CN107449823B - Ancient oil-water interface identification method and application thereof in rebuilding filling history of crude oil - Google Patents
Ancient oil-water interface identification method and application thereof in rebuilding filling history of crude oil Download PDFInfo
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Abstract
The invention provides an oil-gas reservoir paleooil-water interface identification method and application thereof in reconstruction of crude oil filling history, which can quickly and accurately identify the paleooil-water interface of an oil-gas reservoir so as to reconstruct the crude oil filling history. The method for identifying the ancient oil-water interface of the oil-gas reservoir comprises the following steps: sampling different depth positions of a reservoir stratum target layer system in a single well in a research area to obtain a reservoir stratum sample, and recording the corresponding depth of a sampling point; obtaining an adsorbed hydrocarbon extract on the surface of reservoir sample particles, and determining the content of trace elements in the adsorbed hydrocarbon extract; drawing a distribution profile diagram of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the adsorbed hydrocarbons on the surface of the reservoir sample particles; according to the distribution profile, identifying an inflection point when the content of the trace elements in the profile starts and continuously deviates from the baseline along the depth direction of the sampling point from deep to shallow, wherein the depth corresponding to the inflection point is the depth of an oil-gas reservoir ancient oil-water interface.
Description
Technical Field
The invention relates to the field of petroleum and natural gas exploration, in particular to the field of element geochemistry (oil-gas reservoir), and specifically relates to an oil-gas reservoir ancient oil-water interface identification method and application thereof in reconstruction of crude oil filling history.
Background
The research on the oil-gas reservoir history is an important part in the research on the oil-gas reservoir formation rule, and through the research on the crude oil filling history and the combination of the source rock evolution and the structural analysis in the filling period, the formation process and the main control factors of the related oil reservoir can be better known, so that the help is provided for better predicting the position and the property of the oil-gas reservoir in the period. The transition of the oil-water interface of the oil-gas reservoir records the history of adjustment, modification and destruction of the oil-gas reservoir after formation. By restoring the ancient oil-water interface position of the oil-gas reservoir in the geological historical period, the time of oil-gas transportation accumulation and reservoir formation can be determined, the adjustment process of fluid reservoir formation is restored, the formation and distribution rules of the oil-gas reservoir are helped to be known, and a foundation is laid for the research of reservoir formation characteristics of the oil-gas reservoir.
At present, there are two main methods for determining the ancient oil-water interface of an oil-gas reservoir: one method is to identify an ancient oil layer and an ancient migration channel by an oil inclusion abundance analysis method; and the other method is to adopt reservoir quantitative fluorescence technology (QGF, QGF-E and the like) to identify the oil-water interfaces of the ancient oil column, the ancient oil and the modern oil so as to deduce the filling history of the crude oil. The common method for analyzing the abundance of the oil-gas inclusion is as follows: and identifying and counting hydrocarbon inclusion bodies in the slices under a fluorescence microscope, and estimating the abundance of the oil-gas inclusion bodies by adopting GOI (proportion of oil-containing inclusion body particles in clastic rock) and FOI (proportion of oil-gas inclusion bodies in carbonate rock) technologies. However, this method is labor intensive, requires expertise in identifying inclusion, has a large human factor and a limited range of observation statistics, and is difficult to reflect the reservoir overview. Reservoir quantitative fluorescence techniques (QGF-E) are based on the detection of organic molecules (e.g., aromatics, polar organic compounds, and bitumen) that may be damaged (e.g., secondary cracking of oil at high temperatures) in some cases (e.g., deep, ancient reservoirs) leading to failure to identify oil-water interfaces or inaccurate identification, which limits the method.
Therefore, how to provide a quick, simple and more accurate oil-gas reservoir ancient oil-water interface identification method so as to quickly and accurately reconstruct the crude oil filling history is a technical problem which is urgently needed to be solved at present.
Disclosure of Invention
Aiming at the technical problems, the invention provides an oil-gas reservoir ancient oil-water interface identification method and application thereof in reconstruction of crude oil filling history, and the oil-gas reservoir ancient oil-water interface can be quickly, simply, economically and accurately identified so as to be convenient for reconstruction of the crude oil filling history.
