CN118010690A - Tracing method for secondary natural gas - Google Patents
Tracing method for secondary natural gas Download PDFInfo
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- CN118010690A CN118010690A CN202410100184.2A CN202410100184A CN118010690A CN 118010690 A CN118010690 A CN 118010690A CN 202410100184 A CN202410100184 A CN 202410100184A CN 118010690 A CN118010690 A CN 118010690A
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- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical group C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 222
- 239000003345 natural gas Substances 0.000 title claims abstract description 114
- 238000000034 method Methods 0.000 title claims abstract description 62
- 239000007789 gas Substances 0.000 claims abstract description 339
- QSHDDOUJBYECFT-UHFFFAOYSA-N mercury Chemical compound [Hg] QSHDDOUJBYECFT-UHFFFAOYSA-N 0.000 claims abstract description 80
- 229910052753 mercury Inorganic materials 0.000 claims abstract description 80
- OTMSDBZUPAUEDD-UHFFFAOYSA-N Ethane Chemical compound CC OTMSDBZUPAUEDD-UHFFFAOYSA-N 0.000 claims abstract description 22
- 238000002407 reforming Methods 0.000 claims abstract description 12
- 238000012986 modification Methods 0.000 claims description 23
- 230000004048 modification Effects 0.000 claims description 23
- 238000012360 testing method Methods 0.000 claims description 17
- 238000010521 absorption reaction Methods 0.000 claims description 15
- 239000011435 rock Substances 0.000 claims description 14
- 229910052602 gypsum Inorganic materials 0.000 claims description 11
- 239000010440 gypsum Substances 0.000 claims description 11
- VEXZGXHMUGYJMC-UHFFFAOYSA-N Hydrochloric acid Chemical compound Cl VEXZGXHMUGYJMC-UHFFFAOYSA-N 0.000 claims description 10
- 238000001914 filtration Methods 0.000 claims description 10
- 239000007788 liquid Substances 0.000 claims description 10
- SQGYOTSLMSWVJD-UHFFFAOYSA-N silver(1+) nitrate Chemical compound [Ag+].[O-]N(=O)=O SQGYOTSLMSWVJD-UHFFFAOYSA-N 0.000 claims description 10
- 239000004215 Carbon black (E152) Substances 0.000 claims description 9
- 239000003085 diluting agent Substances 0.000 claims description 9
- 229930195733 hydrocarbon Natural products 0.000 claims description 9
- 150000002430 hydrocarbons Chemical class 0.000 claims description 9
- 239000012286 potassium permanganate Substances 0.000 claims description 9
- 238000006722 reduction reaction Methods 0.000 claims description 9
- 150000001335 aliphatic alkanes Chemical class 0.000 claims description 7
- NINIDFKCEFEMDL-UHFFFAOYSA-N Sulfur Chemical compound [S] NINIDFKCEFEMDL-UHFFFAOYSA-N 0.000 claims description 6
- 229910052717 sulfur Inorganic materials 0.000 claims description 6
- 239000011593 sulfur Substances 0.000 claims description 6
- NLXLAEXVIDQMFP-UHFFFAOYSA-N Ammonia chloride Chemical compound [NH4+].[Cl-] NLXLAEXVIDQMFP-UHFFFAOYSA-N 0.000 claims description 5
- 238000007865 diluting Methods 0.000 claims description 5
- 125000001741 organic sulfur group Chemical group 0.000 claims description 5
- 229910052709 silver Inorganic materials 0.000 claims description 5
- 229910001961 silver nitrate Inorganic materials 0.000 claims description 5
- HPGGPRDJHPYFRM-UHFFFAOYSA-J tin(iv) chloride Chemical compound Cl[Sn](Cl)(Cl)Cl HPGGPRDJHPYFRM-UHFFFAOYSA-J 0.000 claims description 5
- DJWUNCQRNNEAKC-UHFFFAOYSA-L zinc acetate Chemical class [Zn+2].CC([O-])=O.CC([O-])=O DJWUNCQRNNEAKC-UHFFFAOYSA-L 0.000 claims description 5
- 229910021627 Tin(IV) chloride Inorganic materials 0.000 claims description 4
- 238000009616 inductively coupled plasma Methods 0.000 claims description 3
- 238000001819 mass spectrum Methods 0.000 claims description 3
- 230000015572 biosynthetic process Effects 0.000 claims 1
- 238000011160 research Methods 0.000 abstract description 2
- 239000000203 mixture Substances 0.000 description 10
- 241000283690 Bos taurus Species 0.000 description 8
- 230000009466 transformation Effects 0.000 description 8
- 229910000037 hydrogen sulfide Inorganic materials 0.000 description 7
- 238000010586 diagram Methods 0.000 description 6
- OKTJSMMVPCPJKN-UHFFFAOYSA-N Carbon Chemical compound [C] OKTJSMMVPCPJKN-UHFFFAOYSA-N 0.000 description 4
- 229910052799 carbon Inorganic materials 0.000 description 4
- QAOWNCQODCNURD-UHFFFAOYSA-L Sulfate Chemical compound [O-]S([O-])(=O)=O QAOWNCQODCNURD-UHFFFAOYSA-L 0.000 description 3
- 238000005266 casting Methods 0.000 description 3
- 230000008569 process Effects 0.000 description 3
- 238000011084 recovery Methods 0.000 description 3
- 230000009467 reduction Effects 0.000 description 3
- RWSOTUBLDIXVET-UHFFFAOYSA-N Dihydrogen sulfide Chemical compound S RWSOTUBLDIXVET-UHFFFAOYSA-N 0.000 description 2
- 229910000831 Steel Inorganic materials 0.000 description 2
- 239000004809 Teflon Substances 0.000 description 2
- 229920006362 Teflon® Polymers 0.000 description 2
- 239000003245 coal Substances 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 238000001095 inductively coupled plasma mass spectrometry Methods 0.000 description 2
- -1 polytetrafluoroethylene Polymers 0.000 description 2
- 229920001343 polytetrafluoroethylene Polymers 0.000 description 2
- 239000004810 polytetrafluoroethylene Substances 0.000 description 2
- 239000002244 precipitate Substances 0.000 description 2
- 238000000611 regression analysis Methods 0.000 description 2
- 239000013049 sediment Substances 0.000 description 2
- 239000002689 soil Substances 0.000 description 2
- 239000010959 steel Substances 0.000 description 2
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 2
- ZOIORXHNWRGPMV-UHFFFAOYSA-N acetic acid;zinc Chemical compound [Zn].CC(O)=O.CC(O)=O ZOIORXHNWRGPMV-UHFFFAOYSA-N 0.000 description 1
- 230000002378 acidificating effect Effects 0.000 description 1
- 238000005273 aeration Methods 0.000 description 1
- 238000004458 analytical method Methods 0.000 description 1
- 244000309464 bull Species 0.000 description 1
- 239000003034 coal gas Substances 0.000 description 1
- 238000012937 correction Methods 0.000 description 1
- 230000008021 deposition Effects 0.000 description 1
- 239000002274 desiccant Substances 0.000 description 1
