A quantitative evaluation method for the difference in mobility between oil and water phases in reservoir cores.

Abstract

This invention discloses a quantitative evaluation method for the difference in mobility between the oil and water phases in reservoir cores, relating to the field of oil and gas reservoir development and dynamic evaluation technology. Representative cores from the target reservoir are selected and divided into water phase and oil phase experimental groups. Group W is vacuum-pressurized saturation to simulate formation water, and Group O is vacuum-temperature saturation to simulate formation oil. The peak area of ​​the T₂ spectrum of both groups of cores before centrifugation is collected using a nuclear magnetic resonance (NMR) spectrometer. After displacement under the same centrifugation rate and temperature conditions, the peak area of ​​the T₂ spectrum after centrifugation is collected again. The mobility of the water phase and oil phase is calculated using formulas, and then the difference coefficient is calculated. This method establishes a scientific oil-water mobility comparison system through standardized two-fluid saturation, displacement by the same driving force, and precise signal analysis. It is applicable to tight oil reservoirs, conventional sandstone, shale, and other reservoirs, providing a quantitative basis for identifying "mobile oil-dominant areas," optimizing oil displacement processes, and formulating development plans.

Description

Technical Field

[0001] This invention relates to the field of oil and gas reservoir development and dynamic evaluation technology, and more specifically to a method for quantitatively evaluating the difference in mobility between oil and water phase fluids in reservoir cores using nuclear magnetic resonance technology. Background Technology

[0002] In the field of oil and gas reservoir evaluation and efficient development, fluid mobility is a core parameter determining reservoir productivity and development strategies. The mobility of the water and oil phases in a reservoir is influenced by multiple factors, including pore structure, wettability, and clay mineral adsorption. Their differences directly reflect the reservoir's ability to store and flow different fluids. However, current technologies primarily focus on evaluating the mobility of water phase fluids (such as formation water), calculating water phase mobility using saturation, centrifugation, and nuclear magnetic resonance techniques. However, regarding the mobility of the oil phase ( There are significant deficiencies in the independent quantification of oil phase and the comparative analysis of the differences in mobility between oil and water phases.

[0003] In conventional evaluation methods, oil phase mobility is often inferred empirically based on aqueous phase data, neglecting its unique occurrence mechanism in reservoirs: in hydrophilic reservoirs, crude oil is easily trapped due to adsorption on clay surfaces, and the strong capillary binding of the oil phase by small-diameter pore throats further reduces its mobility; while in oleophilic reservoirs or areas with well-developed large pore sizes, oil phase mobility may be superior to that of the aqueous phase due to advantages in pore surface affinity or connectivity. Due to the lack of standardized oil phase mobility testing procedures and a comparative system for oil-water mobility differences, reservoir evaluation struggles to accurately identify "mobile oil-dominant areas," leading to reliance on empirical judgments in key development stages such as fracturing site selection and oil displacement agent formulation design, resulting in significant reliance on guesswork. Furthermore, traditional experiments do not standardize the saturation conditions for aqueous phases (e.g., distilled water) and oil phases (e.g., simple white oil). Existing technologies often use only single-component white oil as the simulated oil, failing to consider the adsorption effects of asphaltenes, waxes, and gums in actual crude oil. For example, high-asphaltite crude oil tends to form a strong adsorption layer on the surface of clay minerals, while light oils may be more fluid due to their lower viscosity. This compositional difference was not incorporated into traditional experimental designs, leading to significant deviations between oil phase mobility assessments and actual reservoir conditions. The influence of formation oil viscosity, composition, and reservoir temperature and pressure on mobility was ignored; centrifugal displacement parameters were not matched to the reservoir pore-throat scale; conventional centrifugation experiments used fixed rotation speeds (e.g., 5000 r / min) without dynamically adjusting the displacement pressure based on the reservoir pore-throat distribution (e.g., the proportion of nanoscale pores). For example, for pores smaller than 30 nm, a fixed centrifugal force may not effectively displace the oil phase, leading to an overestimation of the mobility of small-pore oil phases; while in large-pore regions, excessive displacement force may cause experimental errors. This results in either an overestimation or underestimation of the mobility of small-pore oil phases; and the failure to separate the relaxation characteristics of the water-oil phases during nuclear magnetic resonance signal processing further exacerbated the errors in mobility calculations.

