Method and system for correcting logging movable porosity in oil-based drilling fluid environment

Abstract

The invention provides a method and system for correcting logging movable porosity in an oil-based drilling fluid environment, and the method comprises the steps: employing a centrifugal experiment nuclear magnetic resonance T2 cutoff value, a nuclear magnetic resonance porosity of a rock sample, and a power exponential function equation of the nuclear magnetic resonance T2 cutoff value of the rock sample after the invasion of the oil-based drilling fluid; the nuclear magnetic resonance T2 cut-off value is corrected for the reservoir affected by the oil-based drilling fluid invasion, so that the actual nuclear magnetic resonance movable porosity of the reservoir affected by the oil-based drilling fluid invasion in the 100% saturated water state of the stratum is obtained, and the corrected nuclear magnetic resonance movable porosity can accurately represent the pore structure of the stratum. The nuclear magnetic resonance movable porosity correction method has the advantages that the nuclear magnetic resonance movable porosity is more consistent with the core movable porosity, the influence of oil-based drilling fluid invasion on the nuclear magnetic resonance movable porosity is better eliminated, the corrected movable porosity is closer to the real stratum movable porosity, and a theoretical foundation is laid for reservoir stratum fine evaluation and fluid property identification.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of oil and gas well evaluation, and particularly relates to a correction method and system for movable porosity in well logging under an oil-based drilling fluid environment. BACKGROUND

[0002] With the deepening of oil exploration, the exploration target gradually turns to deep and ultra-deep complex clastic rock oil and gas reservoirs, and the oil-based drilling fluid is widely used in deep and ultra-deep layers. The invasion of the oil-based drilling fluid makes the response mechanism of the nuclear magnetic resonance logging complex, the main influencing factors unclear, and other problems, so that the reservoir pore structure and reservoir fluid identification cannot be objectively evaluated, which affects the effect and popularization and application of the nuclear magnetic resonance logging. The nuclear magnetic resonance logging is an important means for logging evaluation of deep and ultra-deep complex clastic rock reservoirs, and a key parameter of reservoir physical properties, and accurate discovery of oil and gas and effective evaluation of reservoir quality are important tasks of logging evaluation.

[0003] At present, the nuclear magnetic resonance correction under the oil-based drilling fluid environment is all aimed at the T2 spectrum shape and geometric mean correction, without combining the nuclear magnetic resonance movable porosity correction under the oil-based drilling fluid invasion mechanism and main influencing factors, so that the pore structure of the reservoir cannot be objectively evaluated. SUMMARY

[0004] In view of the above problems, the application provides a correction method for movable porosity in well logging under an oil-based drilling fluid environment, which comprises the following steps:

[0005] Based on the centrifugal experiment of the rock sample in a water-saturated state, T2 spectrum data in the water-saturated state of the rock sample, nuclear magnetic resonance porosity in the water-saturated state of the rock sample, and a T2 cutoff value in the water-saturated state of the rock sample are obtained;

[0006] A first functional relationship between the T2 cutoff value in the water-saturated state of the rock sample and the nuclear magnetic resonance porosity in the water-saturated state of the rock sample is constructed;

[0007] A displacement experiment is performed on the oil-based drilling fluid in the water-saturated state of the rock sample, and a second functional relationship between the T2 cutoff value in the water-saturated state of the rock sample and the T2 cutoff value after the oil-based drilling fluid invades the rock sample is constructed;

[0008] Based on the T2 cutoff value after the oil-based drilling fluid invades the rock sample, the first functional relationship, and the second functional relationship, a corrected T2 cutoff value is determined, and the movable porosity of the reservoir under the oil-based drilling fluid environment is calculated by using the corrected T2 cutoff value, so that the correction is completed.

[0009] Further, the first functional relationship between the T2 cutoff value in the water-saturated state of the rock sample and the nuclear magnetic resonance porosity in the water-saturated state of the rock sample is:

[0010] T 2citoff =A﹒Φ-B,

[0011] T 2cutoff T2 cutoff values ​​for movable and bound fluids are expressed in milliseconds (ms), Φ represents nuclear magnetic porosity in percentage (%), and A and B are predetermined values.

