Gas drive fine description and gas channeling prevention method based on facies belt division

Abstract

The application discloses a kind of oil reservoir gas drive fine delineation and gas channeling prevention and control method based on facies belt division.The method of the application can be used for the "fine" description of formation fluid migration in the process of CO2 injection development, through long core displacement, interface tension determination is combined, and well stream component is determined, the distribution of each facies zone in the ground is obtained through numerical simulation, accurate gas channeling early warning can be realized, and the starting pressure gradient at different development moments can be obtained in combination with the determined starting pressure gradient;The carbonized water is prepared by generating and breaking CO2 micro-bubbles in the application, and the enhanced CO2 micro-bubbles are generated by using the carbonized water and CO2, which can avoid the influence of water lock effect, improve the stability of micro-bubbles, better play the plugging and profile control effect, and improve the oil displacement efficiency, for the treatment of gas channeling, which is helpful to further improve the recovery efficiency and CO2 storage effect.

Description

Technical Field

[0001] This invention relates to a method for fine characterization of reservoir gas drive and prevention of gas channeling based on phase zone division, belonging to the field of reservoir gas injection development. Background Technology

[0002] Low-permeability, tight oil reservoirs are rich in reserves, but their narrow pore throats make water injection development difficult and recovery rates low. CO2 has good injectability and readily reacts with crude oil through dissolution, expansion, and viscosity reduction. CO2 injection development can achieve high oil displacement efficiency while simultaneously storing CO2, and has been implemented successfully in several fields. However, CO2 differs significantly from crude oil in density and viscosity, and is susceptible to gas channeling due to reservoir heterogeneity, resulting in poor sweep efficiency and low recovery rates. Existing technologies provide overly general descriptions of fluid migration during CO2 injection development, lacking a "refined description." Furthermore, most technologies only characterize fluid migration during gas injection development through numerical simulations, lacking necessary support, making it difficult for CO2 injection development to achieve the desired results. Common existing gas channeling control methods include alternating water-gas injection and co-injection of water and gas, which can effectively improve sweep efficiency, but the water-locking effect reduces oil displacement efficiency to some extent. Clarifying the migration patterns of reservoir fluids during CO2 displacement and accurately characterizing their migration features helps prevent gas channeling and improve gas drive sweep efficiency. Controlling gas channeling while improving oil displacement efficiency is beneficial for further enhancing oil recovery. Summary of the Invention

[0003] The purpose of this invention is to provide a method for fine characterization of reservoir gas drive and prevention of gas channeling based on phase zone division. This invention defines phase zone distribution and proposes a division method for gas channeling early warning, and proposes a development method of "enhanced CO2 microbubble" drive for gas channeling control.

[0004] This invention first provides a method for classifying formation fluid facies zones in oil reservoir gas injection development, comprising the following steps:

[0005] S1, Formation fluid mixture

[0006] Formation active oil is prepared by using formation crude oil and associated gas, and formation water is prepared by using distilled water and corresponding salts;

[0007] S2. Acquisition of fluid components in different phase zones

[0008] S2-1. Saturate the combined core with the formation water, then use the formation active oil to displace it, establish the bound water saturation and saturate the formation active oil, and age it under formation temperature and pressure conditions.

[0009] S2-2. Under the condition of constant back pressure of the combined core, CO2 is injected; at different injection volumes, the fluid at different measuring points of the combined core is obtained, and the pressure at each measuring point is recorded.

[0010] S3. Determination of the composition and properties of phase fluids

[0011] S3-1. Measure the gas-oil ratio, degassed crude oil and gas composition of the fluid at different measuring points, and compound the fluid according to the measured data, and measure the density, viscosity and gas-oil ratio of the compound fluid.

[0012] S3-2. At reservoir temperature, measure the interfacial tension of the formation active oil-CO2 interface at the pressure at the corresponding measuring point. Combined with the definition of each phase zone, determine the composition and properties of the fluids in different phase zones based on the interfacial tension and the composition, density, viscosity and gas-oil ratio of the compound fluid.

[0013] S4. Phase zone distribution determination and gas channeling assessment

[0014] S4-1, Pseudo-component division

[0015] Based on the actual formation fluid composition, pseudo-components are defined;

[0016] S4-2, Numerical Simulation

[0017] The actual geological model is imported into numerical simulation software. Using the pseudo-components, an injection-production regime consistent with the field is set up to conduct numerical simulation. The gas saturation, crude oil viscosity, interfacial tension, and CO2 mole fraction of the well-to-well connection are output. Combined with the definition of each phase zone, the distribution of the phase zones between wells is determined.

