WO2017024700A1 - 一种计算烃源岩中有机碳含量的装置 - Google Patents

一种计算烃源岩中有机碳含量的装置 Download PDF

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WO2017024700A1
WO2017024700A1 PCT/CN2015/096202 CN2015096202W WO2017024700A1 WO 2017024700 A1 WO2017024700 A1 WO 2017024700A1 CN 2015096202 W CN2015096202 W CN 2015096202W WO 2017024700 A1 WO2017024700 A1 WO 2017024700A1
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log
density
index
curve
calculating
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French (fr)
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赵红霞
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深圳朝伟达科技有限公司
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V11/00—Prospecting or detecting by methods combining techniques covered by two or more of main groups G01V1/00 - G01V9/00

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  • the invention relates to the field of petroleum geological exploration, in particular to a device for calculating the content of organic carbon in a source rock.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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:
  • a method of calculating an organic carbon content in a source rock comprising:
  • 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:
  • 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 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:
  • a lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.
  • 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:
  • the selected rock formation is identified as a source rock.
  • 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:
  • TOC is the organic carbon content in the source rock
  • Rt is the resistivity value in the resistivity log
  • ⁇ t is the acoustic time difference in the acoustic time difference log
  • ⁇ is The density values in the density log
  • a, b, and c are known coefficients.
  • an apparatus for calculating an organic carbon content in a source rock 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;
  • 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.
  • 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
  • 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.
  • 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
  • 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.
  • 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 is
  • 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 is the organic carbon content in the source rock
  • Rt is the resistivity value in the resistivity log
  • ⁇ t is the acoustic time difference in the acoustic time difference log
  • ⁇ is The density values in the density log
  • a, b, and c are known coefficients.
  • 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.
  • the lithology index of the sand mudstone is calculated.
  • the source rock can be identified from the sandstone mudstone.
  • the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log.
  • FIG. 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
  • FIG. 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
  • FIG. 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
  • FIG. 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.
  • 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.
  • the mudstone has a massive structure
  • the shale has a bedding structure.
  • the composition and the particle size There is no strict difference between the composition and the particle size.
  • the two are collectively referred to as source rocks.
  • 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.
  • mudstone or shale is a source rock, which is a place where oil or natural gas is generated.
  • 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. It becomes an important reservoir space for oil, natural gas or groundwater, which is called “reservoir” in the oil and gas industry or 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.
  • 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.
  • FIG. 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.
  • 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.
  • the source rock can be identified from the sandstone mudstone.
  • 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.
  • 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:
  • the lithology index of the sand mudstone is calculated based on the first difference, the second difference, and the third difference.
  • 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:
  • the selected rock formation is identified as a source rock.
  • 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:
  • the organic carbon content in the source rock is calculated according to the following formula
  • TOC is the organic carbon content in the source rock
  • Rt is the resistivity value in the resistivity log
  • ⁇ t is the acoustic time difference in the acoustic time difference log
  • ⁇ is in the density log Density values
  • a, b, and c are known coefficients.
  • FIG. 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.
  • the first shale content indication is calculated according to the following 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
  • SP is the natural potential measurement.
  • 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.
  • 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.
  • the second shale content indication is calculated according to the following formula (2);
  • I GR is the second shale content indication
  • GR max is the amplitude of the natural gamma on the mudstone layer
  • GR min is the baseline value of the natural gamma on the pure sandstone layer
  • GR is Natural gamma log values on natural gamma logs.
  • 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.
  • 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.
  • the content of uranium is not only related to the abundance of organic matter, but also affected by the distribution of cracks. Therefore, if natural gamma is used alone The horse logging curve to identify source rocks will reduce accuracy.
  • 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 can indicate the amount of shale content, so the second mud can be defined based on the natural gamma log curve.
  • 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.
  • this step can be implemented according to the following steps (1)-(4), including:
  • the porphyrite porosity index of the limestone is calculated according to the following formula (3);
  • CNL ma is the neutron porosity response of the limestone skeleton
  • CNL f is the neutron porosity response of the formation water
  • CNL is the neutron log on the neutron log value.
  • the limestone skeleton is a non-porous limestone.
  • the neutron log mainly responds to the hydrogen index in the formation, and its magnitude is proportional to the hydrogen content in the formation.
  • the neutron response of the pure sandstone reservoir segment basically reflects the reservoir porosity
  • the neutron response mainly reflects the bound water porosity of the mudstone.
  • 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.
  • the apparent limestone density porosity index is calculated according to the following formula (4);
  • DEN ma is the density value of the limestone skeleton
  • DEN f is the density value of the formation water
  • DEN is the density log value on the density log.
  • the density logging mainly reflects the electron density of the gamma ray interacting with the source in the formation, which is approximately proportional to the density of the formation.
  • the density of the pure sandstone reservoir section basically reflects the reservoir porosity.
  • 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.
  • the limestone acoustic wave porosity index is calculated according to the following formula (5);
  • 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
  • AC is the acoustic wave time difference logging value on the acoustic wave time difference logging curve.
  • 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.
  • the acoustic time difference in the well-knotted pure sandstone reservoir section basically reflects the reservoir porosity
  • 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.
  • a first difference between the ash neutron porosity index and the ash lime density porosity index is calculated.
  • the lithology index of the sand mudstone is calculated based on 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);
  • I lith is a lithology index
  • 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
  • the second value is the neutron-looking limestone pore of the mudstone section.
