A method for characterizing reservoir water saturation distribution

Abstract

This invention belongs to the field of oil and gas development, specifically relating to a method for characterizing reservoir water cut distribution. The method includes: establishing oil-water phase permeability curves based on experiments measuring the relative permeability of two-phase fluids in rocks; combining this with reservoir water saturation data to obtain oil phase relative permeability field data and water phase relative permeability field data; establishing fitting relationships between crude oil viscosity and reservoir pressure, and between crude oil volume coefficient and reservoir pressure, based on reservoir fluid property analysis experiments; combining this with reservoir pressure data to obtain oil phase viscosity field data and oil phase volume coefficient field data; establishing a water cut calculation formula; and establishing a reservoir numerical model based on the calculation formula to generate a water cut distribution map. The water cut distribution map generated using this method can characterize the water cut distribution at different stages of reservoir development, providing a more refined representation of reservoir water cut distribution and potential, and offering a more scientific basis for evaluating water drive development effectiveness and formulating reservoir adjustment plans.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas development, and specifically relates to a method for characterizing the water cut distribution of an oil reservoir. Background Technology

[0002] The reservoir water cut is the proportion of surface produced water to surface produced liquids, and is affected by factors such as reservoir water saturation, oil-water viscosity ratio, and differences in relative oil-water flow velocities. The water cut status in different areas of a water-drive reservoir is an important factor to consider when tapping the potential of local remaining oil, and directly affects the economics of new wells and related measures.

[0003] In oil and gas development, it is necessary to pay attention not only to the water cut in areas with wells but also to the water cut in other areas without wells. This allows for a more precise and reasonable understanding of reservoir water cut, providing a basis for evaluating the effectiveness of waterflooding and developing reservoir adjustment plans. While the water cut in well-produced areas can be calculated using the water production from the wells, effective and accurate methods for characterizing the water cut distribution in areas without wells are still lacking.

[0004] Chinese invention patent application CN 112001055 A, published on November 27, 2020, discloses a method for predicting water cut in low-amplitude light oil reservoirs based on microstructure. This method predicts the theoretical water cut at a specific location within the low-amplitude light oil reservoir by constructing a relative microstructure layer of the reservoir, statistically analyzing the water cut of producing wells in the low-amplitude light oil reservoir, and fitting a linear relationship between the well water cut and the relative microstructure amplitude. While this method can semi-quantitatively predict the water cut at a point within the reservoir, the characterization results are easily limited by the accuracy of the microstructure characterization of the low-amplitude reservoir, and it cannot quantify the water cut distribution in well-free areas. Summary of the Invention

[0005] The purpose of this invention is to provide a method for characterizing the water cut distribution in oil reservoirs, which solves the problem that existing methods cannot achieve quantitative characterization of the water cut distribution in well-free areas.

[0006] To achieve the above objectives, the technical solution adopted by the present invention is as follows:

[0007] A method for characterizing water cut distribution in an oil reservoir includes the following steps:

[0008] S1: Based on the experimental determination of the relative permeability of two-phase fluids in rocks, oil-water phase permeability curves were established. Combined with reservoir water saturation data, the oil phase relative permeability field data K was obtained. ro Water phase relative permeability field data K rw ;

[0009] S2: Based on the fluid property analysis experiments of oil and gas reservoirs, the fitting relationships between crude oil viscosity and reservoir pressure, and between crude oil volume coefficient and reservoir pressure were established respectively. Then, combined with the reservoir pressure data, the oil phase viscosity field data μ was obtained. o Oil phase volume coefficient field data B o ;

[0010] S3: Establishing the relationship between moisture content and μ o B o K ro K rw Water phase viscosity μ w Water phase volume coefficient B w The calculation formula;

[0011] S4: Establish a reservoir numerical model based on the calculation formula and generate a water cut distribution map.

[0012] This invention is pioneering. Based on experimental data and reservoir physical parameters, a numerical model of water cut is established, which highly matches the actual production conditions of the reservoir. The calculated water cut values ​​are accurately verified in areas with wells, proving the effectiveness and accuracy of the invention. The water cut distribution map generated using this method can characterize the water cut distribution at different stages of reservoir development, providing a more refined representation of the reservoir's water cut distribution and potential, and offering a more scientific basis for evaluating the effectiveness of waterflood development and formulating reservoir adjustment plans.