[0018] In the above-mentioned classification method, in step S1, samples are taken from the production well fluid to determine the gas-oil ratio, degassed crude oil components, associated gas components, formation water salinity and ion content, and then the formation active oil and formation water are prepared.

[0019] In the above division method, step S2-1, the combined core is prepared in the following manner: after the formation core is cut, washed with oil, and dried, it is combined in a blended and averaged manner, and filter paper is used to connect different cores.

[0020] In the above division method, in step S2-2, the injection rate is determined by referring to the CO2 migration linear velocity at the reservoir site. Under different injection rates, the pneumatic valve is controlled by the control panel, and the sampling vessel at each measuring point is opened at the same time to obtain the fluid at different measuring points and record the pressure at each measuring point. Then the sampling device is closed.

[0021] To ensure that fluids in each phase zone can be obtained, samples were taken at different CO2 injection rates (0.2 PV, 0.4 PV, 0.6 PV, 0.8 PV). Therefore, long core displacement experiments and sampling need to be repeated.

[0022] The aging time is 3 to 7 days;

[0023] In steps S2-3, the CO2 injection rate is determined by referring to the CO2 migration linear velocity at the reservoir site;

[0024] Samples were taken at injection volumes of 0.2 PV, 0.4 PV, 0.6 PV, and 0.8 PV.

[0025] In the above classification method, in step S4-1, the total error between the density, viscosity, saturation pressure, and gas-oil ratio of the simulated component and the actual crude oil is less than 5%.

[0026] In step S4-2, the results of the numerical simulation shall meet the following requirements:

[0027] The overall error in fitting production data and the composition, gas-oil ratio, density, viscosity, and saturation pressure of the production well fluid is less than 5%.

[0028] Based on the determination of facies distribution, this invention further provides a method for determining and warning of gas channeling in low-permeability reservoirs, comprising the following steps:

[0029] SⅠ. Determine the fluid facies zone of the reservoir for gas injection development according to the aforementioned classification method;

[0030] SⅡ: Compare the composition, density, viscosity, gas-oil ratio and saturation pressure of the fluid in each phase zone determined in step SⅠ to determine the formation fluid phase zone at the production well and determine whether gas channeling has occurred; based on the numerical simulation results of step S4-2, predict the timing of gas channeling and realize gas channeling early warning.

[0031] The present invention further provides a method for determining the start-up pressure at different development times in a gas injection development formation of an oil reservoir, comprising the following steps:

[0032] SA, determine the fluid facies zone of the reservoir for gas injection development according to the aforementioned classification method;

[0033] SB, combined with formation fluids from different phase zones, conducted start-up pressure gradient tests to obtain the start-up pressure gradients of different phase zones;

[0034] Based on the SC and the inter-well facies distribution, the starting pressure is calculated according to formula (1), which provides a basis for the formulation and adjustment of injection and production systems and the prediction of recovery rate.

[0035] ΔP=G o ×L o +GF ×L F +G IM ×L IM +G NM ×L NM +G M ×L M (1)

[0036] Where ΔP is the starting pressure, MPa; G o G F G IM G NM G M The starting pressure gradients for the original oil phase zone, leading edge zone, immiscible zone, near-miscible zone, and miscible zone are respectively, in MPa / m; L o L F L IM L NM L M The lengths, in meters, are the original oil phase zone, the leading edge zone, the immiscible zone, the near-miscible zone, and the miscible zone, respectively.

[0037] Finally, the present invention also provides an apparatus and method for preparing enhanced CO2 microbubbles:

[0038] The apparatus for preparing carbonized water and enhanced CO2 microbubbles provided by the present invention includes a storage tank;

[0039] An input pipeline is connected to the bottom of the side wall of the storage tank, and the input pipeline is connected to a carbon dioxide input pipeline and a water input pipeline respectively;

[0040] An output pipeline is connected to the upper side wall of the storage tank, and the output pipeline is connected to a carbon dioxide input bypass.

