (%) c Zone 4 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Kaolinite 0 49 Pyrite 0 tr Siderite 0 0 Strontianite 0 0.3 Net change in total mineral volume % Change in total pore volume" Final porosity (%)° Final volume (cm 3 ) Predicted Net change* 4703 393 147 0 0 0 0 161 115 0.1 83 4703 393 239 0 0 0 0 161 115 0.2 84 4703 393 1053 102 92 (muscovite)" 90 0 39 0.2 2 0.3 0 0 -913 -154 -112 -26 -17 +161 +115 +0.1 +83 -863 +47.1 32.4 0 0 -821 -154 -112 -26 -17 +161 +115 +0.2 ^tM -770 +42 31.2 0 0 -7 -52 -20 +64 -17 +39 +0.2 +2 +0.3 +9.5 -0.5 21.9 3 Difference between original measured values and values after reaction path ended. b (net change in total mineral volume/original total pore volume) x 100. 0 (1 + (% change in total pore volume/100)) x (original porosity). d Model assumes muscovite is a proxy for illite. tr = trace. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. Model Assisted Analysis and Interpretation of Laboratory Field Tests 587 Table 17-7 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume Before and After Treatment of a Production Well in Energy Field with 7.5% HCI-MCA Mineral Measured Predicted Zone 2 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Kaolinite 0 49 Mordenite-K 0 0 Siderite 0 0 Net change in total mineral volume % Change in total pore volume 6 Final porosity (%) c Zone 3 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Kaolinite 0 0 Mordenite-K 0 0 Pyrite 0 tr Siderite 0 0 Net change in total mineral volume % Change in total pore volume 6 Final porosity (%) c Zone 4 Quartz 4703 4703 Albite 393 393 Calcite 1060 1057 Chlorite 154 123 Illite 112 68 Smectite 26 67 K-feldspar 17 17 Pyrite 0 tr Kaolinite 0 0 Strontianite 0 0.3 Net change in total mineral volume % Change in total pore volume 6 Final porosity (%) c Predicted Net change 8 4703 393 699 0 0 29 0 165 86 80 4703 393 735 0 0 29 0 161 115 0.2 90 4703 393 1056 109 90 (muscovite) 87 0 0.2 37 0.3 0 0 -361 -154 -112 +3 -17 +165 +86 +80 -310 +16.9 25.7 0 0 -325 -154 -112 +3 -17 +161 +115 +0.2 +90 -239 +13 24.9 0 0 -4 -45 d -22 +61 -17 +0.2 +37 +0.3 +10.5 -0.6 21.9 a Difference between original measured values and values after reaction path ended. 6 (net change in total mineral volume/original total pore volume) x 100. c (1 + (% change in total pore volume/100)) x (original porosity). d Model assumes muscovite is a proxy for illite. tr = trace. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. 588 Reservoir Formation Damage Table 17-8 Predicted pH, CO 2 Gas, and Dissolved Iron Species Generated when a Production Well in Energy Field was Treated with MCA Treatment Parameter 15% HCI-MCA CO 2 gas fugacity PH Fe ++ (molal) FeCI 2 (molal) FeCI + (molal) Total Fe (molal) 7.5% HCI-MCA CO 2 gas fugacity pH Fe+ + (molal) FeCI 2 (molal) Fecr (molal) Total Fe (molal) After Demir, 1995; 3- 2- Minerals (log moles) M ± 0 i I i i -3- -4- -5- 0 Zone 2 10 1 ' 9 4.21 0.0072 0.0114 0.0161 0.0340 1Q 1.5 4.50 0.0047 0.0015 0.0049 0.0110 Concentration Zone 3 1Q 1.8 4.29 0.0066 0.0100 0.0144 0.0310 10 13 4.65 0.0041 0.0015 0.0046 0.0100 Zone 4 6.51 0.0012 0.0010 0.0020 0.0042 6.59 0.0008 0.0006 0.0012 0.0026 r eprinted by permission of the Illinois State Geological Survey. Quartz — CalcitB Albite low ts$>^ Kaolinite-^, ••"M 't l\(\ /~^^-^=\ • • WW9!9"tte-K ' ft Minnesotaite ^^N^, / L Daphnite-14a V* / 'Saponite-Na \§ / /^ ^^\ r ••••••• — ^e.