[0012] Furthermore, a second functional relationship exists between the T2 cutoff value of the rock sample under saturated water conditions and the T2 cutoff value after the oil-based drilling fluid invades the rock sample:

[0013] T 2cutoff(侵入后) =C﹒ ln(T) 2cutoff )-D,

[0014] In the formula, T 2cutoff(侵入后) This represents the T2 cutoff value for movable and bound fluids in a rock sample after the intrusion of oil-based drilling fluid, expressed in milliseconds (ms). 2cutoff The T2 cutoff value represents the values ​​of movable and bound fluids, in milliseconds (ms). C and D are predetermined values.

[0015] Furthermore, the movable porosity is:

[0016]

[0017] In the formula, Φ mf T represents movable porosity. 2cutoff T represents the T2 cutoff value for movable and bound fluids. 2max dT2 represents the maximum value of the points in the T2 spectrum data, f(T2) represents the nuclear magnetic resonance porosity of the rock sample under saturated water conditions, and dT2 represents the distribution coefficient of the T2 spectrum data.

[0018] Furthermore, before conducting the centrifugation experiment on the rock sample in a saturated water state, the rock sample is subjected to vacuum pressurization to saturate the formation water salinity.

[0019] Furthermore, the reservoir rock samples were all low-porosity, low-permeability core samples.

[0020] Furthermore, in the displacement experiment of the oil-based drilling fluid under the saturated water state of the rock sample, the rock sample was selected from the plunger parallel sample of the study area.

[0021] Furthermore, based on the corrected T2 cutoff value and movable porosity, a comparison chart of the corrected movable porosity of nuclear magnetic resonance logging and the movable porosity of core analysis under the oil-based drilling fluid environment was drawn.

[0022] This invention also proposes a system for correcting movable porosity in well logging under oil-based drilling fluid conditions, comprising:

[0023] The data acquisition unit, based on the centrifugation experiment of rock samples in the reservoir under saturated water state, is used to acquire T2 spectrum data, nuclear magnetic resonance porosity, and T2 cutoff value of rock samples under saturated water state.

[0024] The first data processing unit is used to construct the first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of the rock sample under saturated water conditions.

[0025] The second data processing unit conducted a displacement experiment with oil-based drilling fluid in a rock sample saturated with water to construct a second functional relationship between the T2 cutoff value of the rock sample in a saturated water state and the T2 cutoff value after the oil-based drilling fluid invaded the rock sample.

[0026] The data correction unit determines the corrected T2 cutoff value based on the T2 cutoff value after the oil-based drilling fluid invades the rock sample, the first functional relationship, and the second functional relationship. It then uses the corrected T2 cutoff value to calculate the movable porosity of the reservoir under the oil-based drilling fluid environment, thus completing the correction.

[0027] Furthermore, the first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of the rock sample under water saturation is constructed as follows:

[0028] T 2cutoff =A﹒Φ-B,

[0029] T 2cutoff T2 cutoff values ​​for movable and bound fluids are expressed in milliseconds (ms), Φ represents nuclear magnetic porosity in percentage (%), and A and B are predetermined values.

[0030] The second functional relationship between the T2 cutoff value of the rock sample under saturated water state and the T2 cutoff value after oil-based drilling fluid invades the rock sample is as follows:

[0031] T 2cutoff(侵入后) =C﹒ ln(T) 2cutoff )-D,

[0032] In the formula, T 2cutoff(侵入后) This represents the T2 cutoff value for movable and bound fluids in a rock sample after the intrusion of oil-based drilling fluid, expressed in milliseconds (ms). 2cutoff The T2 cutoff value represents the values ​​of movable and bound fluids, in milliseconds (ms). C and D are predetermined values.

[0033] The beneficial effects of this invention are that it overcomes the spurious problem of increased nuclear magnetic resonance (NMR) movable porosity in oil-based drilling fluid environments existing in the prior art. By utilizing a power-law function equation between the NMR T2 cutoff value of centrifuged experiments and the NMR porosity of rock samples and the NMR T2 cutoff value of rock samples after oil-based drilling fluid intrusion, the NMR T2 cutoff value of reservoirs affected by oil-based drilling fluid intrusion is corrected. This allows for the determination of the actual NMR movable porosity of the reservoir under 100% water saturation conditions. The corrected NMR movable porosity can more accurately characterize the pore structure of the formation, better matches the movable porosity of the core, and better eliminates the influence of oil-based drilling fluid intrusion on the NMR movable porosity. The corrected movable porosity is closer to the true movable porosity of the formation, laying a theoretical foundation for refined reservoir evaluation and fluid property identification.

