Testing method for determining shale oil core plaster ratio
By measuring the mud-cement ratio in shale oil cores using nuclear magnetic resonance (NMR) technology and calculating the fluid signal quantity of the calcareous laminae using the basement signal segmentation value, the problem of quantitative characterization of the seepage capacity of mud and calcareous materials in shale oil reservoirs was solved, improving the accuracy and reliability of experimental results.
Patent Information
- Application Number
- CN202410695624.3
- Authority / Receiving Office
- CN · China
- Patent Type
- Applications(China)
- Current Assignee / Owner
- Filing Date
- 2024-05-31
- Publication Date
- 2025-12-02
AI Technical Summary
Existing technologies are insufficient to accurately distinguish and quantify the permeability of clay and ash in shale oil reservoirs. Nuclear magnetic resonance (NMR) technology is affected by organic matter signals from dry cores in shale oil reservoir analysis, leading to inaccurate results.
Nuclear magnetic resonance (NMR) technology was used to measure the NMR T2 spectra of dry cores and saturated kerosene cores. The maximum T2 value of the basement signal was used as the mud-lime segmentation value to calculate the signal quantity of fluids and the mud-lime ratio in the calcareous laminar layer, thus avoiding errors in the organic matter signal of dry cores.
It enables precise differentiation of the seepage capacity of clay and ash, provides quantitative parameters for the clay-ash ratio, and improves the accuracy and reliability of the study of seepage patterns in shale oil reservoirs.
Smart Images
Figure CN121049326A_ABST
Abstract
Description
Technical Field
[0001] This invention relates to the field of shale oil testing and characterization, and more particularly to a testing method for determining the shale oil core mud-lime ratio. Background Technology
[0002] Based on the sedimentary characteristics and exploration practices of shale oil in the Jiyang Depression, lamellar, stratiform, and massive shale facies are currently the most prevalent. Oil testing results show that shale with thin layers of sandstone or carbonate rocks, lamellar argillaceous limestone, and calcareous mudstone are the shale facies from which the most industrial oil flows have been obtained. Due to the self-generating and self-storing characteristics of shale oil reservoirs, their dense strata, and narrow micropore spaces, flow within the strata is extremely difficult. Shale oil reservoirs possess diverse storage spaces and multiple flow pathways. The numerous micro- and nano-sized pores in shale are important storage spaces for shale oil and gas, while calcareous lamellars are important seepage channels. Therefore, the degree of development of calcareous lamellars determines the mobilization potential of shale oil reservoirs. Detailed characterization of argillaceous and calcareous lamellars in shale oil is fundamental for evaluating reservoir permeability and formulating development technology policies.
[0003] Currently, research on shale oil samples mainly focuses on: first, using techniques such as fluorescence microscopy, cathodoluminescence, and scanning electron microscopy to analyze the rock mineral composition and occurrence, the genetic mechanism of carbonate minerals, and the genesis and evolution of laminar minerals in shale oil reservoirs, as well as the state of crude oil occurrence; second, conducting experiments on the flow patterns of shale oil reservoirs to analyze the influence of fluid media and stress conditions on seepage patterns. There are no reports on the quantitative characterization of the mud-cement ratio in shale oil cores using nuclear magnetic resonance (NMR) technology. Therefore, research on shale oil seepage patterns is based on the flow capacity characterization of shale core experiments, reflecting the overall seepage capacity of the core and failing to distinguish the seepage capacity of mudstone and limestone. Furthermore, current shale oil seepage models are unable to reflect the seepage characteristics of mudstone and limestone, thus failing to capture the unique features of shale oil.
[0004] Currently, some domestic literature reports the use of well logging technology to identify interlayers or laminae, but the identification accuracy is not high, and quantitative mud-cement ratio parameters cannot be provided. Nuclear magnetic resonance (NMR), as a rapid and non-destructive experimental technique, has unique advantages in evaluating reservoir microstructure and fluid mobility and is widely used. However, shale oil reservoirs are rich in organic matter, resulting in certain basement signals in dry cores, which affects NMR analysis of pore structure. Summary of the Invention
[0005] In view of the above problems, the present invention is proposed to provide a test method for determining the shale oil core mud ratio to overcome or at least partially solve the above problems.