- 238000005516 engineering process Methods 0.000 description 1
- 230000002349 favourable effect Effects 0.000 description 1
- 238000011835 investigation Methods 0.000 description 1
- 230000002045 lasting effect Effects 0.000 description 1
- 239000007791 liquid phase Substances 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 230000007246 mechanism Effects 0.000 description 1
- 238000002156 mixing Methods 0.000 description 1
- 239000005416 organic matter Substances 0.000 description 1
- 239000012071 phase Substances 0.000 description 1
- 238000005201 scrubbing Methods 0.000 description 1
- 239000007787 solid Substances 0.000 description 1
- 229910001220 stainless steel Inorganic materials 0.000 description 1
- 239000010935 stainless steel Substances 0.000 description 1
- 238000006467 substitution reaction Methods 0.000 description 1
- 230000000476 thermogenic effect Effects 0.000 description 1
- 239000004246 zinc acetate Substances 0.000 description 1
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N21/00—Investigating or analysing materials by the use of optical means, i.e. using sub-millimetre waves, infrared, visible or ultraviolet light
- G01N21/62—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light
- G01N21/63—Systems in which the material investigated is excited whereby it emits light or causes a change in wavelength of the incident light optically excited
- G01N21/64—Fluorescence; Phosphorescence
- G01N21/6402—Atomic fluorescence; Laser induced fluorescence
- G01N21/6404—Atomic fluorescence
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- G—PHYSICS
- G01—MEASURING; TESTING
- G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
- G01N27/00—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means
- G01N27/62—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating the ionisation of gases, e.g. aerosols; by investigating electric discharges, e.g. emission of cathode
- G01N27/622—Ion mobility spectrometry
- G01N27/623—Ion mobility spectrometry combined with mass spectrometry
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Abstract
The invention provides a tracing method of secondary natural gas, which comprises the following steps: determining whether the gas to be traced is TSR modified gas; if the gas to be traced is TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR reforming; if the gas to be traced is non-TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced; wherein the first parameter comprises ethane delta 13C2, mercury delta 199 Hg, mercury delta 201 Hg, and mercury delta 202 Hg values. The method can accurately determine the source of the natural gas and provide theoretical guidance for the exploration and research of the natural gas.
Description
Technical Field
The invention relates to the technical field of oil gas geochemistry, in particular to a tracing method of secondary natural gas.
Background
Hydrocarbon-bearing basins, such as Sichuan basin, erdos and Tarim basin, exist with multiple sets of hydrocarbon source rocks of different times humic and sapropel types. Whether the natural gas comes from humic type or humic type hydrocarbon source rock determines the exploration direction and well position deployment has great significance. At present, the mercury concentration in natural gas is commonly used for judging whether the natural gas is from humic type or humic type hydrocarbon source rock.
For methods that use mercury concentrations to identify natural gas sources, the former has found that there is coincidence in the mercury content profiles in the tall basin oil gas and the coal gas. And the inventors found that although the ta and cis-north otto natural gas had a mercury content of 41-1210 ng/m 3 (average 392ng/m 3, n=4), showing some natural gas (> 700ng/m 3) belonging to the coal type gas, the cis-north otto natural gas could not come from the dwarf coal at a distance of 2000m above and at the same time also did not match the composition characteristics of the cis-north otto carbon isotopes (delta 13C2 < -28 mill). Thus, the causative type of natural gas cannot be accurately distinguished only by the mercury concentration.
Further, the ethane delta 13C2 value, mercury concentration and Δ 199Hg(Δ199Hg(‰)＝δ199Hg－(0.2520×δ202 Hg) and Δ 201Hg(Δ201Hg(‰)＝δ201Hg－(0.7520×δ202 Hg) value methods were also utilized to determine whether the natural gas was from humic or humic type hydrocarbon source rock. However, the preconditions that these natural gases are thermogenic and are not subject to secondary reforming such as later-stage significant Thermochemical Sulfate Reduction (TSR), different gas mixing and gas scrubbing are necessary to be satisfied with this process. For a large number of natural gas reservoirs subjected to secondary reformation, there is no effective way to determine their origin.
Accordingly, there is a need to provide a method that can accurately determine the source of secondary natural gas.
Disclosure of Invention
The invention provides a tracing method of secondary natural gas, which can accurately determine the source of the natural gas and provide theoretical guidance for the exploration and research of the natural gas.
The invention provides a tracing method of secondary natural gas, which comprises the following steps:
determining whether the gas to be traced is TSR modified gas;
If the gas to be traced is TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR reforming;
If the gas to be traced is non-TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced;
Wherein the first parameter comprises ethane delta 13C2, mercury delta 199 Hg, mercury delta 201 Hg, and mercury delta 202 Hg values.
The tracing method as described above, wherein the determining whether the gas to be traced is the TSR modified gas includes:
determining whether the gas to be traced is TSR modified gas or not according to a second parameter of the gas to be traced, delta 34 S of H 2 S of the gas to be traced and delta 34 S of stratum gypsum;
Wherein the second parameter comprises H 2 S content C1, CO 2 content C2 and alkane total content C3.