[0004] Therefore, how to develop a quantitative evaluation method for the difference in mobility between the oil and water phases in reservoir cores is a problem that urgently needs to be solved by those skilled in the art. Summary of the Invention

[0005] In view of this, the present invention provides a quantitative evaluation method for the difference in mobility between the oil phase and the water phase in reservoir cores, in order to solve the problems in the background art.

[0006] To achieve the above objectives, the present invention adopts the following technical solution: This invention discloses a method for quantitatively evaluating the difference in mobility between the oil and water phases in reservoir cores. The specific steps are as follows: Step 1: Select representative core samples from the target reservoir, cut them to standard size, and perform oil washing, drying, and basic physical property measurements in sequence, dividing them into aqueous phase experimental group and oil phase experimental group; Step 2: The core samples from the aqueous phase experimental group were saturated with simulated formation water using a vacuum pressurization device. After ensuring complete water saturation of the pores, nuclear magnetic resonance (NMR) data were collected. The spectrum records the initial signal peak area of ​​the aqueous phase before centrifugation. ; Step 3: Saturate the oil phase experimental group cores with simulated formation oil using a vacuum isothermal device, allow them to stand at the corresponding reservoir temperature and pressure until adsorption equilibrium is reached, and collect saturated oil cores. Spectroscopy, via nuclear magnetic resonance Multi-component inversion technique was used to separate the oil phase and bound water signals, and the initial signal peak area of ​​the oil phase before centrifugation was recorded. ; Step 4: Apply the same centrifugation rate to the cores of the aqueous phase experimental group and the oil phase experimental group, centrifuge for a specific time at a constant temperature to simulate the formation driving force conditions, so that the aqueous phase and the oil phase flow under the same external conditions; Step 5: Perform nuclear magnetic resonance (NMR) testing on the centrifuged core, ensuring the acquired parameters are identical to those before centrifugation, based on the calibration parameters set in Step 3. Cutoff value, separation of oil phase and residual bound water relaxation signal, recording the peak area of ​​the signal after centrifugation of the aqueous and oil phases. and ; Step 6: Calculate the mobility of the aqueous phase using the formula. Oil phase mobility Water phase mobility Oil phase mobility Then calculate the difference coefficient. .

[0007] Preferably, in step 1, the selected core samples should represent the characteristics of the target reservoir and be cut to standard dimensions for experimental operation and data comparison. Oil washing involves ultrasonically cleaning the core samples in a dichlorotoluene-ethylene glycol mixture for approximately 6 hours to remove residual organic matter and fluids from the pores, ensuring a consistent initial state. Drying is performed in an oven at 105°C for approximately 48 hours until constant weight. Subsequently, basic physical properties such as the core diameter, length, and air permeability are measured to provide a basis for subsequent experiments. The core samples are divided into groups W and O, with at least one core sample prepared for each group to facilitate parallel comparison experiments of the aqueous and oil phases, ensuring data reliability.

[0008] Preferably, in step 2, the W group core samples are placed in a vacuum pressurization device. First, a vacuum is drawn to remove air from the pores, then simulated formation water is injected. By controlling the pressure and time, the pores are ensured to be completely saturated with water, simulating formation pressure and other conditions to make the experiment more closely resemble actual conditions. When acquiring T2 spectra using a nuclear magnetic resonance spectrometer, standard parameters such as waiting time and echo time are set, and the acquired S... 1w As the benchmark data for calculating the mobility of the aqueous phase, it reflects the initial state of the aqueous phase in the core. It is worth noting that the saturation experiments of both the aqueous and oil phases were completed under simulated reservoir temperature and pressure (e.g., 50℃, 25MPa), and the saturation time was uniformly set at 120h to ensure sufficient fluid adsorption equilibrium.

[0009] Preferably, in step 3, simulated formation oil is prepared according to the viscosity, composition, and other characteristics of the target reservoir crude oil. The O group core samples are placed in a vacuum isothermal device and injected with the simulated oil. The sample is then allowed to stand for a sufficient time under simulated reservoir temperature and pressure to allow the oil phase to fully adsorb onto the pore surface and reach adsorption equilibrium, avoiding signal errors caused by unsaturation. The parameters of the acquired T2 spectrum are kept consistent with those of the aqueous phase to ensure data comparability. 1o This serves as the starting data for calculating the mobility of the oil phase.

[0010] Preferably, in step 4, a suitable centrifugation rate and time are selected, and the two sets of core samples are simultaneously centrifuged using a centrifuge while maintaining a constant temperature, consistent with the temperature during the saturation experiment. This is done to eliminate the interference of driving force differences on the experimental results, ensuring that the subsequent differences in the mobility of the aqueous and oil phases originate solely from the interaction between the fluid and the pores, such as wettability and adsorption.