In order to achieve the purpose, the invention adopts the technical scheme that:
the invention provides an oil-gas reservoir ancient oil-water interface identification method, which comprises the following steps:
sampling different depth positions of a reservoir stratum target layer system in a single well in a research area to obtain a reservoir stratum sample, and recording the corresponding depth of a sampling point;
obtaining an adsorbed hydrocarbon extract on the surface of reservoir sample particles, and determining the content of trace elements in the adsorbed hydrocarbon extract;
drawing a distribution profile diagram of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the adsorbed hydrocarbons on the surface of the reservoir sample particles;
according to the distribution profile, identifying an inflection point when the content of the trace elements in the profile starts and continuously deviates from the baseline along the depth direction of the sampling point from deep to shallow, wherein the depth corresponding to the inflection point is the depth of an oil-gas reservoir ancient oil-water interface.
Preferably, the sampling locations of the reservoir samples extend from the top of the reservoir target formation to the middle of the known water layer below, and the sampling locations are spaced apart by a distance of 5-10 m.
Preferably, the reservoir sample is a core sample or a debris sample of the reservoir.
Preferably, the specific steps for obtaining the hydrocarbon extract adsorbed on the surface of the reservoir sample particles are as follows: the method comprises the steps of crushing a reservoir sample into single-chip particles, removing free hydrocarbon on the surfaces of the particles by using dichloromethane, removing clay on the surfaces of the particles by using hydrogen peroxide, drying the particles, extracting adsorbed hydrocarbon on the surfaces of the particles by using dichloromethane to obtain adsorbed hydrocarbon extraction liquid, and evaporating dichloromethane in the adsorbed hydrocarbon extraction liquid to obtain an adsorbed hydrocarbon extract.
Preferably, for reservoir samples other than carbonate rock, after clay on the surface of the particles is removed, dilute hydrochloric acid is also used to remove carbonate cement on the surface of the particles.
Preferably, the specific steps for determining the content of the trace elements in the adsorbed hydrocarbon extract are as follows: adding nitric acid and a hydrogen peroxide digestion reagent into the adsorbed hydrocarbon extract, digesting in a closed microwave digestion system by adopting a microwave digestion working procedure, and measuring the content of trace elements in the digested adsorbed hydrocarbon extract by adopting an inductively coupled plasma mass spectrometry.
Preferably, the trace elements are selected from one or more of Ni, V, Cr, Mn, Zn, Fe, Cu, and Co.
The invention further provides an application of the oil-gas reservoir ancient oil-water interface identification method in reconstruction of crude oil filling history according to any one of the technical schemes.
Compared with the prior art, the invention has the advantages and positive effects that:
1. the ancient oil-water interface identification method for the oil-gas reservoir, which is provided by the invention, is used for identifying the ancient oil-water interface based on the longitudinal change of the trace element content in the adsorbed hydrocarbons on the particle surfaces of reservoir samples with different depths of a single well, and has the advantages of rapidness, simplicity, convenience, economy, high sensitivity, easiness in obtaining samples, small required sample amount and the like;
2. the method for identifying the ancient oil-water interface of the oil-gas reservoir is not influenced by secondary changes such as oil-gas migration fractionation, reservoir destruction, oxidation and biodegradation, has high accuracy, and can be widely popularized in the research of the oil-gas reservoir formation process.
Drawings
FIG. 1 is a flow chart of a method for identifying an ancient oil-water interface of an oil-gas reservoir according to an embodiment of the invention;
FIG. 2 is a profile of trace element content as a function of depth for a Chalk sandstone reservoir drilled in the North-West continental shelf, Australia, as provided in example 1 of the present invention;
fig. 3 is a profile view of the distribution of the trace element content with depth of a region drilling and reservoir sandstone reservoir in a toweling basin tower provided in embodiment 2 of the present invention;
Detailed Description
The technical solutions in the embodiments of the present invention will be clearly and completely described below, and it is obvious that the described embodiments are only a part of the embodiments of the present invention, and not all embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.
The embodiment of the invention provides an oil-gas reservoir ancient oil-water interface identification method, a flow chart of which is shown in figure 1, and the method comprises the following steps:
s1: sampling positions of different depths of a target layer system of a reservoir in a single well in a research area to obtain reservoir samples, and recording the depths corresponding to the sampling points.