[0006] According to one aspect of the present invention, a test method for determining the mud-cement ratio of shale oil cores is provided, the test method comprising:
[0007] Obtain rock cores for the experiment;
[0008] Calculate multiple parameters of the core sample;
[0009] Nuclear magnetic resonance (NMR) tests were performed to obtain the NMR T2 spectrum of the core, the basement signal, and the NMR T2 spectrum of the saturated kerosene core.
[0010] Calculate the signal quantity and slurry ratio of the fluid in the gray texture layer.
[0011] Optionally, the plurality of parameters specifically include: diameter, length, and gas permeability.
[0012] Optionally, obtaining the core samples for the experiment specifically includes:
[0013] Step S1: Drill a core from the full-diameter core to obtain the experimental core.
[0014] Optionally, the calculation of multiple parameters of the core specifically includes:
[0015] Step S2: Wash and dry the experimental core, and test the diameter and length of the dried core;
[0016] Step S3: Calculate the gas permeability of the core sample.
[0017] Optionally, the step of performing nuclear magnetic resonance (NMR) testing to obtain the NMR T2 spectrum of the core, the basement signal of the core, and the NMR T2 spectrum of the saturated kerosene core specifically include:
[0018] Step S4: Perform nuclear magnetic resonance (NMR) testing;
[0019] Step S5: Place the core into a nuclear magnetic resonance core analyzer to test and obtain the nuclear magnetic resonance T2 spectrum of the core and the basement signal of the core;
[0020] Step S6: The organic matter that generates the substrate signal exists in the mud, while the ash texture does not contain organic matter. The maximum T2 value corresponding to the substrate NMR signal is used as the mud-ash segmentation value.
[0021] Step S7: Vacuum the core, pressurize it to saturate it, and measure the porosity of the core using the weighing method.
[0022] Step S8: Place the saturated kerosene core into a nuclear magnetic resonance core analyzer and test the nuclear magnetic resonance T2 spectrum of the saturated kerosene core.
[0023] Optionally, the calculation of the signal quantity and slurry ratio of the fluid in the gray texture layer specifically includes:
[0024] Step S9: Using the T2 segmentation value, the nuclear magnetic resonance T2 spectrum of kerosene in the same coordinate system is divided into two parts: the left half is the nuclear magnetic resonance T2 spectrum of kerosene in muddy pores, and the right half is the nuclear magnetic resonance T2 spectrum of kerosene in gray laminae.
[0025] Step S10: Divide the signal quantity of the fluid in the gray texture layer by the signal quantity of the fluid in the mud pores to obtain the gray-mud ratio.
[0026] Optionally, step S3, calculating the gas permeability of the core sample, specifically includes:
[0027] Using a pressure-controlled permeability testing system, the gas permeability of the core sample was measured and calculated based on the stable gas flow rate under different pressures.
[0028] Optionally, step S4, performing nuclear magnetic resonance testing, specifically includes: turning on the nuclear magnetic resonance core analyzer and preheating it, and performing nuclear magnetic resonance testing after the temperature control system temperature stabilizes.
[0029] Optionally, the pressurization saturation in step S7 may use kerosene or simulated oil for multiple blocks.
[0030] Optionally, using the maximum T2 value corresponding to the substrate NMR signal as the mud-lime segmentation value specifically includes:
[0031] The maximum T2 value corresponding to the basement nuclear magnetic resonance signal is called the T2 segmentation value for distinguishing marl. For the same block, the average of the T2 segmentation values of different shale oil cores is used to determine the T2 segmentation value of the corresponding block.
[0032] Optionally, step S10, dividing the signal quantity of the fluid in the ash texture layer by the signal quantity of the fluid in the clay pores to obtain the ash-mud ratio, further includes:
[0033] The area enclosed by the region of the T2 spectrum with the T2 segmentation value less than the T2 segmentation value and the horizontal axis in the saturated kerosene state is subtracted from the area enclosed by the region of the basal nuclear magnetic resonance signal with the T2 segmentation value less than the T2 segmentation value and the horizontal axis.
[0034] Optionally, step S10, dividing the signal quantity of the fluid in the ash texture layer by the signal quantity of the fluid in the clay pores to obtain the ash-mud ratio, further includes:
[0035] The area enclosed by the portion of the T2 spectrum greater than the T2 segmentation value and the horizontal axis in the saturated kerosene state is used as the area to subtract the area enclosed by the portion of the basal nuclear magnetic resonance signal greater than the T2 segmentation value and the horizontal axis.