[0011] Preferably, in step 5, immediately after centrifugation, the core sample is subjected to nuclear magnetic resonance (NMR) testing, strictly maintaining the acquisition parameters (such as the number of scans, echo time, etc.) the same as before centrifugation to avoid errors introduced by changes in instrument parameters. The acquired S... 2w and S 2o These figures reflect the remaining amounts of the aqueous and oil phases after centrifugal displacement, providing crucial data for calculating mobility.

[0012] Preferably, step 6 is the core of the present invention, which uses the formula η = 100×(S1–S2) / S1 to calculate the mobility η of the aqueous phase. w And oil phase mobility η o This formula represents the proportion of fluid mobility under centrifugal driving force; the larger the value, the stronger the mobility. The absolute value of Δη reflects the difference in the binding effect of reservoir wettability on the two-phase fluid. A positive value (Δη > 0) indicates that the reservoir is predominantly oleophilic, while a negative value (Δη < 0) indicates that the reservoir is predominantly hydrophilic. This provides a direct basis for judging reservoir development.

[0013] As can be seen from the above technical solution, compared with the prior art, this invention discloses a quantitative evaluation method for the difference in mobility between the oil and water phases in reservoir cores, establishing for the first time a dual-fluid mobility comparison method for the oil and water phases, breaking through the limitations of single-fluid evaluation; through standardized saturation experiments and displacement by the same driving force, it ensures that the difference in oil-water mobility only reflects the interaction between the fluid and the pores; and it introduces an "oil-water mobility difference coefficient Δη" (Δη=η o -η w This allows for the intuitive quantification of the differences in mobility between the two phases, enabling precise identification of the "mobile oil advantage area" and optimization of development plans. Attached Figure Description

[0014] 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 only embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on the provided drawings without creative effort.

[0015] Figure 1 A flowchart of the method provided by the present invention; Figure 2 This is a schematic diagram of the process provided by the present invention. Detailed Implementation

[0016] 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, and 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.

[0017] This invention discloses a method for quantitatively evaluating the difference in mobility between the oil and water phases in reservoir cores. The specific steps are as follows: 1) Core pretreatment Representative core samples from the target reservoir (using shale as an example) were selected and obtained from shale outcrops. These core samples were then machined into cylinders with a diameter of 25 mm and a length of 50 mm using a diamond cutter. The core samples were then ultrasonically cleaned for 6 hours in a dichlorotoluene-ethylene glycol mixture (volume ratio 3:1) to remove adsorbed organic matter and residual hydrocarbons from the clay mineral surface. After cleaning, the core samples were dried in an oven at 105℃ for 48 hours until the difference between two weighings was less than 0.01 g. The dry weight of the core sample at this point was recorded as m. d The diameter D and length L of the core were measured using a vernier caliper with an accuracy of 0.02 mm, and the core volume V = π(D / 2) was calculated. 2 L. The air permeability was measured using the steady-state method. A pressure difference of 0.5 MPa was applied, nitrogen was used as the medium, and the nitrogen flow rate was recorded to calculate the permeability K.

[0018] 2) Aqueous phase saturation and initial NMR test (Group W) The processed core was placed in a vacuum pressurization device, and a vacuum was drawn until the pressure was less than 10 Pa and maintained for 4 hours. Deionized water was slowly injected to simulate formation water, and the pressure was increased to 25 MPa to simulate the burial pressure of the shale reservoir. The core was then placed in a constant temperature chamber at 50°C for saturation for 120 hours. After saturation, the core was removed, the surface moisture was absorbed with filter paper, and the core was weighed to obtain the wet weight m. w Calculate porosity according to the formula ϕ =(m w -m d ) / ( ρ w V). A low-field nuclear magnetic resonance spectrometer (magnetic field strength 0.5T, with accompanying analysis software automatically integrating the T2 spectrum peak area) was used to acquire the T2 spectrum using a CPMG pulse sequence. The waiting time Tw=3000ms, echo time TE=0.5ms, number of scans NS=64, and number of echoes NECH=6000 were set. The initial signal S of the aqueous phase was recorded at this time. 1w .