According to the tracing method, according to the second parameter of the gas to be traced, determining whether the gas to be traced is the TSR modified gas according to delta 34 S of the gas to be traced H 2 S and delta 34 S of the stratum gypsum comprises:
If A is more than 0.03, and the absolute value of the difference between delta 34 S of H 2 S to be traced and delta 34 S of stratum gypsum is less than 5 per mill, the gas to be traced is TSR modified gas; or alternatively, the first and second heat exchangers may be,
If A is less than or equal to 0.03, and the absolute value of the difference between delta 34 S of H 2 S to be traced and delta 34 S of stratum gypsum is more than or equal to 5 per mill, the gas to be traced is non-TSR modified gas;
wherein a= (c1+c2)/(c1+c2+c3).
According to the tracing method, if the gas to be traced is the TSR modified gas, determining the source of the gas to be traced according to at least one first parameter before TSR modification includes:
Establishing at least one first linear fitting curve of the first parameter and A, and acquiring a first linear fitting equation y=ax+b according to the first linear fitting curve, wherein b is the first parameter before TSR modification;
Determining the source of the gas to be traced according to the b;
where x refers to a and y refers to a first parameter.
According to the tracing method, if the gas to be traced is the TSR modified gas, determining the source of the gas to be traced according to at least one first parameter before TSR modification further includes:
And obtaining at least one first correlation coefficient of the first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient is more than 0.3.
According to the tracing method, if the to-be-traced gas is the TSR modified gas, determining the source of the to-be-traced gas according to at least one first parameter of the to-be-traced gas before TSR modification further includes:
establishing a first linear fitting curve of at least one first parameter and A, and acquiring a first correlation coefficient of the at least one first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient is less than or equal to 0.3, and the first parameter of the gas to be traced is the first parameter before TSR modification;
And determining the source of the to-be-traced gas according to the first parameter of the to-be-traced gas.
According to the tracing method, if the gas to be traced is the TSR modified gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR modification comprises:
Establishing a second linear fitting curve of at least one first parameter and delta 34 S of the gas to be traced H 2 S, and acquiring a second linear fitting equation y ' =a ' x ' +b ', x ' =hydrocarbon source rock organic sulfur isotope according to the second linear fitting curve, wherein y ' is the first parameter of the gas to be traced before TSR reconstruction, and determining the source of the gas to be traced according to the y ';
Where x 'refers to delta 34 S of the source gas H 2 S to be traced, and y' refers to the first parameter.
According to the tracing method, if the gas to be traced is the TSR modified gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR modification further includes:
And obtaining a second correlation coefficient of delta 34 S of at least one first parameter and the gas H 2 S to be traced according to the second linear fitting curve, wherein the second correlation coefficient is more than 0.3.
According to the tracing method, if the gas to be traced is the TSR modified gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR modification further includes:
establishing a second linear fitting curve of at least one first parameter and delta 34 S of the gas to be traced H 2 S, and acquiring a second correlation coefficient of the at least one first parameter and delta 34 S of the gas to be traced H 2 S according to the second linear fitting curve, wherein the second correlation coefficient is more than 0.3, and the first parameter of the gas to be traced is the first parameter before TSR reconstruction;
And determining the source of the to-be-traced gas according to the first parameter of the to-be-traced gas.
The tracing method as described above, wherein δ 34 S of the to-be-traced gas H 2 S is obtained by testing a method comprising the following steps:
reacting the to-be-traced gas with saturated zinc acetate to obtain a first mixed system comprising ZnS;
standing the first mixed system overnight, and then filtering to obtain ZnS;
reacting ZnS with hydrochloric acid to obtain H 2 S;
Reacting H 2 S with silver nitrate to obtain a second mixed system comprising Ag 2 S;
Filtering the second mixed system to obtain Ag 2 S, testing the sulfur isotope of Ag 2 S, and obtaining delta 34 S of H 2 S to be traced; and/or the number of the groups of groups,
The mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced are obtained through testing by a method comprising the following steps:
Introducing the gas to be traced into an absorption bottle filled with potassium permanganate solution to obtain mercury-containing absorption liquid;
Carrying out a reduction reaction on the mercury-containing absorption liquid and ammonium hydrogen chloride to obtain a first solution to be tested;
Analyzing the mercury content of the first solution to be detected by using a cold steam atomic fluorescence spectrometer, so as to obtain the mercury content in the gas to be traced;
diluting the first solution to be tested to obtain a diluent with the mercury content of 1-5 ng/g;
reducing the diluent with stannic chloride to obtain a second solution to be detected;
And testing the mercury isotopes in the second solution to be tested by using a multi-receiver inductively coupled plasma mass spectrum to obtain the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced.
The invention provides a tracing method of secondary natural gas, which comprises the steps of firstly determining whether the gas to be traced is TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before TSR reforming for TSR reformed gas, and determining the source of the gas to be traced according to at least one first parameter of the gas to be traced for non-TSR reformed gas. The natural gas tracing method can accurately determine the source of the natural gas, particularly the method for determining the source of the gas in the natural gas reservoir subjected to secondary transformation is helpful for revealing the secondary transformation mechanism of the natural gas and obtaining the composition of the natural gas before secondary transformation, so that the source of the natural gas can be comprehensively analyzed according to the composition characteristics of the natural gas.
Drawings
In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the related art, the drawings that are required to be used in the description of the embodiments of the present invention or the related technologies are briefly described below. It is evident that the drawings in the following description are only some embodiments of the present invention and that other drawings may be obtained from these drawings without inventive effort for a person of ordinary skill in the art.
