A method for determining free hydrocarbon content based on pressure coefficient

Abstract

The present application discloses a method for determining the free hydrocarbon content based on a pressure coefficient, comprising: selecting a well with a sedimentary environment similar to that of a shale reservoir in a target area as a simulation well; obtaining the pressure coefficient and free hydrocarbon data of the shale reservoir in the simulation well and establishing a correlation between the pressure coefficient and the free hydrocarbon; using the pressure coefficient of the shale reservoir in the target area and the correlation to calculate the free hydrocarbon content of the shale reservoir in the target area; and effectively solving the problem of the complex process of the current method for calculating free hydrocarbon S1 based on TOC and Ro.

Description

Technical Field

[0001] The present disclosure relates to the field of oil and natural gas exploration and development, and specifically to a method for calculating the free hydrocarbon S1 content. Background Art

[0002] In current oilfield exploration and development, shale oil and gas has gradually become a key area for oil and gas replacement. Free hydrocarbons (S1) are hydrocarbons that have already formed in the rock but still remain in the rock, existing in a free state. Their amount directly affects the reservoir's yield and is an important indicator for directly evaluating oil production capacity. Accurately determining the free hydrocarbon S1 content is key to shale oil and gas reservoir evaluation.

[0003] Current methods for calculating S1 are based on TOC and Ro. Total organic carbon (TOC) is a commonly used parameter indicating organic matter abundance both domestically and internationally. It refers to the carbon content in the organic matter remaining in the rock after the escape of oil and gas from the source rock. It is the material basis for oil and gas generation and determines the hydrocarbon generation capacity of shale. It can be determined through organic geochemical analysis of core or cutting samples or calculated using well logging data. Maturity (Ro) is an important indicator of shale's hydrocarbon generation potential and a key geochemical parameter in the evaluation of high-yield shale oil and gas. Higher maturity indicates greater oil and gas generation.

[0004] Currently, the main problem in calculating free hydrocarbon S1 based on TOC and Ro is that the organic carbon content (TOC) and S1 in different blocks do not form a fixed proportional relationship, and other parameters are needed to accurately calculate free hydrocarbon S1. According to oil generation theory, the higher the Ro, the more organic matter is converted into oil and gas. However, after Ro reaches a certain critical value, the oil and gas are mainly light components S0 (the content of hydrocarbons per unit mass of reservoir rock detected at 90 degrees Celsius), and free hydrocarbon S1 decreases parabolically with Ro, creating the illusion of deteriorating oil content. A recovery method is established through core calibration to restore free hydrocarbon S1 to the value when the formation was originally oil-bearing. Only by accurately calculating the maturity Ro can the true free hydrocarbon S1 value of the reservoir be obtained. Summary of the Invention

[0005] In view of this, the present disclosure provides a method for determining the free hydrocarbon content based on the pressure coefficient, which solves the problem of the complex process of the current method for obtaining the free hydrocarbon S1 based on TOC and Ro.

[0006] To achieve the above-mentioned object of the invention, the method for determining the free hydrocarbon content based on the pressure coefficient includes:

[0007] Wells with sedimentary environments similar to those of the shale reservoirs in the target area were selected as simulation wells;

[0008] Obtaining the shale reservoir pressure coefficient and free hydrocarbon data of the simulated well and establishing a correlation between the pressure coefficient and the free hydrocarbon;

[0009] The free hydrocarbon content of the shale reservoir in the target area is calculated using the pressure coefficient of the shale reservoir in the target area and the correlation.

[0010] In the present disclosure and possible embodiments, the shale reservoir pressure coefficient is obtained using well logging acoustic wave data.

[0011] In the present disclosure and possible embodiments, the method for calculating the pressure coefficient includes:

[0012] For the normal compaction zone of the shale reservoir, the pressure coefficient is 1.0;

[0013] For abnormal pressure zones, the pressure coefficient is obtained using the equivalent depth method.

[0014] In the present disclosure and possible embodiments, the method of obtaining the pressure coefficient using the equivalent depth method includes:

[0015] The formation pressure is calculated using the equivalent depth method, and the pressure coefficient is obtained by dividing the formation pressure by the current depth.