[0019] 3) Oil phase saturation and initial NMR test (Group O) Simulated oil was prepared based on the viscosity and polarity of the crude oil in the target shale reservoir. White oil (viscosity 10 mPa·s) and toluene were mixed at a volume ratio of 7:3, and 0.8% asphaltenes were added to simulate the adsorption characteristics of heavy components. This 0.8% addition referenced the lower end of the asphaltenes mass fraction in typical shale reservoir crude oil (usually 0.5%–2.0%), effectively reflecting the adsorption effect of asphaltenes on clay mineral surfaces while avoiding excessive asphaltenes content that could lead to a dramatic increase in simulated oil viscosity or pore blockage, ensuring the operability and repeatability of the experiment. In practical applications, the addition ratio can be adjusted within the range of 0.1%–3.0% based on the actual asphaltenes content of the target reservoir crude oil (obtained through group component analysis). The simulated oil was ensured to be insoluble in water and compatible with the hydrophilicity of the shale pore throat surface. The core was placed in a vacuum thermostat and evacuated to a pressure of less than 10 Pa before being injected with simulated oil until the core was completely submerged. The pressure was then increased to 25 MPa and allowed to stand at 50°C for 120 hours to simulate shale reservoir temperatures. During this period, the core holder was rotated every 12 hours to ensure uniform penetration of the simulated oil into the organic matter pores. Using the relaxation time inversion function of a nuclear magnetic resonance spectrometer, the signals of the oil phase (T2 > 20 ms) and clay-bound water (T2 < 5 ms) were separated, and the initial signal S of the oil phase was recorded. 1o .

[0020] It is important to note that in this embodiment, T2 > 20 ms is used as the primary threshold for oil phase identification, based on the calibration results of nuclear magnetic resonance experiments on core samples from the target shale oil reservoir. The specific calibration method involves performing T2 spectrum tests on the same core sample under both water-saturated and oil-saturated conditions, comparing the differences in T2 spectra under the two conditions, and using centrifugal displacement experiments to determine the boundary between water and oil phase signals on the T2 spectrum. Experimental results show that signals with T2 < 5 ms mainly originate from clay-bound water, there is overlap between oil and water signals in the 5–20 ms range, while signals with T2 > 20 ms are dominated by the oil phase (mainly free oil and light components). It should be noted that this threshold varies depending on the pore structure, wettability, and crude oil properties of the reservoir rock; in practical applications, it should be recalibrated according to the characteristics of the target reservoir.

[0021] 4) Centrifugal displacement experiment with the same driving force A high-speed centrifuge was used. Preliminary experiments determined the correlation between centrifugal force and pore size (e.g., a 30nm pore size requires ≥5000 r / min), and the rotation speed was dynamically adjusted based on the core permeability. The centrifugation time was set to 60 min, and the temperature was maintained at 50℃, consistent with the saturation experiment temperature. The core was placed in a PTFE holder with a 0.1μm filter membrane to prevent shale debris from clogging the flow channels, and then symmetrically placed on the centrifuge rotor. The centrifuge was accelerated to the target speed at 1500 r / min / s. After centrifugation, the core was removed within 30 seconds to prevent the oil phase from re-adsorbing onto the pore throat surface during settling.

[0022] 5) Post-centrifugation testing and calculation of the coefficient of difference Nuclear magnetic resonance (NMR) tests were performed on the centrifuged core according to the initial test parameters to obtain the aqueous phase composition. Oil phase group Mobility is calculated using the formula; water phase mobility. Oil phase mobility Then calculate the difference coefficient. .

[0023] when When the oil phase is more mobile than the water phase, it means that in this shale reservoir, the oil phase flows more easily in the pores than the water phase, possibly because the wettability of the reservoir and the pore throat structure have a relatively weaker binding effect on the oil phase; when When the flow rate is low, it indicates that the mobility of the oil phase is inferior to that of the water phase, meaning that the flow of the oil phase in the pores is relatively difficult. This may be due to the stronger adsorption of the oil phase by clay minerals, or the greater capillary binding effect of small-diameter pore throats on the oil phase. If the mobility of the oil and water phases is similar, this indicates that the oil and water phases are relatively rare. This may be because factors such as the pore structure and wettability of the shale reservoir have similar effects on the oil and water phases.

[0024] The various embodiments in this specification are described in a progressive manner, with each embodiment focusing on its differences from other embodiments. Similar or identical parts between embodiments can be referred to interchangeably. For the apparatus disclosed in the embodiments, since they correspond to the methods disclosed in the embodiments, the description is relatively simple; relevant parts can be referred to the method section.

