WO2017024530A1

WO2017024530A1 - Method for calculating content of organic carbon in hydrocarbon source rock

Info

Publication number: WO2017024530A1
Application number: PCT/CN2015/086673
Authority: WO
Inventors: 赵龙
Original assignee: 深圳朝伟达科技有限公司
Priority date: 2015-08-11
Filing date: 2015-08-11
Publication date: 2017-02-16
Also published as: WO2017024700A1

Abstract

Provided is a method for calculating the content of organic carbon in a hydrocarbon source rock, belonging to the field of geological petroleum exploration. The method comprises: a first shale content indication is calculated according to a natural potential logging curve (101); a second shale content indication is calculated according to a natural gamma logging curve (102); the lithological index of sand shale is calculated according to a neutron logging curve, a density logging curve and an interval transit time logging curve (103); a hydrocarbon source rock is recognized in the sand shale according to the first shale content indication, the second shale content indication and the lithological index (104); and the content of organic carbon in the hydrocarbon source rock is calculated according to the density logging curve, the interval transit time logging curve and a resistivity logging curve (105). The device comprises: a first calculation module (401), a second calculation module (402), a third calculation module (403), a recognition module (404) and a fourth calculation module (405). The accuracy of calculation of the content of organic carbon in the hydrocarbon source rock is improved through the multiple logging curves.

Description

Method for calculating organic carbon content in source rock

Technical field

The invention relates to the field of petroleum geological exploration, in particular to a method for calculating the content of organic carbon in a source rock.

Background technique

The source rock is also called the source rock. It is a rock rich in organic matter, massively producing oil and gas and discharging oil and gas. In order to extract a large amount of oil and gas, it is necessary to accurately identify the source rock. However, organic matter abundance is one of the important parameters for evaluating the hydrocarbon generation of hydrocarbon source rocks, and the organic carbon content is the main indicator reflecting the abundance of organic matter in source rocks. Therefore, the method for calculating the organic carbon content in source rocks has been widely attention.

At present, the process of calculating the organic carbon content in the source rock is specifically: the resistivity log and the acoustic time difference log measured in the field. Based on the resistivity log curve and the acoustic time difference log, a weighted average of the difference between the resistivity and the acoustic time difference is calculated. The calculated weighted average is calibrated with geochemical analysis data as the organic carbon content of the source rock.

In the process of implementing the present invention, the inventors have found that the prior art has at least the following problems:

For complex lithology, the acoustic time difference log and resistivity log are affected by lithology, hydrocarbon content and pore structure. Therefore, when calculating the organic carbon content according to the above method, the calculation accuracy is reduced.

Summary of the invention

In order to solve the problems of the prior art, embodiments of the present invention provide a method and apparatus for calculating the content of organic carbon in a source rock. The technical solution is as follows:

In one aspect, a method of calculating an organic carbon content in a source rock is provided, the method comprising:

Calculating the first shale content indication according to the natural potential logging curve;

Calculating a second shale content indication based on the natural gamma log curve;

Calculating the lithology index of sand mudstone according to neutron log curve, density log curve and acoustic time difference log;

Identifying source rocks from the sandstone mudstone according to the first shale content indication, the second shale content indication, and the lithology index;

Calculating an organic carbon content in the source rock according to the density log curve, the acoustic wave time difference log curve, and the resistivity log curve.

Optionally, the calculating a lithology index of the sand mudstone according to the neutron log curve, the density log curve, and the acoustic wave time difference log curve, including:

Calculate the neutron porosity index of the limestone according to the neutron log curve;

Calculating the apparent limestone density porosity index according to the density logging curve;

Calculating the acoustic wave porosity index of the limestone according to the acoustic time difference log;

The lithology index of the sand mudstone is calculated according to the porphyrite neutron porosity index, the ash limestone density porosity index and the ash limestone acoustic porosity index.

Optionally, the calculating a lithology index of the sandstone rock according to the porphyrite neutron porosity index, the ash limestone density porosity index, and the limestone acoustic wave porosity index, including:

Calculating a first difference between the porphyrite neutron porosity index and the ash lime density porosity index;

Calculating a second difference between the porphyrite porosity index of the limestone and the sound wave porosity index of the limestone;

Calculating a third difference between the apparent limestone density porosity index and the apparent limestone acoustic porosity index;

A lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.