[0016] In the present disclosure and possible embodiments, the formula for calculating the formation pressure using the equivalent depth method is:

[0017] p fA =0.231(D A -D B )+0.1·D B ;

[0018] Where: D A is the depth of point A, m; D B is the depth of point B, m; D B D A The equivalent depth of .

[0019] In the present disclosure and possible embodiments, a linear relationship between depth and logarithmic acoustic wave time difference is established through a depth-to-logarithmic acoustic wave time difference relationship graph, and the depths of point A and point B are determined through the linear relationship.

[0020] In the present disclosure and possible embodiments, the free hydrocarbon data of the shale reservoir of the simulated well is obtained through geochemical pyrolysis data of the simulated well.

[0021] The present disclosure has the following beneficial effects:

[0022] The method of the present invention obtains the reservoir pressure coefficient based on conventional logging data. By establishing a correlation between the pressure coefficient and the core pyrolysis S1, the free hydrocarbon S1 of the shale reservoir in the target block is obtained by using the correlation and the pressure coefficient of the target block, thereby achieving the purpose of quickly obtaining S1 using acoustic logging data and effectively solving the problem of complex process of the current method for obtaining free hydrocarbon S1 based on TOC and Ro. BRIEF DESCRIPTION OF THE DRAWINGS

[0023] The above and other objects, features and advantages of the present disclosure will become more apparent through the following description of the embodiments of the present disclosure with reference to the accompanying drawings, in which:

[0024] Figure 1 It is a schematic diagram of the equivalent depth method;

[0025] Figure 2 This is a correlation diagram between the multi-well pressure coefficient and the pyrolysis S1 in the target area of ​​the embodiment of the present disclosure, where the horizontal axis is the pressure coefficient value calculated using the acoustic wave, and the vertical axis is the geochemical pyrolysis analysis S1;

[0026] Figure 3 This is a diagram showing the calculation results of the pressure coefficient of the XX well according to an embodiment of the present disclosure. DETAILED DESCRIPTION

[0027] The present disclosure is described below based on embodiments, but it is worth noting that the present disclosure is not limited to these embodiments. In the detailed description of the present disclosure below, some specific details are described in detail. However, for the parts not described in detail, those skilled in the art can also fully understand the present disclosure.

[0028] In addition, persons of ordinary skill in the art will appreciate that the drawings are provided only to illustrate the objects, features, and advantages of the present disclosure and are not drawn to scale. Furthermore, unless the context clearly requires otherwise, the words "include," "comprising," and similar expressions throughout the specification and claims should be interpreted as including, rather than exclusive or exhaustive; that is, as meaning "including but not limited to."

[0029] The method for determining the free hydrocarbon content based on the pressure coefficient described in the embodiments of the present disclosure is summarized as follows:

[0030] A well with a similar depositional environment and a different burial depth to the target shale reservoir is selected as a simulation well. The shale reservoir pressure coefficient and free hydrocarbon data of the simulation well are obtained, and a correlation between the pressure coefficient and the free hydrocarbon is established. The free hydrocarbon content of the shale reservoir in the target area is calculated using the target shale reservoir pressure coefficient and the correlation. The shale reservoir pressure coefficient is calculated using well logging acoustic data.

[0031] The disclosed method obtains the reservoir pressure coefficient based on conventional logging data. By establishing a correlation between the pressure coefficient and the core pyrolysis S1, the free hydrocarbon S1 of the shale reservoir in the target block is obtained through the correlation and the pressure coefficient of the target block, thereby achieving the purpose of quickly obtaining S1 using acoustic logging data.

[0032] The method for determining the free hydrocarbon content based on the pressure coefficient disclosed in the present invention is further described with reference to the accompanying drawings. The specific steps are as follows:

[0033] 1. Calculate the pressure coefficient. The specific calculation principle is as follows:

[0034] During the compaction process of mudstone, according to the principle of pressure balance,

[0035] p0=p f +δ;

[0036] Where: p0——cover pressure, kg·cm -2 ;

[0037] p f ——Forming pore fluid pressure, kg·cm -2 ;

[0038] δ——Skeleton stress between rock particles, also called skeleton effective stress, kg·cm -2 .