In this step, it should be noted that, during sampling, the best test object is a reservoir sample with moderate granularity, good sorting property, low argillaceous content and good physical property, and the sampling size is generally 20-50 g. In addition, it should be noted that the reservoir target strata is the oil-gas strata in the research area which aims to reconstruct the filling history of crude oil or the ancient oil-bearing strata in the geological historical period. The sampling mode of sampling different depth positions in the step is more systematic, and the sample is more representative, so that the subsequent research on the change rule of the trace element content of hydrocarbon adsorbed on the surface of the reservoir sample particles along with the depth is facilitated.
S2: and obtaining the adsorbed hydrocarbon extract on the surface of the reservoir sample particles, and measuring the content of the trace elements in the adsorbed hydrocarbon extract.
In this step, it should be noted that the adsorbed hydrocarbon extract on the surface of the reservoir sample particles can be obtained by chemical solvent extraction, and the trace elements can be determined by analysis methods such as Atomic Absorption Spectrometry (AAS), X-ray fluorescence spectrometry (XRF), inductively coupled plasma atomic emission spectrometry (ICP-AES), and inductively coupled plasma mass spectrometry (ICP-MS).
S3: and drawing a distribution profile diagram of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the adsorbed hydrocarbons on the surface of the reservoir sample particles.
In this step, it should be noted that, when a profile of distribution of trace element content with depth is drawn, a line graph is drawn with the trace element content of hydrocarbons adsorbed on the surface of reservoir sample particles as abscissa and the depth of a sampling point as ordinate.
S4: according to the distribution profile, identifying an inflection point when the content of the trace elements in the profile starts and continuously deviates from the baseline along the depth direction of the sampling point from deep to shallow, wherein the depth corresponding to the inflection point is the depth of an oil-gas reservoir ancient oil-water interface.
In this step, it should be noted that, for a reservoir in which a large amount of oil gas is filled once or many times during a geological history period, in the course of crude oil migration, crude oil components mainly containing asphaltenes are adsorbed on the surfaces of reservoir particles, so that the hydrocarbon extracts adsorbed on the surfaces of the particles are enriched with trace elements with relatively high abundance, and the content of the trace elements adsorbed on the surfaces of the reservoir particles in the hydrocarbons is not affected by oil gas migration, reservoir destruction, oxidation and biodegradation, so that the oil saturation of the reservoir is increased, and the content of the trace elements adsorbed on the surfaces of the reservoir particles in the hydrocarbons is correspondingly increased; and for the water layer, because the oil saturation is lower, the crude oil transportation and aggregation are lacked, the adsorbed hydrocarbon content on the surface of the reservoir particles is lower, and the content of trace elements is correspondingly lower. Therefore, according to a distribution profile of the trace element content of the hydrocarbon extract adsorbed by the single-well reservoir particles along with the depth, the ancient oil-water interface can be divided by identifying the depth limit with obvious difference in the trace element content in the graph (namely identifying the inflection point when the trace element content in the graph begins and continuously deviates from the baseline), and the ancient oil layer and the water layer can be identified.
The ancient oil-water interface identification method for the oil-gas reservoir, which is provided by the invention, is used for identifying the ancient oil-water interface based on the longitudinal change of the trace element content in the adsorbed hydrocarbons on the particle surfaces of reservoir samples with different depths of a single well, and has the advantages of rapidness, simplicity, convenience, economy, high sensitivity, easiness in obtaining samples, small required sample amount and the like. Moreover, the method identifies the ancient oil-water interface of the oil-gas reservoir without being influenced by secondary changes such as oil-gas migration fractionation, reservoir destruction, oxidation and biodegradation, has high accuracy, and can be widely popularized in the research of the oil-gas reservoir formation process.
In a preferred embodiment, the sampling locations for the reservoir samples extend from the top of the reservoir's target strata to the middle of the known water layer below, and the sampling locations are spaced apart by a distance of 5-10 m. In the preferred embodiment, it should be noted that the optimal sampling range is the middle section extending from the top of the target layer system of the reservoir to the known water layer below, the sampling points in the range are more representative, and the spacing distance between the sampling points defined in the preferred embodiment is the optimal range, and those skilled in the art can specifically select the appropriate spacing distance according to the thickness and uniformity of the reservoir. For example: when the thickness of the reservoir is thicker and the lithology of the reservoir is more uniform, the spacing distance of the sampling points can be properly increased; on the contrary, the spacing distance of the sampling points can be properly reduced; in addition, the sampling point spacing near the oil-gas-water interface may be reduced appropriately to encrypt the sampling. The reservoir sample obtained by adopting the sampling mode is more representative, the number of sampling points is moderate, and the workload is smaller.