  • Degree and density are the sum of the limestone porosity.
  • 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.
  • the first difference, the second difference, and the third difference are all positive numbers, that is, the absolute value of the difference.
  • the porphyrite, density and sound wave three ash limestone porosity can reflect the actual porosity of the reservoir.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • 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.
  • the organic carbon content in the source rock is calculated according to the following formula (7);
  • TOC is the organic carbon content in the source rock
  • Rt is the resistivity value in the resistivity log
  • ⁇ t is the acoustic time difference in the acoustic time difference log
  • ⁇ is the density log.
  • the density values in the curve, a, b and c are known coefficients.
  • the organic source-rich source rock has a low density
  • 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.
  • the change of formation density has a certain correspondence with the change of organic matter abundance.
  • the density calculation curve can be used to correct the calculation formula of the organic carbon content.
  • the acoustic time difference log is also the sonic log, so ⁇ t is the acoustic time difference in the acoustic time difference log.
  • 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.
  • the baseline is mentioned in the above description.
  • 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.
  • 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.
  • 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 ⁇ s/m and the hydrogen content is close to 67%.
  • 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 still can reflect from. 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.
  • the source rocks are classified into high quality, medium and poor according to the organic carbon content.
  • 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.
  • the continuously evaluated source rock distribution can be characterized as different grades of TOC intervals, and the organic source geochemical analysis can realize the source rock thickness map integrated by logging and organic geochemical analysis, which can be realized spatially. Fine evaluation of source rocks and solving the problem of heterogeneity evaluation of source rocks.
  • 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.
  • 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.
  • the source rock can be identified from the sandstone mudstone.
  • the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log.