FIG. 1 is a graph of natural gas A versus delta 13C2 for a geodesic field of cattle;
FIG. 2 is a graph of natural gas A versus Δ 199 Hg for a geodesic field of cattle;
FIG. 3 is a graph of natural gas A versus delta 202 Hg for a geodesic field of cattle;
FIG. 4 is a graph of natural gas delta 34SH2S versus delta 13C2 for a geofence of cattle;
FIG. 5 is a graph of natural gas delta 13C2 versus delta 199 Hg for a geodesic field of cattle;
FIG. 6 is a graph of natural gas delta 13C2 versus delta 202 Hg for a geodesic field of cattle;
FIG. 7 is a schematic diagram of a mercury isotope composition plate of natural gas from different sources and for sediments, vegetation and soil in the literature for actual measurement of mercury isotope composition of natural gas according to the present invention;
FIG. 8 is a diagram of a mercury isotope combined with ethane isotope to identify natural gas causes;
fig. 9 is a schematic diagram of an apparatus for collecting mercury in a gas to be traced according to some embodiments of the invention.
Reference numerals illustrate:
1: a teflon tube;
2: a first container;
3: a second container;
4: a third container;
5: a flow meter;
6: a meter.
Detailed Description
The following description of the technical solutions in the embodiments of the present invention will be clear and complete, and it is obvious that the described embodiments are only some embodiments of the present invention, but not all embodiments. All other embodiments, which can be made by those skilled in the art based on the embodiments of the invention without making any inventive effort, are intended to be within the scope of the invention.
The invention provides a tracing method of secondary natural gas, which comprises the following steps:
determining whether the gas to be traced is TSR modified gas;
if the gas to be traced is TSR modified gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR modification;
if the gas to be traced is the non-TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced;
Wherein the first parameter comprises ethane delta 13C2, mercury delta 199 Hg, mercury delta 201 Hg, and mercury delta 202 Hg values.
In the invention, the gas to be traced can be natural gas which is commonly used in the field and needs tracing. TSR process gas refers to natural gas that has been subjected to thermochemical sulfate reduction, and non-TSR process gas refers to natural gas that has not been subjected to thermochemical sulfate reduction. Δ 199Hg＝δ199Hg－(0.2520×δ202Hg),Δ201Hg＝δ201Hg－(0.7520×δ202 Hg).
The tracing method of the secondary natural gas can be carried out by using at least one of the first parameters. Illustratively, the method for tracing the secondary natural gas comprises the following steps: determining whether the gas to be traced is TSR modified gas; if the gas to be traced is TSR modified gas, the ethane delta 13C2 before TSR modification is compared with the related ethane delta 13C2 disclosed by the former, if the ethane delta 13C2 before TSR modification is close to the sapropel type natural gas ethane delta 13C2 disclosed by the former (the absolute value of the difference value is less than 5 per mill), the gas to be traced is sapropel type natural gas, and if the ethane delta 13C2 before TSR modification is greatly different from the sapropel type natural gas ethane delta 13C2 disclosed by the former (the absolute value of the difference value is more than or equal to 5 per mill), the gas to be traced is sapropel type natural gas; if the gas to be traced is non-TSR reformed gas, ethane delta 13C2 of the gas to be traced is directly used to be compared with related ethane delta 13C2 disclosed by the former, so that whether the gas to be traced is humic type natural gas or humic type natural gas is indicated.
The inventors found in the study that when the first parameter is ethane delta 13C2, the natural gas is traced by using ethane delta 13C2, and the obtained result is more accurate.
The method for determining whether the gas to be traced is TSR modified gas is not limited, and can be carried out by adopting a method commonly used in the field. In some embodiments of the invention, determining whether the source gas to be traced is a TSR retrofit gas comprises:
According to the second parameter of the gas to be traced, determining whether the gas to be traced is TSR modified gas or not according to delta 34 S of H 2 S of the gas to be traced and delta 34 S of stratum gypsum;
Wherein the second parameter comprises H 2 S content C1, CO 2 content C2 and alkane total content C3.
In some embodiments, the total alkane content may be the total alkane content of carbon numbers 1-6.
Specifically, if A is more than 0.03, and the absolute value of the difference between delta 34 S of the to-be-traced gas H 2 S and delta 34 S of the stratum gypsum is less than 5 per mill, the to-be-traced gas is TSR modified gas; or alternatively, the first and second heat exchangers may be,
If A is less than or equal to 0.03, and the absolute value of the difference between delta 34 S of the gas to be traced H 2 S and delta 34 S of the stratum gypsum is more than or equal to 5 per mill, the gas to be traced is non-TSR modified gas;
wherein a= (c1+c2)/(c1+c2+c3).
It is understood that the greater a, the greater the extent to which the gas to be traced is modified by TSR. The method can more accurately determine whether the gas to be traced is TSR modified gas.
In some embodiments of the present invention, if the gas to be traced is a TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter prior to TSR reforming includes:
Establishing a first linear fitting curve of at least one first parameter and A, and acquiring a first linear fitting equation y=ax+b according to the first linear fitting curve, wherein b is the first parameter before TSR modification;
Determining the source of the gas to be traced according to the b;
where x refers to a and y refers to a first parameter.
Specifically, a first linear fitting curve of the first parameter and a may be obtained by marking at least three points in a coordinate system with a first parameter as an abscissa and at least one first parameter as an ordinate (for example, ethane δ 13C2), and then performing linear fitting, and a first linear fitting equation y=ax+b is obtained according to the first linear fitting curve, where b refers to the first parameter when a is 0, that is, the first parameter before TSR reconstruction, and the source of the gas to be traced is determined according to b.
According to the method, the first parameter before TSR is determined through regression analysis, and then the source of the gas to be traced is determined to be humic type natural gas or sapropel type natural gas according to the first parameter before TSR transformation, so that the source of the gas to be traced can be determined more accurately.
Further, if the gas to be traced is the TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before the TSR reformed gas further includes:
And obtaining a first correlation coefficient of at least one first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient R 2 is more than 0.3.
The method further comprises the steps of obtaining a first correlation coefficient of a first parameter and A according to a first linear fitting curve, wherein the first correlation coefficient R 2 is more than 0.3, and the first correlation coefficient is indicated that the first parameter is affected by TSR, so that the first parameter before the TSR is transformed is obtained, and whether the gas to be traced is humic type natural gas or humic type natural gas is determined by comparing the first parameter before the TSR is transformed with the existing first parameter identification standard of related heat-induced gas.