[0025] The above description of the disclosed embodiments enables those skilled in the art to make or use the invention. Various modifications to these embodiments will be readily apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of the invention. Therefore, the invention is not to be limited to the embodiments shown herein, but is to be accorded the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A quantitative evaluation method for the difference in mobility between oil and water phases in reservoir cores, characterized in that, include: Step 1: Select representative core samples from the target reservoir, cut them to standard size, and perform oil washing, drying, and basic physical property measurements in sequence, dividing them into aqueous phase experimental group and oil phase experimental group; Step 2: The core samples from the aqueous phase experimental group were saturated with simulated formation water using a vacuum pressurization device. After ensuring complete water saturation of the pores, nuclear magnetic resonance (NMR) data were collected. The spectrum records the initial signal peak area of ​​the aqueous phase before centrifugation. ; Step 3: Saturate the oil phase experimental group cores with simulated formation oil using a vacuum isothermal device, allow them to stand at the corresponding reservoir temperature and pressure until adsorption equilibrium is reached, and collect saturated oil cores. Spectroscopy, via nuclear magnetic resonance Multi-component inversion technique was used to separate the oil phase and bound water signals, and the initial signal peak area of ​​the oil phase before centrifugation was recorded. ; Step 4: Apply the same centrifugation rate to the cores of the aqueous phase experimental group and the oil phase experimental group, centrifuge for a specific time at a constant temperature to simulate the formation driving force conditions, so that the aqueous phase and the oil phase flow under the same external conditions; Step 5: Perform nuclear magnetic resonance (NMR) testing on the centrifuged core, ensuring the acquired parameters are identical to those before centrifugation, based on the calibration parameters set in Step 3. Cutoff value, separation of oil phase and residual bound water relaxation signal, recording the peak area of ​​the signal after centrifugation of the aqueous and oil phases. and ; Step 6: Calculate the mobility of the aqueous phase using the formula. Oil phase mobility Water phase mobility Oil phase mobility Then calculate the difference coefficient. .

2. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, In step 1, before the core is grouped, it is washed with oil, dried and its basic physical properties are measured in sequence. The oil washing is to place the core in a dichlorotoluene-ethylene glycol mixture for ultrasonic cleaning, and the drying is to dry it to constant weight in an oven at 105°C.

3. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, In step 2, the saturated simulated formation water is produced using a vacuum pressurization device. First, a vacuum is drawn to remove air, then the simulated formation water is injected and pressurized to the simulated reservoir pressure, and saturated at the simulated reservoir temperature for 120 hours. In step 3, the saturated simulated formation oil is produced using a vacuum constant temperature device. After a vacuum is drawn, the simulated formation oil is injected and allowed to stand at the simulated reservoir temperature and pressure for 120 hours until adsorption equilibrium is reached.

4. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, In steps 2 and 3, the parameters used in the nuclear magnetic resonance test are the same, including waiting time, echo time, number of scans, and number of echoes.

5. The method for quantitatively evaluating the difference in mobility between the oil and water phases in reservoir cores according to claim 1, characterized in that, In step 4, the centrifugation rate is dynamically adjusted according to the core permeability or pore size distribution, the centrifugation time is set to 60 min, and the centrifugation temperature is consistent with the saturation experimental temperature.

6. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, In step 3, the simulated formation oil is formulated according to the viscosity and composition of the target reservoir crude oil, and includes white oil, toluene and asphaltene, wherein the mass fraction of asphaltene is 0.1% to 3.0%.

7. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, In the simulated formation oil, the volume ratio of white oil to toluene is 7:3, and the mass fraction of asphaltene is 0.8%.

8. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, when When this occurs, it indicates that the reservoir is predominantly oleophilic, and the oil phase has better mobility than the water phase; when When this occurs, it indicates that the reservoir is predominantly hydrophilic, and the oil phase has inferior mobility compared to the water phase; when... When the time is right, it indicates that the mobility of the oil phase and the water phase is comparable.

9. The method for quantitatively evaluating the difference in mobility between oil and water phases in reservoir cores according to claim 1, characterized in that, The reservoir core is a tight sandstone, shale, or conventional sandstone core.

10. The method for quantitatively evaluating the difference in mobility between the oil and water phases in reservoir cores according to claim 1, characterized in that, After centrifugation and displacement in step 4, the core sample is removed within 30 seconds for nuclear magnetic resonance testing to avoid fluid re-adsorption.

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