In a preferred embodiment, the reservoir sample is a core sample or a debris sample of the reservoir. In the preferred embodiment, it should be noted that the reservoir sample is preferably a core sample, and if there is no core sample, a rock debris sample may be used instead, and when the rock debris sample is used as the reservoir sample, the sample amount is slightly larger than that of the core sample. According to the method for identifying the ancient oil-water interface of the oil-gas reservoir, the reservoir sample is not limited to the core sample, the sampling is easier, and the method is also suitable for the reservoir without the core section.
In a preferred embodiment, the specific steps of obtaining the hydrocarbon extract adsorbed on the surface of the particles of the reservoir sample are as follows: the method comprises the steps of crushing a reservoir sample into single-chip particles, removing free hydrocarbon on the surfaces of the particles by using dichloromethane, removing clay on the surfaces of the particles by using hydrogen peroxide, drying the particles, extracting adsorbed hydrocarbon on the surfaces of the particles by using dichloromethane to obtain adsorbed hydrocarbon extraction liquid, and evaporating dichloromethane in the adsorbed hydrocarbon extraction liquid to obtain an adsorbed hydrocarbon extract. According to the preferable embodiment, pure and more representative reservoir stratum particle samples such as quartz and the like can be obtained through sample crushing screening, free hydrocarbon and clay on the surfaces of the particles can be removed through chemical cleaning by adopting dichloromethane and hydrogen peroxide, the influence of trace elements contained in the free hydrocarbon and clay minerals on detection results is avoided, the sample processing flow is more standardized, and a good foundation is laid for accurately measuring the content of the trace elements subsequently. In the preferred embodiment, after the reservoir sample is crushed into single clastic particles, the clastic rock core reservoir sample is screened out by a standard sieve to obtain particles with the particle size ranging from 0.063 mm to 1.000 mm; stirring the clastic rock type detritus reservoir sample with distilled water for multiple elutriations, pouring suspended mud and silt, drying the rest sand grains with coarse grain size, and screening out grains with grain size of 0.063-1.000mm by using a standard sieve; for carbonate reservoir samples, the samples can be directly crushed to below 0.3mm, and the particles with the particle size in the range of 0.1-0.3mm are screened by using a standard sieve. When dichloromethane is used to remove free hydrocarbons on the surface of particles, about 2g of reservoir sample particles can be weighed, placed in a beaker, added with 20-30mL of dichloromethane, and placed in an ultrasonic instrument for ultrasonic treatment for 10-15min, and it can be understood that a person skilled in the art can specifically select the sampling amount of particles, the adding amount of dichloromethane and the ultrasonic extraction time according to the actual situation of the reservoir sample particles. When the clay on the particle surface is removed by using hydrogen peroxide, 30-40mL of 10% hydrogen peroxide is added into a beaker filled with a sample after the particle sample is dried, ultrasonic treatment is carried out in an ultrasonic instrument for 10-15min, standing is carried out for 40-45min, ultrasonic treatment is carried out for 10-15min, the sample is cleaned by using distilled water after the ultrasonic treatment is finished until residues are cleaned, and it can be understood that a person skilled in the art can specifically select the concentration and the addition amount of the hydrogen peroxide and the ultrasonic time according to the condition of reservoir sample particles. When the sample is dried, the sample treated as above is placed in a tray, and is placed in a constant temperature drying oven, and is baked at 80 ℃ for 1-4 hours until the sample is dried, and it can be understood that the drying temperature and time can be specifically selected by those skilled in the art according to the condition of the reservoir sample particles. When dichloromethane is used for extracting the adsorbed hydrocarbon on the particle surface, 20-30mL of dichloromethane can be added into a beaker filled with a dried sample, ultrasound is carried out in an ultrasonic instrument for 10-20min, and the obtained adsorbed hydrocarbon extract can be placed in a 15mL reagent bottle for sealing and storing before detection.