[0036] This invention provides a testing method for determining the mud-cement ratio in shale oil cores. The method includes: obtaining a core for the experiment; calculating the diameter, length, and gas permeability of the core; performing nuclear magnetic resonance (NMR) testing to obtain the NMR T2 spectrum of the dry core, the basement signal of the dry core, and the NMR T2 spectrum of the saturated kerosene core; and calculating the signal quantity and mud-cement ratio of the fluid in the silty laminae based on the NMR T2 spectrum of the dry core, the basement signal of the dry core, and the NMR T2 spectrum of the saturated kerosene core. This method avoids the error caused by the organic matter signal in the dry core to the experimental results and fully utilizes its characteristics as the basis for distinguishing muddy pores and silty laminae, resulting in more accurate experimental results.
[0037] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, and in order to make the above and other objects, features and advantages of the present invention more apparent and understandable, specific embodiments of the present invention are described below. Attached Figure Description
[0038] To more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings used in the following description of the embodiments will be briefly introduced. Obviously, the drawings described below are only some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.
[0039] Figure 1 A flowchart illustrating a test method for determining the shale oil core mud-lime ratio, provided as an embodiment of the present invention;
[0040] Figure 2 The nuclear magnetic resonance spectra of core #24 in different states provided in Embodiment 1 of the present invention;
[0041] Figure 3 The nuclear magnetic resonance spectra of core #149 in different states provided in Embodiment 2 of the present invention. Detailed Implementation
[0042] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.
[0043] The terms "comprising" and "having," and any variations thereof, in the specification, embodiments, claims, and drawings of this invention are intended to cover non-exclusive inclusion, such as including a series of steps or units.
[0044] The technical solution of the present invention will be further described in detail below with reference to the accompanying drawings and embodiments.
[0045] Example 1
[0046] like Figure 1 As shown, a test method for determining the mud-cement ratio in shale oil cores includes the following steps:
[0047] Step S1: Drill a core sample with a diameter of 2.5 cm from the full-diameter core sample, numbered 24#;
[0048] Step S2: Wash and dry the experimental core. The diameter of the core was 2.526 cm and the length was 2.732 cm.
[0049] Step S3: Using the pressure-controlled permeability testing system, the gas permeability of the core is calculated to be 0.0115 mD based on the stable gas flow rate under different pressures.
[0050] Step S4: Turn on the nuclear magnetic resonance core analyzer and preheat it for 4 hours. After the temperature control system temperature stabilizes, nuclear magnetic resonance testing can be performed.
[0051] Step S5: Place the dry core into a nuclear magnetic resonance (NMR) core analyzer and measure the NMR T2 spectrum of the dry core, i.e., the basement signal of the core, such as... Figure 2 As shown;
[0052] Step S6: Using the maximum T2 value corresponding to the basal nuclear magnetic resonance signal as the marl segmentation value, the T2 segmentation value of the core is determined to be 49.77ms;
[0053] Step S7: Vacuum the core for 48 hours, then saturate the core with kerosene and pressurize it for 48 hours to ensure full saturation. The porosity of the core was measured to be 8.52% using the weighing method.
[0054] Step S8: Place the kerosene-saturated core into a nuclear magnetic resonance (NMR) core analyzer and test the NMR T2 spectrum of the kerosene-saturated core, such as... Figure 2 As shown;
[0055] Step S9: Using the T2 segmentation value of 49.77 ms, the NMR T2 spectrum of kerosene in the same coordinate system is divided into left and right parts. The NMR signal of the saturated kerosene in the left half is 17094.85, and the substrate signal is 2797.55. The difference of 14297.29 represents the signal of kerosene in the muddy pores. The NMR signal of the saturated kerosene in the right half is 423.15, and the substrate signal is 0. The difference of 423.15 represents the signal of kerosene in the gray laminae.
[0056] In step S10, the core exhibits a distinct "three-peak" structure under saturated oil conditions. Based on the T2 segmentation values, the right peak represents a calcareous laminae, and its T2 distribution is discontinuous with that of the muddy pores in the middle and left peaks. This indicates a significant difference in pore structure between the calcareous and muddy laminae. Using the data calculation module, the signal quantity of the fluid in the calcareous laminae is divided by the signal quantity in the muddy pores, yielding a calcareous-muddy ratio of 0.0296 for the core.
