A method for enhancing oil recovery in horizontal wells with multi-stage combined synergy throughout the whole process based on dynamic monitoring

Abstract

The present invention discloses a method for improving oil recovery in a whole-process multi-stage combined enhanced horizontal well based on dynamic monitoring. The method comprises the following steps: S1, injecting an adsorption reducer into the formation and then performing water flooding; S2, during the water flooding process, determining whether to inject a profile modifier according to whether there is a channeling path between the injection well and the production well; S3, after the water flooding is completed, injecting a main displacing agent for chemical flooding; S4, during the chemical flooding process, determining whether to inject an injection enhancer according to the injection pressure and the apparent water absorption index of the injection well, so as to achieve the purpose of improving oil recovery. The method of the present invention can perform dynamic real-time adjustment during the chemical flooding process to achieve "optimal injection and optimal production", ensure the long-term and high efficiency of the whole process of chemical flooding, and effectively improve the utilization rate of the chemical agent and the economic benefit, and is recommended to be popularized and applied in horizontal wells in the medium-high water cut period.

Description

Technical Field

[0001] The invention relates to a method for improving the recovery rate of a horizontal well by a full-process multi-stage combination joint efficiency enhancement method based on dynamic monitoring, and belongs to the technical field of chemical flooding. Background Art

[0002] Chemical flooding technology has been tested in several oil fields in Bohai Sea for nearly 20 years since 2003, achieving significant effects of reducing water and increasing oil production. The success of the field test proves the technical reliability and economic effectiveness of chemical flooding in offshore oil fields. In conventional chemical flooding, a single type of agent system is often used throughout the injection cycle. During the injection process, the injection capacity usually decreases year by year and the oil production effect deteriorates year by year. The main reason is that the use of a single system as a displacement medium is prone to profile reversal in the middle and late stages of injection, causing the injected solution to advance along the high permeability layer. Once the crossflow channel is formed, the water content will rise rapidly, resulting in poor chemical flooding effect and a short effective period.

[0003] The chemical flooding that has been implemented is mainly directional wells, and horizontal wells in Bohai Oilfield account for about 40%. The chemical flooding potential of horizontal wells is huge. Compared with directional wells, the seepage pattern of horizontal wells has changed, transforming the multi-layer radial flow into a composite seepage of linear flow and elliptical flow. In addition, horizontal wells are mainly used in single sand layer reservoirs with relatively thin thickness. The contradiction between layers is transformed into contradiction within the layer, and the reservoir physical properties along the horizontal section are highly heterogeneous. The study found that due to the influence of factors such as the heel-toe effect of horizontal wells, thin reservoirs, and strong heterogeneity along the horizontal section, the injection and production profiles of horizontal wells are usually difficult to advance in a sustained and balanced manner. Conventional chemical flooding of horizontal wells is more likely to have a rapid return of water and a rapid decline in oil production than directional wells. At present, the combination of chemical flooding and horizontal wells at home and abroad is still in the exploratory stage, and there are few indoor research and mine application cases. Summary of the invention

[0004] The purpose of the present invention is to provide a method for improving the recovery rate of horizontal wells by combining multi-stage combination and efficiency enhancement based on dynamic monitoring. The method is based on the dynamic monitoring method to identify the underground seepage direction and the size of the dominant seepage channel before and during the implementation of chemical flooding, and select a suitable injection system according to the dynamic monitoring results. Different systems are injected into different reservoir positions and play corresponding roles. The efficient and high-speed development of the oil field is achieved through the combined injection of multiple injection systems. The method and its injection system can not only improve the injection capacity of the injection well, but also improve the recovery rate of the oil field, and can reduce the operating cost of chemical flooding and improve the economic benefits of chemical flooding.

[0005] The method for improving the recovery rate of a horizontal well by combining multiple stages of combined efficiency enhancement based on dynamic monitoring provided by the present invention comprises the following steps:

[0006] S1, inject desorbent into the formation, and then carry out water flooding;

[0007] S2. During the water flooding process, determine whether to inject a profile modifier based on whether there is a channeling path between the injection well and the production well to ensure the uniform advancement of the displacement front of the main displacing agent injected subsequently.

[0008] Among them, when there is such a channeling path, inject the profile modifier; when there is no such channeling path, do not inject the profile modifier.

[0009] S3. After the water flooding is completed, inject the main displacing agent for chemical flooding.

[0010] S4. During the chemical flooding process, determine whether to inject an injection enhancer based on the injection pressure and apparent water absorption index of the injection well, so as to achieve the purpose of improving the recovery factor.