[0034] Other features and advantages of the invention will be set forth in the following description, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention can be realized and obtained by means of the structures pointed out in the description and the drawings. Attached Figure Description

[0035] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0036] Figure 1 A flowchart illustrating the method for correcting movable porosity in well logging under oil-based drilling fluid conditions, as shown in an embodiment of the present invention, is presented.

[0037] Figure 2 The present invention illustrates the nuclear magnetic resonance (NMR) distribution characteristics and classification statistics of oil-based drilling fluid displacement in a study area with different pore structures obtained by using nuclear magnetic resonance experiments in the method for correcting movable porosity in an oil-based drilling fluid environment provided by an embodiment of the present invention.

[0038] Figure 3 The diagram shows the relationship between nuclear magnetic resonance porosity and T2 cutoff value obtained after nuclear magnetic resonance saturated centrifugation experiment in the method for correcting movable porosity in oil-based drilling fluid environment provided in the embodiments of the present invention.

[0039] Figure 4 The diagram shows the relationship between the T2 cutoff value obtained after nuclear magnetic resonance centrifugation and oil-based drilling fluid displacement experiment and the T2 cutoff value after invasion in the method for correcting movable porosity in well logging under oil-based drilling fluid environment provided in the embodiments of the present invention.

[0040] Figure 5 The diagram shows a comparison between the corrected movable porosity obtained from nuclear magnetic resonance logging in an oil-based drilling fluid environment and the movable porosity obtained from core analysis, provided in the embodiment of the present invention.

[0041] Figure 6 A control system block diagram of the well logging movable porosity correction system provided in an oil-based drilling fluid environment according to an embodiment of the present invention is shown. Detailed Implementation

[0042] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0043] The present invention provides a method and system for correcting movable porosity in well logging under oil-based drilling fluid conditions. Figure 1 A flowchart illustrating a method for correcting movable porosity in well logging under oil-based drilling fluid conditions, according to an embodiment of the present invention, is shown. Figure 1 In the context of oil-based drilling fluid environments, methods for correcting movable porosity in well logging include:

[0044] Based on centrifugation experiments of rock samples in the reservoir under saturated water conditions, T2 spectrum data, nuclear magnetic resonance porosity, and T2 cutoff value of rock samples under saturated water conditions were obtained.

[0045] Construct the first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of rock samples under water saturation.

[0046] Displacement experiments were conducted on oil-based drilling fluid in rock samples under saturated water conditions to construct a second functional relationship between the T2 cutoff value of rock samples under saturated water conditions and the T2 cutoff value after the oil-based drilling fluid invaded the rock samples.

[0047] Based on the T2 cutoff value after the oil-based drilling fluid invades the rock sample, the first functional relationship, and the second functional relationship, the corrected T2 cutoff value is determined, and the movable porosity of the reservoir under the oil-based drilling fluid environment is calculated using the corrected T2 cutoff value to complete the correction.

[0048] Among them, reference Figure 3 The predetermined values ​​A and B were calculated to be 17.59 and 45.615, respectively. The first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of the rock sample under saturated water conditions is as follows:

[0049] T 2cutoff =17.59﹒ Φ-45.615, (1)

[0050] T 2cutoff T2 cutoff values ​​for movable and bound fluids are expressed in milliseconds (ms), and Φ represents NMR porosity in percent.

[0051] Among them, reference Figure 4 The predetermined values ​​C and D were calculated to be 41.512 and 18.704, respectively. Displacement experiments were conducted on oil-based drilling fluid in a rock sample under saturated water conditions. The second functional relationship between the T2 cutoff value in the rock sample under saturated water conditions and the T2 cutoff value after the oil-based drilling fluid invaded the rock sample is as follows:

[0052] T 2cutoff(侵入后) =41.512﹒ ln(T) 2cutoff -18.704, (2)

[0053] In the formula, T 2cutoff(侵入后) This represents the T2 cutoff value for movable and bound fluids in a rock sample after the intrusion of oil-based drilling fluid, expressed in milliseconds (ms). 2cutoff The T2 cutoff value represents the values ​​for movable and bound fluids, expressed in milliseconds (ms).