Optionally, the identifying the source rock from the sandstone mudstone according to the first shale content indication, the second shale content indication, and the lithology index, including:

Selecting, from the sand mudstone, a rock formation indicating that the first shale content is greater than a first threshold, the second shale content is greater than a second threshold, and the lithology index is greater than a third threshold;

The selected rock formation is identified as a source rock.

Optionally, calculating the organic carbon content in the source rock according to the density log curve, the acoustic wave time difference log curve, and the resistivity log curve, including:

Calculating an organic carbon content in the source rock according to the density log, the acoustic time difference log, and the resistivity log according to the following formula;

TOC=(a lg R _t +b△t+c)/ρ

Wherein, in the above formula, TOC is the organic carbon content in the source rock, Rt is the resistivity value in the resistivity log, and Δt is the acoustic time difference in the acoustic time difference log, ρ For the density values in the density log, a, b, and c are known coefficients.

In another aspect, an apparatus for calculating an organic carbon content in a source rock is provided, the apparatus comprising:

a first calculation module, configured to calculate a first shale content indication according to the natural potential logging curve;

a second calculation module, configured to calculate a second shale content indication according to the natural gamma log curve;

a third calculation module is configured to calculate a lithology index of the sand mudstone according to the neutron log curve, the density log curve, and the acoustic time difference log;

An identification module for indicating, according to the first shale content indicator, the second shale content indicator, and the lithology index, Identifying source rocks from the sandstone;

And a fourth calculating module, configured to calculate an organic carbon content in the source rock according to the density logging curve, the acoustic wave time difference logging curve, and the resistivity logging curve.

Optionally, the third calculating module includes:

a first calculating unit, configured to calculate a neutron porosity index of the limestone according to the neutron log curve;

a second calculating unit, configured to calculate a limestone density porosity index according to the density logging curve;

a third calculating unit, configured to calculate a limestone acoustic wave porosity index according to the acoustic wave time difference logging curve;

And a fourth calculating unit, configured to calculate a lithology index of the sand mudstone according to the porphyrite neutron porosity index, the ash limestone density porosity index, and the ash limestone acoustic porosity index.

Optionally, the fourth calculating unit includes:

a first calculating subunit, configured to calculate a first difference between the porphyrite neutron porosity index and the ash lime density porosity index;

a second calculating subunit, configured to calculate a second difference between the porphyrite neutron porosity index and the ash lime sound porosity index;

a third calculating subunit, configured to calculate a third difference between the apparent limestone density porosity index and the apparent limestone acoustic wave porosity index;

And a fourth calculating subunit, configured to calculate a lithology index of the sand mudstone according to the first difference value, the second difference value, and the third difference value.

Optionally, the identifying module includes:

a selection unit, configured to select, from the sand mudstone, the rock formation indicating that the first shale content indicates is greater than a first threshold, the second shale content indicates greater than a second threshold, and the lithology index is greater than a third threshold;

A determining unit for determining the selected rock formation as a source rock.

Optionally, the fourth calculation module includes:

a fifth calculating unit, configured to calculate an organic carbon content in the source rock according to the density log, the acoustic time difference log, and the resistivity log according to the following formula;

TOC=(a lg R _t +b△t+c)/ρ

In an embodiment of the invention, the first shale content indication is calculated based on the natural potential log. Natural gamma The well curve calculates an indication of the second shale content. According to the neutron log curve, the density log curve and the acoustic time difference log, the lithology index of the sand mudstone is calculated. Then, based on the first shale content indication, the second shale content indicator, and the lithology index, the source rock can be identified from the sandstone mudstone. Finally, the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log. Since in the embodiment of the present invention, not only the calculation of the organic carbon content based on the resistivity log curve and the acoustic time difference log curve, but also the natural potential logging curve, the natural gamma log curve, the neutron log curve, Multiple logging curves, such as density logging curves, improve the accuracy of calculating the organic carbon content in source rocks, and provide support for the detailed description of the spatial distribution of source rock organic matter in oil and gas exploration and the prediction of favorable oil and gas exploration prospects.

DRAWINGS

In order to more clearly illustrate the technical solutions in the embodiments of the present invention, the drawings used in the description of the embodiments will be briefly described below. It is obvious that the drawings in the following description are only some embodiments of the present invention. Other drawings may also be obtained from those of ordinary skill in the art in light of the inventive work.

1 is a flow chart of a method for calculating an organic carbon content in a source rock according to a first embodiment of the present invention;

2 is a flow chart of a method for calculating organic carbon content in a source rock according to a second embodiment of the present invention;

3 is a schematic view showing a comparison result between a calculated value and an analysis value of an organic carbon content in a source rock according to a second embodiment of the present invention;

4 is a schematic structural view of an apparatus for calculating an organic carbon content in a source rock according to a third embodiment of the present invention.

detailed description

The embodiments of the present invention will be further described in detail below with reference to the accompanying drawings.