[0041] The carbon dioxide input pipeline, the water input pipeline connection, the output pipeline, and the carbon dioxide input bypass are all equipped with valves and filter elements;

[0042] The top of the storage tank is equipped with a paddle, which is controlled by a motor;

[0043] The bottom of the storage tank is equipped with a piston.

[0044] The method for preparing enhanced CO2 microbubbles provided by this invention includes the following steps:

[0045] CO2 and water are injected into the carbon dioxide input pipeline and water input pipeline of the preparation device, respectively. The generated CO2 microbubbles enter the storage tank until the storage tank is full. Then the paddle is turned on to generate shear force to accelerate the collapse of CO2 microbubbles. The rotation continues until all CO2 is dissolved in the water to obtain carbonated water.

[0046] The carbonized water is output from the output pipeline, while CO2 is input from the carbon dioxide input bypass. After passing through the filter, the dispersed CO2 gas clusters are distributed in the carbonized water to obtain enhanced CO2 microbubbles.

[0047] Based on enhanced CO2 microbubbles, this invention also provides a method for controlling gas channeling in low-permeability reservoirs, including the step of injecting enhanced CO2 microbubbles into the formation;

[0048] This method can avoid the effects of water lock, improve the stability of microbubbles, better exert the effects of plugging and profile control, and improve oil displacement efficiency. It can be used to control gas channeling and help to further improve the recovery rate and CO2 storage effect.

[0049] This invention defines the concept of various phase zones, determines the fluid composition and properties of each phase zone through indoor experiments, and clarifies the phase zone distribution at different gas injection development times through numerical simulation, thus achieving gas channeling early warning and judgment. Furthermore, this invention fully utilizes the small diameter and high performance characteristics of CO2 microbubbles, combining the advantages of carbonized water and CO2 microbubbles, and designs a method and system for preparing carbonized water and enhanced CO2 microbubbles using porous filters. This enables the rapid preparation of carbonized water and enhanced CO2 microbubbles, effectively controlling gas channeling.

[0050] The present invention has the following beneficial technical effects:

[0051] (1) In order to solve the problem that the existing technology describes the fluid migration process during CO2 displacement in a too general way, and to achieve a “refined” description of formation fluid migration, so as to provide strong support for gas channeling early warning, this invention defines each phase zone, describes the fluid migration process, and clarifies the distribution of each phase zone based on the component measurement results and combined with numerical simulation.

[0052] (2) Another objective of this invention is to combine formation fluids of different phases, conduct tests on starting pressure gradient and CO2 oil displacement efficiency, and determine the starting pressure at different development times by combining the distribution of fluid phases between wells, so as to provide a reference for determining injection and production regimes and predicting recovery rate.

[0053] (3) Another objective of this invention is to propose a development method of “enhanced CO2 microbubble” flooding to control gas channeling. This method can not only improve sweep efficiency, but also combine the advantages of carbonized water and CO2 microbubbles. It can effectively avoid water lock effect, overcome the adverse effects of reservoir heterogeneity on reservoir development, further improve oil displacement efficiency, and enhance CO2 storage effect.

[0054] (4) This invention also provides a method and apparatus for rapidly preparing carbonated water and enhancing CO2 microbubbles. By converting CO2 gas into CO2 microbubbles, the contact area between CO2 and water is increased, thereby improving the dissolution rate of CO2 and enabling the rapid preparation of carbonated water. Then, carbonated water and CO2 are used to create enhanced CO2 microbubbles. Furthermore, the rapid method for preparing carbonated water proposed in this invention can also be used for the development of carbonated water in oil reservoirs. Attached Figure Description

[0055] Figure 1 This is a schematic diagram of the formation fluid facies zone division in this invention.

[0056] Figure 2 This is a schematic diagram of the structure of the apparatus for preparing carbonized water and enhanced CO2 microbubbles according to the present invention.

[0057] Figure 3 This is a schematic diagram of the enhanced CO2 microbubbles prepared according to the present invention.

[0058] Figure 4 This refers to the associated gas component in a specific embodiment of the present invention.

[0059] Figure 5 These are the components of the well fluid in a specific embodiment of the present invention.

[0060] Figure 6 The fluid composition of different phase zones is shown in a specific embodiment of the present invention.

[0061] Figure 7 This is a comparison of the recovery rate over time in a specific embodiment of the present invention.

[0062] Figure 8 This refers to the CO2-driven water-locking effect after water-drive in a specific embodiment of the present invention.

