阅读说明：本技术 一种近源存储型油气藏流体性质判别方法 (Near-source storage type oil and gas reservoir fluid property distinguishing method ) 是由 肖亮 刘蝶 张海涛 李高仁 郭浩鹏 于 2020-04-28 设计创作，主要内容包括：本发明提供了一种近源存储型油气藏流体性质判别方法。该方法包括：获取目标储集层对应的有效生油岩的厚度、有效生油岩与目标储集层之间的距离、目标储集层的品质因子、目标储集层的深电阻率；基于获取的有效生油岩的厚度、有效生油岩与目标储集层之间的距离、目标储集层的品质因子以及目标储集层的深电阻率计算目标储集层的储集层流体判别因子；根据计算得到的目标储集层的储集层流体判别因子的大小判断目标储集层流体性质。该方法综合考虑了油气藏充注程度、储集层的品质等因素对油气聚集的影响,能够有效识别近源存储型油气藏流体性质。(The invention provides a near-source storage type oil and gas reservoir fluid property distinguishing method. The method comprises the following steps: acquiring the thickness of an effective oil producing rock corresponding to a target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer and the deep resistivity of the target reservoir layer; calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir; and judging the target reservoir fluid property according to the calculated size of the reservoir fluid discrimination factor of the target reservoir. The method comprehensively considers the influence of factors such as the filling degree of the oil-gas reservoir, the quality of a reservoir layer and the like on oil-gas accumulation, and can effectively identify the fluid property of the near-source storage type oil-gas reservoir.)

1. A near-source storage type oil and gas reservoir fluid property distinguishing method comprises the following steps:

acquiring the thickness of an effective oil producing rock corresponding to a target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer and the deep resistivity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir;

and judging the fluid property of the target reservoir according to the calculated size of the reservoir fluid discrimination factor of the target reservoir.

2. The discrimination method of claim 1, wherein determining the fluid property of the target reservoir based on the calculated magnitude of the reservoir fluid discrimination factor for the target reservoir comprises:

judging whether the fluid property of the target reservoir belongs to an oil-gas-containing layer or a water layer according to the calculated reservoir fluid discrimination factor of the target reservoir;

preferably, the target reservoir is a high productivity fluid layer.

3. The discrimination method according to claim 1, wherein the method comprises:

acquiring the thickness of the effective oil producing rock corresponding to the target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer, the deep resistivity of the target reservoir layer and the porosity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir;

determining a fluid property of a target reservoir based on a reservoir fluid discrimination factor of the target reservoir and a size of a porosity of the target reservoir.

4. The discrimination method of claim 1, wherein the discriminating of the fluid property of the target reservoir from the reservoir fluid discrimination of the target reservoir and the magnitude of the porosity of the target reservoir comprises: judging which of an oil-gas-containing layer, a water layer and a low-yield layer the fluid property of the target reservoir belongs to according to the reservoir fluid discrimination factor of the target reservoir and the porosity of the target reservoir;

preferably, determining whether the fluid property of the target reservoir belongs to a high-yield stratum or a low-yield stratum according to the porosity of the target reservoir; judging whether the high-yield liquid layer belongs to an oil-gas layer or a water layer according to the size of the reservoir fluid discrimination factor of the target reservoir layer;

more preferably, when the porosity is less than the first threshold, a low fluid production layer is identified; when the porosity is larger than or equal to a first threshold value, a high-yield liquid layer is judged;

further preferably, the value of the first threshold is determined by calibrating the test data;

still more preferably, the first threshold is 14.5%.

5. The discrimination method according to any one of claims 1 to 4, wherein said calculating a reservoir fluid discrimination factor for the target reservoir based on the obtained thickness of the productive petrolite, the distance between the productive petrolite and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir is performed by a method comprising:

obtaining a product of a thickness of the effective oil producing rock, a quality factor of the reservoir and a deep resistivity of the reservoir;

obtaining a ratio of the product to a distance between the active oil producing rock and a target reservoir;

determining the reservoir fluid discrimination factor from the ratio.

