Free hydrocarbon content determination method based on pressure coefficient

Abstract

The invention discloses a free hydrocarbon content determination method based on a pressure coefficient. The method comprises the steps that a well similar to a target area shale reservoir sedimentary environment is selected as a simulation well; acquiring a pressure coefficient and free hydrocarbon data of the shale reservoir of the simulated well, and establishing a correlation between the pressure coefficient and the free hydrocarbon; solving the free hydrocarbon content of the shale reservoir in the target area by utilizing the pressure coefficient of the shale reservoir in the target area and the correlation; the problem that an existing method for solving the free hydrocarbon S1 based on TOC and Ro is complex in process is effectively solved.

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 obtaining the free hydrocarbon S1 content. Background Art

[0002] In the current oilfield exploration and development, shale oil and gas has gradually become an important field for oil and gas replacement. Free hydrocarbon S1 is hydrocarbon that has been generated in the rock but still remains in the rock and exists in a free state. Its size directly affects the production of the reservoir and is an important indicator for directly evaluating the oil production capacity. Accurately obtaining the free hydrocarbon S1 content is the key to shale oil and gas reservoir evaluation.

[0003] The current methods for obtaining S1 are based on TOC and Ro. Total organic carbon content (TOC) is a parameter commonly used at home and abroad to indicate the abundance of organic matter. It refers to the carbon content in the organic matter remaining in the rock after the oil and gas from the source rock escape. It is the material basis for oil and gas generation and determines the ability of shale to generate hydrocarbons. It can be obtained by organic geochemical analysis of core or cuttings samples, or calculated using logging data. Maturity (Ro) is an important indicator of shale's hydrocarbon generation potential and a key geochemical parameter for the evaluation of high-yield shale oil and gas. The higher the maturity, the more oil and gas will be generated.

[0004] At present, the main problem in obtaining free hydrocarbon S1 based on TOC and Ro is that the organic carbon content (TOC) and S1 in different blocks are not in a fixed proportional relationship, and other parameters are needed to accurately obtain free hydrocarbon S1; according to oil generation theory, the higher the Ro, the more organic matter is converted into oil and gas, but 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 the free hydrocarbon S1 decreases parabolically with Ro, forming an illusion of poor oil content. A recovery method is established through core calibration to restore the free hydrocarbon S1 to the value when the formation was originally oil-bearing. Only on the basis of accurately obtaining 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 complicated 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 comprises:

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

[0008] Acquiring 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 shale reservoir pressure coefficient in the target area and the correlation.

[0010] In the present disclosure and possible embodiments, the shale reservoir pressure coefficient is obtained using 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 the abnormal pressure zone, the pressure coefficient is calculated 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 obtaining 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 and logarithmic acoustic wave time difference relationship diagram, 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 simulated well shale reservoir 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, establishes a correlation between the pressure coefficient and the core pyrolysis S1, and then uses the correlation and the pressure coefficient of the target block to obtain the free hydrocarbon S1 of the shale reservoir in 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 is a correlation diagram between the multi-well pressure coefficient and the pyrolysis S1 of the target area of ​​the embodiment of the present disclosure, the abscissa is the pressure coefficient value calculated by using the acoustic wave, and the ordinate 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 that are not described in detail, those skilled in the art can also fully understand the present disclosure.

[0028] In addition, those skilled in the art should understand that the drawings are provided only to illustrate the purpose, features and advantages of the present disclosure, and the drawings are not actually drawn to scale. At the same time, unless the context clearly requires, the words "include", "comprise" and the like in the entire specification and claims should be interpreted as inclusive rather than exclusive or exhaustive; that is, "including but not limited to" meaning.