[0063] Figure 9 This invention aims to enhance the water-locking effect of CO2 microbubbles in specific embodiments of the present invention. Detailed Implementation

[0064] Unless otherwise specified, the experimental methods used in the following examples are conventional methods.

[0065] Unless otherwise specified, all materials and reagents used in the following examples are commercially available.

[0066] This invention combines indoor experimental and numerical simulation techniques to predict the distribution of formation fluid phase zones, enabling early warning and prevention of gas channeling. The invention includes the following steps:

[0067] 1. Formation fluid blending

[0068] (1) Samples of the fluid from the production well were taken and the gas-oil ratio, degassed crude oil components, associated gas components, formation water salinity and the content of each ion were determined.

[0069] (2) Formation active oil is obtained by compounding formation crude oil and associated gas according to the actual dissolved gas-oil ratio; formation water is obtained by compounding distilled water and corresponding salts according to the actual mineralization and ion content.

[0070] 2. Obtaining fluid components from different phase zones

[0071] (1) After the formation cores are cut, washed, and dried, they are combined in a blended and averaged manner. To eliminate the end effect, different cores are connected with filter paper.

[0072] (2) Saturate formation water, then use formation active oil to displace formation water, establish bound water saturation and saturate formation active oil, and age the core for 15 days under formation temperature and pressure conditions.

[0073] (3) With constant core back pressure, the injection rate was determined by referring to the CO2 migration linear velocity in the reservoir. At different injection rates, the pneumatic valves were controlled via the control panel, and the sampling vessels at each measuring point were opened simultaneously to obtain fluids at different measuring points and record the pressure at each measuring point. Afterward, the sampling device was closed. To ensure that fluids in each phase zone could be obtained, sampling was conducted at different CO2 injection rates (0.2PV, 0.4PV, 0.6PV, 0.8PV). Therefore, long core displacement experiments and sampling were repeated.

[0074] 3. Determination of the composition and properties of phase zone fluids

[0075] (1) Measure the gas-oil ratio of the fluid at different measuring points and the components of the degassed crude oil and gas. Based on the measured data, compound fluids are prepared, and the density, viscosity and gas-oil ratio of the compound fluids are measured.

[0076] (2) At the reservoir temperature, the interfacial tension of the formation active oil-CO2 interface is measured at the corresponding measuring point pressure. Based on the definition of each phase zone, the composition and properties of fluids in different phase zones are determined according to the interfacial tension and the results of the measurement of formation active oil components, density, viscosity and gas-oil ratio.

[0077] 4. Determination of phase zone distribution and determination of gas channeling

[0078] (1) Proposed component classification. Based on the actual formation fluid composition, proposed components are classified and adjusted multiple times until the total error between the density, viscosity, saturation pressure, and gas-oil ratio of the proposed components and the actual crude oil is less than 5%;

[0079] (2) Numerical simulation. The actual geological model is imported into the numerical simulation software. Using the predefined pseudo-components, the injection and production regime consistent with the field is set. Numerical simulation is carried out, and the production data and the composition, gas-oil ratio, density, viscosity and saturation pressure of the production well fluid are fitted until the overall error is less than 5%. The gas saturation, crude oil viscosity, interfacial tension and CO2 mole fraction of the inter-well connection are output. Then, combined with the definition of each phase zone, the distribution of the inter-well phase zone is determined.

[0080] (3) Gas channeling determination. By comparing the composition, density, viscosity, gas-oil ratio, and saturation pressure of the well fluid in the production well with those in each phase zone, the formation fluid phase zone at the production well is determined, and it is determined whether gas channeling has occurred. In addition, based on the numerical simulation results of the above steps, the timing of gas channeling is predicted, and gas channeling early warning is achieved.