[0039] like Figure 1 As shown in the figure, for the normal compaction zone, the acoustic transit time of mudstone decreases exponentially with increasing depth, and shows a linear relationship on the Depth (depth) vs. ln△t (logarithmic acoustic transit time). The upper part of point C (lithologic interface) is the normal compaction zone. Under normal pressure, i.e., the hydrostatic column pressure environment, the skeleton stress supports the overburden load caused by particle-to-particle contact. At this time, the hydrostatic pressure gradient (pure water or slightly alkaline formation water) is 0.1 kg·cm -2 ·m -1 , the formation pressure is 0.1D (kg·cm -2 ), the pressure coefficient is 1.0.

[0040] For abnormal pressure zones, the formation pressure can be calculated using the equivalent depth method. The so-called "equivalent depth method" refers to the fact that the effective stress δ (the skeleton stress between rock particles) on the skeleton of mudstone with the same rock physical properties (such as porosity) at different depths is equal. The equivalent depth method based on acoustic logging means that, without considering the influence of temperature, if the Δt value (sonic wave time difference) at a point on the normal trend line is the same as the Δt value at a point on the overpressure zone, it reflects that the pore structure and compaction degree of the two points are the same, and the formation skeleton stress at the two points is equivalent. The depth of the point on the normal trend line that is equal to the measured value at the overpressure point is the equivalent depth.

[0041] The basic idea of ​​the equivalent depth method is: if the effective stress of the skeleton at point A in the abnormal layer section and point B in the normal pressure layer section is equal, then D B D A The equivalent depth of δ A =δ B .

[0042] Then the formation pressure value p at point A is fA =p oA -δ A =p oA -(p oB -p fB )

[0043] That is, p fA =G oA ·D A -(G oB D B -G fB ·D B )

[0044] Where: G oA ——Overburden pressure gradient at point A, kg·cm -2 ·m -1 ;

[0045] G oB ——Overburden pressure gradient at point B, kg·cm -2 ·m -1 ;

[0046] D A ——depth of point A, m;

[0047] D B ——depth of point B, m;

[0048] Using its theoretical value G o =0.0231MPa / m for calculation. The error between the result and the measured static pressure is within the allowable range.

[0049] For fresh water or alkaline formation water hydrostatic pressure gradient

[0050]

[0051] Due to the formation pressure gradient at point B in the normal pressure layer

[0052] G fB =G w =0.1kg·cm -2 ·m -1 .

[0053] Finally, the formation pressure p at point A is obtained fA =0.231(D A -D B )+0.1·D B ;

[0054] The formation pressure gradient at point A, i.e., the pressure coefficient, is:

[0055] G fA =p fA / D A .

[0056] 2. Establish the correlation between S1 and pressure coefficient for multiple wells and calculate S1.

[0057] A well with a similar sedimentary environment to the target area but a different burial depth was selected as a simulation well. The pressure coefficient was obtained using the above-mentioned pressure coefficient calculation method. The pressure coefficient was combined with geochemical pyrolysis S1 and a polynomial fitting was performed to establish the correlation between the pressure coefficient and S1.

[0058] If the attached Figure 1 The target block shale reservoir is selected, and four wells G1X, S1X, S2X, and G2HX are selected as typical modeling wells. Figure 1 It shows that as the pressure coefficient increases, S1 increases. According to the correlation between S1 and pressure coefficient of typical modeling wells, as shown in Figure 2 As shown, the binomial formula obtained by fitting is: y = 22.782x 2 -34.83x+14.817. Furthermore, the fitted binomial formula and the pressure coefficient of the target block can be used to calculate the S1 of the shale reservoir in the target block. Obviously, this binomial formula is applicable to the target block, but not to other blocks with different sedimentary environments.

[0059] In addition, the disclosed method is applicable to all shale reservoirs. The relationship between overpressure and oil content of shale reservoirs, i.e., the greater the pressure coefficient, the better the oil content, can be used to find the correlation between the pressure coefficient and the oil content parameter S1, and then calculate S1.

