A method for determining reservoir porosity in a mottled carbonate rock

Abstract

This invention provides a method for determining reservoir porosity in mottled carbonate rocks. The method includes the following steps: (1) drilling core samples of mottled carbonate rocks and cutting a portion of the sample to prepare a cast thin section; (2) calculating the area ratio of the reservoir region and the non-reservoir region based on the microscopic image of the cast thin section obtained in step (1); (3) measuring the external volume and rock skeleton volume of the core sample obtained in step (1); (4) performing a CT scan on the core sample obtained in step (1), and calculating the volume ratio of the reservoir region and the non-reservoir region in the core sample based on the area ratio of the reservoir region and the non-reservoir region in the cast thin section obtained in step (2); (5) calculating the reservoir porosity in the core sample based on the results obtained in steps (3) and (4). The determination method provided by this invention improves the accuracy of porosity logging and lays the foundation for more precise research on porosity-permeability relationships.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil and gas field development, and relates to a method for measuring rock porosity, in particular to a method for measuring reservoir porosity of mottled carbonate rock. BACKGROUND

[0002] The Middle East marine pore type carbonate rock reservoir has strong heterogeneity at both macroscopic and microscopic scales. Core data of many oilfields such as Ahadebu, Hafaya, Xiguerna and Misson shows special "mottled" heterogeneity. The white patches are dense and do not contain oil, and the dark patches are rich in oil. On the logging curve, the white patches show the characteristics of non-reservoir or interlayer, and the dark patches show the characteristics of high porosity and high permeability. The oil test production shows that the dark patches are high-yield layers and are prone to become water flow dominant channels after water injection development.

[0003] Through microscopic identification of thin sections, the development of "mottled" limestone is not controlled by lithology, and white and dark patches are developed in various lithologies. Microscopic observation of pore structure shows that the intergranular pores of white patch limestone are not developed or developed isolated pores, and the pore position is cemented by bright calcite. The intergranular pores of dark patch limestone are developed, and the cementation of bright calcite is weak. The correlation between the current laboratory measurement of rock porosity and permeability is poor, which seriously restricts the accuracy of reservoir characterization and the development of reasonable development plan.

[0004] Laboratory measurement of rock porosity is an important parameter for evaluating reservoir physical properties and calculating oil and gas reserves by volume method. The rock porosity measurement method specified in GB / T 29172-2012 "Rock Analysis Method" is as follows: the volume of the rock skeleton is measured by volume expansion method according to Boyle's law, and the outer surface volume of the cylindrical sample is calculated by volume formula, so that the porosity can be calculated as follows:

[0005]

[0006] In the formula, V p is the rock pore volume, V s is the rock skeleton volume, and V f is the outer surface volume.

[0007] Since the dark patches in the "mottled" carbonate rock are reservoirs, they are developed between the white nodule-shaped patches in the non-reservoir, and the development width of the dark patch reservoir is usually 1-2 cm according to core observation. The diameter of the cylindrical sample taken for laboratory measurement of rock porosity is generally 2.5 to 3.8 cm, which is larger than the development width of the dark patch. Therefore, the small cylindrical sample drilled from the core includes the reservoir and the non-reservoir. However, the current laboratory measurement of rock porosity cannot reflect the true porosity of the reservoir in the "mottled" carbonate rock.

[0008] Therefore, how to provide a method for determining the reservoir porosity in the "mottled" carbonate rock, improve the accuracy of the porosity logging, and lay a foundation for the higher accuracy of the porosity-permeability relationship research has become a problem to be solved by the person skilled in the art. SUMMARY

[0009] The purpose of the present application is to provide a method for determining the reservoir porosity in the mottled carbonate rock, which fills the blank of the experimental logging of the reservoir porosity in the mottled carbonate rock, improves the accuracy of the porosity logging, and lays a foundation for the higher accuracy of the porosity-permeability relationship research.