[0081] Specifically, the leading edge affected by the injected gas components is called the component front; the area unaffected by the component front, i.e., the region between the component front and the production well, is the original oil facies zone; the region affected by the component front and causing improvement in crude oil properties is called the effective component front; the region between the effective component front and the component front is called the front zone. Compared with the original oil facies zone, the gas-oil ratio in the front zone is slightly increased, and the crude oil density, viscosity, and composition are basically the same as in the front zone; the interface between the injected gas and the formation crude oil facies is called the facies front; the region unaffected by the facies front is gas-saturated. The degree is 0; the area affected by the phase front, i.e., the region between the phase front and the injection well, is the residual oil phase zone. In principle, the fluid in the residual oil phase zone cannot be produced, so its fluid composition and properties are not measured; the region between the phase front and the effective component front, depending on the magnitude of the interfacial tension, is a miscible zone (interfacial tension < 0.001 mN / m), a near-miscible zone (interfacial tension 0.001–0.05 mN / m), or an immiscible zone (interfacial tension > 0.05 mN / m). The composition and properties of the crude oil change significantly in this region. Figure 1 This is a schematic diagram illustrating the division of formation fluid facies zones. It is worth noting that... Figure 1 The diagram only shows the inter-well fluid facies distribution of a certain oil reservoir at an injection rate of 0.2 PV. The actual formation fluid facies distribution is dynamic and varies with different injection rates.

[0082] 5. Start-up pressure calculation

[0083] (1) Using formation cores and different phase zone fluids, start-up pressure gradient tests were conducted to obtain the start-up pressure gradients of different phase zones;

[0084] (2) Based on the distribution of phase zones between wells, the starting pressure is calculated according to formula (1), which provides a basis for the formulation and adjustment of injection and production system and the prediction of recovery rate.

[0085] ΔP=G o ×L o +G F×L F +G IM ×L IM +G NM ×L NM +G M ×L M (1)

[0086] Where ΔP is the starting pressure, MPa; G o G F G IM G NM G M The starting pressure gradients for the original oil phase zone, leading edge zone, immiscible zone, near-miscible zone, and miscible zone are respectively, in MPa / m; L o L F L IM L NM L M The lengths, in meters, are the original oil phase zone, the leading edge zone, the immiscible zone, the near-miscible zone, and the miscible zone, respectively.

[0087] 6. Calculate the concentration of carbonized water.

[0088] Based on the temperature and pressure of the target reservoir, the amount of CO2 dissolved in the water, i.e. the concentration of carbonized water, is calculated. Based on the calculation results, the gas-liquid ratio for preparing carbonized water is determined.

[0089] 7. Preparation of carbonized water

[0090] Based on the calculated gas-liquid ratio, a carbonized water and enhanced CO2 microbubble preparation system was used ( Figure 2 Simultaneously, water and CO2 are injected, and the generated CO2 microbubbles enter the storage tank until it is full. Then, the rotary motor switch is turned on, and the rotary motor drives the blades to rotate, generating shear force to accelerate the collapse of CO2 microbubbles. The rotation continues until all the CO2 is dissolved in the water.

[0091] The results of the carbonized water and enhanced CO2 microbubble preparation system are as follows:

[0092] An input pipe is connected to the bottom of the side wall of storage tank 5, which is connected to carbon dioxide input pipe 1 and water input pipe (not shown in the figure). An output pipe 11 is connected to the upper part of the side wall of storage tank 5, and the output pipe 11 is connected to a carbon dioxide input bypass 8. Valves 2 (15, 12 and 10) and filter plates 3 (14, 13 and 9) are provided on carbon dioxide input pipe 1, water input pipe connection, output pipe 11 and carbon dioxide input bypass 8. A paddle 7 is provided on the top of storage tank 5, which is controlled by motor 6, and a piston 4 is provided on the bottom of storage tank 5.

[0093] 8. Enhanced CO2 microbubble propulsion

[0094] TowardsFigure 2 In the apparatus shown, carbonated water and CO2 are injected simultaneously, typically at a gas-liquid ratio of 1:1. Both are filtered, and the dispersed CO2 gas particles are distributed in the carbonated water, resulting in enhanced CO2 microbubbles, which are then injected into the formation. Figure 3 A schematic diagram illustrating the enhancement of CO2 microbubbles.

[0095] Taking a certain offshore oil reservoir as an example, the reservoir is buried at a depth of about 3300m, with an average porosity of 9.7% and a permeability of 17mD, to illustrate the method of the present invention:

[0096] (1) Obtain the composition and properties of well fluids in the reservoir by sampling. Based on the composition and properties of the well fluids ( Figure 4 , Figure 5 (Tables 1 and 2), compounded formation crude oil and formation water.