[0013] Preferably, the calculation formula is as shown in Equation 1:

[0014]

[0015] In Equation 1, f w The reservoir water cut and the viscosity of the aqueous phase (μ) are given. w Water phase volume coefficient B w It is a constant.

[0016] More preferably, μ w =1.24~1.25mPa.s; B w =1.01~1.02m 3 / m 3 . Attached Figure Description

[0017] Figure 1 This is a flowchart of the reservoir water cut distribution characterization method of the present invention;

[0018] Figure 2 This is an oil-water phase permeation curve diagram from an embodiment of the present invention;

[0019] Figure 3 This is a water saturation field diagram in an embodiment of the present invention;

[0020] Figure 4 This is a relative permeability field diagram of the oil phase in an embodiment of the present invention;

[0021] Figure 5 This is a diagram showing the relative permeability field of the aqueous phase in an embodiment of the present invention;

[0022] Figure 6 This is a pressure field diagram in an embodiment of the present invention;

[0023] Figure 7 This is a viscosity field diagram of the oil phase in an embodiment of the present invention;

[0024] Figure 8 This is a field diagram of the oil phase volume coefficient in an embodiment of the present invention;

[0025] Figure 9 This is a planar distribution map of moisture content obtained in an embodiment of the present invention;

[0026] Figure 10 This is a moisture content profile obtained in an embodiment of the present invention;

[0027] Figure 11 This is a graph showing the analysis of moisture content results obtained by different methods. Detailed Implementation

[0028] The technical concept of this invention is to utilize oil phase viscosity field data μ o Oil phase volume coefficient field data B o Oil phase relative permeability field data K ro Water phase relative permeability field data K rw Water phase viscosity μ w Water phase volume coefficient B w A formula for calculating water cut was constructed, which combines core experimental data and reservoir physical parameters. It can more reasonably reflect the relationship between reservoir water cut and reservoir water saturation, oil-water viscosity ratio and relative oil-water flow velocity. Therefore, it can more realistically reflect the changes in water cut at different stages of reservoir development.

[0029] Specifically, the reservoir water cut distribution characterization method of the present invention includes the following steps:

[0030] S1: Based on the experimental determination of the relative permeability of two-phase fluids in rocks, oil-water phase permeability curves were established. Combined with reservoir water saturation data, the oil phase relative permeability field data K was obtained. ro Water phase relative permeability field data K rw ;

[0031] S2: Based on the determination methods in GB / T 26981-2020 Oil and Gas Reservoir Fluid Property Analysis Methods, establish the fitting relationship between crude oil viscosity and reservoir pressure, and the fitting relationship between crude oil volume coefficient and reservoir pressure, respectively. Then, combine the reservoir pressure data to obtain the oil phase viscosity field data μ. o Oil phase volume coefficient field data B o ;

[0032] The order of steps S1 and S2 above is not required; they are based on the oil phase relative permeability field data K obtained from relevant experiments. ro Water phase relative permeability field data K rw Oil phase viscosity field data μ o Oil phase volume coefficient field data B o The process of waiting for experimental data.

[0033] S3: Establishing the relationship between moisture content and μ o B o K ro K rw Water phase viscosity μ w Water phase volume coefficient B w The calculation formula is (1);

[0034]

[0035] In Equation 1, f w The reservoir water cut and the viscosity of the aqueous phase (μ) are given. w Water phase volume coefficient B w It is a constant.

[0036] The above aqueous phase viscosity μ w Water phase volume coefficient B w It is generally believed that it does not change with reservoir pressure, and therefore is usually a fixed value.

[0037] S4: Establish a reservoir numerical model based on the calculation formula and generate a water cut distribution map.

[0038] The above calculation formula can be used to establish a water cut distribution map based on a geological model, realizing a quantitative characterization of reservoir water cut. It is a more refined and reasonable way to characterize water cut distribution, which can provide a basis for the deployment of new wells and measures in the field.

[0039] The implementation process of the present invention will be described in detail below with reference to specific embodiments.

[0040] I. Specific Embodiments of the Reservoir Water Cut Distribution Characterization Method of the Present Invention

[0041] Example

[0042] The flowchart of the reservoir water cut distribution characterization method in this embodiment is as follows: Figure 1 As shown, the numerical model of the Hu7 South oil reservoir is used as an example for illustration. This model is a 6×81×76 black oil model with a total of 467,856 grids and 34,390 effective grids. The specific steps include:

[0043] (1) Based on the experimental determination of the relative permeability of two-phase fluids in rocks, oil-water phase permeability curves were established. Combined with reservoir water saturation data, the oil phase relative permeability field data K was obtained. ro Water phase relative permeability field data K rw .

