CC BY
14
Известия Уральского государственного горного университета. 2018. Вып. 4(52). С. 18-25 УДК 622.276.65 https://doi.org/10.21440/2307-2091-2018-4-18-25
Control of movement of heat front during oil reservoir with thermal treatment
Bagir Ali BAGIROV1*, Agharza Mesud HAJIYEV2**
1SOCAR, OilGas Scientific Research Project Institute, Baku, Republic of Azerbaijan 2Azerbaijan State Oil & Industrial University, Baku, Republic of Azerbaijan
Relevance. For efficiency of oil field development, Enhanced Oil Recovery (EOR) methods are used. These methods can be classified into physical-chemical, thermal, microbiological, nuclear, etc. Among these treatments, the thermal method has a special place. It is related to the fact, that these methods are applied to the formations with scavenger (tight) oil, where ultimate oil recovery factor otherwise cannot exceed 0.2-0.3. Thermal methods are aimed to reduce the viscosity of the oil, thus increasing its mobility in the reservoir. The method is based on pumping the driving substance (steam or hot water) into the reservoir, and also on burning the oil in the reservoir (in-situ combustion).
Purposes and objectives of the study. The efficiency of the thermal treatment largely depends on geological and physical conditions of the oil reservoir - its depth, physical and chemical characteristics of the fluids, reservoir type, oil, gas and water saturation.
The substance to be heated in the reservoir is oil. However, part of thermal energy heats water and the rock as well. Therefore, it is very important to study the reservoir before the start of thermal treatment. Geologically heterogeneous layers especially require detailed study.
The thermal methods have been tested on the reservoirs, occurring at different depth. However, the efficiency of thermal treatment decreases with depth. The reason for that is the loss of the heat on its way in the borehole, from one hand, and higher temperature of the formation itself, on the other. That is why, the application of the thermal methods on the deeper horizons are limited.
Results and recommendation. Apparently, the successful application of thermal treatment of the reservoirs requires the systematic monitoring of the development process, which allows to correct the treatment process in a timely manner. Getting the information about formation current physical characteristics, making temperature measurements are challenging and expensive processes. The processing of the information also takes time. All of this can have negative effect on ultimate recovery factor. Usually, construction of isotherm maps is recommended for thermal treatment monitoring. However, these maps not always indicate the direction of the movement of the injected heat. Thus, the effective method of controlling and monitoring of the thermal treatment is very relevant task of the reservoir geology.
Keywords: reservoir, oil recovery, thermal treatment, temperature, exposure to steam, in-situ combustion, water mineralization.
Introduction
For efficiency of oil field development, Enhanced Oil Recovery (EOR) methods are used. These methods can be classified into physical-chemical, thermal, microbiological, nuclear, etc. [1-3]. Among these treatments, the thermal method has a special place. It is related to the fact, that these methods are applied to the formations with scavenger (tight) oil, where ultimate oil recovery factor otherwise cannot exceed 0.2-0.3 [4]. Thermal methods are aimed to reduce the viscosity of the oil, thus increasing its mobility in the reservoir. The method is based on pumping the driving substance (steam or hot water) into the reservoir, and also on burning the oil in the reservoir (in-situ combustion).
The efficiency of the thermal treatment largely depends on geological and physical conditions of the oil reservoir - its depth, physical and chemical characteristics of the fluids, reservoir type, oil, gas and water saturation.
The substance to be heated in the reservoir is oil. However, part of thermal energy heats water and the rock as well. Therefore, it is very important to study the reservoir before the start of thermal treatment. Geologically heterogeneous layers especially require detailed study.
The thermal methods have been tested on the reservoirs, occurring at different depth. However, the efficiency of thermal treatment decreases with depth. The reason for that is the loss of the heat on its way in the borehole, from one hand, and higher temperature of the formation itself, on the other. That is why, the application of the thermal methods on the deeper horizons are limited.
Apparently, the successful application of thermal treatment of the reservoirs requires the systematic monitoring of the development process, which allows correcting the treatment process in a timely manner. Getting the information about formation current physical characteristics, making temperature measurements are challenging and expensive processes. The processing of information also takes time. All this can have negative effect on ultimate recovery factor. Usually, construction of isotherm maps is recommended for thermal treatment monitoring. However, these maps not always indicate the direction of the movement of the injected heat. Thus, the effective method of controlling and monitoring of the thermal treatment is very relevant task of the reservoir geology.
