Determination method of two-phase relative permeability curve

Abstract

The invention belongs to the technical field of geological exploration, and discloses a method for measuring a two-phase relative permeability curve, which comprises the following steps of: 1, measuring CT values of oil, gas and water for simulation; step 2, respectively carrying out vacuumizing, oil saturation, gas saturation and water saturation on the rock core, and carrying out CT (Computed Tomography) scanning; step 3, injecting simulated oil into the rock core at a set pressure until no water is generated at an outlet, and performing CT scanning as an initial state; step 4, injecting simulation gas into the rock core at set pressure, and performing CT scanning once every set time interval; and 5, sequentially arranging a plurality of pressure measuring points in the length direction of the rock core, calculating the local relative permeability according to the partial pressure data obtained by each pressure measuring point and the calculated on-way saturation, and finally weighting to obtain a relative permeability curve of the whole rock core. According to the method, the gas-driven front edge interface is captured through online CT scanning, and the influence caused by the end effect can be effectively avoided.

Description

Technical Field

[0001] The present invention relates to the technical field of geological exploration, and in particular to a method for measuring a two-phase relative permeability curve. Background Art

[0002] Carbon dioxide retention is a key indicator parameter for carbon dioxide capture, utilization and storage. In order to accurately calculate the bound storage capacity of carbon dioxide in this process, it is extremely important to measure the relative permeability of carbon dioxide.

[0003] However, existing methods for measuring relative permeability mainly include steady-state and non-steady-state methods. Traditional measurement processes cannot accurately obtain the relative permeability of carbon dioxide, especially when the experimental pressure is greater than the minimum miscibility pressure of carbon dioxide. A relatively obvious miscibility zone will form at the displacement front, causing the contact interface between carbon dioxide and crude oil to disappear, making it difficult to measure the relative permeability curve. Summary of the Invention

[0004] The object of the present invention is to provide a method for measuring a two-phase relative permeability curve, thereby enabling the measurement of the relative permeability curve.

[0005] To achieve this object, the present invention adopts the following technical solutions:

[0006] The method for determining the two-phase relative permeability curve includes:

[0007] Step 1: Measure the CT values ​​of the simulated oil, gas and water;

[0008] Step 2: vacuum the core, saturate it with oil, saturate it with gas, and saturate it with water, and then perform CT scanning;

[0009] Step 3: Inject simulated oil into the core at a set pressure until no water is produced at the outlet, and perform a CT scan as the initial state;

[0010] Step 4: Inject simulated gas into the core at a set pressure and perform a CT scan at a set time interval;

[0011] Step 5: Set up multiple pressure measuring points along the length of the core. Calculate the local relative permeability based on the partial pressure data obtained at each pressure measuring point and the calculated saturation along the length. Finally, weighted calculation is performed to obtain the relative permeability curve of the entire core.

[0012] Preferably, in step 1, carbon dioxide is used as the simulated gas, and formation water containing 2% NaBr is used as the simulated water.

[0013] Preferably, in step 2, the core is first dried and then placed in a holder of a permeability measuring device. After adding a confining pressure of 1.5 times the displacement pressure, the holder and the core are kept in position. The core is scanned using a CT scanner of the permeability measuring device to obtain a CT value of the dry core. The core is then vacuumed, saturated with oil, saturated with gas, and saturated with water, and CT scanned to obtain a CT value of the core skeleton, a CT value of the core saturated with oil, a CT value of the core saturated with gas, and a CT value of the core saturated with water.

[0014] The core porosity is calculated using the above CT values, and the vertical porosity distribution of each scanning plane is obtained.

[0015] Preferably, in step three, simulated oil is injected into the core at a set constant pressure, and the pressure is gradually increased step by step according to the set pressure gradient until water is no longer produced at the outlet. The water production and pressure drop at the outlet are recorded, the oil saturation and irreducible water saturation of the core are calculated, and a CT scan is performed as the initial state.

[0016] Preferably, in step 4, the injection process is divided into set stages, and the interval time of the CT scan in each stage increases successively from the beginning to the end.

[0017] Preferably, in step 4, the gas injection process is divided into four stages: initial stage of experiment, stable stage, gas outlet stage and late stage of experiment;

[0018] At the beginning of the experiment, the pressure difference between the inlet and outlet and the pressure measuring point was recorded every 3 minutes, the oil and gas production at the outlet was measured, and a CT scan was performed;

[0019] During the stabilization period, both the recording interval and the CT scanning interval were adjusted to 10 minutes;

[0020] During the exhalation period, the CT scanning interval was adjusted to 40 minutes;

[0021] In the later stage of the experiment, the CT scanning interval was adjusted to 100 minutes.