6. The discrimination method according to any one of claims 1-4, wherein the reservoir fluid discrimination factor is calculated by the formula:

Fi＝e×RT^a×RQI^b×H^c÷h^d+f

wherein a, b, c and d are all positive numbers or negative values; e. f is a coefficient; h is the thickness of the effective oil producing rock corresponding to the target reservoir stratum, m; h is the distance between the effective oil producing rock and the target reservoir, m; RQI is the quality factor of the target reservoir; RT is the deep resistivity of the target reservoir, Ω · m; fi is a reservoir fluid discrimination factor for the target reservoir;

preferably, said values of a, b, c, d are equal, i.e. Fi ═ e × (RT × RQI × H ÷ H)^a+f；

More preferably, the values of a, b, c, d are all 1 or-1, i.e., Fi ═ e × RT × RQI × H ÷ H + f or Fi ═ e × H ÷ (RT × RQI × H) + f;

more preferably, the values of a, b, c, d are all 1, i.e., Fi ═ e × RT × RQI × H ÷ H + f;

the value of e is preferably 1, and the value of f is preferably 0.

7. The method of claim 6, wherein Fi is RT × RQI × H ÷ H, and when Fi < the second threshold, a water layer is identified; when the Fi is larger than or equal to a second threshold value, the oil-gas-containing layer is judged;

preferably, the value of the second threshold is determined by calibrating the test data;

more preferably, the second threshold is 3.0.

8. The discrimination method according to any one of claims 1 to 7, wherein the near-source reservoir fluid property discrimination method comprises:

acquiring the thickness of the effective oil producing rock corresponding to the target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer, the deep resistivity of the target reservoir layer and the porosity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir; wherein Fi ═ RT × RQI × H ÷ H; h is the thickness of the effective oil producing rock corresponding to the target reservoir stratum, m; h is the distance between the effective oil producing rock and the target reservoir, m; RQI is the quality factor of the target reservoir; RT is the deep resistivity of the target reservoir, Ω · m; fi is a reservoir fluid discrimination factor for the target reservoir;

determining a fluid property of a target reservoir based on a reservoir fluid discrimination factor of the target reservoir and a porosity level of the target reservoir:

porosity is greater than or equal to a first threshold and ((RT × RQI). times.H)/H is greater than or equal to a second threshold: judging the layer to be an oil (gas) containing layer;

porosity is greater than or equal to a first threshold and ((RT × RQI). times.H)/H < a second threshold: judging the water layer;

porosity < first threshold: and judging the liquid layer as a low liquid yield layer.

9. The discrimination method according to any one of claims 1 to 8, wherein the quality factor is determined by permeability, porosity;

preferably, the first and second electrodes are formed of a metal,wherein, RQI is the quality factor of the target reservoir; k is the permeability, 10^-3μm²；Porosity,%.

10. The discrimination method according to any one of claims 1 to 8,

the thickness of the effective oil producing rock is determined by a natural gamma logging curve, a sound wave time difference logging curve and a deep resistivity logging curve at the top of the target reservoir stratum; preferably, the thickness of the available oil shale is determined by: overlapping the acoustic time difference and the deep resistivity in the same logging curve track in the oil-producing rock interval with the natural gamma value larger than 110API at the top of the target reservoir layer to determine the effective oil-producing rock thickness adjacent to the target reservoir layer; more preferably, the thickness of the available oil shale is determined by: firstly, replaying the acoustic time difference logging curve at the same logging curve track according to 500-150 mu s/m and the deep resistivity logging curve at the same logging curve track according to 0.1-100 omega.m; judging the interval with the natural gamma value of more than 110API at the top of the target reservoir stratum and the deep resistivity on the right side of the acoustic wave time difference logging curve as an effective oil-producing rock stratum; then, calculating the thickness of the effective oil producing rock according to the depth difference between the bottom and the top of the effective oil producing rock;

the distance between the effective oil producing rock and the target reservoir is determined through a natural gamma logging curve, an acoustic wave time difference logging curve and a deep resistivity logging curve at the top of the target reservoir; preferably, the distance between the active oil producing rock and the target reservoir is determined by: overlapping the acoustic wave time difference and the deep resistivity in the same logging curve track in the oil-producing rock interval with the natural gamma value larger than 110API at the top of the target reservoir layer to determine the distance between the effective oil-producing rock and the target reservoir layer; more preferably, the thickness of the available oil shale is determined by: firstly, replaying a sound wave time difference deep resistivity curve in the same logging curve channel according to 500-150 mu s/m and 0.1-100 omega.m; judging the interval with the natural gamma value of more than 110API at the top of the target reservoir stratum and the deep resistivity on the right side of the acoustic wave time difference logging curve as an effective oil-producing rock stratum; then, the distance between the active oil bearing rock and the target reservoir is calculated from the difference in depth between the bottom of the active oil bearing rock and the top of the target reservoir.