Suggested method
The method is based on the fact, that injected heat transfer agent will increase the temperature and mobility of fluids, but will also change the ion and salt composition of the formation water. The heat transfer agent can be steam, hot water, as well as the products of combustion of oil in the reservoir [5-7]. One has to pay attention to the fact that the water flow in the reservoir is faster than the spreading of the heat in the rock matrix or in the saturated fluids. Therefore, the change in water chemistry is meaningful indicator, which allows finding areas and zones of the field affected by thermal treatment. The behavior of chemical components of the solution depends on the method of treatment. Injected steam will decrease the salinity, or mineralization, since injected substance is basically distilled water. In-situ combustion decreases the viscosity of oil, but also increases the temperature
" И [email protected] "[email protected]
Figure 1. Thermal treatment zones in Balakhany-Sabunchi-Ramany field. Рисунок 1. Зоны тепловой обработки пласта в месторождении Балаханы-Сабунчи-Раманы.
of formation water, which increases its reactivity and solubility of components of the rock matrix. Therefore, water produced with the oil will have higher mineralization and, as a rule, the content of Na + K and Cl ions will increase.
As for hot water injection (which has not been applied in the Azerbaijan oil fields), it is reasonable to suppose that the water chemistry will change according to the chemical composition of the dissolved salts in the injected water [8].
Case studies
Below are the specific examples of realization of the suggested method.
Exposure to steam. This method was successfully used in the oil reservoir horizons II KSu of Balakhani-Sabunchi-Ramany field (Khorasan Zone). The target is represented by frequent and uniform alternation of thin (35-45 m thick) interbeds of argillaceous and sandy rocks. Average porosity is 25% and average permeability is 0.215 mkm2 (215 mDa). The area covered by thermal treatment is not complicated by faults and has 18-25° dip angles.
In place conditions the density of oil is 0.920-0.935 gcc (19.8-22.3 API), while the viscosity is 75-110 mPa x s. Although the horizon has been developed since 1924, at the beginning of treatment the current oil recovery coefficient was only 0.19. Average daily well rate were between 0.6-3.2 t (4-22 bbl) oil and 0.1-8.0 m3 water. WCO was 55-65%, while formation pressure of the site fluctuated from 0.07 to 1.25 MPa. To enhance filtration properties of oil in porous environment of the studied zone steam injection was first implemented in well No. 1396 (1969), and then in well No. 1128 (1970). The temperature of working agent (steam) at the wellhead was 200-220 °C at 3.0 MPa injection pressure (Fig. 1).
It must be noted that the steam injection operations create three specific phase zones - steam drive zone, hot condensate zone and unswept zone [9]. Each of indicated zones affects each other. By compensating each other these zones indicate the nature and direction of heat front.
The work describes the study results of impact of temperature on physical and chemical features of the oil and reservoir water in test wells (No. 2220, 2281, 2547, 2238, 2227). It was established that the test wells exhibit regular decrease in viscosity and density of produced oil with rising temperature. However, the wells where no changes in the temperature of formation were observed (2236), there was some improvement in oil mobility. This suggested that the thermal flow affected wider area. At that, the studies indicated the considerable changes in reservoir water even in the wells where formation temperature did not change. The salinity of this water reduced from 2.5-3.1 to 0.5-2.8 °Be as a result of mixture with steam condensate (Table 1).
Comparison of physical-chemical characteristics of formation water has shown that its properties change as a result of advanced penetration of steam condensate (which is actually distilled water) via more permeable sub-layers. Such situation was observed even in wells (No. 1397, 1934), where other geological-engineering characteristics remained stable (Fig. 2).
In the course of controlled steam treatment, it was found that monitoring of hydrochemical conditions within formations in dynamics allows identifying directions of the heat flow in formations, and this can be used for control of used treatment method [4, 10].
In-situ combustion. This method is based on the capability of hydrocarbons to release heat as a result of oxidizing reactions. Heat generation directly within formation is main advantage and characteristic feature of this method. In-situ combustion works efficiently in clastic reservoirs. Disadvantage of this method is that more than 25% of oil in the reservoir is burned as a fuel, whilst final oil recovery can be increased to 20% when using this method [8, 11-15].
Table 1. Physical-chemical characteristics of formation water of horizon II KSu Balakhany-Sabunchi-Ramany field. Таблица 1. Таблица 1. Физико-химические показатели пластовой воды на залежах горизонта II КС в месторождении Балаханы-Сабунчи-Раманы.
