CN107449823B - Paleo-oil-water interface identification method and its application in reconstruction of crude oil charging history - Google Patents

Abstract

The invention proposes a method for identifying the paleo-oil-water interface of oil and gas reservoirs and its application in reconstructing the crude oil charging history, which can quickly and accurately identify the paleo-oil-water interface of oil and gas reservoirs, so as to facilitate the reconstruction of the crude oil charging history. The method for identifying paleo-oil-water interface in oil and gas reservoirs includes the following steps: sampling at different depths of the reservoir target formation in a single well in the study area to obtain reservoir samples, and record the depth corresponding to the sampling points; Hydrocarbon extract, measure the content of trace elements in the adsorbed hydrocarbon extract; draw the distribution profile of trace element content with depth according to the depth of the sampling point and the data of the trace element content of the adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles; According to the distribution profile, along the depth of the sampling point from deep to shallow, identify the inflection point when the trace element content starts and continues to deviate from the baseline. The depth corresponding to this inflection point is the depth of the paleo-oil-water interface of the oil and gas reservoir.

Description

Paleo-oil-water interface identification method and its application in reconstruction of crude oil charging history

technical field

The invention relates to the field of oil and gas exploration, in particular to the field of element geochemistry (oil and gas accumulation), in particular to a method for identifying a paleo-oil-water interface in oil and gas reservoirs and its application in reconstructing the history of crude oil charging.

Background technique

The research on the history of oil and gas accumulation is an important part of the study of the law of oil and gas accumulation. Through the study of the crude oil charging history, combined with the source rock evolution and structural analysis during the charging period, we can better understand the formation process and main factors of the relevant oil reservoirs. Controlling factors to help better predict the location and nature of hydrocarbon reservoirs during this period. The change of oil-water interface in oil and gas reservoirs records the history of adjustment, reformation and destruction after the formation of oil and gas reservoirs. By restoring the position of the paleo-oil-water interface of oil and gas reservoirs in geological history, the time of oil and gas migration and accumulation can be determined, the adjustment process of fluid accumulation can be restored, the formation and distribution rules of oil and gas reservoirs can be understood, and the foundation for the study of oil and gas accumulation characteristics can be laid.

At present, there are two main methods to determine the paleo-oil-water interface of oil and gas reservoirs: one is to identify paleo-oil layers and paleo-migration channels through the analysis of the abundance of oil inclusions; the other is to use reservoir quantitative fluorescence technology (QGF, QGF -E, etc.) Identify ancient oil columns, ancient and current oil-water interfaces, and then deduce the history of crude oil charging. Among them, the common method for the analysis of the abundance of oil and gas inclusions is to identify and count hydrocarbon inclusions in thin slices under a fluorescence microscope, using GOI (the proportion of oil-bearing inclusions in clastic rocks) and FOI (carbonate). The ratio of oil inclusions in rocks) technology to estimate the abundance of oil and gas inclusions. However, this method is labor-intensive, requires professional skills in identifying inclusions, has large human factors, and has a limited scope of observation and statistics, making it difficult to reflect the full picture of the reservoir. Reservoir Quantitative Fluorescence (QGF-E) is based on the detection of organic molecules (such as aromatic hydrocarbons, polar organic compounds and bitumen), which may be damaged in some cases (such as deep, ancient oil and gas reservoirs) (such as high temperature) secondary cracking of lower oil), resulting in failure to identify the oil-water interface or inaccurate identification, which limits the method to a certain extent.

Therefore, how to provide a quick, simple and more accurate method for identifying the paleo-oil-water interface in oil and gas reservoirs, so as to quickly and accurately reconstruct the history of crude oil charging, is a technical problem that needs to be solved urgently.

SUMMARY OF THE INVENTION

Aiming at the above-mentioned technical problems, the present invention proposes a method for identifying the paleo-oil-water interface of oil and gas reservoirs and its application in reconstructing the filling history of crude oil, which can quickly, simply, economically and accurately identify the paleo-oil-water interface of oil and gas reservoirs, so as to facilitate the reconstruction of crude oil. Filled with history.