[0022] Preferably, in step five, the gas saturation along the section is calculated based on the CT value of the section, and the relative permeability of each section is obtained in combination with the local pressure measuring points. According to the relationship between the section porosity and the total porosity, the relative permeabilities of the obtained sections are weighted averaged to obtain the relative permeability of the gas and oil phases of the entire core.

[0023] Preferably, in step 5, the cross-sectional porosity is calculated using the following formula:

[0024]

[0025] Where: is the core porosity, in %; CT Satured1CT is the CT value of the core saturated with gas, in HU; CT Dry CT is the CT value of the dry core, in HU; CT Phase1 CT is the CT value of the gas phase, in HU; CT Air CT is the CT value of the air, in HU.

[0026] As preferred, in step five, the gas saturation is calculated by the following formula:

[0027]

[0028]

[0029] In the formula, CT two CT is the CT value measured during the core displacement process, in HU; CT is the core porosity, in %; CT grain CT is the CT value of the core skeleton; CT Phase1 CT is the gas saturation, in %; CT Phase1 CT is the CT value of the gas phase, in HU; CT Phase2 CT is the CT value of the oil phase, CT Satured2 CT is the CT value of the core saturated with oil, in HU.

[0030] As preferred, in step five, the relative permeability of the profile is calculated by the following formula:

[0031]

[0032] In the formula, K rg K is the relative permeability of the gas phase, dimensionless; f o L is the core length, in cm; Q t Q is the total flow rate, in cm 3 / min; μ o μ is the viscosity of the oil at the pressure of the measuring point, in mPa·s; K is the absolute permeability of the core, in mD; A is the cross-sectional area of the core, in cm 2 ; V is the fluid volume at the outlet, cm 3 ; ΔP is the pressure difference between the two ends of the core measuring point, in MPa; μ g μ is the viscosity of the gas phase at the pressure of the measuring point, in mPa·s.

[0033] The beneficial effects of the present application are:

[0034] The gas drive front edge interface is captured by the online CT scanning, the CT value obtained by the online CT scanning is used to obtain the saturation and the profile porosity along the path, the front edge oil-gas mixing zone profile pressure difference is obtained by the pressure measuring points, the local profile relative permeability is calculated, the two-phase relative permeability curve is obtained by weighting according to the profile porosity, the gas-oil flow rate at the front edge profile is obtained by the in-situ saturation calculated by the CT value, and the relative permeability of the displacement front edge is obtained, so that the influence of the end effect can be effectively avoided. BRIEF DESCRIPTION OF DRAWINGS

[0035] Figure 1 is a flow chart of the two-phase relative permeability curve measurement method according to the embodiment of the present application;

[0036] Figure 2 is a schematic diagram of the permeability measurement device according to the embodiment of the present application;

[0037] Figure 3 is a schematic diagram of the gripper according to the embodiment of the present application.

[0038] In the drawings:

[0039] 100, core;

[0040] 1, CT scanner;

[0041] 2, gripper; 21, annulus; 22, upper pressure measuring point; 23, lower pressure measuring point; 24, gasket; 25, scanning area;

[0042] 3, oil pump;

[0043] 4, water pump;

[0044] 5, intermediate container;

[0045] 6, differential pressure sensor;

[0046] 7, confining pressure pump;

[0047] 8, computer;

[0048] 9, phase separator;

[0049] 10, back pressure pump;

[0050] 11, heating and temperature control box;

[0051] 12, control valve. DETAILED DESCRIPTION

[0052] The following describes embodiments of the present invention in detail. Examples of the embodiments are shown in the accompanying drawings, wherein the same or similar reference numerals throughout represent the same or similar components or components having the same or similar functions. The embodiments described below with reference to the accompanying drawings are exemplary and are intended to explain the present invention, but are not to be construed as limiting the present invention.

[0053] In the description of the present invention, unless otherwise expressly specified or limited, the terms "connected," "connected," and "fixed" should be understood in a broad sense. For example, they may refer to fixed or detachable connections, mechanical or electrical connections, direct or indirect connections through an intermediate medium, and internal communication between two elements or interaction between two elements. Those skilled in the art will understand the specific meanings of the above terms in the present invention based on specific circumstances.