[0054] Correspondingly, movable porosity:

[0055]

[0056] In the formula, Φ mf T represents movable porosity. 2cutoff T represents the T2 cutoff value for movable and bound fluids. 2max dT2 represents the maximum value of the points in the T2 spectrum data, f(T2) represents the nuclear magnetic resonance porosity of the rock sample under saturated water conditions, and dT2 represents the distribution coefficient of the T2 spectrum data.

[0057] Before conducting the centrifugation experiment on the rock sample under saturated water, the rock sample was subjected to vacuum pressurization to saturate the formation water salinity. The pressurization was 20 MPa, and the saturation time was 48 hours. After saturation, nuclear magnetic resonance T2 spectrum measurement was performed. After the measurement, centrifugation was carried out at a speed of 8000 rpm for 4 hours. Nuclear magnetic resonance experiment was then performed to further determine the nuclear magnetic resonance porosity and T2 cutoff value of the rock sample.

[0058] During the experiment, the reservoir rock samples used were all low-porosity and low-permeability core samples. The porosity of the rock samples under saturated water conditions ranged from 1.15% to 12.65%, with an average porosity of 6.3%. Among the physical properties of the rock samples under saturated water conditions, the permeability ranged from 0.0052 mD to 47.7 mD, with an average of 1.03 mD.

[0059] In the oil-based drilling fluid displacement experiment under saturated water conditions on rock samples, the selected base drilling fluid was an oil-in-water emulsion drilling fluid. Compared with the field drilling fluid, the oil-in-water emulsion drilling fluid, except for slight fluctuations in the oil-water ratio, ensured that the field drilling fluid was basically consistent with the design, thus guaranteeing the reliability of the experimental data, determining the type of oil-based drilling fluid used in the displacement experiment, and ensuring that the selected drilling fluid formulation was consistent with the design.

[0060] The specific formulation of the water-in-oil emulsion drilling fluid selected in the experiment was as follows: the oil-to-water ratio ranged from 85 to 95:15 to 5+2%, the oil was 0# diesel oil, and the water was a 30% CaCl2 aqueous solution; the fluid composition was: organic clay + 2% primary emulsifier TYODF-301 fatty acid polyamide + 3% secondary emulsifier TYODF-401 modified pine oil + 2% wetting agent TYODF-501 quaternary ammonium salt + 3% filtration loss reducer TYODF-201 + 5% plugging agent YX-200 asphalt + 3% calcium oxide + barite, with the selected barite having a density greater than or equal to 4.30 g / cm³. 3 .

[0061] In the oil-based drilling fluid displacement experiment of the rock sample under saturated water state, the rock sample was selected from the plunger parallel sample in the study area, and the selected rock sample was displaced with 5 MPa pressure drilling fluid base fluid under saturated water state so that the pressure difference range during the experiment was consistent with the actual drilling pressure difference range. In the actual operation, it is also necessary to adjust the displacement time according to the rock sample with different physical properties; nuclear magnetic resonance T2 measurement was performed every 24 hours for rock samples with different physical properties.

[0062] To facilitate more detailed reservoir evaluation and fluid property identification, a comparison chart of the movable porosity of nuclear magnetic resonance logging and core analysis under the corrected T2 cutoff value and movable porosity was drawn based on the corrected T2 cutoff value and movable porosity.

[0063] refer to Figure 6 The present invention also discloses a system for correcting movable porosity in well logging under oil-based drilling fluid conditions, comprising:

[0064] The data acquisition unit, based on the centrifugation experiment of rock samples in the reservoir under saturated water state, is used to acquire T2 spectrum data, nuclear magnetic resonance porosity, and T2 cutoff value of rock samples under saturated water state.

[0065] The first data processing unit is used to construct the first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of the rock sample under saturated water conditions.

[0066] The second data processing unit conducted a displacement experiment with oil-based drilling fluid in a rock sample saturated with water to construct a second functional relationship between the T2 cutoff value of the rock sample in a saturated water state and the T2 cutoff value after the oil-based drilling fluid invaded the rock sample.