Before the treatment
After the treatment
Well
Equivalent values, equiv.
Equivalent values, equiv.
De Cl HCO3 Ca + Mg Na + K S a+k De Cl HCO3 Ca + Mg Na + K S a+k
2220 2.9 0.0311 0.0085 0.0014 0.0802 0.1212 0.5 0.019 0.0021 0.0013 0.0032 0.0261
2281 2.9 0.0324 0.009 0.0017 0.0838 0.1269 2.8 0.0313 0.0091 0.002 0.0389 0.0818
1431 3.1 0.0335 0.009 0.0015 0.0862 0.1302 0.7 0.021 0.0034 0.0009 0.0057 0.0315
1397 3.0 0.0322 0.0093 0.0016 0.084 0.1271 2.6 0.0283 0.0091 0.0013 0.0156 0.0758
1432 2.8 0.025 0.0112 0.0012 0.0733 0.1107 2.7 0.0256 0.0109 0.0014 0.0356 0.054
2547 2.5 0.0239 0.0081 0.0019 0.065 0.0989 1.7 0.0156 0.0077 0.0011 0.0229 0.0478
2238 2.7 0.0256 0.0104 0.001 0.073 0.11 2.5 0.0244 0.0101 0.001 0.0339 0.0699
1934 3.1 0.0341 0.009 0.0015 0.0873 0.1319 2.8 0.0291 0.0098 0.0014 0.0383 0.0791
2729 2.7 0.0246 0.0108 0.0011 0.0718 0.1083 2.7 0.0261 0.01 0.0014 0.0153 0.0533
2248 2.9 0.0282 0.01 0.0013 0.0776 0.1171 2.8 0.0277 0.0106 0.0013 0.0175 0.0576
2236 2.5 0.0232 0.009 0.0015 0.0655 0.0992 1.7 0.0124 0.0069 0.0011 0.0188 0.0397
Figure 2. Map of heat distribution as a result of steam treatment in Khorasany area of Balakhany-Sabunchi-Ramany field.
Рисунок 2. Карта распределения тепла в результате паровоздействия в месторождении Балаханы-Сабунчи-Раманы (площадь
Хорасаны).
Let us note that as a result of process of combustion in the reservoir, ion-salt composition of formation water from the treated wells has changed. We registered this effect in wells of the Balakhany-Sabunchi-Ramany and Pirallakhi fields.
1. Horizon PKu of the Balakhany-Sabunchi-Ramany field (Khorasany area). Here PK suite, unlike other areas of the field is characterized by low oil recovery factors (< 0.30), which is mainly related to high viscosity of oil (> 50 mPa • s). Accordingly, in 1973, people began to apply thermal treatment methods, in-situ combustion, in particular.
Summary of geological-engineering characteristics of target is the following.
Development of PKu began in 1919. Numerous wells have been drilled during the whole period of development, however, most wells were soon returned to the overlying formations due to low rates. The process of in-situ combustion was applied in wells No. 3326, 3323, 12z, 3396, 2632. More than 40 producers undergone treatment (Fig. 3).
Treatment continued up to 1995; during the whole period more than 600 thousand m3 of water and over 200 million m3 of compressed air have been injected into reservoir. As a result, about 230 thousand tons (1.5 mm bbl) of incremental oil was produced owing to its improved mobility at the expense of reduction of viscosity. Treatment was carried out under systematic monitoring and control. It should be noted that while temperature changes in the wells happened in different level, in most of them (particularly in wells 3375, 3z and 3518), physical-chemical characteristics of formation water changed significantly (Table 2, Fig. 4).
Period of thermal stimulation is shown in grey color.
It can be seen from the presented data that in the process of in-situ combustion in horizon PKu at the Khorasany area, hydro-chemical parameters of formation experience various changes. In all cases increase of values of Na + K m Cl ions is clearly seen, which allowed identifying zones of heat flow effect across the area.
Figure 3. Map of heat distribution as a result of in-situ combustion in Khorasany area of Balakhany-Sabunchi-Ramany field. Рисунок 3. Карта распределения тепла в результате внутрипластового горения в месторождении Балаханы-Сабунчи-Раманы (площадь Хорасаны).
Table 2. Physical-chemical characteristics of formation water of horizon PKu at Balakhany-Sabunchi-Ramany field.