[0054] In the description of the present invention, unless otherwise expressly specified or limited, a first feature being "above" or "below" a second feature may include the first feature being in direct contact with the second feature, or may include the first feature being in contact with the second feature through another feature between them instead of being in direct contact. Moreover, a first feature being "above," "above," and "above" a second feature may include the first feature being directly above or obliquely above the second feature, or may simply mean that the first feature is higher in level than the second feature. A first feature being "below," "below," and "below" a second feature may include the first feature being directly below or obliquely below the second feature, or may simply mean that the first feature is lower in level than the second feature.

[0055] The technical solution of the present invention will be further described below with reference to the accompanying drawings and through specific implementation methods.

[0056] like Figure 1 As shown, the present invention provides a method for determining a two-phase relative permeability curve, comprising the following steps:

[0057] Step 1: Measure the CT values ​​of the simulated oil, gas, and water.

[0058] Step 2: The core 100 is vacuumed, saturated with oil, saturated with gas, and saturated with water, and then CT scanned.

[0059] Step 3: Inject simulated oil into the core 100 at a set pressure until no water is produced at the outlet, and perform a CT scan as an initial state.

[0060] Step 4: Inject simulated gas into the core 100 at a set pressure, and perform a CT scan at a set time interval.

[0061] Step five, a plurality of pressure measuring points are arranged along the length direction of the core 100 in sequence, the local relative permeability is calculated according to the differential pressure data obtained by each pressure measuring point and the calculated saturation along the way, and finally the relative permeability curve of the whole core 100 is obtained by weighting.

[0062] In the present application, the gas drive front interface is captured by online CT scanning, the CT value obtained by online CT scanning is used to obtain the saturation and porosity along the profile, the profile pressure difference of the front oil-gas mixed zone is obtained by each pressure measuring point, the local profile relative permeability is calculated and weighted according to the profile porosity, and the more accurate two-phase relative permeability curve is obtained. The gas-oil flow rate at the front profile is obtained by using the in-situ saturation calculated by the CT value, so that the relative permeability of the displacement front is obtained, which can effectively avoid the influence of the end effect.

[0063] Specifically, in step one, carbon dioxide is used as the simulation gas, and formation water containing 2% NaBr is used as the simulation water, and the CT value of the oil phase, the CT value of the gas phase and the CT value of the water are detected by the CT scanner 1.

[0064] More specifically, in step two, the core 100 is dried and then placed in the holder 2 of the permeability measuring device, the confining pressure of 1.5 times the displacement pressure is added, the position of the holder 2 and the core 100 is kept unchanged, the CT scanner 1 of the permeability measuring device is used for scanning to obtain the CT value of the dry core, and then the core 100 is vacuumized, saturated with oil, saturated with gas and saturated with water, and CT scanning is performed to obtain the CT value of the core skeleton, the CT value of the core saturated with oil, the CT value of the core saturated with gas and the CT value of the core saturated with water; the core porosity is calculated by the above CT values to obtain the vertical porosity distribution of each scanning plane.

[0065] In other embodiments, the simulation gas can also be nitrogen and the like.

[0066] Specifically, as Figure 2As shown, based on the CT scanner 1 and the holder 2, the permeability measuring device also includes an oil pump 3, a water pump 4, an intermediate container 5, a pressure difference sensor 6, a confining pressure pump 7, a computer 8, a phase separator 9, a back pressure pump 10 and a heating and temperature control box 11. Among them, the clamp 2 is located in the CT scanner 1, the oil pump 3 is connected to the core 100 in the clamp 2 through a pipeline, the water pump 4 is connected to the core 100 in the clamp 2 through an intermediate container 5, the differential pressure sensor 6 detects the pressure difference between the two ends of the core 100 through a pipeline, the confining pressure pump 7 is connected to the clamp 2 through a pipeline, the computer 8 is electrically connected to the CT scanner 1, the phase separator 9 is connected to the core 100 in the clamp 2 through a pipeline, the back pressure pump 10 is connected to the core 100 in the clamp 2 through a pipeline, and the heating and temperature control box 11 is connected to the clamp 2 and is configured to heat and temperature control the clamp 2. In addition, control valves 12 are provided on the connecting pipelines between the above components as needed to control the on-off of the relevant pipelines.