[0010] To achieve the purpose of the present application, the following technical solutions are adopted:

[0011] The present application provides a method for determining the reservoir porosity in the mottled carbonate rock, which comprises the following steps:

[0012] (1) drilling the core sample of the mottled carbonate rock, and cutting part of the sample to prepare a cast thin section;

[0013] (2) calculating the area proportion of the reservoir area and the non-reservoir area, respectively, according to the microscopic image of the cast thin section obtained in step (1);

[0014] (3) measuring the outer surface volume and the rock skeleton volume of the core sample obtained in step (1), respectively;

[0015] (4) performing CT scanning on the core sample obtained in step (1), and combining the area proportions of the reservoir area and the non-reservoir area in the cast thin section obtained in step (2), to calculate the volume proportions of the reservoir area and the non-reservoir area in the core sample, respectively;

[0016] (5) calculating the porosity of the reservoir in the core sample according to the results obtained in steps (3) and (4) as follows:

[0017]

[0018] In the formula: is the porosity of the reservoir, V p is the rock pore volume, V s is the rock skeleton volume, V f is the outer surface volume, V1 is the volume of the reservoir area, and m is the volume proportion of the reservoir area.

[0019] Wherein, steps (3) and (4) are not in a specific order.

[0020] The application establishes a determination method of reservoir porosity in mottled carbonate rocks under the premise that there is no connected pore in non-reservoir area of mottled carbonate rocks, based on the method of traditional laboratory determination of rock porosity, adding the steps of casting thin section identification and CT scan image recognition calculation, combining the volume of the core sample and the volume of the rock skeleton, and filling the blank of experimental logging of reservoir porosity in mottled carbonate rocks, providing a more accurate porosity value for the calculation of the reserves of the oil reservoir, and laying a solid foundation for objectively evaluating the economic value of the oil reservoir and formulating the development strategy.

[0021] Preferably, the core sample in step (1) is a cylindrical sample.

[0022] Preferably, the diameter of the cylindrical sample is 2-4 cm, for example, it can be 2 cm, 2.2 cm, 2.4 cm, 2.6 cm, 2.8 cm, 3 cm, 3.2 cm, 3.4 cm, 3.6 cm, 3.8 cm or 4 cm, but is not limited to the listed values, and other values not listed in the range are also applicable.

[0023] Preferably, the specific calculation method of the area ratio in step (2) is as follows: under the optical microscope, the micro image of the casting thin section is observed, the dark patches are taken as the reservoir area, and the white patches are taken as the non-reservoir area, and the area ratio of the dark patches and the white patches is calculated, that is, the area ratio of the reservoir area and the non-reservoir area in the casting thin section is obtained.

[0024] In the application, the area ratio of the dark patches and the white patches can be calculated by using the grid method.

[0025] Preferably, the outer surface volume in step (3) is directly calculated according to the volume formula of a cylinder, as shown below:

[0026]

[0027] In the formula, V is the outer surface volume, D is the diameter of the cylindrical sample, and L is the length of the cylindrical sample. f

[0028] Preferably, the rock skeleton volume in step (3) is determined by using the gas expansion method.

[0029] In the application, the gas expansion method can use the Boyle's law double-chamber method specified in GB / T 29172-2012 "Rock Analysis Method".

[0030] Preferably, the CT scanning in step (4) uses the core micron CT scanning technology.

[0031] ​Preferably, the specific process of the core micron CT scanning technology is as follows: starting from the sampling position of the cast thin section, at least 5 CT scans are performed at equal intervals along the axial direction of the core sample, and 2 CT scans are performed perpendicular to each other on the longitudinal section of the core sample. The scanned images are then processed to reduce noise, resulting in a series of CT scan grayscale images.

[0032] Preferably, the area ratio of the reservoir region and the non-reservoir region in the cast sheet obtained in step (2) is used to calibrate the CT scan grayscale image of the sampled position of the cast sheet, so as to determine the standard segmentation threshold of the remaining CT scan grayscale images.