Таблица 2. Физико-химические показатели пластовой воды на залежах горизонта PKu в месторождении Балаханы-Сабунчи-
Раманы.
Well No. 3375 Equivalent values
Measurement date Cl SO4 HCO3 Ca Mg Na + K ^a + k
Before the treatment
24.06.1971 0.0252 0.0001 0.0074 0.0002 0.0017 0.0305 0.0651
28.07.1971 0.0235 0.0002 0.0067 0.0006 0.0012 0.0284 0.0606
22.12.1971 0.0235 0.0001 0.0066 0.0005 0.0016 0.0281 0.0604
19.03.1972 0.0275 0.0001 0.0072 0.0006 0.0013 0.0328 0.0695
17.06.1972 0.032 0.0003 0.0054 0.0006 0.0017 0.0354 0.0754
03.09.1972 0.028 0.0002 0.0068 0.0001 0.0022 0.0327 0.07
18.01.1973 0.0255 0.0004 0.0069 0.0006 0.0016 0.0306 0.0656
After the treatment
09.04.1973 0.1004 0.0086 0.0059 0.0154 - 0.0995 0.2298
26.06.1973 0.087 - 0.0062 0.0012 0.0039 0.0881 0.1864
07.09.1973 0.029 - 0.0069 0.0002 0.0019 0.0338 0.0718
09.02.1974 0.0265 0.0001 0.0019 0.0004 0.0014 0.0314 0.0617
19.05.1974 0.0245 - 0.0068 0.0004 0.0017 0.0292 0.0626
09.08.1974 0.026 0.0006 0.0063 0.0001 0.0023 0.0315 0.0668
14.12.1974 0.0275 0.0001 0.0075 0.0002 0.0021 0.0327 0.0701
Figure 4. Change of physical-chemical characteristics of formation water in time (well No. 3375). Рисунок 4. Изменение физико-химических показателей пластовой воды с течением времени (скважина 3375).
Table 3. Physical-chemical characteristics of formation water of horizon ^u at Pirallakhi field.
Таблица 3. Физико-химические показатели пластовой воды горизонта КС в месторождении Пираллахи.
Well No. 633 Equivalent values
Measurement date Cl SO4 HCO3 Ca Mg Na + K
Before the treatment
24.01.1978 0.1550 - 0.0017 0.0071 0.0050 0.1446
21.02.1979 0.1430 0.0009 0.0012 0.0107 0.0076 0.1268
30.10.1979 0.1100 0.0013 0.0019 0.0067 0.0063 0.1002
11.01.1980 0.1515 0.0007 0.0010 0.0108 0.0066 0.1358
20.03.1980 0.1725 0.0009 0.0008 0.0132 0.0071 0.1539
23.10.1980 0.1290 0.0023 0.0008 0.0094 0.0073 0.1154
After the treatment
17.02.1981 0.2000 0.0001 0.0007 0.0112 0.0020 0.1876
25.02.1981 0.2120 0.0001 0.0004 0.0150 0.0077 0.1898
27.03.1981 0.2085 0.0001 0.0004 0.0139 0.0104 0.1847
11.05.1981 0.1360 0.0004 0.0017 0.0084 0.0061 0.1236
20.05.1981 0.1610 0.0014 0.0012 0.0162 0.0046 0.1428
07.08.1981 0.1405 0.0015 0.0012 0.0134 0.0028 0.1270
18.12.1981 0.0165 0.0053 0.0004 0.0016 0.0052 0.0154
26.01.1982 0.0720 0.0012 0.0032 0.0010 0.0053 0.0664
15.03.1983 0.0745 0.0010 0.0038 0.0032 0.0046 0.0745
31.05.1983 0.1025 - 0.0042 0.0032 0.0036 0.0999
26.03.1984 0.0965 - 0.0039 0.0014 0.0029 0.0921
19.06.1984 0.0800 - 0.0041 0.0018 0.0052 0.0771
08.07.1984 0.0845 0.0004 0.0029 0.0052 0.003 0.0796
23.10.1984 0.0865 - 0.0036 0.0031 0.0039 0.0831
15.11.1984 0.0870 - 0.0043 0.0037 0.0048 0.0828
12.12.1984 0.0610 0.0010 0.0039 0.0034 0.0035 0.0590
Figure 5. Map of heat distribution as a result of in-situ combustion in horizon KSu of Pirallakhi field.