  • 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.
  • the third calculating module 403 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
  • 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.
  • 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
  • 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.
  • 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;
  • a determining unit for determining the selected rock formation as a source rock is
  • 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 is the organic carbon content in the source rock
  • Rt is the resistivity value in the resistivity log
  • ⁇ t is the acoustic time difference in the acoustic time difference log
  • ⁇ is in the density log Density values
  • a, b, and c are known coefficients.
  • 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.
  • the source rock can be identified from the sandstone mudstone.
  • the organic carbon content in the source rock is calculated based on the density log, the acoustic time difference log and the resistivity log.
  • 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.
  • 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.
  • 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.
  • 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.

Abstract

一种计算烃源岩中有机碳含量的装置，属于石油地质勘探领域。所述装置包括：第一计算模块(401)，用于根据自然电位测井曲线，计算第一泥质含量指示(101)；第二计算模块(402)，用于根据自然伽马测井曲线，计算第二泥质含量指示(102)；第三计算模块(403)，用于根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数(103)；识别模块(404)，将用于根据所述第一泥质含量指示、所述第二泥质含量指示和所述岩性指数，从所述砂泥岩中识别烃源岩(104)；第四计算模块(405)，用于根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，计算所述烃源岩中的有机碳含量(105)。该装置通过多条测井曲线，提高了计算烃源岩中的有机碳含量的精确度。

Description

一种计算烃源岩中有机碳含量的装置 技术领域
本发明涉及石油地质勘探领域，特别涉及一种计算烃源岩中有机碳含量的装置。
背景技术
烃源岩也叫生油岩，是富含有机质、大量生成油气与排出油气的岩石。为了开采出大量的油气，需要准确地识别出烃源岩。然而，有机质丰度是评价烃源岩生成油气的重要参数之一，且有机碳含量是反映烃源岩有机质丰度的主要指标，所以，计算烃源岩中有机碳含量的方法受到了广泛的关注。
目前，计算烃源岩中有机碳含量的过程具体为：野外测得电阻率测井曲线和声波时差测井曲线。根据电阻率测井曲线和声波时差测井曲线，计算电阻率和声波时差异常差值的加权平均值。将计算的加权平均值用地化分析数据标定为烃源岩中有机碳含量。
在实现本发明的过程中，发明人发现现有技术至少存在以下问题：
对于复杂岩性的岩层，由于声波时差测井曲线和电阻率测井曲线受岩性、含油气性和孔隙结构的影响，所以，根据上述方法计算有机碳含量时，降低了计算精度。
发明内容
为了解决现有技术的问题，本发明实施例提供了一种计算烃源岩中有机碳含量的方法及装置。所述技术方案如下：
一方面，提供了一种计算烃源岩中有机碳含量的方法，所述方法包括：
根据自然电位测井曲线，计算第一泥质含量指示；
根据自然伽马测井曲线，计算第二泥质含量指示；
根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数；
根据所述第一泥质含量指示、所述第二泥质含量指示和所述岩性指数，从所述砂泥岩中识别烃源岩；
根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，计算所述烃源岩中的有机碳含量。
可选地，所述根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数，包括：
根据中子测井曲线，计算视灰岩中子孔隙度指数；
根据密度测井曲线，计算视灰岩密度孔隙度指数；
根据声波时差测井曲线，计算视灰岩声波孔隙度指数；
根据所述视灰岩中子孔隙度指数、所述视灰岩密度孔隙度指数和所述视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
可选地，所述根据所述视灰岩中子孔隙度指数、所述视灰岩密度孔隙度指数和所述视灰岩声波孔隙度指数，计算砂泥岩的岩性指数，包括：