__^ 5 10 15 20 H* — _ _ ^x 25 30 reacted (moles) — . Mordenrte-K ~v \ \ \ \ P"< 35 40 45 - — -^ 50 Figure 17-17. Predicted changes in mineralogical compositions along the reaction path when 1 part of pore water is flushed with 10 parts of 15% HCI- MCA in an Energy Field well (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Model Assisted Analysis and Interpretation of Laboratory Field Tests 589 20 25 30 H* reacted (moles) Figure 17-18. Predicted change in CO 2 fugacity along the reaction path when 1 part of pore water is flushed with 10 parts of 15% HCI-MCA in an Energy Field well (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Table 17-9 Mineralogical Composition and Porosity of the Producing Sandstone Interval in McCreery No. 1 Well, Dale Consolidated Field Minerals (wt. %, except the last row) Porosity Depth (ft) Illite Illite/smectite Chlorite Quartz K-feldspar Plagioclase Calcite (%) -3190.5 -3191.5 -3192.7 -3194.0 -3195.7 -3197.9 -3199.4 -3201.0 -3203.0 -3205.8 -3207.1 -3208.4 -3209.9 3.2 2.8 2.5 3.4 2.6 3.1 2.1 3.1 2.1 2.4 3.1 1.7 5.2 Average (wt.%) 2.9 Average (vol.%)2.9 1.4 1.5 1.1 2.5 1.5 1.7 1.5 2.3 2.1 2.1 4.2 1.9 4.7 2.2 2.1 0.7 0.7 0.6 0.9 0.7 0.8 0.6 0.9 0.4 0.5 0.7 0.5 1.9 0.8 0.8 84.5 81.6 84.9 79.5 88 80.7 82.5 82.3 77.8 83.7 67.8 82.9 68.4 80.4 80.8 1.3 1.7 1.5 1.2 1.9 2.6 2.7 2.6 1.5 1.2 0.8 1.7 1.2 1.5 1.6 2.5 3.2 3.7 4.3 3.2 2.6 3.7 3.3 1.9 2.4 1.5 2.8 1.8 2.7 2.7 6.4 8.6 5.6 8.1 2.0 8.5 6.8 5.5 14.2 7.6 21.8 8.4 16.8 9.3 9.1 20.4 23.4 25.6 23.6 19.8 24.8 24.3 21.4 18.6 21.4 14.5 13.1 11.5 20.0 a a 20.2 was rounded to 20 in geochemical modeling computations. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. 590 Reservoir Formation Damage Table 17-10 Mineral Volume Corresponding to Each kg (917 cm 3 ) of Pore Water (at a 50% water saturation), or 1834 cm 3 Total Pore Volume, Before and After Flushing the Pore Volume Ten Times with Injection Water in Dale Consolidated Field Original mineral volume (cm 3 ) P, Predicted vc Minerals Measured by model re Quartz 5853 Albite 193 Calcite 657 Chlorite 58 Illite 290 Smectite 77 K-feldspar 116 Kaolinite 0 Pyrite 0 Strontianite 0 Witherite 0 Net change in total mineral volume % Change in total pore volume 0 Final porosity (%) d 5894 193 657 22 (daphnite) 176 (muscovite) b 71 (nontronite + saponite) 116 131 tr 0.1 tr redicted mineral Hume (cm 3 ) after action path Net change 8 5937 167 656 0 331 (muscovite) b 111 (nontronite + saponite) 0 38 1 1 tr +84 -26 -1 -58 +41 +34 -116 + 38 +1 +1 nd -2 +0.1 20.0 a Difference between original measured values and values after reaction path ended. b Model assumes muscovite is a proxy for illite. c (net change in total mineral volume/original total pore volume) x 100. d (1 + (% change in total pore volume/100)) x (original porosity). tr = trace, nd = not detectable. After Demir, 1995; reprinted by permission of the Illinois State Geological Survey. (text continued from page 585) until thermodynamic equilibrium. The results presented by Demir (1995) in Table 17-11 indicate a negligible change of porosity from 20 to 20.2%. In both the 10 times pore volume flush and 1:1 mixture cases, the pH was predicted to remain approximately neutral (Figure 17-20 by Demir, 1995). Therefore, Demir (1995) concludes that asphaltene precipitation, which occurs in acidic media, is not