Technical Field

The invention relates to the field of reservoir stratum evaluation, in particular to a near-source storage type oil and gas reservoir fluid property distinguishing method.

Background

The judgment of the fluid property is a very important link in reservoir evaluation and reservoir estimation, and the accuracy of the judgment of the reservoir fluid property directly determines the reliability of the estimated reservoir and the selection of effective development measures. For hydrocarbon reservoirs that are conventionally formed by hydrocarbon migration, buoyancy due to density differences between oil (gas) -water is the primary motive force for the hydrocarbon reservoir. Therefore, the oil (gas) and the water have better differentiation, and the oil-gas reservoir has a uniform oil (gas) water interface. For such reservoirs, porosity is exploitedAnd the resistivity RT enable relatively accurate determination of reservoir fluid properties. However, for near-source storage reservoirs, the reservoir formation and accumulation of hydrocarbons is related to many factors, including the degree of reservoir filling, the quality of the reservoir, and pore connectivity. For reservoirs with high degrees of charge, better quality and pore connectivity, reservoirs are more likely to form. And when the degree of flooding is low, the reservoir quality and pore connectivity are poor, often water or dry layers. Therefore, the conventional oil and gas reservoir distinguishing method is low in distinguishing coincidence rate in the near-source storage type oil and gas reservoir and cannot meet the basic requirements of reservoir evaluation.

In order to effectively distinguish the fluid property of a near-source storage type oil and gas reservoir, the filling degree of the oil and gas reservoir, the quality of a reservoir layer and other factors need to be fully considered. At present, how to judge the fluid property of a near-source storage type oil and gas reservoir is a difficult point in the field of reservoir evaluation, and a widely-accepted method capable of effectively judging the fluid property of the near-source storage type oil and gas reservoir is not provided.

Disclosure of Invention

In view of the defects of the prior art, the invention aims to provide a method for effectively judging the fluid properties of a near-source storage type oil and gas reservoir. The method comprehensively considers the influence of factors such as the filling degree of the oil-gas reservoir, the quality of the reservoir layer and the like on oil-gas accumulation.

In order to achieve the above object, the present invention provides a near-source storage type reservoir fluid property determination method, wherein the method comprises:

acquiring the thickness of an effective oil producing rock corresponding to a target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer and the deep resistivity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir;

and judging the fluid property of the target reservoir according to the calculated size of the reservoir fluid discrimination factor of the target reservoir.

In the above near-source storage type reservoir fluid property discriminating method, preferably, the judging the fluid property of the target reservoir based on the calculated reservoir fluid discrimination factor of the target reservoir includes: and judging whether the fluid property of the target reservoir belongs to the oil-gas layer or the water layer according to the calculated reservoir fluid discrimination factor of the target reservoir. More preferably, the target reservoir is a high productivity fluid layer. In this preferred embodiment, the reservoir fluid discrimination factor for the target reservoir may be compared to a second threshold and the reservoir fluid property may be discriminated as either a hydrocarbon-bearing layer or a water-bearing layer bounded by the second threshold.

In the method for discriminating a fluid property of a near-source reservoir, the method preferably includes:

acquiring the thickness of the effective oil producing rock corresponding to the target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer, the deep resistivity of the target reservoir layer and the porosity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir;

judging the fluid property of the target reservoir according to the reservoir fluid discrimination factor of the target reservoir and the porosity of the target reservoir;

more preferably, the determining the fluid property of the target reservoir from the reservoir fluid discrimination of the target reservoir and the magnitude of the porosity of the target reservoir comprises determining which of a hydrocarbon-bearing zone, a water zone, and a low production zone the fluid property of the target reservoir belongs to from the reservoir fluid discrimination of the target reservoir and the magnitude of the porosity of the target reservoir. Further preferably, determining whether the fluid property of the target reservoir belongs to a high pay zone or a low pay zone according to the porosity of the target reservoir; and judging whether the high-yield liquid layer belongs to an oil-gas layer or a water layer according to the size of the reservoir fluid discrimination factor of the target reservoir layer. Most preferably, a low fluid yield layer is identified when the porosity is below a first threshold; when the porosity is larger than or equal to a first threshold value, a high-yield liquid layer is judged; wherein, the numerical value of the first threshold is preferably determined by a way of oil testing data calibration; in one embodiment, the first threshold is determined by calibration using the testing data of the tested reservoir in the same block as the target reservoir, specifically: determining a porosity threshold value of the high yield fluid layer and the low yield fluid layer as a first threshold value of the block by using the porosity of the reservoir subjected to oil testing and reservoir fluid properties (belonging to the high yield fluid layer or the low yield fluid layer) obtained by the oil testing information; in a specific embodiment, the first threshold is 14.5%.