[0033] Preferably, the specific calibration process is as follows: a segmentation threshold is preset, and F(i,j) represents the pixel grayscale value in the CT scan grayscale image. The set of pixels with grayscale values ​​greater than or equal to the segmentation threshold is divided into reservoir regions, and the set of pixels with grayscale values ​​less than the segmentation threshold is divided into non-reservoir regions. Then, the discriminant for reservoir regions and non-reservoir regions is:

[0034]

[0035] In the formula: g(i,j) is the pixel state value, where a state value of 1 indicates that the pixel belongs to the reservoir region, and a state value of 0 indicates that the pixel belongs to the non-reservoir region; i represents the x-coordinate value of the pixel, and j represents the y-coordinate value of the pixel; M represents the number of pixels in the x-axis direction, and N represents the number of pixels in the y-axis direction; T represents the segmentation threshold.

[0036] Preferably, the area ratio of the reservoir region and the non-reservoir region in the CT scan grayscale image of the sampled casting sheet is calculated according to g(i,j). When the area ratio is equal to the area ratio of the reservoir region and the non-reservoir region in the casting sheet obtained in step (2), the set segmentation threshold is used as the standard segmentation threshold for the remaining CT scan grayscale images.

[0037] Preferably, the area ratio of reservoir region and non-reservoir region in each CT scan grayscale image is calculated according to the standard segmentation threshold, and the arithmetic mean of the obtained series of area ratios is used as the volume ratio of reservoir region and non-reservoir region in the core sample.

[0038] As a preferred technical solution of the present invention, the method includes the following steps:

[0039] (1) Drill core samples of mottled carbonate rocks and cut some samples to prepare cast thin sections; the core samples are cylindrical samples with a diameter of 2-4 cm;

[0040] (2) Observe the microscopic image of the cast sheet obtained in step (1) under an optical microscope. Take the dark patch as the reservoir area and the white patch as the non-reservoir area. Calculate the area ratio of the dark patch and the white patch respectively, and then obtain the area ratio of the reservoir area and the non-reservoir area in the cast sheet.

[0041] (3) The external volume of the core sample was directly calculated according to the volume formula of a cylinder, and the volume of the rock skeleton of the core sample was determined by the gas expansion method.

[0042] (4) The core sample obtained in step (1) is scanned using core micron CT scanning technology. The specific process is as follows: starting from the sampling position of the cast thin section, at least 5 CT scans are performed at equal intervals along the axial direction of the core sample, and 2 CT scans are performed perpendicular to each other on the longitudinal section of the core sample. The scanned images are then processed to reduce noise and obtain a series of CT scan grayscale images.

[0043] (5) The area ratio of the reservoir region and the non-reservoir region in the thin film obtained in step (2) is used to calibrate the CT scan grayscale images of the sampling positions of the thin film obtained in step (4) in order to determine the standard segmentation threshold of the remaining CT scan grayscale images. The specific process is as follows:

[0044] (A) A pre-defined segmentation threshold is set, where F(i,j) represents the pixel grayscale value in the CT scan grayscale image. The set of pixels with grayscale values ​​greater than or equal to the segmentation threshold is classified as reservoir region, and the set of pixels with grayscale values ​​less than the segmentation threshold is classified as non-reservoir region. The discriminant for reservoir region and non-reservoir region is:

[0045]

[0046] In the formula: g(i,j) is the pixel state value, where a state value of 1 indicates that the pixel belongs to the reservoir region, and a state value of 0 indicates that the pixel belongs to the non-reservoir region; i represents the x-coordinate value of the pixel, and j represents the y-coordinate value of the pixel; M represents the number of pixels in the x-axis direction, and N represents the number of pixels in the y-axis direction; T represents the segmentation threshold.

[0047] (B) Calculate the area ratio of reservoir region and non-reservoir region in the CT scan grayscale image of the sampled casting sheet according to g(i,j). When the area ratio is equal to the area ratio of reservoir region and non-reservoir region in the casting sheet obtained in step (2), the set segmentation threshold is used as the standard segmentation threshold for the remaining CT scan grayscale images.