Prior to the detailed explanation of embodiments of the present invention, the concepts and structural compositions associated with source rocks are first described.

The source rock is usually mudstone or shale, which is a type of sedimentary rock with a particle diameter of less than 1/256 mm. Generally, the mudstone has a massive structure, and the shale has a bedding structure. There is no strict difference between the composition and the particle size. For the convenience of expression, the two are collectively referred to as source rocks. Among the clastic reservoirs, most of the source rocks are fine-grained sedimentary rocks dominated by mudstones and shale. The most characteristic of such rocks is the richness of organic matter and poor connectivity of pores, especially the fine pore size. The permeability of the rock is very low, so the source rock is still the most common barrier or cap. From the perspective of oil and gas generation, mudstone or shale is a source rock, which is a place where oil or natural gas is generated. Compared with mudstone and shale, sandstone and conglomerate with larger particle size have a lower proportion in sedimentary rock strata, but due to their good pore connectivity, the pore size is relatively large and the permeability is high. An important reservoir space for oil, natural gas or groundwater, known as the “reservoir” in the oil and gas industry or the hydrological engineering industry.

Organic matter and clay minerals are two major components of argillaceous source rocks. Among them, organic matter is often present in clay minerals in the form of dispersion, bedding enrichment, local enrichment, and biological residues. Organic matter and clay minerals are two important components that contribute to the log response of source rock. Logging is the difference between the physical and electrochemical properties of the organic matter and clay minerals in the rock, such as the type, abundance, compaction degree, enrichment state, mature evolution and fluid composition filled in the pores. The well curve identifies and evaluates the theoretical basis of the source rock.

The theory of organic geochemistry is that kerogen is the main body of organic matter in source rocks. Although kerogen is an organic matter in source rocks, it is separated from the inorganic minerals coexisting with it, which does not reflect the occurrence and difference of organic matter. What is the type of organic matter? Laboratory cracking analysis shows that the organic matter present in the sedimentary rock consists mainly of two parts, the soluble organic matter and the insoluble organic matter (kerogen), which together form an organically connected whole, which together reflect the surface of the deposited organic matter. The soluble organic matter is chemically bonded to the clay mineral. Among the research results obtained by the organic geochemical community, it is the discovery of low-mature oils, and it is believed that soluble organic matter contributes a lot to the formation of low-mature oils, while the abundance and occurrence of soluble organic matter are sound, The response of electric logging has a certain influence, which provides a basis for the identification and evaluation of low-mature oil using logging information. At the same time, organic matter itself has low density and adsorption characteristics, so it also has a certain impact on radioactive logging.

Embodiment 1

1 is a flow chart of a method for calculating organic carbon content in a source rock according to an embodiment of the present invention. Referring to Figure 1, the method includes:

Step 101: Calculate the first shale content indication according to the natural potential logging curve.

Step 102: Calculate a second shale content indication according to the natural gamma log curve.

Step 103: Calculate the lithology index of the sand mudstone according to the neutron log curve, the density log curve and the acoustic wave time difference log curve.

Step 104: Identify the source rock from the sandstone mudstone according to the first shale content indication, the second shale content indication, and the lithology index.

Step 105: Calculate the organic carbon content in the source rock according to the density log curve, the acoustic wave time difference log curve and the resistivity log curve.

In an embodiment of the invention, the first shale content indication is calculated based on the natural potential log. A second shale content indicator is calculated based on the natural gamma log curve. According to the neutron log curve, the density log curve and the acoustic time difference log, the lithology index of the sand mudstone is calculated. Then, based on the first shale content indication, the second shale content indicator, and the lithology index, the source rock can be identified from the sandstone mudstone. Finally, the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log. Since in the embodiment of the present invention, not only the calculation of the organic carbon content based on the resistivity log curve and the acoustic time difference log curve, but also the natural potential logging curve, the natural gamma logging curve, and the middle Multiple logging curves such as sub-logging curve and density logging curve improve the accuracy of calculating the organic carbon content in the source rock, and describe the spatial distribution of the source rock organic matter and predict the favorable oil and gas exploration prospects for oil and gas exploration. Provide support.