计算所述视灰岩中子孔隙度指数与所述视灰岩密度孔隙度指数之间的第一差值；
计算所述视灰岩中子孔隙度指数与所述视灰岩声波孔隙度指数之间的第二差值；
计算所述视灰岩密度孔隙度指数与所述视灰岩声波孔隙度指数之间的第三差值；
根据所述第一差值、所述第二差值和所述第三差值，计算砂泥岩的岩性指数。
可选地，所述根据所述第一泥质含量指示、所述第二泥质含量指示和所述岩性指数，从所述砂泥岩中识别烃源岩，包括：
从所述砂泥岩中选择所述第一泥质含量指示大于第一阈值、所述第二泥质含量指示大于第二阈值且所述岩性指数大于第三阈值的岩层；
将选择的岩层确定为烃源岩。
可选地，所述根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，计算所述烃源岩中的有机碳含量，包括：
根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，按照如下公式计算所述烃源岩中的有机碳含量；
TOC＝(algRt+bΔt+c)/ρ
其中，上述公式中，TOC为所述烃源岩中的有机碳含量，Rt为所述电阻率测井曲线中的电阻率值，Δt为所述声波时差测井曲线中的声波时差，ρ为所述密度测井曲线中的密度值，a、b和c是已知系数。
另一方面，提供了一种计算烃源岩中有机碳含量的装置，所述装置包括：
第一计算模块，用于根据自然电位测井曲线，计算第一泥质含量指示；
第二计算模块，用于根据自然伽马测井曲线，计算第二泥质含量指示；
第三计算模块，用于根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数；
识别模块，将用于根据所述第一泥质含量指示、所述第二泥质含量指示和所述岩性指数， 从所述砂泥岩中识别烃源岩；
第四计算模块，用于根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，计算所述烃源岩中的有机碳含量。
可选地，所述第三计算模块包括：
第一计算单元，用于根据中子测井曲线，计算视灰岩中子孔隙度指数；
第二计算单元，用于根据密度测井曲线，计算视灰岩密度孔隙度指数；
第三计算单元，用于根据声波时差测井曲线，计算视灰岩声波孔隙度指数；
第四计算单元，用于根据所述视灰岩中子孔隙度指数、所述视灰岩密度孔隙度指数和所述视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
可选地，所述第四计算单元包括：
第一计算子单元，用于计算所述视灰岩中子孔隙度指数与所述视灰岩密度孔隙度指数之间的第一差值；
第二计算子单元，用于计算所述视灰岩中子孔隙度指数与所述视灰岩声波孔隙度指数之间的第二差值；
第三计算子单元，用于计算所述视灰岩密度孔隙度指数与所述视灰岩声波孔隙度指数之间的第三差值；
第四计算子单元，用于根据所述第一差值、所述第二差值和所述第三差值，计算砂泥岩的岩性指数。
可选地，所述识别模块包括：
选择单元，用于从所述砂泥岩中选择所述第一泥质含量指示大于第一阈值、所述第二泥质含量指示大于第二阈值且所述岩性指数大于第三阈值的岩层；
确定单元，用于将选择的岩层确定为烃源岩。
可选地，所述第四计算模块包括：
第五计算单元，用于根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，按照如下公式计算所述烃源岩中的有机碳含量；
TOC＝(algRt+bΔt+c)/ρ
其中，上述公式中，TOC为所述烃源岩中的有机碳含量，Rt为所述电阻率测井曲线中的电阻率值，Δt为所述声波时差测井曲线中的声波时差，ρ为所述密度测井曲线中的密度值，a、b和c是已知系数。
在本发明实施例中，根据自然电位测井曲线，计算第一泥质含量指示。根据自然伽马测 井曲线，计算第二泥质含量指示。根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数。然后，根据第一泥质含量指示、第二泥质含量指示和岩性指数，从砂泥岩中可以识别出烃源岩。最后，根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。由于在本发明实施例中不仅仅是根据电阻率测井曲线和声波时差测井曲线进行有机碳含量的计算，还包括自然电位测井曲线、自然伽马测井曲线、中子测井曲线、密度测井曲线等多个测井曲线，提高了计算烃源岩中的有机碳含量的精确度，为油气勘探中精细描述烃源岩有机质空间分布及预测有利油气勘探远景区提供支撑。
附图说明
为了更清楚地说明本发明实施例中的技术方案，下面将对实施例描述中所需要使用的附图作简单地介绍，显而易见地，下面描述中的附图仅仅是本发明的一些实施例，对于本领域普通技术人员来讲，在不付出创造性劳动的前提下，还可以根据这些附图获得其他的附图。
图1是本发明实施例一提供的一种计算烃源岩中有机碳含量的方法流程图；
图2是本发明实施例二提供的一种计算烃源岩中有机碳含量的方法流程图；
图3是本发明实施例二提供的烃源岩中有机碳含量的计算值与分析值之间的对比结果示意图；
图4是本发明实施例三提供的一种计算烃源岩中有机碳含量的装置结构示意图。
具体实施方式
为使本发明的目的、技术方案和优点更加清楚，下面将结合附图对本发明实施方式作进一步地详细描述。
在对本发明实施例进行详细地解释说明之前，先对烃源岩相关的概念和结构组成予以介绍。
烃源岩通常为泥岩或页岩，它是颗粒直径小于1/256mm的一类沉积岩。通常，泥岩呈块状构造，页岩具层理构造，从成份和粒度上看二者没有严格的差别，为表述方便，下面将两者统称为烃源岩。碎屑岩储层中，绝大多数烃源岩是以泥岩、页岩为主的细粒沉积岩，这类岩石的最大特点是富含有机质、孔隙的连通性较差，尤其是孔隙尺寸细微，导致岩石的渗透率非常低，因此，烃源岩还是最常见的隔层或盖层。从油气生成的角度看，泥岩或页岩是烃源岩，它是石油或天然气生成的场所。与之泥岩和页岩相比，颗粒粒径较大的砂岩、砾岩，在沉积岩地层中所占比例很低，但由于其孔隙的连通性好，孔隙的尺寸比较大，渗透率高， 成为石油、天然气或地下水的重要储集空间，即油气业界或水文工程业界所称的“储层”。