Рисунок 5. Карта распределения тепла в результате внутрипластового горения в залежах горизонта KSu месторождения Пираллахи.
0,018
0,0! 6
0,25
0,15
0,002
SO, НСО, Са Mg
а
Na+K
0,05
Figure 6. Change of physical-chemical characteristics of formation water in time (well No. 633).
Рисунок 6. Изменение физико-химических показателей пластовой воды с течением времени (скважина 633).
2. Horizon II KSu of the Pirallakhi field. Horizon KSu of the Pirallakhi field is in development over 70 years. This horizon is quite heterogeneous and compartmentalized, which lead to different level of recovery in different blocks. Accumulation of significant remaining recoverable reserves of highly viscous oil in come blocks required design and application of in-situ combustion method. This method was applied in a number of wells: well 208 - 1974; wells 800 and 801 - 1976; well 172 - 1981; well 843 - 1982 (Fig. 5).
During the period of formation treatment, alongside with other geological-engineering measures hydrochemical studies were carried out. It should be noted that vast volume of data had been accumulated for this target, and increased content of Na + K and Cl ions in formation water was registered. Results of analyses for a number of wells are presented in Table 3, Fig. 6. Period of thermal stimulation is shown in grey color.
As follows from Fig. 3, 4, 6, affected zones established just by data of thermal studies cover only part of areas, which is related to natural physical tendency of heat to move to elevated parts of the structure. Chemical-structural changes in mineralization of water encompass much greater area, giving better indication of coverage with thermal treatment.
Thermal treatment in a form of hot water injection was not used in the Azerbaijan fields. Nevertheless, one can assume that on injection of hot water mineralization of formation water will change depending on the ion-salt composition of injected water. Conclusions
1. For the improvement of mobility of highly-viscous oils in reservoirs temperature within the development targets has to be increased.
2. In the process of thermal treatment, in any modification, specific variations in chemical composition of formation water are observed.
3. This effect is in favor of inclusion of water sampling and hydrochemical analysis data into monitoring process of formations thermal treatment.
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The article was received on March 30, 2018
УДК 622.276.65 https://doi.org/10.21440/2307-2091-2018-4-18-25
Контроль за продвижением теплового потока в процессе нефтяных месторождений с применением термической
Багир Али оглы БАГИРОВ1- *, Агарза Месуд оглы ГАДЖИЕВ2- **
Азербайджанский государственный университет нефти и промышленности, Баку, Азербайджан 2НИПИ «Нефтегаз», SOCAR, Баку, Азербайджан
Актуальность. Для увеличения нефтеотдачи пластов в процессе разработки залежей применяются тепловые методы (закачка в пласт пара и горячей воды, внутрипластовое горение). Эффективное применение этих методов требует надежного контроля проводимых процессов. С этой целью обычно проводятся соответствующие замеры в скважинах, результаты которых отражаются на картах изотерм. Сопоставление таких карт, составленных для различных периодов разработки залежей, позволяет получать информацию о направлении и скорости продвижения теплоносителя по пласту. В итоге выдвигается концепция о регулировании (если это необходимо) проводимых процессов.
Цель и задачи исследования. Проводимые нами геолого-промысловые исследования по месторождениям Азербайджана показывают, что для более надежного контроля за тепловоздействием целесообразно использовать данные о гидрохимии пласта. Так, при внедрении теплоносителя не только повышается температура пласта и тем самым снижается вязкость и плотность пластовых нефтей, но и изменяются физико-химические характеристики пластовых вод. Следует отметить и то, что в процессе термовоздействия наряду с пластовыми флюидами подвергается изменениям и порода этого пласта. В итоге тепло, продвигающееся от возбуждающей скважины к скважинам реагирующим, представляет собой весьма сложную термодинамическую систему. К тому же процесс изменения гидрохимии пласта всегда опережает подобные процессы в нефтях и породах залежи. Именно этим обстоятельством обосновывается необходимость включения в комплекс исследований по контролю за тепловоздействием информации о гидрохимии пласта.
Вывод. Опираясь на материалы разработки ряда месторождений Азербайджана, авторы выявили механизм изменчивости теплового режима залежей. В частности, было установлено, что при закачке в пласт пара, представляющего собой, по существу, дистиллированную воду, соленость вод залежей уменьшается; при внутрипластовом горении за счет резкого повышения температуры пласта повышается и химическая активность вод. Это, как правило, приводит к изменению химизма вод (содержание Na + K и C1 повышается). Концепция, выдвинутая в данной статье, подтверждается геолого-промысловой информацией и иллюстрируется соответствующими картами и таблицами.