Optionally, the lithology index of the sandstone rock is calculated according to the neutron log curve, the density log curve, and the acoustic time difference log, including:

The lithology index of sand-shale rock is calculated according to the neutron porosity index, the limestone density porosity index and the ashes limestone acoustic porosity index.

Optionally, the lithology index of the sand-shale rock is calculated according to the ash neutron porosity index, the apparent limestone density porosity index, and the apparent limestone acoustic porosity index, including:

Calculating a first difference between the neutron porosity index of the limestone and the density index of the limestone density;

Calculating a second difference between the neutron porosity index of the limestone and the acoustic porosity index of the limestone;

Calculating a third difference between the limestone density porosity index and the apparent limestone acoustic porosity index;

The lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.

Optionally, the source rock is identified from the sandstone mudstone according to the first shale content indication, the second shale content indicator, and the lithology index, including:

Selecting, from the sand mudstone, a rock formation indicating that the first shale content is greater than the first threshold, the second shale content is greater than the second threshold, and the lithology index is greater than the third threshold;

The selected rock formation is identified as a source rock.

Optionally, the organic carbon content in the source rock is calculated based on the density log curve, the acoustic time difference log, and the resistivity log, including:

According to the density logging curve, the acoustic time difference logging curve and the resistivity logging curve, the organic carbon content in the source rock is calculated according to the following formula;

TOC=(a lg R _t +b△t+c)/ρ

Among them, in the above formula, TOC is the organic carbon content in the source rock, Rt is the resistivity value in the resistivity log, Δt is the acoustic time difference in the acoustic time log, and ρ is in the density log. Density values, a, b, and c are known coefficients.

All the above optional technical solutions may form an optional technical solution of the present invention according to any combination, and the present invention will not be repeated herein.

Embodiment 2

2 is a flow chart of a method for calculating the content of organic carbon in a source rock according to an embodiment of the present invention. Referring to Figure 2, the method includes:

Step 201: Calculate the first shale content indication according to the natural potential logging curve.

Specifically, according to the natural potential logging curve, the first shale content indication is calculated according to the following formula (1);

Among them, in the above formula (1), I _SP is the first shale content indication, SP _max is the amplitude of the natural potential on the pure sandstone, SP _min is the baseline value of the natural potential on the mudstone layer, and SP is the natural potential measurement. The natural potential log value on the well curve. In addition, when the I _SP value is larger, it indicates that the shale content in the rock formation is larger, and conversely, when the I _SP value is smaller, the shale content in the rock formation is indicated to be smaller. When the shale content in the formation is small, the formation is a sandstone layer with better permeability.

Among them, in the sand-shale section, the permeability of the sandstone layer is relatively good, showing a significant difference in the natural potential logging curve. Therefore, when the salinity of the formation water is stable on the well profile, the natural potential can be used. The relative amplitude difference defines the shale content indication of the natural potential log, such as the formula for the first shale content indication described above.

Among them, the natural potential logging curve is a curve in which the natural potential changes with the depth of the well.

Step 202: Calculate a second shale content indication according to the natural gamma log curve.

Specifically, according to the natural gamma log curve, the second shale content indication is calculated according to the following formula (2);

Among them, in the above formula (2), I _GR is the second shale content indication, GR _max is the amplitude of the natural gamma on the mudstone layer, and GR _min is the baseline value of the natural gamma on the pure sandstone layer, and GR is Natural gamma log values on natural gamma logs. In addition, when the I _GR value is larger, it indicates that the muddy content in the rock formation is larger, and conversely, when the I _GR value is smaller, the muddy content in the rock formation is indicated to be smaller.

Among them, the hydrocarbon source rock layer is generally rich in carbon, which can adsorb more radioactive elements, such as the adsorption of special element uranium, so that the source rock shows high anomaly on the natural gamma log curve, so natural gamma logging can be utilized. Curve to identify source rocks. However, the uranium content is not only related to the abundance of organic matter, but also affected by the distribution of cracks. Therefore, if the natural gamma log is used alone to identify the source rock, the accuracy will be reduced. Similarly, in a well profile with no radioactive minerals in the formation matrix and pores, the relative magnitude of the natural gamma log can indicate the amount of shale content, so the second mud can be defined based on the natural gamma log curve. The formula for the quality content indication.

Among them, the natural gamma log curve is the intensity of the gamma ray emitted during the decay of the naturally occurring radionuclide in the well, and the natural gamma log curve is also a curve that varies with the depth of the well.

Step 203: Calculate the lithology index of the sand mudstone according to the neutron log curve, the density log curve, and the acoustic wave time difference log curve.