有机质和粘土矿物是泥质烃源岩的两大组成部分。其中，有机质常以分散状、顺层富集状、局部富集状和生物残体等形式赋存于粘土矿物中。有机质、粘土矿物是对烃源岩测井响应产生主要贡献的两个重要组分。测井对岩石中有机质和粘土矿物的类型、丰度、压实程度、富集状态、成熟演化以及充填在孔隙中的流体组分不同而产生的岩石物理、电化学性质的差异，是利用测井曲线识别和评价烃源岩的理论基础。
有机地球化学理论认为干酪根是烃源岩中有机质的主体，干酪根虽属烃源岩中的有机质，但它脱离了与之共存的无机矿物，不能很好地反映有机质的赋存状态以及不同类型有机质含量的多少。实验室裂解分析显示，赋存于沉积岩石中的有机质主要由两部分组成，即可溶有机质和不溶有机质(干酪根)，它们一起构成一个有机联系的整体，共同反映着沉积有机质的面貌。其中可溶有机质是与粘土矿物通过化学键合在一起的。有机地球化学界取得的研究成果中值得关注的是低熟油的发现，并认为可溶有机质对低熟油的形成有很大的贡献，而可溶有机质的丰度及赋存状态对声、电测井的响应有一定的影响，这为运用测井信息识别与评价低熟油提供了依据。同时，有机质本身具有低密度和吸附性等特征，因此对放射性测井也存在一定的影响。
实施例一
图1是本发明实施例提供的一种计算烃源岩中有机碳含量的方法流程图。参见图1，该方法包括：
步骤101：根据自然电位测井曲线，计算第一泥质含量指示。
步骤102：根据自然伽马测井曲线，计算第二泥质含量指示。
步骤103：根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数。
步骤104：根据第一泥质含量指示、第二泥质含量指示和该岩性指数，从砂泥岩中识别烃源岩。
步骤105：根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。
在本发明实施例中，根据自然电位测井曲线，计算第一泥质含量指示。根据自然伽马测井曲线，计算第二泥质含量指示。根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数。然后，根据第一泥质含量指示、第二泥质含量指示和岩性指数，从砂泥岩中可以识别出烃源岩。最后，根据密度测井曲线、声波时差测井曲线和电阻率测井曲 线，计算烃源岩中的有机碳含量。由于在本发明实施例中不仅仅是根据电阻率测井曲线和声波时差测井曲线进行有机碳含量的计算，还包括自然电位测井曲线、自然伽马测井曲线、中子测井曲线、密度测井曲线等多个测井曲线，提高了计算烃源岩中的有机碳含量的精确度，为油气勘探中精细描述烃源岩有机质空间分布及预测有利油气勘探远景区提供支撑。
可选地，根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数，包括：
根据中子测井曲线，计算视灰岩中子孔隙度指数；
根据密度测井曲线，计算视灰岩密度孔隙度指数；
根据声波时差测井曲线，计算视灰岩声波孔隙度指数；
根据视灰岩中子孔隙度指数、视灰岩密度孔隙度指数和视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
可选地，根据视灰岩中子孔隙度指数、视灰岩密度孔隙度指数和视灰岩声波孔隙度指数，计算砂泥岩的岩性指数，包括：
计算视灰岩中子孔隙度指数与视灰岩密度孔隙度指数之间的第一差值；
计算视灰岩中子孔隙度指数与视灰岩声波孔隙度指数之间的第二差值；
计算视灰岩密度孔隙度指数与视灰岩声波孔隙度指数之间的第三差值；
根据第一差值、第二差值和第三差值，计算砂泥岩的岩性指数。
可选地，根据第一泥质含量指示、第二泥质含量指示和岩性指数，从砂泥岩中识别烃源岩，包括：
从砂泥岩中选择第一泥质含量指示大于第一阈值、第二泥质含量指示大于第二阈值且岩性指数大于第三阈值的岩层；
将选择的岩层确定为烃源岩。
可选地，根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量，包括：
根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，按照如下公式计算烃源岩中的有机碳含量；
TOC＝(algRt+bΔt+c)/ρ
其中，上述公式中，TOC为烃源岩中的有机碳含量，Rt为电阻率测井曲线中的电阻率值，Δt为声波时差测井曲线中的声波时差，ρ为密度测井曲线中的密度值，a、b和c是已知系数。
上述所有可选技术方案，均可按照任意结合形成本发明的可选技术方案，本发明在此不 再一一赘述。
实施例二
图2是本发明实施例提供的一种计算烃源岩中的有机碳含量的方法流程图。参见图2，该方法包括：
步骤201：根据自然电位测井曲线，计算第一泥质含量指示。
具体地，根据自然电位测井曲线，按照如下的公式(1)计算第一泥质含量指示；
Figure PCTCN2015096202-appb-000001
其中，在上述公式(1)中，ISP为第一泥质含量指示，SPmax为自然电位在纯砂岩上的幅度，SPmin为自然电位在泥岩层上的基线值，SP为自然电位测井曲线上的自然电位测井值。另外，当ISP值越大时，指示岩层中的泥质含量越大，反之，当ISP值越小时，指示岩层中的泥质含量越小。当岩层中的泥质含量越小时，该岩层为渗透性越好的砂岩层。
其中，在砂泥岩剖面中，砂岩层的渗透性相对较好，在自然电位测井曲线上表现出明显的幅度差，因此，在井剖面上地层水矿化度较为稳定时，可以用自然电位的相对幅度差定义自然电位测井曲线的泥质含量指示，如上述第一泥质含量指示的公式。
其中，自然电位测井曲线是自然电位随井深而变化的曲线。
步骤202：根据自然伽马测井曲线，计算第二泥质含量指示。
具体地，根据自然伽马测井曲线，按照如下公式(2)计算第二泥质含量指示；
Figure PCTCN2015096202-appb-000002
其中，在上述公式(2)中，IGR为第二泥质含量指示，GRmax为自然伽马在泥岩层上的幅度，GRmin为自然伽马在纯砂岩层上的基线值，GR为自然伽马测井曲线上的自然伽马测井值。另外，当IGR值越大时，指示岩层中的泥质含量越大，反之，当IGR值越小时，指示岩层中的泥质含量越小。
其中，烃源岩层一般富含碳，可以吸附较多的放射性元素，如吸附特殊元素铀，从而烃源岩在自然伽马测井曲线上表现为高异常，所以，可以利用自然伽马测井曲线来识别烃源岩。但是，铀的含量不仅与有机质丰度有关，还受裂缝分布的影响，因此，如果单独使用自然伽 马测井曲线来识别烃源岩会降低精度。同样，在地层基质和孔隙中没有放射性矿物的井剖面上，自然伽马测井曲线的相对幅度可以指示泥质含量的大小，所以，可以根据自然伽马测井曲线，定义上述的第二泥质含量指示的公式。