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

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

[0031] The disclosed method obtains the reservoir pressure coefficient based on conventional logging data, establishes a correlation between the pressure coefficient and the core pyrolysis S1, and then obtains the free hydrocarbon S1 of the shale reservoir in the target block 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 in conjunction with the accompanying drawings. The specific steps are as follows:

[0033] 1. Obtain 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——covering layer 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 time difference of mudstone decreases exponentially with the increase of depth, and shows a linear change relationship on the relationship diagram of Depth (depth) and ln△t (logarithmic acoustic time difference). The upper part of point C (lithology interface point) is the normal compaction zone. In the normal pressure environment, that is, the static water column pressure environment, the skeleton stress supports the overburden load caused by the contact between particles. At this time, the static water (pure water or slightly alkaline formation water) pressure gradient 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 obtained by the equivalent depth method. The so-called "equivalent depth method" means that the effective stress δ (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 sonic logging means that without considering the influence of temperature, if the Δt value (sonic time difference value) of a point on the normal trend line is the same as the Δt value of a point on the overpressure zone, it reflects that the pore structure and compaction degree of the two points are the same, the formation skeleton stress of the two points is equivalent, and the depth of a point on the normal trend line that is equal to the measured value of 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 A =δ B .

[0042] Then the formation pressure value at point A is p 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 ——Pressure gradient of the overburden at point A, kg·cm -2 ·m -1 ;

[0045] G oB ——Pressure gradient of the overburden 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 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 of multiple wells and obtain S1.

[0057] Wells with similar sedimentary environments to those in the target area but different burial depths were selected as simulation wells. The pressure coefficient was obtained using the above-mentioned pressure coefficient calculation method. The pressure coefficient and geochemical pyrolysis S1 were used to establish a correlation between the pressure coefficient and S1 through polynomial fitting.

[0058] If for 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. Further, 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 obtain 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) Determine 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] According to the relationship diagram 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] The above pressure coefficient calculation formula is used in combination with the pyrolysis S1, and a correlation formula between the pressure coefficient and S1 is established through polynomial fitting, and the S1 value is obtained using the correlation formula.

[0070] (3) Effect verification

[0071] exist Figure 3 In the above actual production well, at 2410-2420 meters, the calculated pressure coefficient is 1.49, and the calculated S1 is 13.2 mg / g, which means that 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 that 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] It can be seen from the application results of the actual production well 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 only embodiments of the present disclosure, and the descriptions thereof are relatively specific and detailed, but they cannot be construed as limiting the scope of the present disclosure. It should be noted that, for a person of ordinary skill in the art, without departing from the concept of the present disclosure, several variations, equivalent substitutions, improvements, etc. may be made, all of which fall within the scope of protection of the present disclosure. Therefore, the scope of protection of the present disclosure shall be subject to the attached 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 are selected as simulation wells; Acquiring 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; The free hydrocarbon content of the shale reservoir in the target area is calculated using the shale reservoir pressure coefficient in the target area and the correlation.

2. The method for determining free hydrocarbon content based on pressure coefficient according to claim 1, characterized in that: The shale reservoir pressure coefficient is obtained using logging acoustic wave data.

3. The method for determining free hydrocarbon content based on pressure coefficient according to claim 2, characterized in that: The calculation method of the pressure coefficient includes: For the normal compaction zone of the shale reservoir, the pressure coefficient is 1.0; For the abnormal pressure zone, the pressure coefficient is calculated using the equivalent depth method.

4. The method for determining free hydrocarbon content based on pressure coefficient according to claim 3, characterized in that: The method of 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.

5. The method for determining free hydrocarbon content based on pressure coefficient according to claim 4, characterized in that: The formula for obtaining the formation pressure using the equivalent depth method is: p fA =0.231(D A -D B )+0.1·D B ; 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 .

6. The method for determining free hydrocarbon content based on pressure coefficient according to claim 5, characterized in that: A linear relationship between depth and logarithmic acoustic wave time difference is established through a depth-to-logarithmic acoustic wave time difference relationship diagram, and the depths of point A and point B are determined through the linear relationship.

7. The method for determining free hydrocarbon content based on pressure coefficient according to any one of claims 1 to 6, characterized in that: The free hydrocarbon data of the simulated well shale reservoir are obtained through geochemical pyrolysis data of the simulated well.

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