In order to achieve the above object, the technical scheme adopted in the present invention is:

The present invention provides a method for identifying the paleo-oil-water interface of oil and gas reservoirs, comprising the following steps:

Sampling at different depths of the reservoir target strata in a single well in the study area to obtain reservoir samples, and record the depths corresponding to the sampling points;

Obtaining the adsorbed hydrocarbon extract on the surface of the particles of the reservoir sample, and measuring the content of trace elements in the adsorbed hydrocarbon extract;

According to the depth of the sampling point and the data of the trace element content of adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles, draw the distribution profile of trace element content with depth;

According to the distribution profile, along the depth of the sampling point from deep to shallow, identify the inflection point when the trace element content starts and continues to deviate from the baseline.

Preferably, the sampling position of the reservoir sample extends from the top of the reservoir target formation to the middle section of the known water layer below, and the sampling points are separated by a distance of 5-10m.

Preferably, the reservoir sample is a core sample or a cuttings sample of the reservoir.

Preferably, the specific steps for obtaining the adsorbed hydrocarbon extract on the particle surface of the reservoir sample are: crushing the reservoir sample into monoclastic particles, using dichloromethane to remove free hydrocarbons on the particle surface, using hydrogen peroxide to remove the clay on the particle surface, Drying, using dichloromethane to extract the adsorbed hydrocarbons on the surface of the particles, to obtain an adsorbed hydrocarbon extract, and evaporating the dichloromethane in the adsorbed hydrocarbon extract to obtain an adsorbed hydrocarbon extract.

Preferably, for reservoir samples other than carbonate rocks, after removing the clay on the particle surface, it is also necessary to use dilute hydrochloric acid to remove the carbonate cement on the particle surface.

Preferably, the specific steps for determining the content of trace elements in the adsorbed hydrocarbon extract are as follows: adding nitric acid and hydrogen peroxide digestion reagents to the adsorbed hydrocarbon extract, and using a microwave digestion working procedure for digestion in a closed microwave digestion system, Inductively coupled plasma mass spectrometry was used to determine the content of trace elements in the digested adsorbed hydrocarbon extracts.

Preferably, the trace elements are selected from one or more of Ni, V, Cr, Mn, Zn, Fe, Cu, and Co.

The present invention also proposes an application of the method for identifying the paleo-oil-water interface of oil and gas reservoirs according to any one of the above technical solutions in reconstructing the history of crude oil charging.

Compared with the prior art, the advantages and positive effects of the present invention are:

1. The method for identifying paleo-oil-water interfaces in oil and gas reservoirs provided by the present invention is based on the vertical changes of the content of trace elements in the adsorbed hydrocarbons on the particle surfaces of reservoir samples of different depths of a single well to identify paleo-oil-water interfaces, which is fast, simple, economical, highly sensitive, The advantages of easy access to samples and less sample volume required;

2. The method for identifying the paleo-oil-water interface of oil and gas reservoirs provided by the present invention is not affected by secondary changes such as oil and gas migration and fractionation, oil reservoir destruction, oxidation and biodegradation, has high accuracy, and can be widely used in the study of oil and gas accumulation processes. promotion.

Description of drawings

1 is a flowchart of a method for identifying paleo-oil-water interfaces in oil and gas reservoirs provided by an embodiment of the present invention;

2 is a cross-sectional view of the distribution of trace element content with depth in the Cretaceous sandstone oil reservoir drilled in the Dampier Basin of the Northwest Continental Shelf of Australia provided in Example 1 of the present invention;

3 is a sectional view of the distribution of trace element content with depth in the Tazhong area of the Tarim Basin drilled into the Silurian sandstone oil reservoir provided by Embodiment 2 of the present invention;

Detailed ways

The technical solutions in the embodiments of the present invention will be described clearly and completely below. Obviously, the described embodiments are only a part of the embodiments of the present invention, rather than all the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative efforts shall fall within the protection scope of the present invention.

An embodiment of the present invention provides a method for identifying a paleo-oil-water interface in an oil and gas reservoir, the flowchart of which is shown in FIG. 1 and includes the following steps:

S1: Sampling at different depths of the reservoir target formation in a single well in the study area to obtain reservoir samples, and record the depths corresponding to the sampling points.