In a further preferred embodiment, for reservoir samples other than carbonate rock, after clay removal from the particle surface, dilute hydrochloric acid is also used to remove the carbonate cement from the particle surface. In the preferred embodiment, the carbonate cement on the surface of the particles is removed by using dilute hydrochloric acid, so that the influence of the carbonate cement on the detection of the content of the trace elements can be removed. In this embodiment, the reservoir samples except for carbonate rock are mainly clastic rock reservoir samples, and for carbonate rock reservoir samples, since the structure of the reservoir samples contains a large amount of carbonate minerals, the sample structure is damaged by dilute hydrochloric acid treatment, and thus for carbonate rock reservoir samples, dilute hydrochloric acid treatment cannot be adopted. In addition, in the preferred embodiment, when dilute hydrochloric acid is used to remove the carbonate cement on the surface of the particles, 30-40ml of 3.6% dilute hydrochloric acid is added into a beaker containing the sample, the sample is subjected to ultrasonic treatment for 10-15min and then stands still, a glass rod is used for stirring until no bubbles are generated, and the sample is washed by distilled water until the residue is cleaned.
In a preferred embodiment, the specific steps for determining the trace element content in the adsorbed hydrocarbon extract are: adding nitric acid and a hydrogen peroxide digestion reagent into the adsorbed hydrocarbon extract, digesting in a closed microwave digestion system by adopting a microwave digestion working procedure, and measuring the content of trace elements in the digested adsorbed hydrocarbon extract by adopting an inductively coupled plasma mass spectrometry. When the preferred embodiment is cleared up, the clearing up reagent consisting of nitric acid and hydrogen peroxide is adopted, higher clearing up temperature and pressure are obtained by utilizing the internal heating and absorption polarization caused by microwave radiation, the clearing up speed is accelerated, the using amount of the clearing up reagent is reduced, and in addition, the clearing up is carried out in a closed state, the clearing up is more thorough, and the environment is not easily polluted. It should be noted that, during digestion, 6-10mL of 5% nitric acid and 2-5mL of hydrogen peroxide may be added to the adsorbed hydrocarbon extract for digestion, and after digestion, cooling is performed, and the volume is increased to 20-30mL with ultrapure water. In addition, when the content of the trace elements is measured by adopting the inductively coupled plasma mass spectrometry (ICP-MS) in the preferred embodiment, the measurement result is more accurate.
In a preferred embodiment, the trace elements are selected from one or more of Ni, V, Cr, Mn, Zn, Fe, Cu, Co. In the preferred embodiment, it should be noted that, because the content difference of different trace elements in hydrocarbons adsorbed on the surface of the same reservoir sample particle is large, the content of multiple trace elements is determined, which is beneficial to improving the accuracy of identification.
The embodiment of the invention also provides application of the oil-gas reservoir ancient oil-water interface identification method in reconstruction of crude oil filling history. The transition of the oil-water interface of the oil-gas reservoir records the history of adjustment, modification and destruction of the oil-gas reservoir after formation. For a specific oil and gas reservoir in a certain research area, the following situations exist on the ancient oil and water interface divided by the oil and gas reservoir ancient oil and water interface identification method based on any one of the embodiments: (1) if the water content is lower than the oil (gas) water interface explained at present, the early filling of the formed ancient oil deposit is shown, the later stage is subjected to secondary adjustment and transformation, and the scale of the oil deposit is reduced; (2) if the oil (gas) water interface is higher than the oil (gas) water interface explained at present, the early oil deposit is smaller than the oil and gas deposit explained at present, and the early oil deposit is adjusted and modified in the near term, if the near term high-maturity condensate oil and gas filling moves the oil-water interface downwards; (3) if the oil-water interface is consistent with the oil-water interface, the ancient oil deposit is not obviously adjusted and reformed after being formed; in addition, if the oil-water interface is lost, the ancient oil reservoir is damaged seriously, and the ancient oil reservoir exists in the form of asphalt. And the hydrocarbon generation and expulsion characteristics and structural evolution analysis of the corresponding hydrocarbon source rock are combined, so that the oil and gas reservoir formation process of the research area can be further explained.
In order to more clearly and specifically describe the method for identifying an ancient oil-water interface of a hydrocarbon reservoir provided by the embodiment of the invention, the following description is given with reference to specific embodiments.