[0097] Table 1. Crude Oil Properties in the Formation

[0098] Saturation pressure P b (137.65 °C) 10.36 MPa Formation oil density at saturation pressure (137.65°C) 0.6600 g / cm 3 ]]

[0099] Table 2 Formation water composition

[0100]

[0101]

[0102] (2) By conducting multi-point long core displacement experiments and taking multiple samples, fluids at different core locations with different injection volumes were obtained.

[0103] (3) Determine the fluid composition and properties, and in conjunction with interfacial tension measurement, obtain the fluid composition and properties of different phase zones according to the definition of phase zones. Figure 6 Table 3 shows the compounding of fluids from different facies zones.

[0104] Table 3 Fluid properties of each phase zone

[0105]

[0106] (4) The starting pressure gradients of different phase bands were obtained by testing (Table 4).

[0107] Table 4 Pressure Start-up Gradients in Different Phase Zones

[0108]

[0109] (5) Based on the actual formation fluid composition, the pseudo-components were divided and adjusted multiple times until the total error between the density, viscosity, saturation pressure, and gas-oil ratio of the pseudo-components and the actual crude oil was less than 5%. The comparison between the division results and the actual values ​​is shown in Table 5. The actual geological model was imported into numerical simulation software. Using the divided pseudo-components, the injection and production regime consistent with the field was set, and numerical simulation was performed to determine the formation facies distribution. Based on the composition of the well fluids, the fluid facies zone at the production well was determined. According to the simulation results, after 6 years of gas drive development, the effective component front had migrated to the production well. After 8 years of gas drive development, the gas-oil ratio results showed that gas channeling had occurred (gas-oil ratio higher than 1500). Gas channeling control measures were taken in two scenarios (Scenario 1: gas channeling followed by water-gas alternation; Scenario 2: effective component front migrated to the production well followed by water-gas alternation), and the final recovery rate results were compared. Figure 7 As shown, taking measures to control gas channeling when the component migrates to the production well is more conducive to improving the recovery rate.

[0110] Table 5. Formation crude oil properties after component fitting.

[0111]

[0112] (6) Through numerical simulation, the reservoir fluid phase distribution at different development times is obtained, and the start-up pressure at different times is further calculated (Table 6). During on-site development, the change of start-up pressure should be considered, the production system should be adjusted, and the production pressure difference should be controlled.

[0113] Table 6. Starting pressure corresponding to different phase band widths under different gas injection rates.

[0114]

[0115] Enhanced CO2 microbubbles refer to the dispersion of CO2 microbubbles in a carbonized water system, such as... Figure 8 As shown, in water flooding followed by CO2 flooding, due to the water lock effect, a water film forms on the surface of the crude oil. CO2 needs to "pass through" this water film to contact the crude oil, hindering the interaction between CO2 and crude oil. However, in enhanced CO2 microbubble flooding, CO2 microbubbles are dispersed in the carbonated water system. The carbonated water and the water film are "miscible," causing the water film to dissolve and making it easier for CO2 to contact the crude oil, thus breaking the water lock effect. Figure 9 ).

[0116] CO2 microbubble flooding followed by water flooding and enhanced CO2 microbubble flooding followed by water flooding were conducted separately. The peak drag coefficients of both were obtained using the drag coefficient calculation formula. The experimental results show that the peak drag coefficients of CO2 microbubble flooding and enhanced CO2 microbubble flooding are 3.6 and 1.95, respectively, indicating that enhanced CO2 microbubble flooding has better dynamic stability.

[0117]

[0118] Where, ΔP 气泡驱 ΔP represents the pressure difference in the core before and after microbubble injection. 水驱 This represents the pressure difference before and after water injection into the core sample.

[0119] Core displacement experiments were conducted to investigate the plugging performance and oil displacement effects of CO2 microbubbles and enhanced CO2 microbubbles, comparing the gas breakthrough timing and recovery rate during the oil displacement process. The results are shown in Table 7. CO2 microbubbles broke through at an injection level of 0.48 PV, achieving a recovery rate of 48.2% at 1.2 PV. Enhanced CO2 microbubbles broke through at 0.56 PV, ultimately achieving a recovery rate of 54.8%. The later breakthrough time and higher recovery rate of enhanced CO2 microbubbles indicate better plugging performance and better oil displacement effect.