In this step, it should be noted that when sampling, the best test object is a reservoir sample with moderate particle size, good sorting ability, low mud content and good physical properties, and the sampling size is generally 20-50g. In addition, it should also be noted that the target reservoir series refers to the oil-gas-bearing formations in the study area for reconstructing the history of crude oil charging or the paleo-oil-bearing formations in the geological history period. The sampling method of sampling at different depths in this step is more systematic and the samples are more representative, which is conducive to the subsequent study of the variation law of the content of trace elements in the adsorbed hydrocarbons on the surface of the reservoir sample particles with depth.

S2: Obtain the adsorbed hydrocarbon extract on the particle surface of the reservoir sample, and measure the content of 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 atomic absorption spectrometry (AAS), X-ray fluorescence spectrometry (XRF) ), inductively coupled plasma atomic emission spectrometry (ICP-AES), inductively coupled plasma mass spectrometry (ICP-MS) and other analytical methods.

S3: According to the depth of the sampling point and the data of the trace element content of adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles, draw a profile of the distribution of trace element content with depth.

In this step, it should be noted that when drawing the distribution profile of trace element content with depth, the line graph is drawn with the trace element content of hydrocarbon adsorbed on the surface of the reservoir sample particles as the abscissa and the depth of the sampling point as the ordinate.

S4: According to the distribution profile, along the depth of the sampling point from deep to shallow, identify the inflection point when the trace element content starts and continues to deviate from the baseline, and the depth corresponding to the inflection point is the depth of the paleo-oil-water interface of the oil and gas reservoir.

In this step, it should be noted that for a reservoir that has been filled with oil and gas one or more times during the geological history, during the process of crude oil migration and accumulation, the crude oil components mainly composed of asphaltenes will be adsorbed in the reservoir. On the particle surface, the adsorbed hydrocarbon extract on the particle surface is enriched with relatively high abundance of trace elements, and the content of trace elements in the hydrocarbon adsorbed on the surface of the reservoir particles is not affected by oil and gas migration, reservoir damage, oxidation and biodegradation. As a result, the oil saturation of the reservoir increases, and the content of trace elements in the adsorbed hydrocarbons on the surface of the reservoir particles also increases accordingly; while for the water layer, due to the low oil saturation and the lack of crude oil migration and accumulation, the content of adsorbed hydrocarbons on the surface of the reservoir particles increases accordingly. lower, the trace element content is correspondingly lower. Therefore, according to the distribution profile of trace element content in hydrocarbon extracts adsorbed by single-well reservoir particles with depth, we can identify the depth boundaries where there are significant differences in trace element content in the figure (that is, identify the time when the trace element content starts and continues to deviate from the baseline in the figure. Inflection point), the paleo-oil-water interface can be divided, and the paleo-oil layer and water layer can be identified.

The method for identifying the paleo-oil-water interface of oil and gas reservoirs provided by the present invention is based on the vertical variation of the content of trace elements in the adsorbed hydrocarbons on the particle surfaces of reservoir samples of different depths of a single well, and has the advantages of rapidity, simplicity, economy, high sensitivity and easy sampling. The advantages of acquisition, less sample volume and so on. Moreover, the method for identifying the paleo-oil-water interface of oil and gas reservoirs is not affected by secondary changes such as oil and gas migration and fractionation, reservoir destruction, oxidation and biodegradation, with high accuracy, and can be widely used in the study of oil and gas accumulation processes.

In a preferred embodiment, the sampling position of the reservoir sample extends from the top of the reservoir target formation to the middle section of the known water layer below, and the sampling points are separated by a distance of 5-10 m. In this preferred embodiment, it should be noted that the optimal sampling range extends from the top of the reservoir target formation to the middle of the known water layer below, and the sampling points within this range are more representative. The sampling point spacing distance defined in the embodiment is an optimal range, and those skilled in the art can specifically select an appropriate spacing distance according to the thickness and uniformity of the reservoir. For example, when the thickness of the reservoir is thick and the lithology of the reservoir is relatively uniform, the distance between sampling points can be appropriately increased; otherwise, the distance between sampling points can be appropriately reduced; in addition, the sampling points close to the oil-gas-water interface The interval can be appropriately reduced to encrypt the samples. The reservoir samples obtained by this sampling method are more representative, and the number of sampling points is moderate and the workload is small.