Example 1
Selecting a Dampier basin of the northwest continental shelf of Australia as a research area, and identifying the ancient oil-water interface of the oil-gas reservoir, wherein the method comprises the following steps:
(1) sampling a single well drilled in the basin and meeting the chalk sandstone oil reservoir to obtain a reservoir sample, wherein the sampling position extends from the top of the chalk sandstone oil reservoir to the middle section of a known water layer below the chalk sandstone oil reservoir, the spacing distance of the sampling points is 5-10m, 7 sampling points are counted in total, the sampling points are numbered in sequence, and the corresponding depths of the sampling points are recorded, and the data are shown in table 1. It should be noted that, during sampling, about 20g of core samples are selected as reservoir samples, and when no core sample exists, 20-50g of rock debris samples are selected as reservoir samples.
Table 1 data statistics table for chalk-line sandstone reservoir encountered by the Dampier drilling in northwest continental shelf of australia
(2) The hydrocarbon adsorbing extract on the surface of the reservoir sample particles is obtained, and the contents of seven trace elements of Ni, Cr, Mn, Zn, V, Fe and Cu in the hydrocarbon adsorbing extract are measured, wherein the data are shown in Table 1.
The method comprises the following specific steps of obtaining the adsorbed hydrocarbon extract on the surface of the reservoir sample particles:
crushing a rock core reservoir sample into single-clastic particles, and screening out the particles with the particle size of 0.063-1.000mm by using a standard sieve; stirring the rock debris reservoir sample with distilled water for multiple times, then dumping suspended mud and silt, drying the residual sand grains with coarser granularity, and then screening out grains with the grain diameter of 0.063-1.000mm by using a standard sieve; weighing about 2g of reservoir sample particles, recording the specific weight, placing the reservoir sample particles in a beaker, adding 20mL of dichloromethane, placing the reservoir sample particles in an ultrasonic instrument for ultrasonic treatment for 10min, and removing free hydrocarbon on the surfaces of the particles; after the particle sample is dried, adding 40mL of 10% hydrogen peroxide into a beaker filled with the sample to remove clay on the surface of the particles, carrying out ultrasonic treatment in an ultrasonic instrument for 10min, standing for 40min, carrying out ultrasonic treatment for 10min again, and cleaning the sample with distilled water after the ultrasonic treatment is finished until residues are cleaned; adding 40mL of 3.6% diluted hydrochloric acid into a beaker filled with a sample to remove carbonate cement on the surface of particles, carrying out ultrasonic treatment in an ultrasonic instrument for 10min, standing, stirring by using a glass rod until no bubbles are generated, and washing the sample by using distilled water until residues are cleaned; drying the granules in a drying box at 80 ℃ and placing the dried granules in a beaker; adding 20mL of dichloromethane into a beaker filled with a sample, performing ultrasonic treatment in an ultrasonic instrument for 10min to extract adsorbed hydrocarbons on the surfaces of the particles to obtain adsorbed hydrocarbon extract, and evaporating dichloromethane in the obtained adsorbed hydrocarbon extract to obtain an adsorbed hydrocarbon extract.
The specific steps for determining the content of the trace elements in the adsorbed hydrocarbon extract are as follows:
adding 6mL of 5% nitric acid and 2mL of hydrogen peroxide digestion reagent into the adsorbed hydrocarbon extract, digesting in a closed microwave digestion system by adopting a microwave digestion working procedure, cooling after digestion, metering the volume to 30mL by using ultrapure water, and measuring the content of trace elements in the digested adsorbed hydrocarbon extract by adopting inductively coupled plasma mass spectrometry.
(3) And drawing a distribution profile of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the hydrocarbons adsorbed on the surfaces of the particles of the reservoir sample, as shown in figure 2.
(4) According to fig. 2, along the depth direction of the sampling point from deep to shallow, the inflection point of the trace element content in the graph is identified when the trace element content starts and continuously deviates from the baseline, and the identification process is as follows: as can be seen from fig. 2, when the depth is below 1295m, the contents of various trace elements are low and all approach the baseline, and when the depth is above 1295m, the contents of various trace elements show a sharp rising trend and continuously deviate from the baseline, so 1295m is the depth corresponding to the inflection point, i.e. the depth of the ancient oil-water interface of the oil-gas reservoir.