[0120] Table 7 Comparison of oil displacement effects of CO2 microbubbles and enhanced CO2 microbubbles

[0121]

[0122]

Claims

1. A method for delineating formation fluid facies zones in oil reservoir gas injection development, comprising the following steps: S1, Formation fluid mixture Formation active oil is prepared by using formation crude oil and associated gas, and formation water is prepared by using distilled water and corresponding salts; S2. Acquisition of fluid components in different phase zones S2-1. Saturate the combined core with the formation water, then use the formation active oil to displace it, establish the bound water saturation and saturate the formation active oil, and age it under formation temperature and pressure conditions. The composite cores are prepared in the following manner: after cutting, washing oil, and drying, the formation cores are combined in a blending and averaging manner, and filter paper is used to connect the different cores. S2-2. Under the condition of constant back pressure of the combined core, CO2 is injected; at different injection volumes, the fluid at different measuring points of the combined core is obtained, and the pressure at each measuring point is recorded. S3. Determination of the composition and properties of phase fluids S3-1. Measure the gas-oil ratio, degassed crude oil and gas composition of the fluid at different measuring points, and compound the fluid according to the measured data, and measure the density, viscosity and gas-oil ratio of the compound fluid. S3-2. At reservoir temperature, measure the interfacial tension of the formation active oil-CO2 interface at the pressure at the corresponding measuring point. Combined with the definition of each phase zone, determine the composition and properties of the fluids in different phase zones based on the interfacial tension and the composition, density, viscosity and gas-oil ratio of the compound fluid. S4. Phase zone distribution determination and gas channeling assessment S4-1, Pseudo-component division Based on the actual formation fluid composition, pseudo-components are defined; S4-2, Numerical Simulation The actual geological model is imported into numerical simulation software. Using the pseudo-components, an injection-production regime consistent with the field is set up to conduct numerical simulation. The gas saturation, crude oil viscosity, interfacial tension, and CO2 mole fraction of the well-to-well connection are output. Combined with the definition of each phase zone, the distribution of the phase zones between wells is determined.

2. The division method according to claim 1, characterized in that: In step S1, samples are taken from the production well fluid to determine the gas-oil ratio, degassed crude oil components, associated gas components, formation water salinity, and the content of each ion, and then the formation active oil and formation water are prepared.

3. The division method according to claim 1 or 2, characterized in that: In step S2-2, the aging time is 3 to 7 days; In step S2-2, the CO2 injection rate is determined based on the on-site CO2 transport linear velocity; Samples were taken at injection volumes of 0.2 PV, 0.4 PV, 0.6 PV, and 0.8 PV.

4. The division method according to claim 1 or 2, characterized in that: In step S4-1, the total error between the density, viscosity, saturation pressure, and gas-oil ratio of the simulated component and the actual crude oil is less than 5%. In step S4-2, the results of the numerical simulation shall meet the following requirements: The overall error in fitting production data and the composition, gas-oil ratio, density, viscosity, and saturation pressure of the production well fluid is less than 5%.

5. A method for identifying and warning of gas channeling in low-permeability reservoirs, comprising the following steps: SⅠ. Determine the fluid facies zone of the reservoir for gas injection development using the partitioning method according to any one of claims 1-4; SⅡ: Compare the composition, density, viscosity, gas-oil ratio and saturation pressure of the fluid in each phase zone determined in step SⅠ to determine the formation fluid phase zone at the production well and determine whether gas channeling has occurred; based on the numerical simulation results of step S4-2, predict the timing of gas channeling and realize gas channeling early warning.

6. A method for determining the starting pressure at different development stages in a gas injection development formation of an oil reservoir, comprising the following steps: SA, the method of dividing the reservoir for gas injection development formation fluid facies zone according to any one of claims 1-4; SB, combined with formation fluids from different phase zones, conducted start-up pressure gradient tests to obtain the start-up pressure gradients of different phase zones; Based on the SC and the inter-well facies distribution, the starting pressure is calculated according to formula (1), which provides a basis for the formulation and adjustment of the injection-production system and the prediction of the recovery rate. （1）； in, Start-up pressure, MPa; , , , , The starting pressure gradients, in MPa / m, are for the original oil phase zone, the leading edge zone, the immiscible zone, the near-miscible zone, and the miscible zone, respectively. , , , , The lengths, in meters, are the original oil phase zone, the leading edge zone, the immiscible zone, the near-miscible zone, and the miscible zone, respectively.

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