[0044] The experiment to determine the relative permeability of two-phase fluids in rock was conducted according to the specifications of GB / T 28912-2012, "Method for Determining Relative Permeability of Two-Phase Fluids in Rock." Specifically, the steady-state method was used, employing real core samples obtained from the Hu 7 South core well. The main steps involved establishing bound water saturation, followed by displacement with crude oil. When the inlet and outlet pressures and oil-water flow rates were stable, the relative permeability and water saturation could be calculated using Darcy's law and the mass balance method. By varying the oil-water injection flow rate ratio, relative permeability at different water saturations could be obtained, and the relative permeability curve could be obtained through fitting. The oil-water relative permeability curves obtained from the above experiments are shown below. Figure 2 As shown. The specific fitting formulas for the relative permeability of oil and the relative permeability of water are as follows:

[0045] Relative oil permeability: y = 1.7318x 2 -3.6982x+1.9587; R 2 =0.9999;

[0046] Relative water permeability: y = 1.1804x 2 -0.0713x-0.1003; R 2 =0.9997.

[0047] Water saturation is the proportion of groundwater volume to pore volume, reflecting the static volume ratio in a formation, and can be determined using the mass balance method. Based on water saturation data and oil-water phase permeability fitting curves, the relative permeability field data K for the oil and water phases are obtained. ro K rw ;

[0048] In this embodiment, the water saturation field diagram is as follows: Figure 3 As shown, the obtained oil phase relative permeability field diagram is as follows: Figure 4 As shown, the relative permeability field diagram of the water phase is as follows: Figure 5 As shown.

[0049] (2) Based on the determination methods in GB / T 26981-2020 Oil and Gas Reservoir Fluid Property Analysis Methods, the fitting relationships between crude oil viscosity and reservoir pressure, and between crude oil volume coefficient and reservoir pressure were established respectively. Then, combined with reservoir pressure data, the oil phase viscosity field data μ were obtained. o Oil phase volume coefficient field data B o .

[0050] This step can be carried out according to the determination methods in GB / T 26981-2020 Oil and Gas Reservoir Fluid Property Analysis Methods. Specifically, the fitting relationship between crude oil viscosity and reservoir pressure is determined by the formation oil viscosity determination method in section 13, and the fitting relationship between crude oil volume factor and reservoir pressure is determined by the formation crude oil single degassing volume factor determination method in section 14.2.3.

[0051] The fitting result of crude oil viscosity and reservoir pressure is: y = 9E -13 x 6 -7E -10 x 5 +2E -07 x 4 -3E -05 x 3 +0.0023x 2 -0.1005x + 3.8142; R 2 =0.9988;

[0052] The fitting result of the crude oil volume factor and reservoir pressure is y = -6E. -07 x 2 +0.0014x+1.1147;R 2 =0.9871.

[0053] The relationship between reservoir pressure and crude oil volume factor and crude oil viscosity in this study area is shown in Table 1.

[0054] Table 1. Relationship between reservoir pressure and crude oil volume factor and crude oil viscosity.

[0055]

[0056]

[0057] Reservoir pressure was calculated using dynamic production data such as injected and produced oil and water volumes from the corresponding functional module of the commercial numerical simulation software tNavigator. The pressure field map for this study area is shown below. Figure 6 As shown.

[0058] Based on the above fitting relationship between crude oil viscosity and reservoir pressure, the calculated oil phase viscosity field diagram is as follows: Figure 7As shown. Based on the above fitting relationship between crude oil volume factor and reservoir pressure, the calculated oil phase volume factor field diagram is shown below. Figure 8 As shown.

[0059] Furthermore, the volume coefficient and viscosity of the aqueous phase change negligibly with pressure, and can therefore be considered as μ. w B w μ is a fixed value (i.e., a constant). w The range can be taken as 1.24~1.25 mPa·s, B w The range can be taken as 1.01~1.02m 3 / m 3 In this embodiment, μ w =1.245 mPa·s, B w =1.0106m 3 / m 3 .

[0060] (3) Establish the relationship between moisture content and μ o B o K ro K rw Water phase viscosity μ w Water phase volume coefficient B w The calculation formula.

[0061] The process of obtaining the moisture content calculation formula is as follows:

[0062] Surface water production rate Formulas (1), (2), (3), and (4) are from Yang Shenglai's "Oil Layer Physics".