The identification result is verified by adopting a reservoir quantitative fluorescence analysis technology (QGF-E), and as shown in figure 2, the oil-gas reservoir ancient oil-water interface identification method provided by the invention has good consistency with an oil-water interface obtained by the reservoir quantitative fluorescence technology (QGF-E). The depth of the ancient oil-water interface of the oil-gas reservoir obtained based on the method is approximately equal to that of the oil-water interface obtained based on a single-well oil testing conclusion, and the oil reservoir is not obviously adjusted and transformed after the crude oil is filled and formed in a geological historical period, and the later-period storage condition is good.
Example 2
Selecting a region in a Tarim basin tower as a research region, and identifying an oil-gas reservoir ancient oil-water interface, wherein the method comprises the following steps:
(1) and systematically sampling one single well drilled in the area and encountering the bitumen sandstone reservoir of the reservoir system to obtain a reservoir sample, wherein the sampling position extends from the top of the reservoir system to the middle section of a water layer below the bitumen sand, the spacing distance of the sampling points is 2-10m, 17 sampling points are counted, the sampling points are sequentially numbered, the corresponding depths of the sampling points are recorded, and the data are shown in a table 2. It should be noted that, during sampling, about 20g of core samples are selected as reservoir samples, and when no core sample exists, 20-50g of rock debris samples are selected as reservoir samples.
Table 2 data statistics table for drilling-encountering reservoir sandstone reservoir in area of tabebuia basin tower
(2) The hydrocarbon adsorbing extract on the surface of the reservoir sample particles is obtained, and the contents of seven trace elements of Ni, V, Zn, Co, Cr, Cu and Fe in the hydrocarbon adsorbing extract are measured, wherein the data are shown in Table 2.
The method comprises the following specific steps of obtaining the adsorbed hydrocarbon extract on the surface of the reservoir sample particles:
crushing a rock core reservoir sample into single-clastic particles, and screening out the particles with the particle size of 0.063-1.000mm by using a standard sieve; stirring the rock debris reservoir sample with distilled water for multiple times, then dumping suspended mud and silt, drying the residual sand grains with coarser granularity, and then screening out grains with the grain diameter of 0.063-1.000mm by using a standard sieve; weighing about 2g of reservoir sample particles, recording the specific weight, placing the reservoir sample particles in a beaker, adding 20mL of dichloromethane, placing the reservoir sample particles in an ultrasonic instrument for ultrasonic treatment for 10min, and removing free hydrocarbon on the surfaces of the particles; after the particle sample is dried, adding 40mL of 10% hydrogen peroxide into a beaker filled with the sample to remove clay on the surface of the particles, carrying out ultrasonic treatment in an ultrasonic instrument for 10min, standing for 40min, carrying out ultrasonic treatment for 10min again, and cleaning the sample with distilled water after the ultrasonic treatment is finished until residues are cleaned; adding 40mL of 3.6% diluted hydrochloric acid into a beaker filled with a sample to remove carbonate cement on the surface of particles, carrying out ultrasonic treatment in an ultrasonic instrument for 10min, standing, stirring by using a glass rod until no bubbles are generated, and washing the sample by using distilled water until residues are cleaned; drying the granules in a drying box at 80 ℃ and placing the dried granules in a beaker; adding 20mL of dichloromethane into a beaker filled with a sample, performing ultrasonic treatment in an ultrasonic instrument for 10min to extract adsorbed hydrocarbons on the surfaces of the particles to obtain adsorbed hydrocarbon extract, and evaporating dichloromethane in the obtained adsorbed hydrocarbon extract to obtain an adsorbed hydrocarbon extract. The specific steps for determining the content of the trace elements in the adsorbed hydrocarbon extract are as follows:
adding 6mL of 5% nitric acid and 2mL of hydrogen peroxide digestion reagent into the adsorbed hydrocarbon extract, digesting in a closed microwave digestion system by adopting a microwave digestion working procedure, cooling after digestion, metering the volume to 30mL by using ultrapure water, and measuring the content of trace elements in the digested adsorbed hydrocarbon extract by adopting inductively coupled plasma mass spectrometry.
(3) And drawing a distribution profile of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the hydrocarbons adsorbed on the surfaces of the particles of the reservoir sample, as shown in fig. 3.