[0057] Example 2
[0058] Step S1: Drill a core sample with a diameter of 2.5 cm from the full-diameter core sample, numbered 149#;
[0059] Step S2: Wash and dry the experimental core. The diameter of the core was 2.534 cm and the length was 2.618 cm.
[0060] Step S3: Using the pressure-controlled permeability testing system, the gas permeability of the core was calculated to be 0.2299 mD based on the stable gas flow rate under different pressures.
[0061] Step S4: Turn on the nuclear magnetic resonance core analyzer and preheat it for 4 hours. After the temperature control system temperature stabilizes, nuclear magnetic resonance testing can be performed.
[0062] Step S5: Place the dry core into a nuclear magnetic resonance (NMR) core analyzer and measure the NMR T2 spectrum of the dry core, i.e., the basement signal of the core, such as... Figure 3 As shown;
[0063] Step S6: Using the maximum T2 value corresponding to the basal nuclear magnetic resonance signal as the marl segmentation value, the T2 segmentation value of the core is determined to be 28.48 ms;
[0064] Step S7: Vacuum the core for 48 hours, then saturate the core with kerosene and pressurize it for 48 hours to ensure full saturation. The porosity of the core was measured to be 6.49% using the weighing method.
[0065] Step S8: Place the kerosene-saturated core into a nuclear magnetic resonance (NMR) core analyzer and test the NMR T2 spectrum of the kerosene-saturated core, such as... Figure 3 As shown;
[0066] Step S9: Using a T2 segmentation value of 28.48 ms, the NMR T2 spectrum of kerosene in the same coordinate system is divided into left and right parts. The NMR signal of the saturated kerosene in the left half is 8343.89, and the substrate signal is 6422.34. The difference of 1921.55 represents the signal of kerosene in the muddy pores. The NMR signal of the saturated kerosene in the right half is 580.46, and the substrate signal is 0. The difference of 580.46 represents the signal of kerosene in the gray laminae.
[0067] Step S10: The core exhibits a distinct "three-peak" structure under saturated oil conditions. The signal at the base of the core largely overlaps with the left peak of the unsaturated state, indicating that the micropores are mainly composed of organic pores. The right peak represents the continuous T2 distribution of the calcareous laminae and the argillaceous pores of the middle and left peaks. This indicates that the pore space encompassed by the T2 spectrum at the T2 segmentation value and the concave point of the middle and right peaks is a mixture of calcareous and muddy pores. Using the data calculation module, the signal quantity of the fluid in the calcareous laminae is divided by the signal quantity in the argillaceous pores, yielding a calcareous-muddy ratio of 0.3021 for the core.
[0068] Beneficial effects: The method of determining T2 segmentation value using nuclear magnetic resonance T2 spectrum data from dry cores in this invention not only avoids the error caused by organic matter signals in dry cores to the experimental results, but also makes full use of its characteristics as the basis for dividing argillaceous pores and calcareous laminae, resulting in more accurate experimental results.
[0069] This invention uses nuclear magnetic resonance T2 spectrum to calculate the volume of kerosene in muddy pores and ash-laden pores, respectively. The resulting ash-mud ratio characterizes the ratio of pore space. Compared with the apparent volume of the overall skeleton, the ratio of pore space is more meaningful for characterizing its flow capacity and evaluating its development potential.
[0070] This invention utilizes nuclear magnetic resonance to test the mud-cement ratio of shale oil cores, which is fast and non-destructive, and the cores can also be used for other subsequent experiments.
[0071] The testing device provided in this invention can automatically perform each step of the shale oil core mud-lime ratio test without the need for specific personnel to participate, and can directly output the test results, making it more practical.
[0072] The above specific embodiments further illustrate the purpose, technical solution, and beneficial effects of the present invention. It should be understood that the above are merely specific embodiments of the present invention and are not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of the present invention should be included within the scope of protection of the present invention.
Claims
1. A test method for determining the mud-cement ratio in shale oil cores, characterized in that, The testing method includes: Obtain rock cores for the experiment; Calculate multiple parameters of the core sample; Nuclear magnetic resonance (NMR) tests were performed to obtain the NMR T2 spectrum of the core, the basement signal, and the NMR T2 spectrum of the saturated kerosene core. Calculate the signal quantity and slurry ratio of the fluid in the gray texture layer.
2. The test method for determining the shale oil core mud-cement ratio according to claim 1, characterized in that, The parameters specifically include: diameter, length, and gas permeability.