其中，自然伽马测井曲线是在井内测量岩层中自然存在的放射性核素衰变过程中放射出来的γ射线的强度，且自然伽马测井曲线也是随井深而变化的曲线。
步骤203：根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数。
具体地，本步骤可以根据如下(1)-(4)的步骤来实现，包括：
(1)、根据中子测井曲线，计算视灰岩中子孔隙度指数。
具体地，根据中子测井曲线，按照如下公式(3)计算视灰岩中子孔隙度指数；
Figure PCTCN2015096202-appb-000003
其中，在上述公式(3)中，
Figure PCTCN2015096202-appb-000004
为视灰岩中子孔隙度指数，CNLma为灰岩骨架的中子孔隙度响应值，CNLf为地层水的中子孔隙度响应值，CNL为中子测井曲线上的中子测井值。另外，当
Figure PCTCN2015096202-appb-000005
值越大时，指示岩层中的含水孔隙度越大，反之，当
Figure PCTCN2015096202-appb-000006
值越小时，指示岩层中的含水空隙度越小。
其中，灰岩骨架为无孔隙度的灰岩。
其中，在泥质砂岩储层中，中子、密度和声波三孔隙度测井对砂岩和泥质存在较大差异。中子测井主要响应地层中的含氢指数，其幅度大小与地层中的含氢量成正比。在砂泥岩剖面上，纯砂岩储层段的中子响应基本反映储层孔隙度，而在泥岩段上，中子响应主要反映泥岩的束缚水孔隙度。在泥质砂岩储层上，是两者的体积分数的加权平均值。由于泥岩层含有较大的束缚水孔隙度，实测曲线上会出现比砂岩储层还大的测井响应。所以，可以定义上述的视灰岩中子孔隙度指数的公式。
(2)、根据密度测井曲线，计算视灰岩密度孔隙度指数。
具体地，根据密度测井曲线，按照如下公式(4)计算视灰岩密度孔隙度指数；
Figure PCTCN2015096202-appb-000007
其中，在上述公式(4)中，
Figure PCTCN2015096202-appb-000008
为视灰岩密度孔隙度指数，DENma为灰岩骨架的密度值，DENf为地层水的密度值，DEN为密度测井曲线上的密度测井值。另外，在储层段岩性 稳定的条件下，当
Figure PCTCN2015096202-appb-000009
值越大时，指示岩层中的孔隙度越大，反之，当
Figure PCTCN2015096202-appb-000010
值越小时，指示岩层中的孔隙度越小。
其中，密度测井主要反映地层中与放射源伽马射线作用的电子密度大小，它近似与地层密度成正比。在砂泥岩剖面上，纯砂岩储层段的密度大小基本反映储层孔隙度，而在泥岩段上，由于粘土的密度常比石英、长石等的密度大，因此，利用统一的骨架时差计算的密度孔隙度明显比实际地层的束缚水孔隙度小，所以，可以定义上述视灰岩密度孔隙度指数的公式。
(3)、根据声波时差测井曲线，计算视灰岩声波孔隙度指数。
具体地，根据声波时差测井曲线，按照如下公式(5)计算视灰岩声波孔隙度指数；
Figure PCTCN2015096202-appb-000011
其中，在上述公式(5)中，
Figure PCTCN2015096202-appb-000012
为视灰岩声波孔隙度指数，ACf为地层水的声波时差响应值，ACma为灰岩骨架的声波时差响应值，AC为声波时差测井曲线上的声波时差测井值。另外，在储层段岩性稳定的条件下，当
Figure PCTCN2015096202-appb-000013
值越大时，指示岩层中的孔隙度越大，反之，当
Figure PCTCN2015096202-appb-000014
值越小时，指示岩层中的孔隙度越小。
其中，声波时差测井主要反映地层中纵波的传播时，其大小与地层中骨架岩性和孔隙度相关。在砂泥岩剖面上，在胶结较好的纯砂岩储层段的声波时差基本反映储层孔隙度，而在泥岩段上，声波时差是泥质类型、分布方式和束缚水孔隙度的综合响应。由于泥岩层含有较大的束缚水孔隙度，实测曲线上会出现比砂岩储层还大的声波时差。，所以，可以定义上述视灰岩声波孔隙度指数的公式。
(4)、根据视灰岩中子孔隙度指数、视灰岩密度孔隙度指数和视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
具体地，计算视灰岩中子孔隙度指数与视灰岩密度孔隙度指数之间的第一差值。计算视灰岩中子孔隙度指数与视灰岩声波孔隙度指数之间的第二差值。计算视灰岩密度孔隙度指数与视灰岩声波孔隙度指数之间的第三差值。根据第一差值、第二差值和第三差值，计算砂泥岩的岩性指数。
其中，根据第一差值、第二差值和第三差值，按照如下公式(6)计算砂泥岩的岩性指数；
Figure PCTCN2015096202-appb-000015
其中，在上述公式(6)中，Ilith为岩性指数，
Figure PCTCN2015096202-appb-000016
为第一差值，
Figure PCTCN2015096202-appb-000017
为第二差值，
Figure PCTCN2015096202-appb-000018
为 第三差值，
Figure PCTCN2015096202-appb-000019
为第一数值与第二数值的差值，第一数值为纯砂岩段的中子视灰岩孔隙度与密度视灰岩孔隙度之和，第二数值为泥岩段的中子视灰岩孔隙度与密度视灰岩孔隙度之和。另外，对于纯砂岩储层段Ilith较小，接近于0，而对于泥页岩段Ilith较大，且接近于1。
需要补充说明的是，在本发明实施例中，第一差值、第二差值和第三差值均为正数，即为差值的绝对值。
其中，在砂岩储层段，中子、密度和声波三个视灰岩孔隙度都可反映储层的实际孔隙度。而在泥岩段，中子和声波的视灰岩孔隙度将比密度视灰岩孔隙度大许多。因此，利用三个视灰岩孔隙度的两两差值可以构造判识储层岩性的指标，以划分泥页岩段。
步骤204：从砂泥岩中选择第一泥质含量指示大于第一阈值、第二泥质含量指示大于第二阈值且岩性指数大于第三阈值的岩层。