(4) According to fig. 3, along the depth direction of the sampling point from deep to shallow, the inflection point of the trace element content in the graph is identified when the trace element content starts and continuously deviates from the baseline, and the identification process is as follows: as can be seen from fig. 3, when the depth is below 3810m, the contents of various trace elements are low and all approach the baseline, and when the depth is above 3810m, the contents of various trace elements are high and show a sharp upward rising trend and continuously deviate from the baseline, so 3810m is the depth corresponding to the turning point, i.e., the depth of the paleor oil-water interface of the oil-gas reservoir.
The identification result is verified by adopting a reservoir quantitative fluorescence analysis technology (QGF-E), and as shown in figure 3, the method for identifying the ancient oil-water interface of the oil-gas reservoir provided by the invention has good consistency with the ancient oil-water interface obtained by the reservoir quantitative fluorescence analysis technology (QGF-E). Because the early-filled ancient oil reservoir undergoes serious reservoir formation and destruction, the oil-water interface is lost, and early-filled hydrocarbons exist in reservoir spaces such as sandstone pores in the form of asphalt. The ancient oil-water interface obtained based on the method represents the maximum range of early oil-gas reservoir formation.
Claims (7)
1. The method for identifying the ancient oil-water interface of the oil-gas reservoir is characterized by comprising the following steps of:
sampling different depth positions of a reservoir stratum target layer system in a single well in a research area to obtain a reservoir stratum sample, and recording the corresponding depth of a sampling point;
obtaining an adsorbed hydrocarbon extract on the surface of reservoir sample particles, and determining the content of trace elements in the adsorbed hydrocarbon extract; the trace elements are selected from one or more of Ni, V, Cr, Mn, Zn, Fe, Cu and Co;
drawing a distribution profile diagram of the trace element content along with the depth according to the depth of the sampling point and the corresponding trace element content data of the adsorbed hydrocarbons on the surface of the reservoir sample particles;
according to the distribution profile, identifying an inflection point when the content of the trace elements in the profile starts and continuously deviates from the baseline along the depth direction of the sampling point from deep to shallow, wherein the depth corresponding to the inflection point is the depth of an oil-gas reservoir ancient oil-water interface.
2. The method for identifying the ancient oil-water interface of the oil-gas reservoir as claimed in claim 1, wherein: the sampling position of the reservoir sample extends from the top of the target layer system of the reservoir to the middle section of the known water layer below, and the spacing distance of the sampling points is 5-10 m.
3. The method for identifying the ancient oil-water interface of the oil-gas reservoir according to claim 1 or 2, wherein the method comprises the following steps: the reservoir sample is a core sample or a rock fragment sample of the reservoir.
4. The method for identifying the ancient oil-water interface of the oil-gas reservoir as claimed in claim 1, wherein the specific steps for obtaining the hydrocarbon extract adsorbed on the surface of the reservoir sample particles are as follows: the method comprises the steps of crushing a reservoir sample into single-chip particles, removing free hydrocarbon on the surfaces of the particles by using dichloromethane, removing clay on the surfaces of the particles by using hydrogen peroxide, drying the particles, extracting adsorbed hydrocarbon on the surfaces of the particles by using dichloromethane to obtain adsorbed hydrocarbon extraction liquid, and evaporating dichloromethane in the adsorbed hydrocarbon extraction liquid to obtain an adsorbed hydrocarbon extract.
5. The method for identifying the ancient oil-water interface of the oil-gas reservoir as claimed in claim 4, wherein: for reservoir samples other than carbonate rock, after clay removal from the particle surface, dilute hydrochloric acid is also used to remove the carbonate cement from the particle surface.
6. The method for identifying the ancient oil-water interface of the oil-gas reservoir as claimed in claim 1, wherein the specific steps for measuring the content of the trace elements in the adsorbed hydrocarbon extract are as follows: adding nitric acid and a hydrogen peroxide digestion reagent into the adsorbed hydrocarbon extract, digesting in a closed microwave digestion system by adopting a microwave digestion working procedure, and measuring the content of trace elements in the digested adsorbed hydrocarbon extract by adopting an inductively coupled plasma mass spectrometry.
7. Use of the method of identifying an ancient oil and water interface of a hydrocarbon reservoir according to any one of claims 1 to 6 for reconstructing a crude oil filling history.
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