In a preferred embodiment, the reservoir sample is a core sample or a cuttings sample of the reservoir. In this preferred embodiment, it should be noted that the core sample is the best for the reservoir sample. If there is no core sample, the cutting sample can also be used instead. When the cutting sample is used as the reservoir sample, the sampling amount is relatively Core samples are slightly more. The method for identifying the paleo-oil-water interface of oil and gas reservoirs provided by this preferred embodiment, the reservoir samples are not limited to core samples, and the sampling is easier, and is also applicable to reservoirs without coring sections.

In a preferred embodiment, the specific steps for obtaining the adsorbed hydrocarbon extract on the particle surface of the reservoir sample are: crushing the reservoir sample into monoclastic particles, using dichloromethane to remove free hydrocarbons on the surface of the particles, and using hydrogen peroxide to remove the surface of the particles. The clay is dried, and the adsorbed hydrocarbons on the surface of the particles are extracted with dichloromethane to obtain an adsorbed hydrocarbon extract, and the dichloromethane in the adsorbed hydrocarbon extract is evaporated to obtain an adsorbed hydrocarbon extract. In this preferred embodiment, purer and more representative samples of reservoir particles such as quartz can be obtained through crushed sample screening. By chemical cleaning with dichloromethane and hydrogen peroxide, free hydrocarbons and clays on the surface of the particles can be removed to avoid free hydrocarbons and The influence of trace elements contained in clay minerals on the test results, this sample processing process is more standardized, which lays a good foundation for the subsequent accurate determination of trace element content. It should be noted that, in this preferred embodiment, after the reservoir samples are crushed to single clastic particles, for clastic rock core reservoir samples, particles with a particle size in the range of 0.063-1.000 mm are screened out with a standard sieve ; For clastic rock debris reservoir samples, it is necessary to stir and wash with distilled water for several times, pour out the suspended mud and silt, and dry the remaining coarser sand particles. Particles in the range of 1.000mm; for carbonate reservoir samples, the samples can be directly crushed to less than 0.3mm, and the particles in the range of 0.1-0.3mm can be screened out using a standard sieve. When using dichloromethane to remove free hydrocarbons on the surface of the particles, specifically, about 2 g of the reservoir sample particles can be weighed, placed in a beaker, added with 20-30 mL of dichloromethane, and placed in a sonicator to sonicate for 10-15 min. It is understandable that Yes, those skilled in the art can specifically select the sampling amount of particles, the amount of methylene chloride added and the ultrasonic extraction time according to the actual situation of the particles in the reservoir sample. When using hydrogen peroxide to remove the clay on the surface of the particles, after the particle samples are dried, add 30-40 mL of 10% hydrogen peroxide to the beaker containing the samples, ultrasonicate in the ultrasonic device for 10-15 minutes, stand still for 40-45 minutes, and then ultrasonicate again. 10-15min, after the ultrasonication, the sample is washed with distilled water until the residue is washed. It is understandable that those skilled in the art can specifically select the concentration and addition amount of hydrogen peroxide, and the ultrasonic time according to the situation of the reservoir sample particles. When drying the sample, place the above-treated sample in a tray, put it in a constant temperature drying oven, and bake it at 80°C for 1-4 hours until the sample is dry. It is understandable that those skilled in the art can The condition of the sample particles, the specific selection of drying temperature and time. When dichloromethane is used to extract the adsorbed hydrocarbons on the surface of the particles, 20-30 mL of dichloromethane can be added to the beaker containing the dried sample, and sonicated in the ultrasonic device for 10-20 min. The obtained adsorbed hydrocarbon extract can be obtained before detection. It is stored in a 15 mL reagent bottle with a cap, and it can be understood that those skilled in the art can specifically select the amount of dichloromethane added and the ultrasonic time according to the conditions of the reservoir sample particles.