[0067] More specifically, if Figure 3 As shown, the clamp 2 includes an annulus 21, an upper pressure measuring point 22, a lower pressure measuring point 23, and a gasket 24. The core 100 is located in the annulus 21 and clamped between the two gaskets 24. The upper pressure measuring point 22 and the lower pressure measuring point 23 extend into the annulus 21. The scanning area 25 corresponding to the core 100 is located between the upper pressure measuring point 22 and the lower pressure measuring point 23. Pipelines are provided at both ends of the core 100, passing through the gaskets 24 and connected to the outside. Control valves 12 are provided on the pipelines as needed to control on / off.

[0068] Specifically, in step three, simulated oil is injected into the core 100 at a set constant pressure, and the pressure is gradually increased step by step according to the set pressure gradient until water is no longer produced at the outlet. The water production and pressure drop at the outlet are recorded, the oil saturation and irreducible water saturation of the core 100 are calculated, and a CT scan is performed as the initial state.

[0069] More specifically, in step 4, the injection process is divided into set stages, and the interval time of the CT scan in each stage increases sequentially from the beginning to the end.

[0070] In this embodiment, in step 4, the gas injection process is divided into four stages: the initial stage of the experiment, the stabilization stage, the gas release stage and the late stage of the experiment.

[0071] At the beginning of the experiment, the pressure difference between the inlet and outlet and the pressure measuring point was recorded every 3 minutes, the oil and gas production at the outlet was measured, and a CT scan was performed.

[0072] During the stabilization period, the recording interval and CT scanning interval were both adjusted to 10 minutes.

[0073] During the exhalation period, the CT scanning interval was adjusted to 40 minutes.

[0074] In the later stage of the experiment, the CT scanning interval was adjusted to 100 minutes.

[0075] The number of stages into which the injection process is divided and the length of the interval between each set stage are set based on experience or needs.

[0076] Specifically, in step five, the gas saturation along the section is calculated based on the CT value of the section, and the relative permeability of each section is obtained in combination with the local pressure measuring points. According to the relationship between the section porosity and the total porosity, the relative permeabilities of the obtained sections are weighted averaged to obtain the relative permeability of the gas and oil phases of the entire core 100.

[0077] More specifically, in step five, the cross-sectional porosity is calculated using the following formula:

[0078]

[0079] Where: is the core porosity, in %; CT Satured1 is the CT value of the core saturated gas, the unit is HU, CT Dry is the CT value of the dry core, in HU; CT Phase1 is the CT value of the gas phase, unit HU; CT Air is the CT value of air, in HU.

[0080] More specifically, in step 5, the gas saturation is calculated using the following formula:

[0081]

[0082]

[0083] Where: CT two is the CT value measured during the core flooding process, in HU; is the core porosity, in %; CT grain is the CT value of the core skeleton; S Phase1 is the gas saturation, in %; CT Phase1 is the CT value of the gas phase, unit HU; CT Phase2 is the CT value of the oil phase, CT Satured2 is the CT value of the core saturated with oil, in HU.

[0084] In this embodiment, in step 5, the relative permeability of the cross section is calculated using the following formula:

[0085]

[0086] Where: K rgis the relative permeability of the gas phase, dimensionless; f o is the oil content, in %; L is the core length, in cm; Q t is the total flow rate in cm 3 / min; μ o is the viscosity of the oil at the pressure measuring point, in mPa·s; K is the absolute permeability of the core, in mD; A is the cross-sectional area of ​​the core, in cm 2 ; V is the volume of fluid at the outlet, cm 3 ; ΔP is the pressure difference between the two ends of the core pressure measuring point, unit is MPa; μ g It is the gas phase viscosity at the pressure measuring point, in mPa·s.

[0087] In addition, in step 5, if you want to observe the relative permeability of a specified section, there is no need to perform weighted averaging.

[0088] Obviously, the above embodiments of the present invention are merely examples for the purpose of clearly illustrating the present invention, and are not intended to limit the embodiments of the present invention. Those skilled in the art will appreciate that other variations or modifications can be made based on the above description. It is not necessary and impossible to enumerate all embodiments here. Any modifications, equivalent substitutions, and improvements made within the spirit and principles of the present invention shall be included within the scope of protection of the claims of the present invention.

Claims

1. A method for determining a two-phase relative permeability curve, characterized in that: include: Step 1: Measure the CT values ​​of the simulated oil, gas and water; Step 2: vacuuming, saturating the core (100) with oil, gas and water, and performing CT scanning; Step 3: injecting simulated oil into the core (100) at a set pressure until no water is produced at the outlet, and performing a CT scan as an initial state; Step 4: injecting simulated gas into the core (100) at a set pressure, and performing a CT scan at a set time interval; Step 5: Set multiple pressure measuring points in sequence along the length of the core (100), calculate the local relative permeability based on the partial pressure data obtained at each pressure measuring point and the calculated saturation along the length, and finally obtain the relative permeability curve of the entire core (100) by weighting.