Specifically, this step can be implemented according to the following steps (1)-(4), including:

(1) Calculate the neutron porosity index of the limestone according to the neutron log curve.

Specifically, according to the neutron log curve, the porphyrite porosity index of the limestone is calculated according to the following formula (3);

Wherein, in the above formula (3),

For the limestone neutron porosity index, CNL _ma is the neutron porosity response of the limestone skeleton, CNL _f is the neutron porosity response of the formation water, and CNL is the neutron log on the neutron log value. In addition, when

The larger the value, the greater the water porosity in the formation, and vice versa.

The smaller the value, the smaller the water-containing voids in the formation.

Among them, the limestone skeleton is a non-porous limestone.

Among them, in argillaceous sandstone reservoirs, neutron, density and acoustic three-porosity logging have large differences in sandstone and muddy. The neutron log mainly responds to the hydrogen index in the formation, and its magnitude is proportional to the hydrogen content in the formation. In the sand-shale section, the neutron response of the pure sandstone reservoir segment basically reflects the reservoir porosity, while in the mudstone section, the neutron response mainly reflects the bound water porosity of the mudstone. On argillaceous sandstone reservoirs, a weighted average of the volume fractions of the two. Since the mudstone layer contains large bound water porosity, a log response larger than that of the sandstone reservoir will appear on the measured curve. Therefore, the above formula for the neutron porosity index of the limestone can be defined.

(2) Calculate the density index of the limestone density according to the density log.

Specifically, according to the density log curve, the apparent limestone density porosity index is calculated according to the following formula (4);

Wherein, in the above formula (4),

For the limestone density porosity index, DEN _ma is the density value of the limestone skeleton, DEN _f is the density value of the formation water, and DEN is the density log value on the density log. In addition, under the condition that the reservoir section is stable in lithology,

The larger the value, the greater the porosity in the formation, and vice versa.

The smaller the value, the smaller the porosity in the formation.

Among them, the density logging mainly reflects the electron density of the gamma ray in the stratum, which approximates the stratum. The density is proportional. In the sand-shale section, the density of the pure sandstone reservoir section basically reflects the reservoir porosity. In the mudstone section, since the density of the clay is often larger than that of quartz and feldspar, the calculation of the uniform skeleton time difference is used. The density porosity is significantly smaller than the bound water porosity of the actual formation, so the above formula for the density of the limestone density can be defined.

(3) Calculate the acoustic wave porosity index of the limestone according to the acoustic time difference log.

Specifically, according to the acoustic wave time difference log curve, the limestone acoustic wave porosity index is calculated according to the following formula (5);

Wherein, in the above formula (5),

For the limestone acoustic wave porosity index, AC _f is the acoustic wave time difference response value of the formation water, AC _ma is the acoustic wave time difference response value of the limestone skeleton, and AC is the acoustic wave time difference logging value on the acoustic wave time difference logging curve. In addition, under the condition that the reservoir section is stable in lithology,

The smaller the value, the smaller the porosity in the formation.

Among them, the acoustic time difference log mainly reflects the propagation of longitudinal waves in the formation, and its size is related to the lithology and porosity of the skeleton in the formation. In the sand-shale section, the acoustic time difference in the well-knotted pure sandstone reservoir section basically reflects the reservoir porosity, while in the mudstone section, the acoustic time difference is the comprehensive response of the shale type, distribution mode and bound water porosity. Since the mudstone layer contains large bound water porosity, there is a larger acoustic time difference than the sandstone reservoir on the measured curve. Therefore, the above formula for the limestone acoustic wave porosity index can be defined.

(4) Calculate the lithology index of sand-shale rock according to the ash neutron porosity index, the limestone density porosity index and the ashes limestone acoustic porosity index.

Specifically, a first difference between the ash neutron porosity index and the ash lime density porosity index is calculated. Calculate the second difference between the neutron porosity index of the limestone and the acoustic porosity index of the limestone. Calculate the third difference between the limestone density porosity index and the apparent limestone acoustic porosity index. The lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.

Wherein, according to the first difference, the second difference and the third difference, the lithology index of the sand mudstone is calculated according to the following formula (6);

Wherein, in the above formula (6), I _lith is a lithology index,

For the first difference,

For the second difference,

For the third difference,

The difference between the first value and the second value, the first value is the sum of the porosity and density of the neutron-looking limestone in the pure sandstone section and the porosity of the limestone, and the second value is the neutron-looking limestone pore of the mudstone section. Degree and density are the sum of the limestone porosity. In addition, I _{lith is} small for the pure sandstone reservoir, close to 0, and I _{lith is} larger for the shale segment and close to 1.