Further, if the gas to be traced is the TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before the TSR reformed gas further includes:
Establishing a first linear fitting curve of at least one first parameter and A, and acquiring a first correlation coefficient of the at least one first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient is less than 0.2, and the first parameter of the gas to be traced is the first parameter before TSR reconstruction;
and determining the source of the gas to be traced according to the first parameter of the gas to be traced.
Specifically, if the first correlation coefficient is less than or equal to 0.3, which indicates that the first parameter has no correlation with the A, the first parameter in the TSR modified gas is not subjected to TSR modification, the first parameter of the gas to be traced is the first parameter before TSR modification, and the first parameter of the gas to be traced is directly compared with the first parameter identification standard of the related heat source gas of the former person to determine the source of the gas to be traced. By the method, operation steps can be saved, and accuracy of a determination result can be further improved.
Illustratively, fig. 1 is a graph of natural gas a and δ 13C2 in a geofence, and as can be seen from fig. 1, a first correlation coefficient R 2 =0.696 of natural gas a and δ 13C2 in a geofence of large Niu Deqi, the first correlation coefficient being > 0.3, indicates that a has a good correlation with δ 13C2, indicating that δ 13C2 is significantly affected by TSR. If the influence of TSR is not considered, except 2 gas samples, all other gas samples delta 13C2 are more than-28 per mill (delta 13C2 > -28 per mill described in the former, belonging to humic type natural gas), which shows that most of the gas samples are from humic type natural gas; however, considering the influence of TSR, delta 13C2 before the recovery of TSR is less than-28.5 per mill, which shows that the natural gas is the sapropel type natural gas.
As can be seen from fig. 2, the relationship diagram between the natural gas a and Δ 199 Hg in the Niu Deqi field in fig. 2 shows that the first correlation coefficient R 2 =0.494 between the natural gas a and Δ 199 Hg in the Niu Deqi field, and the first correlation coefficient is greater than 0.3, which indicates that the natural gas a and Δ 199 Hg have a good correlation relationship, and that Δ 199 Hg is affected by TSR. If the influence of TSR is not considered, 1 gas sample delta 199 Hg is less than 0 per mill (delta 199 Hg is less than 0 per mill recorded by the former, and the gas sample belongs to humic natural gas), which indicates that most of the gas samples are from the humic natural gas; however, considering the effect of TSR, the Δ 199 Hg value before recovery of TSR was about +0.26 permillage, indicating that the natural gas is a sapropel type natural gas.
Similarly, fig. 3 is a graph of natural gas a and δ 202 Hg in a geofence, and as can be seen from fig. 3, a first correlation coefficient R 2 =0.71 (ignoring a suspicious point formed by test errors and the like) of a natural gas a and δ 202 Hg in a geofence of large Niu Deqi, the first correlation coefficient is > 0.3, which indicates that a and δ 202 Hg have a good correlation, and that δ 202 Hg is affected by TSR. Delta 202 Hg value before TSR recovery is less than 0.01, which shows that the natural gas is sapropel type natural gas.
In some embodiments of the present invention, if the gas to be traced is a TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter prior to TSR reforming includes:
Establishing a second linear fitting curve of delta 34 S of at least one first parameter and the gas H 2 S to be traced, acquiring a second linear fitting equation y '=a' x '+b', when x '=the organic sulfur isotope of the source rock according to the second linear fitting curve, wherein y' is the first parameter before TSR modification, and determining the source of the gas to be traced according to y 'when x' =the organic sulfur isotope of the source rock;
Where x 'refers to delta 34 S of the source gas H 2 S to be traced, and y' refers to the first parameter.
Specifically, δ 34 S of the gas to be traced H 2 S may be taken as an abscissa, at least one first parameter is taken as an ordinate (for example, ethane δ 13C2), at least three points are marked in a coordinate system, then linear fitting is performed to obtain a second linear fitting curve of the first parameter and δ 34 S of the gas to be traced H 2 S, a second linear fitting equation y '=a' x '+b' is obtained according to the second linear fitting curve, and when x 'is an organic sulfur isotope of the hydrocarbon source rock, the value of y' is obtained, and at this time y 'is the first parameter before TSR reconstruction, the source of the gas to be traced is determined according to y'.
According to the method, the first parameter before TSR is determined through regression analysis, and then the source of the gas to be traced is determined to be humic type natural gas or sapropel type natural gas according to the first parameter before TSR transformation, so that the source of the gas to be traced can be determined more accurately.
Further, if the gas to be traced is the TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before the TSR reformed gas further includes:
And obtaining a second correlation coefficient R 2 of delta 34 S of at least one first parameter and the gas H 2 S to be traced according to a second linear fitting curve, wherein the second correlation coefficient R 2 is more than 0.3.
The method further comprises the steps of obtaining a first correlation coefficient of a first parameter and delta 34 S of H 2 S to be traced according to a first linear fitting curve, wherein the first correlation coefficient is more than 0.3, and the first correlation coefficient indicates that the first parameter is influenced by TSR, so that the first parameter before the TSR is reformed is obtained, and comparing the first parameter before the TSR is reformed with the existing first parameter identification standard related to heat-induced gas to determine whether the gas to be traced is humic-type natural gas or humic-type natural gas.
Further, if the gas to be traced is the TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before the TSR reformed gas further includes:
Establishing a second linear fitting curve of at least one first parameter and delta 34 S of the gas to be traced H 2 S, and acquiring a second correlation coefficient of the at least one first parameter and delta 34 S of the gas to be traced H 2 S according to the second linear fitting curve, wherein the second correlation coefficient is less than or equal to 0.3, and the first parameter of the gas to be traced is the first parameter before TSR transformation;
and determining the source of the gas to be traced according to the first parameter of the gas to be traced.
Specifically, if the second phase relation number is less than or equal to 0.3, which indicates that the first parameter has no correlation with delta 34 S of the gas to be traced H 2 S, the first parameter in the TSR modified gas is not subjected to TSR modification, the first parameter of the gas to be traced is the first parameter before TSR modification, and the first parameter of the gas to be traced is directly compared with the first parameter identification standard of the related heat-induced gas of the former to determine the source of the gas to be traced. By the method, operation steps can be saved, and accuracy of a determination result can be further improved.