Ключевые слова: резервуар, нефтеотдача, термическое воздействие, температура, паровоздействие, внутрипластовое горение, минерализация воды.
разработки обработки
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Статья поступила в редакцию 30 марта 2018 г.
Известия Уральского государственного горного университета. 2018. Вып. 4(52). С. 26-32 УДК 549.514.81+550.93(470.5) https://doi.org/10.21440/2307-2091-2018-4-26-32
The chemical composition and dating of accessory zircon from granitic pegmatites in the north-eastern part of the Aduisky massif
Vera Vital'evna KHILLER*, Yuriy Viktorovich EROKHIN**
Institute of geology and geochemistry of the Ural branch of the Russian Academy of Sciences Ekaterinburg, Russia
This work is made relevant by the necessity to improve chemical dating methods, when applied to high atomic and thorium zircons, for which isotopic methods cannot be used.
The purpose of the work is to study the chemical composition of the accessory zircon (cyrtolite) from granitic pegmatites in the north-eastern part of the Aduisky massif (in the Middle Urals) and determine how best to date it.
Methodology. The study comprised quantitative analysis of the chemical composition of the zircon by using a CAMECA SX 100 X-ray electron probe micro-analyser (with an electron beam diameter from 1 pm, BSE, SE, Cat, and determination of elements from beryllium to uranium). To measure the intensity of elements, we have selected the following analytical lines: Y La, Si Ka, Zr La, Hf Ma (analysing crystal TAP), U MP, Pb Ma, Ca Ka, Th Ma (analysing crystal PET), Yb La, Er La, Lu La (analysing crystal LiF). Calculation of the age of the zircon was carried out aca/cording to well-known, existing methods in addition to those developed by the authors. Results. According to the microprobe analysis, the impurity content of ThO2, UO2 and PbO in the zircon varied significantly, within the ranges 0.13 to 2.69, 1.59 to 15.42 and 0.05 to 0.57 wt.%, respectively. The dating calculation was carried out for each mineral (in which the analysis took place). Their age was found to be between 280 and 219 Ma. At the same time, the weighted mean was 254 ± 6 Ma (with the Mean Square of Weighted Deviates being 0.17) and the isochron showed 255 ± 7 Ma. The values of the ages found for the zircon from the pegmatites "Mys-2" agree with the isotopic data. The period of formation of the Aduisky granite massif has been estimated to be between 291 ± 8.0 Ma and 256 ± 0.6 Ma (according to zircon and monazite dating, respectively) or within the range 255 to 241 Ma (according to mica dating).
Conclusion. We have studied the accessory zircon (cyrtolite) from granite pegmatites from the "Mys-2" vein, in the north-eastern part of the Aduisky massif. We have obtained the chemical composition and calculated the age to be 255 ± 7 Ma. Dating calculations show that veined pegmatites and host granites were formed almost simultaneously (at least, in this part of the Aduisky massif). This situation justifies microprobe dating of the U-Th zircon content because the minerals are usually in a metamict state and not suitable for accurate age determination.
Keywords: zircon, chemical dating, granite pegmatites, Aduisky granite massif, Middle Ural.