[0063] in

[0064]

[0065] K w =K×K rw (3)

[0066] K o =K×K ro (4)

[0067]

[0068] In the above formulas, f w f is the reservoir water cut; K is the reservoir water cut. w —Aqueous phase effective permeability, mD; K rw —Relative permeability of the aqueous phase, dimensionless; K—Absolute permeability, mD; μ w —Viscosity of aqueous phase, mPa·s; B w —Water phase volume coefficient, m3 / m 3 ;K o —Effective oil phase permeability, mD; K ro —Relative permeability of the oil phase, dimensionless; μ o —Oil phase viscosity, mPa·s; B o —Oil phase volume index, m 3 / m 3 μ w B w It is a constant.

[0069] After conversion, we obtain the moisture content calculation formula shown in Equation 1:

[0070]

[0071] (4) Establish a reservoir numerical model based on calculation formula 1 and generate a water cut distribution map. Specifically, as follows... Figure 9 The water content distribution map shown and as shown Figure 10 The moisture content profile shown is a diagram illustrating the distribution of moisture content.

[0072] II. Method Testing

[0073] To analyze the effectiveness and applicability of this method, and to verify its practicality and reliability, a layer in the Hu7 South oil reservoir was randomly selected as the target layer. The water cut of this area (grid) was calculated using traditional methods based on the oil production water content (water cut could not be obtained from other well-free areas). The calculation formula is as follows: It can be calculated directly by numerical simulation software.

[0074] Water cut calculations were performed on 20 old wells and 10 new wells (WU1-1–WU1-10) in the reservoir. The results are as follows: Figure 11 As shown in Table 2 below. Figure 11 In the diagram, the numerical model represents the traditional method, while the moisture content distribution map represents the method of this invention.

[0075] Table 2. Calculation results of water cut in well-covered areas using different methods.

[0076]

[0077]

[0078] from Figure 11 As can be seen from Table 2, the actual water cut calculated by the method of this invention based on production data is basically consistent with that calculated by the traditional method, proving the effectiveness of the method of this invention. Furthermore, the water cut distribution map obtained based on the method of this invention can more accurately and reasonably characterize the water cut distribution in well-free areas at different stages of reservoir development, thus providing a more scientific basis for evaluating the effectiveness of waterflood development and formulating reservoir adjustment plans.

[0079] Researchers utilized this patented technology to deepen their understanding of the Ming 16 block of the Wenmingzhai Oilfield, a reservoir with exceptionally high water cut. This included enhancing the precise characterization of water cut, optimizing injection and production parameters, and strengthening performance tracking and analysis. Following this, the Ming 225C2 well was successfully drilled on June 25, 2024, and put into production on July 8, 2024, achieving a daily oil production of 6.38 tons with a water cut of 69.6%, far exceeding the designed daily production of 3.5 tons, demonstrating excellent results. The successful implementation of the Ming 225C2 well not only improved the injection-production well network of the polymer flooding test well group and expanded the utilization scale of the remaining reserves in the Ming 16 block, but also laid the foundation for increased production through polymer flooding.

Claims

1. A method for characterizing the water cut distribution in an oil reservoir, characterized in that, Includes the following steps: S1: Based on the experimental determination of the relative permeability of two-phase fluids in rocks, oil-water phase permeability curves were established. Combined with reservoir water saturation data, the oil phase relative permeability field data K was obtained. ro Water phase relative permeability field data K rw ; S2: Based on the fluid property analysis experiments of oil and gas reservoirs, the fitting relationships between crude oil viscosity and reservoir pressure, and between crude oil volume coefficient and reservoir pressure were established respectively. Then, combined with the reservoir pressure data, the oil phase viscosity field data μ was obtained. o Oil phase volume coefficient field data B o ; S3: Establishing the relationship between moisture content and μ o B o K ro K rw Water phase viscosity μ w Water phase volume coefficient B w The calculation formula; S4: Establish a reservoir numerical model based on the calculation formula and generate a water cut distribution map.

2. The method for characterizing reservoir water cut distribution as described in claim 1, characterized in that, The calculation formula is shown in Equation 1: In Equation 1, f w The reservoir water cut and the water phase viscosity (μ) are given. w Water phase volume coefficient B w It is a constant.

3. The method for characterizing reservoir water cut distribution as described in claim 2, characterized in that, μ w =1.24~1.25mPa.s;B w =1.01~1.02m 3 / m 3 。

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