[0048] (6) Calculate the area ratio of reservoir region and non-reservoir region in each CT scan grayscale image based on the standard segmentation threshold obtained in step (5), and use the arithmetic mean of a series of area ratios as the volume ratio of reservoir region and non-reservoir region in the core sample.

[0049] (7) Based on the results obtained in steps (3) and (6), the porosity of the reservoir in the core sample is calculated as follows:

[0050]

[0051] In the formula: V represents the porosity of the reservoir. p V is the pore volume of the rock. s V is the volume of the rock skeleton. f V1 is the volume of the reservoir region, and m is the volume percentage of the reservoir region.

[0052] Compared with the prior art, the present invention has the following beneficial effects:

[0053] This invention, based on the premise that there are no connected pores in the non-reservoir areas of mottled carbonate rocks, incorporates casting thin section identification and CT scan image recognition calculations into the traditional laboratory method for determining rock porosity. By calculating the volume ratio of the reservoir area depicted in the CT scan image through casting thin sections, and combining the external volume of the core sample and the volume of the rock skeleton, a method for determining reservoir porosity in mottled carbonate rocks is established. This fills the gap in experimental logging of reservoir porosity in mottled carbonate rocks, provides more accurate porosity values ​​for reservoir reserve calculation, and lays a solid foundation for objectively evaluating the economic value of reservoirs and formulating development strategies. Attached Figure Description

[0054] Figure 1 These are microscopic images of the cast thin sheet in the measurement method provided by this invention;

[0055] Figure 2 This is a schematic diagram of a CT scan of the cross-section of a core sample in the measurement method provided by this invention;

[0056] Figure 3 This is a schematic diagram of a CT scan of the longitudinal section of a core sample in the measurement method provided by this invention;

[0057] Figure 4 This is a comparison chart showing the relationship between the corrected porosity obtained in Example 1 and the uncorrected porosity obtained in Comparative Example 1 on rock permeability.

[0058] Wherein: 1-reservoir area; 2-non-reservoir area. Detailed Implementation

[0059] The technical solution of the present invention will be further illustrated below through specific embodiments. Those skilled in the art should understand that the embodiments described are merely illustrative of the present invention and should not be construed as limiting the invention in any way.

[0060] Example 1

[0061] This embodiment provides a method for determining reservoir porosity in mottled carbonate rocks, the method comprising the following steps:

[0062] (1) Drill core samples of mottled carbonate rocks and cut some samples to prepare cast thin sections; the core samples are cylindrical samples with a diameter of 3 cm;

[0063] (2) Figure 1 As shown, the microscopic image of the cast sheet obtained in step (1) is observed under an optical microscope. Dark patches are taken as reservoir region 1 and white patches are taken as non-reservoir region 2. The area ratio of dark patches and white patches is calculated respectively, which gives the area ratio of reservoir region 1 and non-reservoir region 2 in the cast sheet.

[0064] (3) The external volume of the core sample is calculated directly using the formula for the volume of a cylinder, as shown below:

[0065]

[0066] In the formula: V f Let D be the external volume, D be the diameter of the cylindrical sample, and L be the length of the cylindrical sample.

[0067] The volume of the rock skeleton in the core sample was determined by the gas expansion method, and the gas expansion method adopted was the Boyle's law two-chamber method specified in GB / T29172-2012 "Rock Analysis Methods";

[0068] (4) The core sample obtained in step (1) was CT scanned using core micron CT scanning technology. The specific process is as follows: starting from the sampling position of the cast thin section, along the axial direction of the core sample, the cross-section of the core sample was scanned 5 times at equal intervals (see...). Figure 2 ), and two mutually perpendicular CT scans were performed on the longitudinal section of the core sample (see Figure 3 The scanned images are then denoised to obtain a series of grayscale CT scan images.