其中，第一阈值、第二阈值和第三阈值均为事先设置的，本发明实施例对此不做具体限定。
步骤206：将选择的岩层确定为烃源岩。
需要补充说明的是，在常见的砂泥岩储层中，烃源岩主要为泥岩和页岩，也有煤系烃源岩。而煤系烃源岩在测井曲线上表现为“三高三低”的特征，即，高中子、高声波时差、高电阻率、低密度、低自然电位、低自然伽马(由于煤层的放射性弱)。因此，上述的第一差值、第二差值和第三差值不能用于煤系烃源岩的识别，在此，可以利用煤系地层的电阻率和含水储层电阻率的差异、自然放射性极地和密度低的特征识别煤系烃源岩。
另外，当烃源岩为泥岩时，可以包括碳质泥岩和暗色泥岩。碳质泥岩和暗色泥岩的测井响应表现为“五高一低”特征,即高中子、高声波时差、高电阻率(高于围岩泥岩)、高自然伽马、高铀含量、低密度，并且有机碳含量高的层段其自然伽马和铀曲线值相对较高。所以，除了利用上边分析的几个指标外，还需要单独建立其它的判别指标来识别碳质泥岩和暗色泥岩。
其中，根据上述步骤从砂泥岩中识别出烃源岩之后，可以根据下述的步骤计算烃源岩中的有机碳含量。
步骤207：根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。
具体地，根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，按照如下公式(7)计算烃源岩中的有机碳含量；
TOC＝(algRt+bΔt+c)/ρ    (7)
其中，上述公式(7)中，TOC为烃源岩中的有机碳含量，Rt为电阻率测井曲线中的电阻率值，Δt为声波时差测井曲线中的声波时差，ρ为密度测井曲线中的密度值，a、b和c是已知系数。
需要补充说明的是，在本发明实施例中，富含有机质的烃源岩密度较低，密度测井测量的是地层的体积密度，包括骨架密度和流体密度。烃源岩中有机质的密度(1.03～1.1g/cm3)明显低于围岩基质的密度(粘土骨架的密度为2.3～3.1g/cm3)，使烃源岩密度测井值降低。富含有机质的低孔泥页岩中，地层密度的变化与有机质丰度的变化存在一定的对应关系。在岩性变化较小的剖面上，泥页岩的有机质丰度和地层密度存在负相关关系。但当重矿物富集时，密度测井就不可能是有机质的可靠指标。所以，可以采用密度测井曲线对有机碳含量的计算公式进行校正。
另外，声波时差测井曲线也即是声波测井曲线，所以，Δt为声波时差测井曲线中的声波时差值。另外，a、b和c三个参数可以通过对研究区系统采集样品后，采用最小二乘法拟合求得的，并且，为了准确获取a、b和c的值，可选取泥岩取芯段较长、TOC分析数据较多且深度对应较准确的井段进行回归拟合。
其中，在本发明实施例中，通过上述公式(7)计算有机碳含量时，由于电阻率测井曲线和声波时差测井曲线对孔隙度的变化比较灵敏，一旦某一岩性的基线确定，孔隙度的变化会直接引起这两条测井曲线的响应，所以可不需岩芯实验分析就可以直接计算TOC。
其中，上述描述中提到基线，然而，基线的确定方法可以为：声波时差测井曲线采用算术坐标，电阻率测井曲线采用对数坐标，当两条测井曲线在某一深度内平行或者重叠时，将该深度内的测井曲线确定为基线。
测井曲线对岩层有机碳含量和充填孔隙流体物理性质差异的响应，是利用测井曲线识别和评价烃源岩的基础。正常情况下，有机碳含量越高的岩层在测井曲线上的异常越大，测定异常值就能反算出有机碳含量。当沉积岩中总有机质重量百分含量超过30-35％时，岩石即具有有机岩类的特征。由于其中分散的有机质干酪根具有特殊的物理性质,如它的导电性差、自然放射性强、密度接近于水的密度、属于轻组分，声波时差接近550μs/m、含氢指数接近67％。因此，好的生油岩，其有机碳TOC含量接近30％，在测井曲线上有明显的反映，而较差的生油岩，有机碳TOC含量为小于30％，测井曲线虽没有特明显的异常，但还是可以反映 出来的。所以，在本发明实施例中可以采用上述的测井曲线计算烃源岩中的有机碳含量。
另外，为了精细评价烃源岩的分布状况，根据研究区烃源岩的沉积相特征，按照有机碳含量将烃源岩划分为优质、中等和差三类。通常TOC≥2％为优质烃源岩；1％≤TOC≤2％为中等烃源岩；0.3％≤TOC≤1％为差烃源岩。通过这一分类,可将连续评价的烃源岩分布表征为不同等级的TOC层段，结合有机地球化学分析实现测井和有机地化一体化评价的烃源岩厚度图，在空间上能够实现烃源岩的精细评价和解决烃源岩的非均质性评价难题。
图3是冀中凹陷岔深80井深部层段稿有机碳层段的地球化学分析值与测井响应计算值的对比，从TOC那条连续的曲线是根据本发明实施例提供的方法计算得到的有机碳含量的曲线，而TOC那条曲线上的横向的短线为通过地球化学分析得到的有机碳含量。由此可以看出，此高有机碳含量层段，通过本发明实施例提供的方法计算的有机碳含量和地球化学分析值吻合较好，因此，本本发明实施例提供的方法对不同有机碳含量的烃源岩也可以取得较好的效果
在本发明实施例中，根据自然电位测井曲线，计算第一泥质含量指示。根据自然伽马测井曲线，计算第二泥质含量指示。根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数。然后，根据第一泥质含量指示、第二泥质含量指示和岩性指数，从砂泥岩中可以识别出烃源岩。最后，根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。由于在本发明实施例中不仅仅是根据电阻率测井曲线和声波时差测井曲线进行有机碳含量的计算，还包括自然电位测井曲线、自然伽马测井曲线、中子测井曲线、密度测井曲线等多个测井曲线，提高了计算烃源岩中的有机碳含量的精确度，为油气勘探中精细描述烃源岩有机质空间分布及预测有利油气勘探远景区提供支撑。
实施例三
图4是本发明实施例提供的一种计算烃源岩中有机碳含量的装置结构示意图。参见图4，该装置包括：第一计算模块401、第二计算模块402、第三计算模块403、识别模块404和第四计算模块405；
第一计算模块401，用于根据自然电位测井曲线，计算第一泥质含量指示；
第二计算模块402，用于根据自然伽马测井曲线，计算第二泥质含量指示；
第三计算模块403，用于根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数；
识别模块404，将用于根据第一泥质含量指示、第二泥质含量指示和该岩性指数，从砂泥岩中识别烃源岩；