In a further preferred embodiment, for reservoir samples other than carbonate rock, after removing the clay on the particle surface, dilute hydrochloric acid needs to be used to remove the carbonate cement on the particle surface. In this preferred embodiment, dilute hydrochloric acid is used to remove the carbonate cement on the particle surface, which can remove the influence of the carbonate cement on the detection of trace element content. It should be noted that, in this embodiment, the reservoir samples other than carbonate rocks are mainly clastic rock reservoir samples, while for carbonate rock reservoir samples, because the structure contains a large amount of carbon For carbonate minerals, dilute hydrochloric acid treatment will destroy the sample structure, so for carbonate rock reservoir samples, dilute hydrochloric acid treatment cannot be used. In addition, in this preferred embodiment, when dilute hydrochloric acid is used to remove the carbonate cement on the surface of the particles, specifically, 30-40 mL of 3.6% dilute hydrochloric acid can be added to the beaker containing the sample, and sonicated for 10- After 15min, stand still, stir with a glass rod until no bubbles are generated, and wash the sample with distilled water until the residue is washed. It is understandable that those skilled in the art can specifically select the concentration of dilute hydrochloric acid and Add amount, and sonication time.

In a preferred embodiment, the specific steps for determining the content of trace elements in the adsorbed hydrocarbon extract are: adding nitric acid and hydrogen peroxide digestion reagents to the adsorbed hydrocarbon extract, and using microwave digestion in a closed microwave digestion system. The digestion procedure was carried out, and the content of trace elements in the digested adsorbed hydrocarbon extracts was determined by inductively coupled plasma mass spectrometry. During digestion in this preferred embodiment, a digestion reagent composed of nitric acid and hydrogen peroxide is used, and the internal heating and absorption polarization caused by microwave radiation are used to obtain a higher digestion temperature and pressure, accelerate the digestion rate, and reduce the consumption of the digestion reagent, and , Digestion in a closed state, the digestion is more thorough, and it is not easy to pollute the environment. It should be noted that, during digestion, 6-10 mL of 5% nitric acid and 2-5 mL of hydrogen peroxide can be added to the adsorbed hydrocarbon extract for digestion, cooled after digestion, and the volume is adjusted to 20-30 mL with ultrapure water. It should be understood that those skilled in the art can specifically select the concentration and addition amount of nitric acid and the addition amount of hydrogen peroxide according to the situation of adsorbing the hydrocarbon extract. In addition, when the content of trace elements is measured in this preferred embodiment, inductively coupled plasma mass spectrometry (ICP-MS) is used for measurement, and 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, and Co. In this preferred embodiment, it should be noted that since the content of different trace elements in the adsorbed hydrocarbons on the particle surface of the same reservoir sample varies greatly, the determination of the content of various trace elements is conducive to improving the accuracy of identification.

The embodiment of the present invention also provides an application of the method for identifying the paleo-oil-water interface of oil and gas reservoirs according to any one of the above-mentioned embodiments in reconstructing the charging history of crude oil. The change of oil-water interface in oil and gas reservoirs records the history of adjustment, reformation and destruction after the formation of oil and gas reservoirs. For a specific oil and gas reservoir in a certain study area, the paleo-oil-water interface classified based on the method for identifying paleo-oil-water interface of oil and gas reservoirs described in any of the above embodiments has the following situations: (1) If the oil is lower than the oil ( gas) water interface, indicating that the ancient oil reservoir formed by charging in the early stage suffered secondary adjustment and reformation in the later stage, and the scale of the oil reservoir became smaller; (2) If it is higher than the oil (gas) water interface explained by the present, it indicates that the scale of the early oil reservoir is It is smaller than the current oil and gas reservoir, and the early oil reservoir has been adjusted and reformed recently. For example, the recent charging of high-mature condensate oil and gas has moved the oil-water interface down; (3) If it is consistent with the current oil-water interface, it indicates that the ancient oil reservoir has not been formed since its formation. After obvious adjustment and transformation; in addition, if the oil-water interface is missing today, it shows that the ancient oil reservoir has been severely damaged, and it is mostly existing in the form of asphalt. Combined with the corresponding hydrocarbon generation and expulsion characteristics of source rocks and structural evolution analysis, the hydrocarbon accumulation process in the study area can be further explained.