Introduction
Chemical dating of minerals is widely carried out [1, 2] and is based on the precise determination of the contents of radioactive elements (Th, U) and (not) radiogenic (total) Pb by X-ray microprobe analysis. Through the use of modern microprobe analysers and the thorough development of analytical procedures, it has become possible to quickly solve problems in the direct geochronological dating of accessory minerals in thin sections of rock. The X-ray microprobe analysis method can be used for chemical dating when the content of Th, U, Pb in these minerals is above 0.03 wt.% therefore, most of the work is devoted to monazites, although some relates to dating of uraninite and other radioactive minerals [2, 3]. There are only a few studies concerning the application of this method to zircon [2, 4, 5]. Due to the low contents of thorium, uranium and lead (Pb is often n x 0.001 wt.%), zircon dating is performed using local isotope mass spectrometry with laser (LA-ICP-MS) or ion (SIMS) sampling. In practice, zircons with abnormally high concentrations of Th, U, Pb are found, particularly in alkaline and granitic pegmatites. In this case, isotope dating using a device with an ion probe is not applicable for technical reasonsand it is assumed that a high adulteration of radioactive and radiogenic elements makes the result of dating unreliable ([6] and others). It is not always possible to use mass spectrometry with laser sampling (which gives the average value) due to the large diameter and depth of the crater (n x 10 |m). In our work, the microprobe analysis method was used for chemical dating of the zircon with abnormally high concentrations of U, Th, Pb, Hf, Y (i.e. we have determined the age of the cyrtolite). Geology of the study area
In recent years, a number of new pegmatite veins have been discovered in the Aduisky granite massif [7]. A large number of them are located 6 to 7 km north of the village of Ozerny, south of Rezh. Pegmatites are located in the hills on the right bank of the river Rezh, which is situated on the north-eastern edge of the massif (1.5 km) [8]. There is a forest corridor at this location, associated with the power lines that cross the area. This site is rich in ceramic pegmatite veins, the largest of which were mined by tributors for feldspar for the ceramic industry at the beginning of the last century (1925-1927). Lump feldspar was mined from the upper, fractured parts of the veins to a depth of 2 to 3 m and in workings between 4 and 30 m long. The feldspar was transported by carts to the river and then further on to the station at Rezh. In total, about 1000 tons of feldspar were mined [9].
©https://orcid.org/0000-0001-8491-4958 "" ED [email protected] ©https://orcid.org/0000-0002-0577-5898
Asbest
Figure 1. The lineaments of the Aduisky granite massif with marked settlements and water bodies (according to [11] with our simplifications). The filled square shows the location of the granite pegmatite "Mys-2".
Рисунок 1. Контуры Адуйского гранитного массива с вынесенными населенными пунктами и водоемами (дано по [11] с нашими упрощениями). Залитым квадратом показано расположение гранитного пегматита «Мыс-2».
One of the veins (known as "Mys-2" and located at GPS-fixing: 57°20'36,9'' N, 61°12'38,3'' E) was opened with a small digging pit of 10.0 x 1.0 x 1.5 m (Fig. 1). The pegmatite body lies in the fine-grained, slightly sheared, biotite granites and its strike is about 20°. The vein has a visual zonality because it contains graphic pegmatite with muscovite in its casing and a quartz core at its centre. The vein contains the following accessory minerals: garnet, apatite, brockite, columbite, zircon, ilmenite, magnetite, polycrase, titanite, allanite and epidote [8, 10].
For the dating studies, relatively large but short, prismatic zircon (cyrtolite) crystals (up to 2.5 mm long) were selected from the block zone of the "Mys-2" vein. The mineral is characterised by a zoned colouration: light brown in the centre and dark green around the periphery of the crystals (Fig. 2, a). The green colour seems to be associated with the smallest inclusions of uraninite and thorite, which are found all over the zircon matrix. While preparing the specimens during the first grinding, the top part of the crystal was revealed (Fig. 2, b); the second grinding then opened up the deeper parts of the crystal. In addition, both polished surfaces were studied with respect to chemical dating to provide statistical data.
Study Methods
Quantitative analysis of the chemical composition of the zircon was carried out using a CAMECA SX 100 X-ray electron probe micro-analyser (electron beam diameter being from 1 ^m, BSE, SE, Cat, determination of elements from beryllium to uranium). The optical field of view was 0.25 to 1.75 mm from the sample surface. The BSE image of the crystal shows weak, spotted heterogeneity due to different heavy element contents. Small inclusions of uranium and thorium phases (not more than 5 to 10 microns in size) are fixed in the zircon matrix. To measure the intensity of elements, we selected the following analytical lines: Y La, Si Ka, Zr La, Hf Ma (analysing crystal TAP), U Mp, Pb Ma, Ca Ka, Th Ma (analysing crystal PET), and Yb La, Er La, Lu La (analysing crystal LiF). The calculation of the chemical age was carried out according to well-known methods [1, 2] in addition to those developed by the authors [3, 4].
Results and discussion
According to the quantitative microprobe analysis, the impurity content of ThO2, UO2, PbO in the zircon significantly varies within the ranges 0.13 to 2.69, 1.59 to 15.42 and 0.05 to 0.57 wt.% respectively (see Table). For each point of the crystal in which analysis was carried out, the age was calculated by the Montel method [1]; the range was found to be from 219 to 280 Ma. The weighted average is 254 ± 6 Ma and the Mean Square of Weighted Deviates = 0.17 (Fig. 3).