It should be noted that, in the embodiment of the present invention, the first difference, the second difference, and the third difference are all positive numbers, that is, the absolute value of the difference.

Among them, in the sandstone reservoir section, the porphyrite, density and sound wave three ash limestone porosity can reflect the actual porosity of the reservoir. In the mudstone section, the porphyrite porosity of the neutron and sound waves will be much larger than the density of the limestone. Therefore, using the difference between the two ash limestone porosity, an index for identifying the lithology of the reservoir can be constructed to divide the shale section.

Step 204: Select a rock formation from the sand mudstone that indicates that the first shale content indicates greater than the first threshold, the second shale content indicates greater than the second threshold, and the lithology index is greater than the third threshold.

The first threshold, the second threshold, and the third threshold are all set in advance, and are not specifically limited in this embodiment of the present invention.

Step 206: Determine the selected rock formation as a source rock.

It should be added that in the common sand-shale reservoirs, the source rocks are mainly mudstones and shale, as well as coal-series source rocks. The coal-based source rocks are characterized by “three highs and three lows” on the logging curve, ie, high neutrons, high acoustic time difference, high resistivity, low density, low natural potential, low natural gamma (due to coal seam radioactivity) weak). Therefore, the first difference, the second difference, and the third difference described above cannot be used for the identification of coal-based source rocks. Here, the difference between the resistivity of the coal-bearing formation and the resistivity of the aqueous reservoir can be utilized, and naturally The characteristics of radioactive polar and low density identify coal-series source rocks.

In addition, when the source rock is mudstone, carbonaceous mudstone and dark mudstone may be included. The logging response of carbonaceous mudstone and dark mudstone is characterized by “five high and one low”, namely high neutron, high acoustic time difference, high electrical resistivity (higher than surrounding rock mudstone), high natural gamma, high uranium content, low density. And the layer with high organic carbon content has a relatively high natural gamma and uranium curve value. Therefore, in addition to using several indicators of the above analysis, it is necessary to separately establish other discriminant indicators to identify carbonaceous mudstone and dark mudstone.

Where, after identifying the source rock from the sandstone mud according to the above steps, the organic carbon content in the source rock can be calculated according to the following steps.

Step 207: Calculate the organic carbon content in the source rock according to the density log curve, the acoustic time difference log and the resistivity log.

Specifically, according to the density log curve, the acoustic wave time difference log curve and the resistivity log curve, the organic carbon content in the source rock is calculated according to the following formula (7);

TOC=(algR _t +b△t+c)/ρ (7)

Wherein, in the above formula (7), TOC is the organic carbon content in the source rock, Rt is the resistivity value in the resistivity log, Δt is the acoustic time difference in the acoustic time difference log, and ρ is the density measurement The density values in the well curve, a, b and c are known coefficients.

It should be additionally noted that in the embodiment of the present invention, the organic source-rich source rock has a low density, and the density log measures the bulk density of the formation, including the skeleton density and the fluid density. The density of organic matter in the source rock (1.03~1.1g/cm ³ ) is significantly lower than the density of the surrounding rock matrix (the density of the clay skeleton is 2.3-3.1g/cm ³ ), which reduces the log value of the source rock density. In low-porosity shale rich in organic matter, the change of formation density has a certain correspondence with the change of organic matter abundance. On the section with less lithological changes, there is a negative correlation between the organic matter abundance and the formation density of the shale. However, when heavy minerals are enriched, density logging is unlikely to be a reliable indicator of organic matter. Therefore, the density calculation curve can be used to correct the calculation formula of the organic carbon content.

In addition, the acoustic time difference log is also the sonic log, so Δt is the acoustic time difference in the acoustic time difference log. In addition, the three parameters a, b and c can be obtained by the least squares fitting after collecting samples from the study area system, and in order to accurately obtain the values of a, b and c, the mudstone cores can be selected. The regression analysis is performed on the well sections with long and TOC analysis data and corresponding depths.

Wherein, in the embodiment of the present invention, when the organic carbon content is calculated by the above formula (7), since the resistivity log and the acoustic time difference log are sensitive to the change of the porosity, once the baseline of a certain lithology is determined, The change in porosity directly causes the response of the two well logs, so the TOC can be calculated directly without core analysis.