[0069] (5) The area ratio of the reservoir region and the non-reservoir region in the thin film obtained in step (2) is used to calibrate the CT scan grayscale images of the sampling positions of the thin film obtained in step (4) in order to determine the standard segmentation threshold of the remaining CT scan grayscale images. The specific process is as follows:

[0070] (A) A pre-defined segmentation threshold is set, where F(i,j) represents the pixel grayscale value in the CT scan grayscale image. The set of pixels with grayscale values ​​greater than or equal to the segmentation threshold is classified as reservoir region, and the set of pixels with grayscale values ​​less than the segmentation threshold is classified as non-reservoir region. The discriminant for reservoir region and non-reservoir region is:

[0071]

[0072] In the formula: g(i,j) is the pixel state value, where a state value of 1 indicates that the pixel belongs to the reservoir region, and a state value of 0 indicates that the pixel belongs to the non-reservoir region; i represents the x-coordinate value of the pixel, and j represents the y-coordinate value of the pixel; M represents the number of pixels in the x-axis direction, and N represents the number of pixels in the y-axis direction; T represents the segmentation threshold.

[0073] (B) Calculate the area ratio of reservoir region and non-reservoir region in the CT scan grayscale image of the sampled casting sheet according to g(i,j). When the area ratio is equal to the area ratio of reservoir region and non-reservoir region in the casting sheet obtained in step (2), the set segmentation threshold is used as the standard segmentation threshold for the remaining CT scan grayscale images.

[0074] (6) Calculate the area ratio of reservoir region and non-reservoir region in each CT scan grayscale image based on the standard segmentation threshold obtained in step (5), and use the arithmetic mean of a series of area ratios as the volume ratio of reservoir region and non-reservoir region in the core sample.

[0075] (7) Based on the results obtained in steps (3) and (6), the porosity of the reservoir in the core sample is calculated as follows:

[0076]

[0077] In the formula: V represents the porosity of the reservoir. p V is the pore volume of the rock. s V is the volume of the rock skeleton. f V1 is the volume of the reservoir region, and m is the volume percentage of the reservoir region.

[0078] Comparative Example 1

[0079] This comparative example provides a method for determining the porosity of mottled carbonate rocks. The method adopts the rock porosity determination method specified in GB / T29172-2012 "Rock Analysis Methods". Specifically, it involves determining the rock skeleton volume using Boyle's law through the volume expansion method, then calculating the external volume of the cylindrical sample using the volume formula, thereby calculating the rock porosity.

[0080]

[0081] In the formula: V represents the porosity of the rock. p V is the pore volume of the rock. s V is the volume of the rock skeleton. f It represents the external volume.

[0082] Plot the corrected porosity obtained in Example 1 against the permeability of the rock, using the porosity before correction obtained in Comparative Example 1 as the plots. For a detailed comparison of the porosity-permeability relationship, see [link to relevant documentation]. Figure 4 .

[0083] Depend on Figure 4 It can be seen that there is no effective linear relationship between porosity and permeability before correction obtained in Comparative Example 1. The linear relationship between porosity and permeability after correction obtained in Example 1 is significantly improved, and the correlation between porosity and permeability reaches 80%, which lays the foundation for subsequent reservoir property research.

[0084] Therefore, this invention, under the premise that there are no connected pores in the non-reservoir areas of mottled carbonate rocks, is based on the traditional laboratory method for determining rock porosity. It incorporates casting thin section identification and CT scan image recognition calculation. By calculating the volume ratio of the reservoir area depicted in the CT scan image through casting thin sections, and combining the external volume of the core sample and the volume of the rock skeleton, a method for determining reservoir porosity in mottled carbonate rocks is established. This fills the gap in experimental logging of reservoir porosity in mottled carbonate rocks, provides more accurate porosity values ​​for reservoir reserve calculation, and lays a solid foundation for objectively evaluating the economic value of oil reservoirs and formulating development strategies.

[0085] The applicant declares that the above description is only a specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Those skilled in the art should understand that any changes or substitutions that can be easily conceived by those skilled in the art within the technical scope disclosed in the present invention fall within the protection and disclosure scope of the present invention.