[0067] The data correction unit determines the corrected T2 cutoff value based on the T2 cutoff value after the oil-based drilling fluid invades the rock sample, the first functional relationship, and the second functional relationship. It then uses the corrected T2 cutoff value to calculate the movable porosity of the reservoir under the oil-based drilling fluid environment, thus completing the correction.

[0068] Among them, the first functional relationship between the T2 cutoff value and the nuclear magnetic resonance porosity of the rock sample under saturated water conditions is constructed as follows:

[0069] T 2cutoff =A﹒Φ-B, (4)

[0070] T 2cutoff T2 cutoff values ​​for movable and bound fluids are expressed in milliseconds (ms), Φ represents nuclear magnetic porosity in percentage (%), and A and B are predetermined values.

[0071] The second functional relationship between the T2 cutoff value of the rock sample under saturated water state and the T2 cutoff value after oil-based drilling fluid invades the rock sample is as follows:

[0072] T 2cutoff(侵入后) =C﹒ ln(T) 2cutoff )-D, (5)

[0073] In the formula, T 2cutoff(侵入后) This represents the T2 cutoff value for movable and bound fluids in a rock sample after the intrusion of oil-based drilling fluid, expressed in milliseconds (ms). 2cutoff The T2 cutoff value represents the values ​​of movable and bound fluids, in milliseconds (ms). C and D are predetermined values.

[0074] This application provides a method for correcting the movable porosity of logging under oil-based drilling fluid conditions. It overcomes the spurious problem of increased nuclear magnetic resonance (NMR) movable porosity under oil-based drilling fluid conditions present in existing technologies. Using a power-law function equation of the T2 cutoff value of rock samples under saturated water conditions after centrifugation, the NMR porosity of rock samples under saturated water conditions, and the NMR T2 cutoff value of rock samples after oil-based drilling fluid intrusion, the method corrects the NMR T2 cutoff value of reservoirs affected by oil-based drilling fluid intrusion. This yields the actual NMR movable porosity of the reservoir under 100% water saturation conditions. The corrected NMR movable porosity more accurately characterizes the formation pore structure, better matches the core movable porosity, and better eliminates the influence of oil-based drilling fluid intrusion on the NMR movable porosity. The corrected movable porosity is closer to the true formation movable porosity, laying a theoretical foundation for refined reservoir evaluation and fluid property identification.

[0075] The following detailed description of the specific implementation of this embodiment is provided to support the technical problem to be solved by the present invention.

[0076] Taking a region where oil-based drilling fluids are widely used in an oil and gas field as an example, this study uses a large amount of experimental data on saturated water from rock samples displaced by oil-based drilling fluids under different pore structures and permeabilities in the study area. The displacement data are classified and summarized to obtain the nuclear magnetic resonance distribution characteristics of displacement under different pore structures in the region and the lower limit of movable porosity correction.

[0077] refer to Figure 2 The nuclear magnetic resonance (NMR) peak characteristics of the rock samples in the water-saturated state in the study area were divided into two types: single-peak and double-peak. The lower limit of permeability was low, and reservoirs below 0.1 mD existed. In the previous displacement experiments, the samples were all above 0.1 mD, which could be inferred that permeability was the main controlling factor. However, when the permeability was below 0.1 mD, the phenomenon of a significant rightward shift of the peak in the figure indicated that the displacement law was different from the previous understanding that the higher the permeability, the greater the displacement. From the distribution characteristics of the NMR peaks, no NMR characteristics of oil-based drilling fluid were observed. After analysis and summary, it was concluded that when the permeability was below 0.1 mD, permeability was no longer the main controlling factor, and pore structure became the main reason affecting the displacement efficiency.

[0078] As can be seen from the above, the lower limit of the movable porosity correction was determined by the oil-based drilling fluid invasion experiment with different T2 cutoff values ​​in the dense rock sample. When the movable porosity in this area is less than 1.5%, there is no oil-based drilling fluid invasion.

[0079] The oil-based drilling fluid used at the drilling site in the study area was basically consistent with the design, and the drilling fluid formula selected for this experiment was consistent with the design.