Wherein, the baseline is mentioned in the above description. However, the determination method of the baseline may be: the acoustic wave time difference logging curve adopts arithmetic coordinates, and the resistivity logging curve adopts logarithmic coordinates, when the two logging curves are parallel in a certain depth or When overlapping, the log curve within this depth is determined as the baseline.

The response of the logging curve to the difference between the organic carbon content of the rock formation and the physical properties of the filled pore fluid is the basis for identifying and evaluating the source rock using the logging curve. Under normal circumstances, the higher the organic carbon content, the greater the anomaly on the log, and the abnormal value can be used to calculate the organic carbon content. When the total organic matter content in the sedimentary rock exceeds 30-35%, the rock is characterized by organic rocks. Due to the special physical properties of the dispersed organic kerogen, such as its poor conductivity, strong natural radioactivity, density close to water density, and light components, the acoustic time difference is close to 550 μs/m and the hydrogen content is close to 67%. Therefore, the good oil-bearing rock has an organic carbon TOC content of nearly 30%, which is clearly reflected in the log curve, while the poor oil-bearing rock has an organic carbon TOC content of less than 30%. Obvious anomaly, but it can still be reflected. Therefore, in the embodiment of the present invention, the above-mentioned logging curve can be used to calculate the organic carbon content in the source rock.

In addition, in order to finely evaluate the distribution of source rocks, according to the sedimentary facies characteristics of the source rocks in the study area, the source rocks are classified into high quality, medium and poor according to the organic carbon content. Generally, TOC≥2% is a high-quality source rock; 1%≤TOC≤2% is a medium source rock; 0.3%≤TOC≤1% is a poor source rock. Through this classification, continuous evaluation of source rock distribution characterization For the different levels of TOC interval, combined with organic geochemical analysis, the reservoir source and organic geochemical integrated evaluation of the source rock thickness map can spatially achieve the fine evaluation of the source rock and solve the heterogeneity of the source rock. Sexual evaluation problem.

3 is a comparison of the geochemical analysis values of the organic carbon layer of the deep layer of the deep well 80 of the Yuzhong depression in the Suizhong depression with the calculated value of the log response. The continuous curve from the TOC is calculated according to the method provided by the embodiment of the present invention. The curve of the organic carbon content, while the horizontal short line on the TOC curve is the organic carbon content obtained by geochemical analysis. It can be seen that the organic carbon content calculated by the method provided by the embodiment of the present invention is in good agreement with the geochemical analysis value of the high organic carbon content layer. Therefore, the method provided by the embodiment of the present invention has different organic carbon content. The source rock can also achieve better results.

In an embodiment of the invention, the first shale content indication is calculated based on the natural potential log. A second shale content indicator is calculated based on the natural gamma log curve. According to the neutron log curve, the density log curve and the acoustic time difference log, the lithology index of the sand mudstone is calculated. Then, based on the first shale content indication, the second shale content indicator, and the lithology index, the source rock can be identified from the sandstone mudstone. Finally, the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log. Since in the embodiment of the present invention, not only the calculation of the organic carbon content based on the resistivity log curve and the acoustic time difference log curve, but also the natural potential logging curve, the natural gamma log curve, the neutron log curve, Multiple logging curves, such as density logging curves, improve the accuracy of calculating the organic carbon content in source rocks, and provide support for the detailed description of the spatial distribution of source rock organic matter in oil and gas exploration and the prediction of favorable oil and gas exploration prospects.

Embodiment 3

4 is a schematic structural view of an apparatus for calculating an organic carbon content in a source rock according to an embodiment of the present invention. Referring to FIG. 4, the device includes: a first calculation module 401, a second calculation module 402, a third calculation module 403, an identification module 404, and a fourth calculation module 405;

a first calculating module 401, configured to calculate a first shale content indication according to the natural potential logging curve;

a second calculation module 402, configured to calculate a second shale content indication according to the natural gamma log curve;

a third calculation module 403, configured to calculate a lithology index of the sand mudstone according to the neutron log curve, the density log curve, and the acoustic time difference log;

The identification module 404 is configured to identify the source rock from the sandstone mudstone according to the first shale content indication, the second shale content indication, and the lithology index;

The fourth calculation module 405 is configured to calculate the organic carbon content in the source rock according to the density log curve, the acoustic wave time difference log curve and the resistivity log curve.

Optionally, the third calculating module 403 includes:

The fourth calculating unit is configured to calculate the lithology index of the sand-shale rock according to the porphyrite porosity index, the limestone density porosity index and the apparent limestone acoustic porosity index.