Illustratively, fig. 4 is a graph of relationship between delta 34SH2S and delta 13C2 of natural gas in a geodesic field, and as can be seen from fig. 4, a second correlation coefficient R 2 =0.696 between delta 34SH2S and delta 13C2 of natural gas in a geodesic field of large Niu Deqi, and a second correlation number > 0.3, which indicates that delta 34SH2S has a good correlation with delta 13C2, and that delta 13C2 is obviously affected by TSR. If the influence of TSR is not considered, all measured gas samples delta 13C2 are larger than-28 per mill (recorded by the former, delta 13C2 > -28 per mill belongs to humic type natural gas), which means that most of the gas samples are from the humic type natural gas; however, considering the effect of TSR, when δ 34SH2S value = source rock organosulfur isotope value (-10%o based on the test results of the tarry basin otto source rock), δ 13C2 value is about-32%o. Obviously, the natural gas is sapropel type natural gas.
The inventors found in the study that the conclusions obtained from the source of the source gas to be traced, which are respectively obtained by each first parameter, are consistent. I.e., the source of natural gas determined using ethane delta 13C2 is consistent with the conclusion that the source of natural gas was determined using mercury delta 199 Hg.
In the invention, a linear fitting curve between any two first parameters can be established, the correlation between any two first parameters is obtained, and whether the conclusion of determining the source of the gas to be traced by using any two first parameters is consistent is further verified according to the correlation between any two first parameters. If the correlation coefficient between any two first parameters is larger than 0.3, the correlation between the two first parameters is higher, and the two parameters are used for respectively determining that the to-be-traced gas is consistent.
Illustratively, FIG. 5 is a graph of natural gas delta 13C2 versus delta 199 Hg for a geodesic field of cattle. As can be seen from fig. 5, the natural gas delta 13C2 has a significant negative correlation with delta 199 Hg, indicating that both delta 13C2 and delta 199 Hg significantly received TSR modifications.
Fig. 6 is a graph of natural gas delta 13C2 versus delta 202 Hg for a geodesic field of cattle. As can be seen from fig. 6, there is also a correlation between the natural gas delta 13C2 value and the delta 202 Hg value, indicating that both delta 13C2 and delta 202 Hg are significantly affected by TSR.
Fig. 7 is a schematic diagram of a mercury isotope composition plate of natural gas and different sources of natural gas and sediments, vegetation and soil in the literature, which is actually measured by mercury isotope composition casting points of natural gas according to the invention. As can be seen from fig. 7, no TSR correction was performed (the source of the gas to be traced was determined directly using the mercury isotope of the gas to be traced), the northbound natural gas and the 7 natural gases in the 8 edodes basin bull land gas field otto mokuh group (O 1m5) to be traced were all from the slough type hydrocarbon source rock, but one of the two basin natural gases was from the humic kerogen. However, the natural gas of Jacola (K) is almost between the two, and the delta 199 Hg and delta 201 Hg values are close to 0, which indicates that the natural gas is the mixed cause of the two organic matter source gases of the humic type and the humic type.
Fig. 8 is a graph of mercury isotope combined with ethane isotope identification natural gas cause. As can be seen from fig. 8, the natural gas in the north direction is sapropel type natural gas; the relation casting point of the Earthur basin Olympic gas delta 199 Hg and delta 13C2 is mainly located in the upper right corner area, namely, only one Olympic gas sample is the sapropel gas based on the judgment of delta 13C2 value. Obviously, the judgment is carried out based on the delta 199 Hg and delta 13C2 values respectively, but the conclusion is completely opposite. However, by adopting the method for tracing the source gas, delta 199 Hg and delta 13C2 before TSR transformation are obtained, and the casting points are positioned in the circles in the upper left corner area, and obviously, the natural gas is the sapropel natural gas before TSR transformation.
The method for acquiring delta 34 S of the gas H 2 S to be traced is not limited, and can be acquired by adopting a method commonly used in the field. In some embodiments of the invention, delta 34 S of the source gas H 2 S to be traced is tested by a method comprising the steps of:
reacting the gas to be traced with saturated zinc acetate to obtain a first mixed system comprising ZnS;
standing the first mixed system overnight, and then filtering to obtain ZnS;
reacting ZnS with hydrochloric acid to obtain H 2 S;
Reacting H 2 S with silver nitrate to obtain a second mixed system comprising Ag 2 S;
And filtering the second mixed system to obtain Ag 2 S, testing the sulfur isotope of Ag 2 S, and obtaining delta 34 S of H 2 S to be traced.
Specifically, the to-be-traced gas can be reacted with saturated zinc acetate, and hydrogen sulfide in the to-be-traced gas can be reacted with the zinc acetate, so that a first mixed system comprising ZnS is obtained; standing the first mixed system overnight to enable ZnS to be more fully settled, and then filtering to obtain ZnS; reacting ZnS with hydrochloric acid to obtain H 2 S; and then reacting H 2 S with silver nitrate to obtain a second mixed system comprising Ag 2 S, filtering the second mixed system to obtain a sulfur isotope of the to-be-traced gas H 2 S in Ag 2S,Ag2 S, testing the sulfur isotope of the Ag 2 S, and obtaining delta 34 S of the to-be-traced gas H 2 S.
In a specific embodiment, natural gas (to-be-traced gas) in an oilfield wellhead or a separator can be introduced into a large beaker filled with 5L of saturated zinc acetate solution, stirred until enough white suspended or precipitated ZnS is seen, and the aeration is stopped to obtain a first mixed system comprising ZnS;
The first mixed system including ZnS was then allowed to stand overnight, and the mixed system after overnight was subjected to filtration treatment with filter paper, and ZnS precipitate was collected. Adding 10% hydrochloric acid into ZnS to obtain H2S, and driving the generated H 2 S into a solution containing 10% silver nitrate through N 2 until no H 2 S is released (lasting about 1 hour), so as to obtain a second mixed system further comprising Ag 2 S; and then filtering the second mixed system, collecting Ag 2 S precipitate, and testing the sulfur isotope composition of Ag 2 S solid, namely the isotope of H 2 S in natural gas.