In the above near-source storage type reservoir fluid property discrimination method, preferably, the calculating of the reservoir fluid discrimination factor of the target reservoir based on the acquired thickness of the effective petroliferous rock, the distance between the effective petroliferous rock and the target reservoir, the quality factor of the target reservoir, and the deep resistivity of the target reservoir is performed by a method including the steps of:

obtaining a product of a thickness of the effective oil producing rock, a quality factor of the reservoir and a deep resistivity of the reservoir;

obtaining a ratio of the product to a distance between the active oil producing rock and a target reservoir;

determining the reservoir fluid discrimination factor from the ratio.

In the above near-source stored reservoir fluid property identification method, preferably, the reservoir fluid identification factor is calculated by the following formula:

Fi＝e×RT^a×RQI^b×H^c÷h^d+ f, wherein a, b, c and d are all positive numbers or all negative values; e. f is a coefficient; h is the thickness of the effective oil producing rock corresponding to the target reservoir stratum, m; h is the distance between the effective oil producing rock and the target reservoir, m; RQI is the quality factor of the target reservoir; RT is the deep resistivity of the target reservoir, Ω · m; fi is a reservoir fluid discrimination factor for the target reservoir;

more preferably, said values of a, b, c, d are equal, i.e. Fi ═ e × (RT × RQI × H ÷ H)^a+f；

More preferably, the values of a, b, c, d are all 1 or-1, i.e., Fi ═ e × RT × RQI × H ÷ H + f or Fi ═ e × H ÷ (RT × RQI × H) + f;

most preferably, the values of a, b, c, d are all 1, i.e., Fi ═ e × RT × RQI × H ÷ H + f;

the value of e is preferably 1, and the value of f is preferably 0.

In the above near-source storage type hydrocarbon reservoir fluid property discrimination method, preferably, Fi ═ RT × RQI × H ÷ H, H is a thickness of an effective petrolite corresponding to the target reservoir layer, H is a distance between the effective petrolite and the target reservoir layer, RQI is a quality factor of the target reservoir layer, RT is a deep resistivity of the target reservoir layer, and Fi is a reservoir fluid discrimination factor of the target reservoir layer; when the Fi is smaller than the second threshold value, the water layer is judged; when the Fi is larger than or equal to a second threshold value, the oil-gas-containing layer is judged; the numerical value of the second threshold is preferably determined in a mode of oil testing data calibration; in one embodiment, the second threshold is determined by calibration using the testing data of the tested reservoir in the same block as the target reservoir, specifically: determining the Fi limit value of the oil-bearing layer and the water layer as the second threshold value of the block by using the Fi value of the reservoir layer with finished oil testing (the calculation method of the Fi value of the reservoir layer with finished oil testing is the same as that of the target reservoir layer) and the reservoir fluid property (belonging to the oil-bearing layer or the water layer) obtained by the oil testing data of the reservoir layer; in one embodiment, the second threshold is 3.0.

In one embodiment, the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir comprises the following steps:

acquiring the thickness of the effective oil producing rock corresponding to the target reservoir layer, the distance between the effective oil producing rock and the target reservoir layer, the quality factor of the target reservoir layer, the deep resistivity of the target reservoir layer and the porosity of the target reservoir layer;

calculating a reservoir fluid discrimination factor of the target reservoir based on the obtained thickness of the effective oil producing rock, the distance between the effective oil producing rock and the target reservoir, the quality factor of the target reservoir and the deep resistivity of the target reservoir; wherein Fi ═ RT × RQI × H ÷ H; h is the thickness of the effective oil producing rock corresponding to the target reservoir stratum, m; h is the distance between the effective oil producing rock and the target reservoir, m; RQI is the quality factor of the target reservoir; RT is the deep resistivity of the target reservoir, Ω · m; fi is a reservoir fluid discrimination factor for the target reservoir;

determining a fluid property of a target reservoir based on a reservoir fluid discrimination factor of the target reservoir and a porosity level of the target reservoir:

porosity is greater than or equal to a first threshold and ((RT × RQI). times.H)/H is greater than or equal to a second threshold: judging the layer to be an oil (gas) containing layer;

porosity is greater than or equal to a first threshold and ((RT × RQI). times.H)/H < a second threshold: judging the water layer;

porosity < first threshold: and judging the liquid layer as a low liquid yield layer.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, the quality factor (i.e., the factor reflecting the quality of the reservoir) is preferably determined by permeability and porosity. More preferably still, the first and second liquid crystal compositions are,wherein, RQI is the quality factor of the target reservoir; k is the permeability of the mixture, and K is the permeability of the mixture,10^-3μm²；porosity,%.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, preferably, the porosity is determined according to a sonic time difference log. In a specific embodiment, the porosity is calculated by a core calibration logging method according to an acoustic time difference logging curve.