Optionally, the fourth calculating unit comprises:

a first calculating subunit for calculating a first difference between the ash neutron porosity index and the apparent limestone density porosity index;

a second calculating subunit for calculating a second difference between the porphyrite porosity index of the limestone and the acoustic wave porosity index of the limestone;

a third calculating subunit for calculating a third difference between the apparent limestone density porosity index and the apparent limestone acoustic porosity index;

Optionally, the identification module 404 includes:

a selection unit, configured to select, from the sand mudstone, a formation having a first shale content indicating greater than a first threshold, a second shale content indicating greater than a second threshold, and a lithology index greater than a third threshold;

Optionally, the fourth calculating module 405 includes:

a fifth calculating unit, configured to calculate an organic carbon content in the source rock according to the density log, the acoustic time difference log, and the resistivity log;

TOC=(a lg R _t +b△t+c)/ρ

It should be noted that the device for calculating the organic carbon content in the source rock provided by the above embodiment is only illustrated by the division of the above functional modules when calculating the organic carbon content in the source rock. In practical applications, according to the needs, The above function assignment is completed by different functional modules, that is, the internal structure of the device is divided into different functional modules to complete all or part of the functions described above. In addition, the apparatus for calculating the organic carbon content in the source rock provided by the above embodiment is the same as the method embodiment for calculating the organic carbon content in the source rock. The specific implementation process is described in detail in the method embodiment, and details are not described herein again.

The serial numbers of the embodiments of the present invention are merely for the description, and do not represent the advantages and disadvantages of the embodiments.

A person skilled in the art may understand that all or part of the steps of implementing the above embodiments may be completed by hardware, or may be instructed by a program to execute related hardware, and the program may be stored in a computer readable storage medium. The storage medium mentioned may be a read only memory, a magnetic disk or an optical disk or the like.

The above are only the preferred embodiments of the present invention, and are not intended to limit the present invention. Any modifications, equivalents, improvements, etc., which are within the spirit and scope of the present invention, should be included in the protection of the present invention. Within the scope.

Claims

A method for calculating an organic carbon content in a source rock, characterized in that the method comprises:

Calculating the first shale content indication according to the natural potential logging curve;

Calculating a second shale content indication based on the natural gamma log curve;

Calculating the lithology index of sand mudstone according to neutron log curve, density log curve and acoustic time difference log;

Identifying source rocks from the sandstone mudstone according to the first shale content indication, the second shale content indication, and the lithology index;

Calculating an organic carbon content in the source rock according to the density log curve, the acoustic wave time difference log curve, and the resistivity log curve.
The method of claim 1 wherein said calculating a lithology index of the sand-shale rock based on the neutron log curve, the density log curve, and the sonic time difference log curve comprises:

Calculate the neutron porosity index of the limestone according to the neutron log curve;

Calculating the apparent limestone density porosity index according to the density logging curve;

Calculating the acoustic wave porosity index of the limestone according to the acoustic time difference log;

The lithology index of the sand mudstone is calculated according to the porphyrite neutron porosity index, the ash limestone density porosity index and the ash limestone acoustic porosity index.
The method according to claim 2, wherein said calculating a sand-shale rock based on said limestone neutron porosity index, said limestone density porosity index, and said limestone acoustic wave porosity index Lithology index, including:

Calculating a first difference between the porphyrite neutron porosity index and the ash lime density porosity index;

Calculating a second difference between the porphyrite porosity index of the limestone and the sound wave porosity index of the limestone;

Calculating a third difference between the apparent limestone density porosity index and the apparent limestone acoustic porosity index;

A lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.
The method of claim 1 wherein said identifying source rocks from said sandstone mudstone based on said first shale content indicator, said second shale content indicator, and said lithology index ,include:

Selecting, from the sand mudstone, a rock formation indicating that the first shale content is greater than a first threshold, the second shale content is greater than a second threshold, and the lithology index is greater than a third threshold;

The selected rock formation is identified as a source rock.
The method according to any one of claims 1 to 4, wherein said calculating said source rock according to said density log, said acoustic time difference log and resistivity log Organic carbon content, including:

Calculating an organic carbon content in the source rock according to the density log, the acoustic time difference log, and the resistivity log according to the following formula;

TOC=(algR t +bΔt+c)/ρ

Wherein, in the above formula, TOC is the organic carbon content in the source rock, Rt is the resistivity value in the resistivity log, and Δt is the acoustic time difference in the acoustic time difference log, ρ is The density values in the density log, a, b, and c are known coefficients.