In order to introduce the method for identifying the paleo-oil-water interface of oil and gas reservoirs provided by the embodiments of the present invention more clearly and in detail, the following description will be made with reference to specific embodiments.

Example 1

The Dampier Basin on the northwest continental shelf of Australia was selected as the study area to identify the paleo-oil-water interface of oil and gas reservoirs, including the following steps:

(1) Sampling a single well drilled into a Cretaceous sandstone reservoir in the basin to obtain a reservoir sample. The sampling location extends from the top of the Cretaceous reservoir to the middle of the known water layer below, and the interval between sampling points is 5 -10m, a total of 7 sampling points, numbered in sequence, record the depth corresponding to the sampling points, the data is shown in Table 1. It should be noted that when sampling, about 20 g of core samples are selected as reservoir samples, and when there are no core samples, 20-50 g of cuttings samples are selected as reservoir samples.

Table 1 Statistics of Cretaceous sandstone reservoirs drilled in Dampier Basin, Northwest Shelf, Australia

(2) Obtain the adsorbed hydrocarbon extract on the particle surface of the reservoir sample, and measure the contents of seven trace elements including Ni, Cr, Mn, Zn, V, Fe, and Cu in the adsorbed hydrocarbon extract. The data are shown in Table 1.

Wherein, the specific steps for obtaining the adsorbed hydrocarbon extract on the particle surface of the reservoir sample are as follows:

The core reservoir samples are crushed to single debris particles, and the particles with a particle size in the range of 0.063-1.000mm are screened with a standard sieve; for the rock debris reservoir samples, after several times of elutriation with distilled water, the suspended mud is discarded. and silt, dry the remaining sand with coarser particle size, and then screen out the particles with a particle size of 0.063-1.000mm using a standard; weigh about 2g of the reservoir sample particles and record the specific weight, put it in a beaker, add 20mL Dichloromethane was placed in a sonicator for 10 min to sonicate to remove free hydrocarbons on the surface of the particles; after the particle samples were dried, 40 mL of 10% hydrogen peroxide was added to the beaker containing the samples to remove the clay on the surface of the particles. Ultrasonic for 10min, static for 40min, then ultrasonic for 10min. After ultrasonication, wash the sample with distilled water until the residue is washed; add 40mL of 3.6% dilute hydrochloric acid to the beaker containing the sample to remove the carbonate cement on the particle surface, After sonicating for 10 min in the ultrasonic instrument, stand still, stir with a glass rod until no bubbles are generated, wash the sample with distilled water until the residue is washed; dry the particles in a drying oven at 80 °C, and place them in a beaker; Add 20 mL of dichloromethane to the beaker of the sample, and sonicate for 10 min in an ultrasonic instrument to extract the adsorbed hydrocarbons on the surface of the particles to obtain an adsorbed hydrocarbon extract, and evaporate the dichloromethane in the obtained adsorbed hydrocarbon extract to obtain an adsorbed hydrocarbon extract. .

The specific steps for determining the content of trace elements in the adsorbed hydrocarbon extract are as follows:

6 mL of 5% nitric acid and 2 mL of hydrogen peroxide digestion reagent were added to the adsorbed hydrocarbon extract, and the microwave digestion working procedure was used for digestion in a closed microwave digestion system. After digestion, it was cooled, and the volume was adjusted to 30 mL with ultrapure water. Plasma mass spectrometry determination of trace element content in digested adsorbed hydrocarbon extracts.

(3) According to the depth of the sampling point and the data of the trace element content of adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles, draw a profile of the distribution of trace element content with depth, as shown in Figure 2.

(4) According to Figure 2, along the depth of the sampling point from deep to shallow, identify the inflection point when the content of trace elements in the figure begins and continues to deviate from the baseline. The identification process is: as can be seen from Figure 2, when the depth is below 1295m, various The content of trace elements is relatively low, all close to the baseline, while above 1295m, the contents of various trace elements show a sharp increase trend and continue to deviate from the baseline. Therefore, 1295m is the depth corresponding to the inflection point, that is, the depth of the paleo-oil-water interface of the oil and gas reservoir. .