[0080] Among them, by subtracting the formation external pressure from the drilling fluid column pressure during regional drilling and testing, the pressure difference range is obtained as 2 MPa-4.2 MPa, and the upper limit of the displacement pressure in the experiment can be set to 5 MPa.

[0081] By selecting rock samples from the study area and adjusting the rotation speed and time, it was found that there was no fluid volume loss after 4 hours, indicating that the actual displacement pressure of the drilling fluid and the experimental displacement pressure remained basically consistent. The centrifugal pressure of the rock samples was calculated to be in the range of 4.49-5.05 MPa using the rock sample capillary pressure calculation method. The rotation speed was set to 8000 rpm and the duration was 4 hours.

[0082] The experimental results above show that oil-based drilling fluid has the greatest impact on nuclear magnetic resonance movable porosity when it invades the formation, and the most accurate correction is made by correcting the nuclear magnetic resonance movable porosity.

[0083] Analysis was conducted on underwater centrifugation experiments of rock samples under saturated water conditions. Sensitive parameters for the T2 cutoff value under saturated water conditions were analyzed, and references were made. Figure 3 and Figure 4R² represents the square of the comparison coefficients of the relevant factors in the figure, which is an evaluation index of the fitting regression effect. The closer R² is to 1, the better the fitting regression effect. By determining that R² is 0.8421 and 0.9066, it can be seen that there is a good correlation between the T² cutoff value under saturated water conditions, the T² cutoff value after intrusion, and the nuclear magnetic resonance porosity under saturated water.

[0084] The conclusion is that the T2 cutoff value after invasion can be characterized by nuclear magnetic resonance porosity, and a predictive model for the variable T2 cutoff value under oil-based drilling fluid environment can be obtained by fitting the model.

[0085] T 2cutoff(侵入后) =41.152﹒ ln(17.59﹒Φ-45.615)-18.704, (6)

[0086] In the formula, T 2cutoff(侵入后) T2 cutoff values ​​for mobile and bound fluids in a rock sample after oil-based drilling fluid intrusion are represented in milliseconds (ms), and Φ represents nuclear magnetic porosity in percent.

[0087] The nuclear magnetic resonance movable porosity is obtained by integrating the area based on the calculated T2 cutoff value from the nuclear magnetic resonance logging:

[0088]

[0089] In the formula, Φ mf T represents movable porosity. 2cutoff T represents the T2 cutoff value for movable and bound fluids. 2max dT2 represents the maximum value of the points in the T2 spectrum data, f(T2) represents the nuclear magnetic resonance porosity of the rock sample under saturated water conditions, and dT2 represents the distribution coefficient of the T2 spectrum data.

[0090] refer to Figure 5 The image shows the results of nuclear magnetic resonance (NMR) movable porosity after T2 cutoff correction in an oil-based drilling fluid environment in the study area. The core section of this well consists of fine sandstone with strong vertical heterogeneity. The results of conventional NMR parameter processing show that the movable porosity is significantly higher than the processed value, indicating that the oil-based drilling fluid has significantly invaded the reservoir with good physical properties, resulting in an inflated movable porosity. Finally, the NMR movable porosity obtained after correction using the method of this invention is more consistent with the core movable porosity, better eliminating the influence of oil-based drilling fluid invasion on the NMR movable porosity. The corrected movable porosity is closer to the actual formation movable porosity, laying the foundation for subsequent fine evaluation of the reservoir and identification of fluid properties in this area.

[0091] Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some of the technical features; and these modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for correcting movable porosity from well logging in an oil-based drilling fluid environment, characterized by, The method comprises the following steps: Based on the centrifugal experiment of the rock sample saturated with water, T2 spectrum data of the rock sample saturated with water, nuclear magnetic resonance porosity of the rock sample saturated with water, and T2 cutoff value of the rock sample saturated with water are obtained; A first function relationship between the T2 cutoff value of the rock sample saturated with water and the nuclear magnetic resonance porosity of the rock sample saturated with water is constructed; A displacement experiment is performed on the oil-based drilling fluid saturated with water, and a second function relationship between the T2 cutoff value of the rock sample saturated with water and the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample is constructed; Based on the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample, the first function relationship, and the second function relationship, a corrected T2 cutoff value is determined, and the movable porosity of the reservoir under the oil-based drilling fluid environment is calculated by using the corrected T2 cutoff value, so as to complete the correction.