第四计算模块405，用于根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。
可选地，第三计算模块403包括：
第一计算单元，用于根据中子测井曲线，计算视灰岩中子孔隙度指数；
第二计算单元，用于根据密度测井曲线，计算视灰岩密度孔隙度指数；
第三计算单元，用于根据声波时差测井曲线，计算视灰岩声波孔隙度指数；
第四计算单元，用于根据视灰岩中子孔隙度指数、视灰岩密度孔隙度指数和视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
可选地，第四计算单元包括：
第一计算子单元，用于计算视灰岩中子孔隙度指数与视灰岩密度孔隙度指数之间的第一差值；
第二计算子单元，用于计算视灰岩中子孔隙度指数与视灰岩声波孔隙度指数之间的第二差值；
第三计算子单元，用于计算视灰岩密度孔隙度指数与视灰岩声波孔隙度指数之间的第三差值；
第四计算子单元，用于根据第一差值、第二差值和第三差值，计算砂泥岩的岩性指数。
可选地，识别模块404包括：
选择单元，用于从砂泥岩中选择第一泥质含量指示大于第一阈值、第二泥质含量指示大于第二阈值且岩性指数大于第三阈值的岩层；
确定单元，用于将选择的岩层确定为烃源岩。
可选地，第四计算模块405包括：
第五计算单元，用于根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，按照如下公式计算烃源岩中的有机碳含量；
TOC＝(algRt+bΔt+c)/ρ
其中，上述公式中，TOC为烃源岩中的有机碳含量，Rt为电阻率测井曲线中的电阻率值，Δt为声波时差测井曲线中的声波时差，ρ为密度测井曲线中的密度值，a、b和c是已知系数。
在本发明实施例中，根据自然电位测井曲线，计算第一泥质含量指示。根据自然伽马测井曲线，计算第二泥质含量指示。根据中子测井曲线、密度测井曲线和声波时差测井曲线， 计算砂泥岩的岩性指数。然后，根据第一泥质含量指示、第二泥质含量指示和岩性指数，从砂泥岩中可以识别出烃源岩。最后，根据密度测井曲线、声波时差测井曲线和电阻率测井曲线，计算烃源岩中的有机碳含量。由于在本发明实施例中不仅仅是根据电阻率测井曲线和声波时差测井曲线进行有机碳含量的计算，还包括自然电位测井曲线、自然伽马测井曲线、中子测井曲线、密度测井曲线等多个测井曲线，提高了计算烃源岩中的有机碳含量的精确度，为油气勘探中精细描述烃源岩有机质空间分布及预测有利油气勘探远景区提供支撑。
需要说明的是：上述实施例提供的计算烃源岩中有机碳含量的装置在计算烃源岩中有机碳含量时，仅以上述各功能模块的划分进行举例说明，实际应用中，可以根据需要而将上述功能分配由不同的功能模块完成，即将装置的内部结构划分成不同的功能模块，以完成以上描述的全部或者部分功能。另外，上述实施例提供的计算烃源岩中有机碳含量的装置与计算烃源岩中有机碳含量的方法实施例属于同一构思，其具体实现过程详见方法实施例，这里不再赘述。
上述本发明实施例序号仅仅为了描述，不代表实施例的优劣。
本领域普通技术人员可以理解实现上述实施例的全部或部分步骤可以通过硬件来完成，也可以通过程序来指令相关的硬件完成，所述的程序可以存储于一种计算机可读存储介质中，上述提到的存储介质可以是只读存储器，磁盘或光盘等。
以上所述仅为本发明的较佳实施例，并不用以限制本发明，凡在本发明的精神和原则之内，所作的任何修改、等同替换、改进等，均应包含在本发明的保护范围之内。

Claims (5)

  1. 一种计算烃源岩中有机碳含量的装置，其特征在于，所述装置包括：
    第一计算模块，用于根据自然电位测井曲线，计算第一泥质含量指示；
    第二计算模块，用于根据自然伽马测井曲线，计算第二泥质含量指示；
    第三计算模块，用于根据中子测井曲线、密度测井曲线和声波时差测井曲线，计算砂泥岩的岩性指数；
    识别模块，将用于根据所述第一泥质含量指示、所述第二泥质含量指示和所述岩性指数，从所述砂泥岩中识别烃源岩；
    第四计算模块，用于根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线，计算所述烃源岩中的有机碳含量。
  2. 如权利要求1所述的装置，其特征在于，所述第三计算模块包括：
    第一计算单元，用于根据中子测井曲线，计算视灰岩中子孔隙度指数；
    第二计算单元，用于根据密度测井曲线，计算视灰岩密度孔隙度指数；
    第三计算单元，用于根据声波时差测井曲线，计算视灰岩声波孔隙度指数；
    第四计算单元，用于根据所述视灰岩中子孔隙度指数、所述视灰岩密度孔隙度指数和所述视灰岩声波孔隙度指数，计算砂泥岩的岩性指数。
  3. 如权利要求2所述的装置，其特征在于，所述第四计算单元包括：
    第一计算子单元，用于计算所述视灰岩中子孔隙度指数与所述视灰岩密度孔隙度指数之间的第一差值；
    第二计算子单元，用于计算所述视灰岩中子孔隙度指数与所述视灰岩声波孔隙度指数之间的第二差值；
    第三计算子单元，用于计算所述视灰岩密度孔隙度指数与所述视灰岩声波孔隙度指数之间的第三差值；
    第四计算子单元，用于根据所述第一差值、所述第二差值和所述第三差值，计算砂泥岩的岩性指数。
  4. 如权利要求1所述的装置，其特征在于，所述识别模块包括：
    选择单元，用于从所述砂泥岩中选择所述第一泥质含量指示大于第一阈值、所述第二泥质含量指示大于第二阈值且所述岩性指数大于第三阈值的岩层；
    确定单元，用于将选择的岩层确定为烃源岩。
  5. 如权利要求1-4任一权利要求所述的装置，其特征在于，所述第四计算模块包括：
    第五计算单元，用于根据所述密度测井曲线、所述声波时差测井曲线和电阻率测井曲线， 按照如下公式计算所述烃源岩中的有机碳含量；
    TOC＝(alg Rt+bΔt+c)/ρ
    其中，上述公式中，TOC为所述烃源岩中的有机碳含量，Rt为所述电阻率测井曲线中的电阻率值，Δt为所述声波时差测井曲线中的声波时差，ρ为所述密度测井曲线中的密度值，a、b和c是已知系数。
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