The identification result is verified by the quantitative reservoir fluorescence analysis technology (QGF-E), as shown in Fig. 2, it can be seen that the oil and gas reservoir paleo-oil-water interface identification method provided by the present invention and the reservoir quantitative fluorescence technology (QGF-E) obtain The oil-water interface has good consistency. The paleo-oil-water interface of oil and gas reservoirs obtained based on this method is roughly equivalent to the current depth of oil-water interface obtained based on the conclusion of single-well oil testing, indicating that after the formation of crude oil charging in the geological history, the reservoir has not been significantly adjusted and reformed, and the later preservation conditions are relatively poor. it is good.

Example 2

The Tazhong area of the Tarim Basin was selected as the study area to identify the paleo-oil-water interface of oil and gas reservoirs, including the following steps:

(1) Systematically sample a single well drilled into the Silurian bituminous sandstone reservoir in this area to obtain reservoir samples. The sampling location extends from the top of the reservoir Silurian to the middle of the water layer below the bituminous sands. The interval distance is 2-10m, a total of 17 sampling points, numbered sequentially, and the depth corresponding to the sampling points is recorded. The data are shown in Table 2. It should be noted that when sampling, about 20 g of core samples are selected as reservoir samples, and when there are no core samples, 20-50 g of cuttings samples are selected as reservoir samples.

Table 2 Statistical table of data of drilling Silurian sandstone reservoirs in Tazhong area of Tarim Basin

(2) Obtain the adsorbed hydrocarbon extract on the particle surface of the reservoir sample, and determine the contents of seven trace elements including Ni, V, Zn, Co, Cr, Cu, and Fe in the adsorbed hydrocarbon extract. The data are shown in Table 2.

Wherein, the specific steps for obtaining the adsorbed hydrocarbon extract on the particle surface of the reservoir sample are as follows:

The core reservoir samples are crushed to single debris particles, and the particles with a particle size in the range of 0.063-1.000mm are screened with a standard sieve; for the rock debris reservoir samples, after several times of elutriation with distilled water, the suspended mud is discarded. and silt, dry the remaining sand with coarser particle size, and then screen out the particles with a particle size of 0.063-1.000mm using a standard; weigh about 2g of the reservoir sample particles and record the specific weight, put it in a beaker, add 20mL Dichloromethane was placed in a sonicator for 10 min to sonicate to remove free hydrocarbons on the surface of the particles; after the particle samples were dried, 40 mL of 10% hydrogen peroxide was added to the beaker containing the samples to remove the clay on the surface of the particles. Ultrasonic for 10min, static for 40min, then ultrasonic for 10min. After ultrasonication, wash the sample with distilled water until the residue is washed; add 40mL of 3.6% dilute hydrochloric acid to the beaker containing the sample to remove the carbonate cement on the particle surface, After sonicating for 10 min in the ultrasonic instrument, stand still, stir with a glass rod until no bubbles are generated, wash the sample with distilled water until the residue is washed; dry the particles in a drying oven at 80 °C, and place them in a beaker; Add 20 mL of dichloromethane to the beaker of the sample, and sonicate for 10 min in an ultrasonic instrument to extract the adsorbed hydrocarbons on the surface of the particles to obtain an adsorbed hydrocarbon extract, and evaporate the dichloromethane in the obtained adsorbed hydrocarbon extract to obtain an adsorbed hydrocarbon extract. . The specific steps for determining the content of trace elements in the adsorbed hydrocarbon extract are as follows:

6 mL of 5% nitric acid and 2 mL of hydrogen peroxide digestion reagent were added to the adsorbed hydrocarbon extract, and the microwave digestion working procedure was used for digestion in a closed microwave digestion system. After digestion, it was cooled, and the volume was adjusted to 30 mL with ultrapure water. Plasma mass spectrometry determination of trace element content in digested adsorbed hydrocarbon extracts.

(3) According to the depth of the sampling point and the data of the trace element content of adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles, draw a profile of the distribution of trace element content with depth, as shown in Figure 3.