2. The method of claim 1, wherein, The first function relationship between the T2 cutoff value of the rock sample saturated with water and the nuclear magnetic resonance porosity of the rock sample saturated with water is: T 2cutoff = A. Φ - B, T 2cutoff T2 cutoff value of mobile and bound fluids in ms, Φ represents nuclear magnetic porosity in %, A, B are predetermined values.

3. The method of calibrating movable porosity in oil-based drilling fluid environments of claim 2, wherein, The second function relationship between the T2 cutoff value of the rock sample saturated with water and the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample is: T 2cutoff(侵入后) = C. ln(T 2cutoff ) - D, In the formula, T 2cutoff(侵入后) T2 cutoff value of movable fluid and bound fluid of the rock sample after the invasion of the oil-based drilling fluid, in ms, T 2cutoff T2 cutoff value of movable fluid and bound fluid, in ms, C and D are predetermined values.

4. The method of claim 3, wherein, The movable porosity is: where Φ mf represents the movable porosity, T 2cutoff represents the T2 cutoff value of the movable fluid and the bound fluid, T 2max represents the maximum value of the distribution points in the T2 spectrum data, f(T2) represents the nuclear magnetic resonance porosity of the rock sample in the saturated water state, and dT2 represents the distribution coefficient of the T2 spectrum data.

5. The method of claim 1, wherein, Before the centrifugal experiment of the rock sample saturated with water is performed, the rock sample is subjected to a vacuum pressurized saturation of formation water salinity treatment.

6. The method of claim 1, wherein, The rock sample of the reservoir is a low-porosity and low-permeability core sample.

7. The method of claim 1, wherein, In the displacement experiment of the oil-based drilling fluid saturated with water, the rock sample is selected from the piston parallel sample of the research area.

8. The method of claim 1, wherein, Further comprising: According to the corrected T2 cutoff value and the movable porosity, a comparison chart of the movable porosity of the nuclear magnetic resonance logging under the oil-based drilling fluid environment after correction and the movable porosity of the core analysis is drawn.

9. A correction system for movable porosity from well logging in an oil-based drilling fluid environment, characterized by, Comprise: A data acquisition unit is configured to obtain T2 spectrum data of a rock sample saturated with water, nuclear magnetic resonance porosity of the rock sample saturated with water, and T2 cutoff value of the rock sample saturated with water based on a centrifugal experiment of the rock sample saturated with water; A data processing first unit is configured to construct a first function relationship between the T2 cutoff value of the rock sample saturated with water and the nuclear magnetic resonance porosity of the rock sample saturated with water; A data processing second unit is configured to perform a displacement experiment on an oil-based drilling fluid saturated with water, and construct a second function relationship between the T2 cutoff value of the rock sample saturated with water and the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample; A data correction unit is configured to determine a corrected T2 cutoff value based on the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample, the first function relationship, and the second function relationship, and calculate the movable porosity of the reservoir under the oil-based drilling fluid environment by using the corrected T2 cutoff value, so as to complete the correction.

10. The system for calibrating movable porosity in oil-based drilling fluid environment of claim 9, wherein, The first function relationship between the T2 cutoff value of the rock sample saturated with water and the nuclear magnetic resonance porosity of the rock sample saturated with water is: T 2cutoff = A. Φ - B, T 2cutoff T2 cutoff value of mobile and bound fluids in ms, Φ represents nuclear magnetic porosity in %, A, B are predetermined values; The second function relationship between the T2 cutoff value of the rock sample saturated with water and the T2 cutoff value of the rock sample after the oil-based drilling fluid invades the rock sample is: T 2cutoff(侵入后) = C. ln(T 2cutoff ) - D, In the formula, 2cutoff(侵入后) T2cutoff represents the T2 cutoff value of the movable fluid and the bound fluid of the rock sample after the invasion of the oil-based drilling fluid, in ms, T 2cutoff T2cutoff represents the T2 cutoff value of the movable fluid and the bound fluid, in ms, and C and D are predetermined values.

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