[0060] The method of the present invention is applied to Figure 3 In the actual production well shown, the application process is as follows:

[0061] (1) Calculate the pressure coefficient

[0062] The equivalent depth method is used to calculate the formation pressure, and the formation pressure divided by the depth is the pressure coefficient.

[0063] Formation pressure: p fA =0.231(D A -D B )+0.1·D B ;

[0064] Where: D A ——depth of point A, m; D B ——depth of point B, m;

[0065] Based on the relationship between Depth (depth) and ln△t (logarithmic acoustic wave time difference), a linear relationship between Depth and ln△t can be established: Depth = ab*ln△t, where a and b are regional coefficients. Therefore, the above formation pressure formula is:

[0066] p fA =0.231*[(ab*ln △tA )-(ab*ln △tB )]+0.1*(ab*ln △tB );

[0067] The pressure coefficient at point A is: G fA =p fA / D A .

[0068] (2) Obtaining S1

[0069] Using the above pressure coefficient calculation formula, combined with the pyrolysis S1, a correlation formula between the pressure coefficient and S1 is established through polynomial fitting, and the S1 value is calculated using this correlation formula.

[0070] (3) Effect verification

[0071] exist Figure 3 In the actual production well mentioned above, at 2410-2420 meters, the calculated pressure coefficient is 1.49, and the calculated S1 is 13.2 mg / g, which means the pressure coefficient is high, the oil content is good, the test oil production is 42.1 cubic meters per day, and the oil production is high; at 2466-2474 meters, the calculated pressure coefficient is 1.47, and the calculated S1 is 12.2 mg / g, which means the pressure coefficient is slightly poor, the oil content is slightly poor, the test oil production is 30.56 cubic meters per day, and the oil production is slightly poor; Figure 3 As shown, the S1 calculated by the present invention is consistent with the oil test results.

[0072] The application results of the actual production well show that the S1 obtained by the method disclosed in the present invention through the pressure coefficient has a good correspondence with the test oil production, which proves the accuracy of the method for determining the free hydrocarbon S1 content based on the fracturing coefficient of the present invention.

[0073] The above-described embodiments are merely examples of implementation methods of the present disclosure, and their descriptions are relatively specific and detailed. However, they should not be construed as limiting the scope of the present invention. It should be noted that a person skilled in the art may make various modifications, equivalent substitutions, and improvements without departing from the scope of the present disclosure, and these modifications are all within the scope of protection of the present disclosure. Therefore, the scope of protection of the present invention shall be based on the appended claims.

Claims

1. A method for determining free hydrocarbon content based on pressure coefficient, characterized in that: include: Wells with sedimentary environments similar to those of the shale reservoirs in the target area were selected as simulation wells; Obtaining the shale reservoir pressure coefficient and free hydrocarbon data of the simulated well and establishing a correlation between the pressure coefficient and the free hydrocarbon; Calculating the free hydrocarbon content of the shale reservoir in the target area by using the pressure coefficient of the shale reservoir in the target area and the correlation; Calculating the pressure coefficient of the shale reservoir using well logging acoustic wave data; The calculation method of the pressure coefficient includes: For the normal compaction zone of the shale reservoir, the pressure coefficient is 1.0; For abnormal pressure zones, the pressure coefficient is obtained using the equivalent depth method; The method for obtaining the pressure coefficient using the equivalent depth method includes: The formation pressure is calculated using the equivalent depth method, and the pressure coefficient is obtained by dividing the formation pressure by the current depth; The formula for obtaining the formation pressure using the equivalent depth method is: ； Where: D A is the depth of point A, m; D B is the depth of point B, m; D B for D A The equivalent depth of .

2. The method for determining free hydrocarbon content based on pressure coefficient according to claim 1, characterized in that: A linear relationship between depth and logarithmic acoustic wave time difference is established through a depth and logarithmic acoustic wave time difference relationship diagram, and the depths of point A and point B are determined through the linear relationship.

3. The method for determining the free hydrocarbon content based on the pressure coefficient according to claim 1 or 2, characterized in that: The free hydrocarbon data of the shale reservoir of the simulated well is obtained through geochemical pyrolysis data of the simulated well.

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