In the method for distinguishing the fluid property of the near-source storage type oil and gas reservoir, preferably, the permeability is calculated by a method of core scale logging, and is calculated by utilizing the porosity of the layer.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, the porosity is preferably determined according to a nuclear magnetic resonance logging curve.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, preferably, the permeability is determined according to a nuclear magnetic resonance logging curve.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, preferably, the thickness of the effective oil producing rock is determined by a natural gamma logging curve, an acoustic time difference logging curve and a deep resistivity logging curve at the top of the target reservoir. More preferably, the thickness of the available oil shale is determined by: and overlapping the acoustic wave time difference and the deep resistivity in the same logging curve track in the oil-producing rock interval with the natural gamma value larger than 110API at the top of the target reservoir layer to determine the effective oil-producing rock thickness adjacent to the target reservoir layer. In a specific embodiment, the thickness of the pay oil shale is determined by: firstly, replaying the acoustic time difference logging curve at the same logging curve track according to 500-150 mu s/m and the deep resistivity logging curve at the same logging curve track according to 0.1-100 omega.m; judging the interval with the natural gamma value of more than 110API at the top of the target reservoir stratum and the deep resistivity on the right side of the acoustic wave time difference logging curve as an effective oil-producing rock stratum; then, the thickness of the active petrolite is calculated from the difference in depth between the bottom and top of the active petrolite.

In the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir, preferably, the distance between the effective oil producing rock and the target reservoir is determined by a natural gamma logging curve, an acoustic wave time difference logging curve and a deep resistivity logging curve at the top of the target reservoir. More preferably, the distance between the active oil producing rock and the target reservoir is determined by: and overlapping the acoustic wave time difference and the deep resistivity in the same logging curve path in the oil-producing rock interval with the natural gamma value larger than 110API at the top of the target reservoir layer to determine the distance between the effective oil-producing rock and the target reservoir layer. In a specific embodiment, the thickness of the pay oil shale is determined by: firstly, replaying a sound wave time difference deep resistivity curve in the same logging curve channel according to 500-150 mu s/m and 0.1-100 omega.m; judging the interval with the natural gamma value of more than 110API at the top of the target reservoir stratum and the deep resistivity on the right side of the acoustic wave time difference logging curve as an effective oil-producing rock stratum; then, the distance between the active oil bearing rock and the target reservoir is calculated from the difference in depth between the bottom of the active oil bearing rock and the top of the target reservoir.

In the method for discriminating the fluid property of the near-source storage type oil and gas reservoir, the deep resistivity of the target reservoir layer can be directly obtained from deep lateral, deep induction or array induction resistivity.

In the near-source storage type hydrocarbon reservoir fluid property discrimination method, the low fluid production layer can be generally regarded as a reservoir with a fluid (water) production amount of less than 2.2 tons, and the high fluid production layer can be generally regarded as a reservoir with a fluid (water) production amount of 2.2 tons or more.

For conventional hydrocarbon reservoirs formed by hydrocarbon migration, the distribution of gas, oil and water in the reservoir is relatively regular. Gas, oil and water are stored in the upper, middle and lower parts of the reservoir in sequence according to their density. The reservoir has a uniform gas, oil, water interface. Fluid properties can be more accurately discriminated using the cross plot of porosity and resistivity. However, for near-source storage reservoirs, the accumulation of hydrocarbons does not meet classical laws. Whether a reservoir is capable of storing hydrocarbons is affected by many factors. The applicant has for the first time found that these factors include the quality of the reservoir itself, the thickness of the available pay rocks adjacent to the reservoir and the distance between the available pay rocks and the reservoir, etc. Due to the influence of the multiple factors, the fluid properties of the near-source storage type oil and gas reservoir cannot be accurately judged through a conventional porosity and resistivity cross-plot. Based on the method, the invention provides a brand-new near-source storage type oil and gas reservoir fluid property distinguishing method.