By using the method, delta 34 S of the gas H 2 S to be traced can be more accurately tested, and the accuracy of the natural gas tracing result is improved.
The invention is not limited to the testing method of the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced, and can be tested by adopting the testing method commonly used in the field. Fig. 9 is a schematic diagram of an apparatus for collecting mercury in a gas to be traced according to some embodiments of the invention. As shown in fig. 9, in some embodiments of the present invention, the mercury of the gas to be traced Δ 199 Hg, the mercury of the gas to be traced Δ 201 Hg, and the delta 202 Hg of the gas to be traced were tested by a method comprising the steps of:
Introducing the gas to be traced into an absorption bottle filled with potassium permanganate solution to obtain mercury-containing absorption liquid;
carrying out reduction reaction on the mercury-containing absorption liquid and ammonium hydrogen chloride to obtain a first solution to be tested;
analyzing the mercury content of the first solution to be detected by using a cold steam atomic fluorescence spectrometer, so as to obtain the mercury content in the gas to be traced;
diluting the first solution to be tested to obtain a diluent with the mercury content of 1-5 ng/g;
The diluted solution and the stannic chloride undergo a reduction reaction to obtain a second solution to be measured;
And testing mercury isotopes in the second solution to be tested by using the multi-receiver inductively coupled plasma mass spectrometry to obtain the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced.
Specifically, introducing the gas to be traced into an absorption bottle filled with potassium permanganate solution, and absorbing mercury in the gas to be traced by using potassium permanganate to obtain mercury-containing absorption liquid; carrying out a reduction reaction on the mercury-containing absorption liquid and ammonium hydrogen chloride so as to reduce excessive potassium permanganate, thereby obtaining a first solution to be tested; analyzing the mercury content of the first solution to be detected by using a cold steam atomic fluorescence spectrometer, and calculating the mercury content in the gas to be traced; diluting the first solution to be tested to obtain a diluent with the mercury content of 1-5 ng/g; reducing Hg 2+ to Hg 0 by a reduction reaction between the diluent and tin chloride to obtain a second solution to be tested containing Hg 0; and the isotope of mercury in the second solution to be detected is the isotope of mercury in the gas to be traced, and the multi-receiver inductively coupled plasma mass spectrometry is used for testing the isotope of mercury in the second solution to be detected to obtain the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced.
In a specific embodiment, as shown in fig. 9, an oilfield wellhead or a separator natural gas (to-be-traced gas) enters a first container 2 through a teflon pipe 1 at a flow rate of less than 6L/min to remove a liquid phase (water or oil) in the to-be-traced gas to obtain a first intermediate to-be-traced gas, then the first intermediate to-be-traced gas enters a second container 3 (500 ml of an impact absorption bottle filled with an acidic potassium permanganate solution), mercury in the natural gas is absorbed by the potassium permanganate solution in the second container 3 to obtain an absorption liquid and a second intermediate to-be-traced gas, then the second intermediate to-be-traced gas flows out from the second container 3 into a third container 4, the second intermediate to-be-traced gas is dried by a drying agent in the third container 4 to obtain a third to-be-traced gas, the volume of the third to-be-traced gas is measured by using a flowmeter 5 and a flowmeter 6, the volume of the natural gas is measured and the volume of the gas is recorded after the natural gas is dried;
Adding ammonium hydrogen chloride into the absorption liquid to reduce excessive potassium permanganate, so as to obtain a first solution to be tested, analyzing the content of mercury in the first solution to be tested by using a cold steam atomic fluorescence spectrometer, and calculating the content of mercury in natural gas;
Diluting the mercury concentration in the first solution to be tested to 1-5ng/g to obtain a diluent, adding stannic chloride into the diluent to reduce Hg 2+ to Hg 0 to obtain a second solution to be tested, and introducing the second solution to be tested into a multi-receiving inductively coupled plasma mass spectrum (MC-ICP-MS) on line to perform mercury isotope analysis to obtain the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced.
By using the method, the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced can be tested more accurately, and the accuracy of the natural gas tracing result is improved.
The method for acquiring the content of H 2 S in the gas to be traced, the content of CO 2 in the gas to be traced, the content of alkane gases such as CH 4 in the gas to be traced and the carbon isotope composition of ethane in the gas to be traced is not limited, and can be obtained by adopting a method commonly used in the field for testing. Illustratively, natural gas (to-be-traced gas) in an oilfield wellhead or a separator can be introduced into a domestic 1.5L high-pressure stainless steel cylinder with a polytetrafluoroethylene lining, or into a 750ml double-head steel cylinder with a polytetrafluoroethylene lining of a Swagelok company for 10-15 minutes, air in the steel cylinder is driven, and then the gas is collected until the pressure reaches 5 atm, so as to obtain gas to be detected, and the masonry to be detected is tested to obtain the content of H 2 S in the gas to be traced, the content of CO 2 in the gas to be traced, the content of alkane gas such as CH 4 in the gas to be traced and the carbon isotope composition of ethane in the gas to be traced.
By applying the natural gas tracing method, the spatial-temporal distribution of the dominant source rock is determined by combining the deposition microphase, the geographic distribution and the horizon of the source rock in the investigation basin; and then the existing exploration results (oil/gas/water well distribution) and dredging systems (such as faults, unconformity surfaces and relatively high-hole hypertonic reservoir distribution) are combined, so that the method can be used for delineating a favorable exploration area and providing well position deployment suggestions.
Finally, it should be noted that: the above embodiments are only for illustrating the technical solution of the present invention, and not for limiting the same; although the invention has been described in detail with reference to the foregoing embodiments, it will be understood by those of ordinary skill in the art that: the technical scheme described in the foregoing embodiments can be modified or some or all of the technical features thereof can be replaced by equivalents; such modifications and substitutions do not depart from the spirit of the invention.