2. The method for measuring the two-phase relative permeability curve according to claim 1, wherein: In step 1, carbon dioxide is used as the simulated gas, and formation water containing 2% NaBr is used as the simulated water.

3. The method for measuring the two-phase relative permeability curve according to claim 1, wherein: In step 2, the core (100) is first dried and then placed in a holder (2) of a permeability measuring device. After adding a confining pressure of 1.5 times the displacement pressure, the holder (2) and the core (100) are kept in position. The core is scanned using a CT scanner (1) of the permeability measuring device to obtain a CT value of the dry core. The core (100) is then vacuumed, saturated with oil, saturated with gas, and saturated with water, and CT scanned to obtain a CT value of the core skeleton, a CT value of the core saturated with oil, a CT value of the core saturated with gas, and a CT value of the core saturated with water. The core porosity is calculated using the above CT values, and the vertical porosity distribution of each scanning plane is obtained.

4. The method for measuring the two-phase relative permeability curve according to claim 1, wherein: In step three, simulated oil is injected into the core (100) at a set constant pressure, and the pressure is gradually increased step by step according to the set pressure gradient until water is no longer produced at the outlet. The water production and pressure drop at the outlet are recorded, the oil saturation and bound water saturation of the core (100) are calculated, and a CT scan is performed as the initial state.

5. The method for measuring the two-phase relative permeability curve according to claim 1, wherein: In step 4, the injection process is divided into set stages, and the interval time of CT scanning in each stage increases successively from the beginning to the end.

6. The method for measuring the two-phase relative permeability curve according to claim 5, characterized in that: In step 4, the gas injection process is divided into four stages: the initial stage of the experiment, the stabilization stage, the gas release stage, and the late stage of the experiment; At the beginning of the experiment, the pressure difference between the inlet and outlet and the pressure measuring point was recorded every 3 minutes, the oil and gas production at the outlet was measured, and a CT scan was performed; During the stabilization period, both the recording interval and the CT scanning interval were adjusted to 10 minutes; During the exhalation period, the CT scanning interval was adjusted to 40 minutes; In the later stage of the experiment, the CT scanning interval was adjusted to 100 minutes.

7. The method for measuring the two-phase relative permeability curve according to claim 1, wherein: In step five, the gas saturation along the section is calculated based on the CT value of the section, and the relative permeability of each section is obtained by combining the local pressure measuring points. According to the relationship between the section porosity and the total porosity, the relative permeabilities of the obtained sections are weighted averaged to obtain the relative permeability of the gas and oil phases of the entire core (100).

8. The method for measuring the two-phase relative permeability curve according to claim 7, wherein: In step 5, the cross-section porosity is calculated using the following formula: Where: is the core porosity, in %; CT Satured1 is the CT value of the core saturated gas, the unit is HU, CT Dry is the CT value of the dry core, in HU; CT Phase1 is the CT value of the gas phase, unit HU; CT Air is the CT value of air, in HU.

9. The method for measuring the two-phase relative permeability curve according to claim 8, characterized in that: In step 5, the gas saturation is calculated using the following formula: Where: CT two is the CT value measured during the core flooding process, in HU; is the core porosity, in %; CT grain is the CT value of the core skeleton; S Phase1 is the gas saturation, in %; CT Phase1 is the CT value of the gas phase, unit HU; CT Phase2 is the CT value of the oil phase, CT Satured2 is the CT value of the core saturated with oil, in HU.

10. The method for measuring the two-phase relative permeability curve according to claim 7, characterized in that: In step 5, the relative permeability of the profile is calculated using the following formula: Where: K rg is the relative permeability of the gas phase, dimensionless; f o is the oil content, in %; L is the core length, in cm; Q t is the total flow rate in cm 3 / min; μ o is the viscosity of the oil at the pressure measuring point, in mPa·s; K is the absolute permeability of the core, in mD; A is the cross-sectional area of ​​the core, in cm 2 ; V is the volume of fluid at the outlet, cm 3 ; ΔP is the pressure difference between the two ends of the core pressure measuring point, unit is MPa; μ g It is the gas phase viscosity at the pressure measuring point, in mPa·s.

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