The near-source storage type oil and gas reservoir fluid property distinguishing method comprehensively considers factors such as the filling degree of an oil and gas reservoir and the quality of a reservoir layer, and effectively distinguishes the near-source storage type oil and gas reservoir fluid property through a fluid property comprehensive distinguishing factor based on the thickness of effective oil producing rocks, the distance between the effective oil producing rocks and a target reservoir layer, the quality factor of the target reservoir layer and the deep resistivity of the target reservoir layer. Compared with the traditional method (porosity and resistivity cross plot method) for distinguishing the fluid property of the near-source storage type oil and gas reservoir, the method for distinguishing the fluid property of the near-source storage type oil and gas reservoir provided by the invention can accurately distinguish the fluid property of the near-source storage type oil and gas reservoir, and improves the precision of distinguishing the fluid property of the near-source storage type oil and gas reservoir.

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 introduced below, and it is obvious that the drawings in the following description are only some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to the drawings without creative efforts:

figure 1 shows comparative example 1 provides an erudos basin penyang zone length 8 reservoir utilizing conventional porosityAnd a reservoir fluid property discrimination chart established by the deep resistivity RT;

fig. 2 is a flowchart of a method for discriminating a fluid property of a near-source storage type hydrocarbon reservoir provided in embodiment 1;

FIG. 3 is a plot of the correlation between the distance h between the long 8 reservoir and the long 7 productive oil petrography of the E.dolostomis Pengyang region and the long 8 reservoir depth resistivity RT provided in example 1;

FIG. 4 provides the utilization of porosity for example 1Judging a near source storage type oil and gas reservoir fluid property drawing board with a fluid property judgment factor Fi;

FIG. 5 provides the combined reservoir porosity of example 1And a fluid property discrimination factor Fi to discriminate an effect map of reservoir fluid properties.

Detailed Description

In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be described in detail and completely with reference to the drawings in the embodiments of the present invention. It is to be understood that the embodiments described are only a few embodiments of the present invention, and not all embodiments. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present invention.

In one embodiment, the method for discriminating the fluid property of the near-source storage type hydrocarbon reservoir comprises the following steps:

1) extracting the deep resistivity RT, the natural gamma GR and the acoustic time difference AC from the conventional logging curve, processing the acoustic time difference curve AC, and calculating to obtain the porosity of the target reservoir stratumAnd a permeability K;

2) overlapping the acoustic wave time difference AC and the acoustic wave time difference RT in the same logging curve path in the oil-producing rock interval with the GR value larger than 110API at the top of the target reservoir layer, and determining the effective oil-producing rock thickness H adjacent to the target reservoir layer and the distance H between the effective oil-producing rock and the target reservoir layer;

3) exploiting target reservoir porosityAnd permeability K, calculating a quality factor RQI for the target reservoir using the formula:

4) and calculating a reservoir fluid property discrimination factor Fi of the target reservoir by combining the target reservoir deep resistivity RT, the quality factor RQI, the effective petroliferous thickness H and the distance H between the effective petroliferous and the target reservoir according to the following formula:

Fi＝((RT×RQI)×H)/h

5) incorporating target reservoir porosityAnd a reservoir fluid discrimination factor Fi for discriminating the fluid property of the target reservoir using the criteria:

a)judging the layer to be an oil (gas) containing layer;

b)judging the water layer;

c)judging the liquid layer as a low liquid yield layer;

the first threshold value and the second threshold value are determined in a mode of oil testing data calibration.

Comparative example 1

This comparative example provides a reservoir fluid property identification method for identifying the fluid properties of a typical near-source reservoir type reservoir of 8 reservoir length in the pales Pengyang region of Ordos reservoir, using conventional porosityThe method is carried out by a resistivity RT cross method, and specifically comprises the following steps:

porosity of any number of target reservoirs using the 8-long reservoir in the Pengyang Pengyi of Ordos basinCross-breeding with resistivity RT to determine fluid properties of the long 8 reservoir in the gordong region of the deldos basin; wherein the target reservoir is a reservoir of known reservoir fluid properties.

The result is shown in fig. 1, and it can be seen from fig. 1 that there is no obvious difference in porosity and resistivity between the oil (gas) bearing layer and the water layer, the high-resistivity water layer and the low-resistivity oil layer develop simultaneously, and the discrimination conformity rate of the reservoir fluid property is only 66.7%, which is far from the basic requirements of reservoir evaluation and prediction.