Claims (10)
1. The tracing method of the secondary natural gas is characterized by comprising the following steps of:
determining whether the gas to be traced is TSR modified gas;
If the gas to be traced is TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced before TSR reforming;
If the gas to be traced is non-TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced;
Wherein the first parameter comprises ethane delta 13C2, mercury delta 199 Hg, mercury delta 201 Hg, and mercury delta 202 Hg values.
2. The tracing method of claim 1, wherein said determining whether the gas to be traced is TSR retrofit gas comprises:
determining whether the gas to be traced is TSR modified gas or not according to a second parameter of the gas to be traced, delta 34 S of H 2 S of the gas to be traced and delta 34 S of stratum gypsum;
Wherein the second parameter comprises H 2 S content C1, CO 2 content C2 and alkane total content C3.
3. The tracing method of claim 2, wherein said determining whether the gas to be traced is TSR reformed gas according to the second parameter of the gas to be traced, delta 34 S of the gas to be traced H 2 S, and delta 34 S of the formation gypsum comprises:
If A is more than 0.03, and the absolute value of the difference between delta 34 S of H 2 S to be traced and delta 34 S of stratum gypsum is less than 5 per mill, the gas to be traced is TSR modified gas; or alternatively, the first and second heat exchangers may be,
If A is less than or equal to 0.03, and the absolute value of the difference between delta 34 S of H 2 S to be traced and delta 34 S of stratum gypsum is more than or equal to 5 per mill, the gas to be traced is non-TSR modified gas;
wherein a= (c1+c2)/(c1+c2+c3).
4. The tracing method according to claim 3, wherein if the gas to be traced is a TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before TSR reforming comprises:
Establishing at least one first linear fitting curve of the first parameter and A, and acquiring a first linear fitting equation y=ax+b according to the first linear fitting curve, wherein b is the first parameter before TSR modification;
Determining the source of the gas to be traced according to the b;
where x refers to a and y refers to a first parameter.
5. The tracing method according to claim 4, wherein if the gas to be traced is a TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter before TSR reforming further comprises:
And obtaining at least one first correlation coefficient of the first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient is more than 0.3.
6. The tracing method according to claim 3, wherein if the to-be-traced gas is a TSR modified gas, determining the source of the to-be-traced gas according to at least one first parameter of the to-be-traced gas before TSR modification further comprises:
establishing a first linear fitting curve of at least one first parameter and A, and acquiring a first correlation coefficient of the at least one first parameter and A according to the first linear fitting curve, wherein the first correlation coefficient is less than or equal to 0.3, and the first parameter of the gas to be traced is the first parameter before TSR modification;
And determining the source of the to-be-traced gas according to the first parameter of the to-be-traced gas.
7. A tracing method according to any one of claims 1-3, wherein if said gas to be traced is a TSR reformed gas, determining a source of said gas to be traced according to at least one first parameter of the gas to be traced prior to TSR reforming comprises:
Establishing a second linear fitting curve of at least one first parameter and delta 34 S of the gas to be traced H 2 S, and acquiring a second linear fitting equation y ' =a ' x ' +b ', x ' =hydrocarbon source rock organic sulfur isotope according to the second linear fitting curve, wherein y ' is the first parameter of the gas to be traced before TSR reconstruction, and determining the source of the gas to be traced according to the y ';
Where x 'refers to delta 34 S of the source gas H 2 S to be traced, and y' refers to the first parameter.
8. The tracing method of claim 7, wherein if the gas to be traced is a TSR reformed gas, determining the source of the gas to be traced according to at least one first parameter of the gas to be traced prior to TSR reforming further comprises:
And obtaining a second correlation coefficient of delta 34 S of at least one first parameter and the gas H 2 S to be traced according to the second linear fitting curve, wherein the second correlation coefficient is more than 0.3.
9. A tracing method according to any one of claims 1-3, wherein if said gas to be traced is a TSR reformed gas, determining a source of said gas to be traced according to at least one first parameter of the gas to be traced prior to TSR reforming further comprises:
establishing a second linear fitting curve of at least one first parameter and delta 34 S of the gas to be traced H 2 S, and acquiring a second correlation coefficient of the at least one first parameter and delta 34 S of the gas to be traced H 2 S according to the second linear fitting curve, wherein the second correlation coefficient is more than 0.3, and the first parameter of the gas to be traced is the first parameter before TSR reconstruction;
And determining the source of the to-be-traced gas according to the first parameter of the to-be-traced gas.
10. The tracing method according to any one of claims 1-9, wherein delta 34 S of said gas to be traced H 2 S is tested by a method comprising the steps of:
reacting the to-be-traced gas with saturated zinc acetate to obtain a first mixed system comprising ZnS;
standing the first mixed system overnight, and then filtering to obtain ZnS;
reacting ZnS with hydrochloric acid to obtain H 2 S;
Reacting H 2 S with silver nitrate to obtain a second mixed system comprising Ag 2 S;
Filtering the second mixed system to obtain Ag 2 S, testing the sulfur isotope of Ag 2 S, and obtaining delta 34 S of H 2 S to be traced; and/or the number of the groups of groups,
The mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced are obtained through testing by a method comprising the following steps:
Introducing the gas to be traced into an absorption bottle filled with potassium permanganate solution to obtain mercury-containing absorption liquid;
Carrying out a reduction reaction on the mercury-containing absorption liquid and ammonium hydrogen chloride to obtain a first solution to be tested;
Analyzing the mercury content of the first solution to be detected by using a cold steam atomic fluorescence spectrometer, so as to obtain the mercury content in the gas to be traced;
diluting the first solution to be tested to obtain a diluent with the mercury content of 1-5 ng/g;
reducing the diluent with stannic chloride to obtain a second solution to be detected;
And testing the mercury isotopes in the second solution to be tested by using a multi-receiver inductively coupled plasma mass spectrum to obtain the mercury delta 199 Hg of the gas to be traced, the mercury delta 201 Hg of the gas to be traced and the delta 202 Hg of the gas to be traced.
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| US20200132649A1 (en) * | 2018-10-31 | 2020-04-30 | Petrochina Company Limited | Methods and devices for detecting mercury isotopes in oil-gas sources |
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