likely during waterflooding, and clay swelling should not occur because the TDS and chemical compositions of the injection and formation brines are similar. Model Assisted Analysis and Interpretation of Laboratory Field Tests 591 H 2 O reacted (kg) Figure 17-19. Predicted changes in mineral concentrations along the reaction path when 1 part pore water is flushed with 10 parts injection water in the Aux Vases reservoir, Dale Consolidated Field (after Demir, 1995; reprinted by permission of the Illinois State Geological Survey). Carbon Dioxide Flooding Demir (1995) simulated the consequences of carbon dioxide flooding in Tamaroa field. Demir (1995) compared the results of two scenarios: (1) reaction of 1 mole of carbon dioxide, and (2) reaction of 5 mole of carbon dioxide with the formation minerals and/or brine until thermo- dynamic equilibrium. The formation brine was assumed the same as sample EOR-B22 given in Table 17-1 and the average formation mineral composition and porosity were assumed as those given in Table 17-12 by Demir (1995). The reservoir temperature was taken as 32°C. In the first case, the reaction of 1 mole of carbon dioxide within a formation containing 1 kg of brine was simulated. As can be seen from the results presented in Table 17-13 and Figure 17-21 by Demir (1995), the porosity remain approximately constant, in spite of the changes of the individual mineral constitutes. Demir (1995) concludes that pH is above the original pH value of 6.5 (Figure 17-22) making the asphaltene precipitation unlikely and the relatively high TDS should prevent clay swelling. In the second case, Demir (1995) simulates the reaction of 5 mole of carbon dioxide. The results presented in Table 17-14 and Figure 17-23 [...]... -1 155 .5 tr -1160 .5 0 .3 -11 63. 5 0 .5 -11 65. 5 tr Average (wt.%) 0.2 Average (vol.%)0 .3 tr 0.2 0.8 tr 0 .3 0 .3 0.6 3. 5 3. 7 0 .5 2.9 2.9 0.2 1.6 3. 1 0 .3 1 .3 1.1 Quartz 98 90 77 97 90 .5 90 Plagioclase 0 .5 4.1 9.8 1.8 4.1 4.2 a In geochemical modeling computations 19 .3 was rounded to 19 tr = trace After Demir, 19 95; reprinted by permission of the Illinois State Geological Survey Calcite 0.4 0.1 4.6 0.2 1 .3 1 .3. .. model 90 45 4 23 132 1 03 291 22 9 Gibbsite 0 Dawsonite 0 Siderite 0 Pyrite 0 Strontianite 0 Witherite 0 Net change in total mineral volume % Change in total pore volumed Final porosity (%)e P,redicted mineral vc>lume (cm3) after re(action path 90 45 90 45 4 23 132 4 23 133 47 (daphnite) 2 73 4 (daphnite) 30 3 13( muscovite)c 67 (nontronite 13( muscovite)c 64 (saponite) + saponite) 33 0 0 tr 0.1 tr 23 5 26 0.2... Smectite6 90 45 90 45 90 45 4 23 132 1 03 291 22 9 4 23 132 4 23 121 0 2 93 0 0 0 Gibbsite Clinoptilolite 0 Dawsonite 0 Siderite 0 0 Magnesite 0 Mordenite Pyrite 0 0 Strontianite 0 Witherite Net change in total mineral volume % Change in total pore volumed Final porosity (%)e a 47 (daphnite) 2 73 13( muscovite)c 67 (nontronite + saponite) 33 0 0 0 0 0 tr 0.1 tr Net change3 0 0 -11 -1 03 +2 -22 -9 0 76 61 28 30 20 0.2... Geological Survey) 59 8 Reservoir Formation Damage Table 17- 15 Mineral Volume Corresponding to Each kg (9 43 cm3) of Pore Water (at a 40% water saturation), or a Total Pore Volume of 2 35 8 cm3, Before and After the Reaction of 0 .5 mol NaOH Solution with the Cypress Reservoir in Tamaroa Field Original mineral volume (cm3) Minerals