(4) According to Figure 3, along the depth of the sampling point from deep to shallow, identify the inflection point when the content of trace elements in the figure starts and continues to deviate from the baseline. The identification process is: as can be seen from Figure 3, when the depth is below 3810m, various The content of trace elements is low, all close to the baseline, while above 3810m, the content of various trace elements is high, and shows a sharp upward trend, continuing to deviate from the baseline. Therefore, 3810m is the depth corresponding to the turning point, that is, the oil and gas reservoir. Depth of the paleo-oil-water interface.

The identification result is verified by the quantitative reservoir fluorescence analysis technology (QGF-E), as shown in FIG. 3 , it can be seen that the oil and gas reservoir paleo-oil-water interface identification method and reservoir quantitative fluorescence analysis technology (QGF-E) provided by the present invention The obtained paleo-oil-water interface has good consistency. Due to the serious accumulation and destruction of the early-charged paleo-reservoir, the current oil-water interface is missing, and the early-charged hydrocarbons are present in the reservoir spaces such as sandstone pores and fractures in the form of bitumen. The paleo-oil-water interface obtained based on this method represents the largest range of early hydrocarbon accumulation.

Claims (7)

1. oil-gas reservoir paleo-oil-water interface identification method, is characterized in that, comprises the steps: Sampling at different depths of the reservoir target strata in a single well in the study area to obtain reservoir samples, and record the depths corresponding to the sampling points; Obtain the adsorbed hydrocarbon extract on the particle surface of the reservoir sample, and measure the content of trace elements in the adsorbed hydrocarbon extract; the trace elements are selected from one of Ni, V, Cr, Mn, Zn, Fe, Cu, and Co. or more; According to the depth of the sampling point and the data of the trace element content of adsorbed hydrocarbons on the surface of the corresponding reservoir sample particles, draw the distribution profile of trace element content with depth; According to the distribution profile, along the depth of the sampling point from deep to shallow, identify the inflection point when the trace element content starts and continues to deviate from the baseline. 2. The method for identifying paleo-oil-water interface in oil and gas reservoirs according to claim 1, wherein the sampling position of the reservoir sample extends from the top of the reservoir target formation to the middle section of the known water layer below, and the interval distance between the sampling points is 5-10m. 3 . The method for identifying the paleo-oil-water interface of an oil and gas reservoir according to claim 1 or 2 , wherein the reservoir sample is a core sample or a cuttings sample of the reservoir. 4 . 4. The method for identifying the paleo-oil-water interface of oil and gas reservoirs according to claim 1, wherein the specific step of obtaining the adsorbed hydrocarbon extract on the surface of the reservoir sample particle is: breaking the reservoir sample into monoclastic particles, using dichloride Methane removes free hydrocarbons on the surface of the particles, hydrogen peroxide is used to remove the clay on the surface of the particles, the particles are dried, and dichloromethane is used to extract the adsorbed hydrocarbons on the surface of the particles to obtain an adsorbed hydrocarbon extract, and the dichloromethane in the adsorbed hydrocarbon extract is After evaporation an adsorbed hydrocarbon extract is obtained. 5. The method for identifying paleo-oil-water interface in oil and gas reservoirs according to claim 4, characterized in that: for reservoir samples other than carbonate rock, after removing the clay on the particle surface, dilute hydrochloric acid also needs to be used to remove the surface of the particle. Carbonate cement. 6. The method for identifying the ancient oil-water interface of oil and gas reservoirs according to claim 1, wherein the concrete step of measuring the content of trace elements in the adsorbed hydrocarbon extract is: adding nitric acid and peroxide in the adsorbed hydrocarbon extract Hydrogen digestion reagent is used for digestion in a closed microwave digestion system using microwave digestion working procedures, and inductively coupled plasma mass spectrometry is used to determine the content of trace elements in the adsorbed hydrocarbon extract after digestion. 7 . The application of the method for identifying the paleo-oil-water interface of oil and gas reservoirs according to any one of claims 1 to 6 in reconstructing the charging history of crude oil. 8 .

Images