Claims

1. A method for determining reservoir porosity in mottled carbonate rocks, characterized in that, The method includes the following steps: (1) Drill core samples of mottled carbonate rocks and cut some samples to prepare cast thin sections; (2) Based on the microscopic images of the cast thin sections obtained in step (1), calculate the area ratio of the reservoir region and the non-reservoir region respectively; (3) Measure the external volume and rock skeleton volume of the core sample obtained in step (1) respectively; (4) Perform CT scans on the core samples obtained in step (1), and calculate the volume ratio of the reservoir region and the non-reservoir region in the core samples by combining the area ratio of the reservoir region and the non-reservoir region in the thin section of the cast obtained in step (2). (5) Based on the results obtained in steps (3) and (4), the porosity of the reservoir in the core sample is calculated as follows: In the formula: The porosity of the reservoir. For the pore volume of the rock, For the volume of the rock skeleton, For external volume, The volume of the reservoir region. This represents the volume percentage of the reservoir region. In this process, steps (3) and (4) are not in any particular order. Step (4) calculates the area ratio of reservoir region and non-reservoir region in each CT scan grayscale image based on the standard segmentation threshold, and uses the arithmetic mean of the obtained series of area ratios as the volume ratio of reservoir region and non-reservoir region in the core sample.

2. The method according to claim 1, characterized in that, The core sample mentioned in step (1) is a cylindrical sample; The diameter of the cylindrical sample is 2-4 cm.

3. The method according to claim 1 or 2, characterized in that, The specific calculation method for the area ratio in step (2) is as follows: observe the microscopic image of the cast thin sheet under an optical microscope, take the dark patch as the reservoir area and the white patch as the non-reservoir area, calculate the area ratio of the dark patch and the white patch respectively, and obtain the area ratio of the reservoir area and the non-reservoir area in the cast thin sheet.

4. The method according to claim 2, characterized in that, The external volume mentioned in step (3) is calculated directly using the formula for the volume of a cylinder; The volume of the rock skeleton in step (3) is determined by the gas expansion method.

5. The method according to claim 1 or 2, characterized in that, The CT scan described in step (4) uses core micron CT scanning technology; The specific process of the core micron CT scanning technology is as follows: starting from the sampling position of the cast thin section, at least 5 CT scans are performed at equal intervals along the axial direction of the core sample, and 2 CT scans are performed perpendicular to each other on the longitudinal section of the core sample. The scanned images are then processed to reduce noise, resulting in a series of CT scan grayscale images.

6. The method according to claim 5, characterized in that, The area ratio of the reservoir region and the non-reservoir region in the thin film obtained in step (2) is used to calibrate the CT scan grayscale images of the thin film sampling location in order to determine the standard segmentation threshold of the remaining CT scan grayscale images.

7. The method according to claim 6, characterized in that, The specific calibration process is as follows: a segmentation threshold is preset, so that... Let represent the grayscale values ​​of pixels in a CT scan grayscale image. Pixels with grayscale values ​​greater than or equal to a segmentation threshold are classified as reservoir regions, and pixels with grayscale values ​​less than the segmentation threshold are classified as non-reservoir regions. The discriminant for reservoir regions and non-reservoir regions is: In the formula: , where a state value of 1 indicates that the pixel belongs to the reservoir region, and a state value of 0 indicates that the pixel belongs to the non-reservoir region; i represents the x-coordinate value of the pixel, j represents the y-coordinate value of the pixel; M represents the number of pixels in the x-axis direction, N represents the number of pixels in the y-axis direction; T represents the segmentation threshold.

8. The method according to claim 7, characterized in that, According to the above Calculate the area ratio of reservoir region and non-reservoir region in the CT scan grayscale image of the sampled casting sheet. When the area ratio is equal to the area ratio of reservoir region and non-reservoir region in the casting sheet obtained in step (2), the set segmentation threshold is used as the standard segmentation threshold for the remaining CT scan grayscale images.

Images