3. The test method for determining the shale oil core mud-cement ratio according to claim 1, characterized in that, The specific steps of obtaining core samples for the experiment include: Step S1: Drill a core from the full-diameter core to obtain the experimental core.
4. The test method for determining the shale oil core mud-cement ratio according to claim 1, characterized in that, The calculation of multiple parameters of the core specifically includes: Step S2: Wash and dry the experimental core, and test the diameter and length of the dried core; Step S3: Calculate the gas permeability of the core sample.
5. The test method for determining the shale oil core mud-cement ratio according to claim 1, characterized in that, The nuclear magnetic resonance (NMR) test is performed to obtain the NMR T2 spectrum of the core, including the basement signal of the core. Specifically, the NMR T2 spectrum of the saturated kerosene core includes: Step S4: Perform nuclear magnetic resonance (NMR) testing; Step S5: Place the core into a nuclear magnetic resonance core analyzer to test and obtain the nuclear magnetic resonance T2 spectrum of the core and the basement signal of the core; Step S6: The organic matter that generates the substrate signal exists in the mud, while the ash texture does not contain organic matter. The maximum T2 value corresponding to the substrate NMR signal is used as the mud-ash segmentation value. Step S7: Vacuum the core, pressurize it to saturate it, and measure the porosity of the core using the weighing method. Step S8: Place the saturated kerosene core into a nuclear magnetic resonance core analyzer and test the nuclear magnetic resonance T2 spectrum of the saturated kerosene core.
6. The test method for determining the shale oil core mud-cement ratio according to claim 1, characterized in that, The calculation of the signal quantity and slurry ratio of the fluid in the gray texture layer specifically includes: Step S9: Using the T2 segmentation value, the nuclear magnetic resonance T2 spectrum of kerosene in the same coordinate system is divided into two parts: the left half is the nuclear magnetic resonance T2 spectrum of kerosene in muddy pores, and the right half is the nuclear magnetic resonance T2 spectrum of kerosene in gray laminae. Step S10: Divide the signal quantity of the fluid in the gray texture layer by the signal quantity of the fluid in the mud pores to obtain the gray-mud ratio.
7. The test method for determining the shale oil core mud-cement ratio according to claim 4, characterized in that, Step S3, which involves testing and calculating the gas permeability of the core sample, specifically includes: Using a pressure-controlled permeability testing system, the gas permeability of the core sample was measured and calculated based on the stable gas flow rate under different pressures.
8. The test method for determining the shale oil core mud-cement ratio according to claim 5, characterized in that, Step S4, performing nuclear magnetic resonance testing, specifically includes: turning on the nuclear magnetic resonance core analyzer and preheating it, and then performing nuclear magnetic resonance testing after the temperature control system has stabilized.
9. The test method for determining the shale oil core mud-cement ratio according to claim 5, characterized in that, The pressurization saturation in step S7 uses kerosene or simulated oil for multiple blocks.
10. The test method for determining the shale oil core mud-cement ratio according to claim 6, characterized in that, The specific use of the maximum T2 value corresponding to the basal nuclear magnetic resonance signal as the mortar segmentation value includes: The maximum T2 value corresponding to the basement nuclear magnetic resonance signal is called the T2 segmentation value for distinguishing marl. For the same block, the average of the T2 segmentation values of different shale oil cores is used to determine the T2 segmentation value of the corresponding block.
11. The test method for determining the shale oil core mud-cement ratio according to claim 6, characterized in that, Step S10, which divides the signal quantity of the fluid in the gray texture layer by the signal quantity of the fluid in the clay pores to obtain the gray-mud ratio, further includes: The area enclosed by the region of the T2 spectrum with the T2 segmentation value less than the T2 segmentation value and the horizontal axis in the saturated kerosene state is subtracted from the area enclosed by the region of the basal nuclear magnetic resonance signal with the T2 segmentation value less than the T2 segmentation value and the horizontal axis.
12. The test method for determining the shale oil core mud-cement ratio according to claim 6, characterized in that, Step S10, which divides the signal quantity of the fluid in the gray texture layer by the signal quantity of the fluid in the clay pores to obtain the gray-mud ratio, further includes: The area enclosed by the portion of the T2 spectrum greater than the T2 segmentation value and the horizontal axis in the saturated kerosene state is used as the area to subtract the area enclosed by the portion of the basal nuclear magnetic resonance signal greater than the T2 segmentation value and the horizontal axis.