Measured Quartz Albite Calcite Chlorite6 90 45 4 23 132 1 03 Kaolinite llliteb... volume % Change in total pore volumed Final porosity (%)e a 90 45 4 23 132 47 (daphnite) 2 73 13 (muscovite)c 67 (nontronite + saponite) 0 0 0 33 tr 0.1 tr PIredicted mineral 3 vc>lume (cm ) after re'action path 90 45 4 23 104 93 (daphnite + ripidolite) Net change3 0 0 -28 -10 0 0 0 -291 -22 -9 53 261 14 82 0 0.1 tr + 53 +261 +14 +82 +0.1 nd +50 .1 -2.1 18.6 Difference between original measured values and.. .59 2 Reservoir Formation Damage Table 17-11 Mineral Volume Corresponding to Each kg (917 cm3) of Pore Water (at a 50 % water saturation), or 1 834 cm3 Total Pore Volume, Before and After Mixing Injection and Formation Waters at a 1:1 Ratio in Dale Consolidated Field Original mineral volume (cm3) Minerals Measured Quartz Albite Calcite Chlorite Illite Smectite Predicted by model 58 53 1 93 657 58 290... Geological Survey Calcite 0.4 0.1 4.6 0.2 1 .3 1 .3 21 .5 20.7 15. 8 19 .3 19.0a 59 4 Reservoir Formation Damage Table 17- 13 Mineral Volume Corresponding to Each kg (9 43 cm3) of Pore Water (at a 40% water saturation), or a Total Pore Volume of 2 35 8 cm3, Before and After the Reaction of 1 mol CO2 Gas with the Cypress Reservoir in Tamaroa Field Original mineral volume (cm3) Minerals Measured Quartz Albite Calcite Chlorite"... volume (cm3) after re;action path Minerals Measured Quartz Albite Calcite Chlorite6 Kaolinite llliteb Smectiteb 90 45 90 45 90 45 4 23 132 1 03 291 2 9 4 23 132 4 23 134 Dawsonite 0 Analcime 0 Gibbsite 0 0 Rhodochrosite Pyrite 0 Strontianite 0 Witherite 0 Net change in total mineral volume % Change in total pore volumed Final porosity (%)e 47 (daphnite) 2 73 13( muscovite)c 67 (nontronite + saponite) 0 0 33 0 tr... (cm3) ProrlirteH mineral Minerals Measured Quartz Albite Calcite Chlorite 15 90 45 4 23 132 1 03 Kaolinite llliteb Smectite" Predicted by model 291 22 9 Analcime 0 Prehnite 0 Phlogopite 0 Gibbsite 0 Pyrite 0 Strontianite 0 Witherite 0 Net change in total mineral volume % Change in total pore volumed Final porosity (%)e 90 45 4 23 132 47 (daphnite) 2 73 13 (muscovite)0 67 (nontronite + saponite) 0 0 0 33 tr... After Demir, 19 95; reprinted by permission of the Illinois State Geological Survey 600 Reservoir Formation Damage Table 17-17 Mineral Volume Corresponding to Each kg (9 43 cm3) of Pore Water (at a 40% water saturation), or a Total Pore Volume of 2 35 8 cm3, Before and After the Reaction of 0. 25 mol Na2CO3 Solution with the Cypress Reservoir in Tamaroa Field Original mineral volume (cm3) Predicted by . change 8 47 03 3 93 699 0 0 29 0 1 65 86 80 47 03 3 93 7 35 0 0 29 0 161 1 15 0.2 90 47 03 3 93 1 056 109 90 (muscovite) 87 0 0.2 37 0 .3 0 0 -36 1 - 154 -112 +3 -17 +1 65 +86 +80 -31 0 +16.9 25. 7 0 0 -32 5 - 154 -112 +3 -17 +161 +1 15 +0.2 +90 - 239 + 13 24.9 0 0 -4 - 45 d . Plagioclase Calcite (%) -31 90 .5 -31 91 .5 -31 92.7 -31 94.0 -31 95. 7 -31 97.9 -31 99.4 -32 01.0 -32 03. 0 -32 05. 8 -32 07.1 -32 08.4 -32 09.9 3. 2 2.8 2 .5 3. 4 2.6 3. 1 2.1 3. 1 2.1 2.4 3. 1 1.7 5. 2 Average (wt.%) . Calcite -1 155 .5 tr -1160 .5 0 .3 -11 63. 5 0 .5 -11 65. 5 tr Average (wt.%) 0.2 Average (vol.%)0 .3 tr 0.2 0.8 tr 0 .3 0 .3 0.6 3. 5 3. 7 0 .5 2.9 2.9 0.2 1.6 3. 1 0 .3 1 .3 1.1 98 90 77 97 90 .5 90 0 .5 4.1 9.8 1.8 4.1 4.2 0.4 0.1 4.6 0.2 1 .3 1 .3 21 .5 20.7 15. 8 19 .3 19.0 a 59 4