[0011] In the above method, in step S1, by injecting the adsorption reducer, the adsorption amount of the agent injected later in the near-wellbore zone is reduced, so as to achieve the purpose of improving the economy of the injected agent and ensuring the injection capacity.

[0012] The adsorption reducer is a type of agent that can compete with polymers for adsorption on reservoir minerals. By shielding the effective adsorption sites on the adsorption medium, the adsorption and retention amount of polymers are reduced, thereby reducing the polymer injection pressure to improve the economy of the injected agent and ensure the injection capacity. Its injection volume is calculated and determined according to the horizontal section length and the pretreatment radius.

[0013] The cost of the adsorption reducer is relatively low, and it has the ability of strong adsorption and changing the wettability of the rock surface. After injecting the adsorption reducer, the molecule can shield the effective adsorption sites on the adsorption medium and compete with the agent injected later for adsorption, thereby reducing the adsorption and retention amount of the subsequent agent in the near-wellbore zone, effectively reducing the loss of the subsequent agent and reducing the injection pressure. At the same time, the adsorption reducer can form a protective film on the rock surface, changing the wetting of the porous medium from water phase to oil phase, and the subsequent injected agent no longer interacts with the porous medium in the near-wellbore zone.

[0014] In the above method, in step S2, judge whether there is such a channeling path according to the following analysis and test results:

[0015] At least one of the well-to-well connectivity analysis result, tracer test result, pressure drop test result, and water absorption profile test result.

[0016] In the above method, in step S2, the profile modifier is a gel-type modifier or a dispersion-type modifier.

[0017] In the above method, the profile adjustment rate of the gel-type modifier is greater than 85%, and the profile is adjusted in the near-wellbore area from a macroscopic level. The profile adjustment rate of the gel-type modifier is calculated according to Equation (1):

[0018] D w =(k1 - k2) / k1×100% (1)

[0019] In the formula: D w represents the profile adjustment rate, %; k1 represents the initial aqueous phase permeability measured in the core displacement experiment, μm 2 ; k2 represents the aqueous phase permeability measured after injecting the gel-type modifier, μm 2 .

[0020] The dispersed modifier generally uses pre-crosslinked particles matching the formation pore throat size, which can migrate to the deep formation and realize the profile adjustment from a microscopic level. Generally, the profile adjustment rate is required to be greater than 60%. The matching relationship between the diameter of the dispersed modifier after swelling and the pore throat diameter is closely related to the profile adjustment rate. Considering the elasticity of the particles, the swelling performance and the loss of viscoelasticity under pressure, and combining with the self-stability of the particles, the optimal ratio of the diameter after swelling to the pore throat diameter is 1:1. The residual resistance coefficient reflects the ability of the particles to resist erosion and shear in the reservoir, as well as the ability to migrate deeper into the reservoir and change the liquid flow direction. The residual resistance coefficient is required to be greater than 3. The residual resistance coefficient is different for different concentrations of the dispersion system, and the reasonable injection concentration is optimized according to the residual resistance coefficient.

[0021] In the above method, in step S3, the main displacing agent is a chemical agent that increases the viscosity of the displacing phase, and it plays a role in expanding the swept volume by increasing the viscosity of the displacing phase. Generally, polymers such as polyacrylamide are used;

[0022] Based on the numerical simulation model of the target reservoir, a certain parameter value range is set, and the slug volume, injection concentration, and / or injection rate of the main displacing agent are optimized through the results of numerical simulation calculations with the comprehensive index as the evaluation standard;

[0023] Comprehensive index = enhanced oil recovery amplitude × cumulative incremental oil volume / dry powder consumption of the main displacing agent.

[0024] The main displacing agent has the largest slug volume applied throughout the implementation process of chemical flooding, and it mainly improves the oil recovery rate by expanding the swept volume. Generally, a polymer system is used. According to the reservoir temperature, permeability, and physical properties of crude oil, formation water, etc., the type and adsorption and other performance parameters of the polymer are determined based on indoor evaluation experiments.

[0025] In the above method, in step S4, compared with water flooding, the injection capacity decreases during the chemical flooding stage, and during the construction process, problems such as abnormal increase in injection pressure and failure to reach the injection allocation due to near-wellbore pollution, wellbore scaling, etc. sometimes occur, affecting the chemical flooding effect;

[0026] When the injection pressure rises by more than 3 MPa, the apparent water absorption index decreases by more than 20%, or the injection volume fails to reach the injection allocation, the injection enhancer is injected.

[0027] In the above method, in step S4, the injection enhancer is a polymer solution, compatible injection water or an acidic system. By injecting a small-volume slug of the injection enhancement system, the wellbore and the near-wellbore area are effectively treated to alleviate the problem of decreasing injection capacity;

[0028] The concentration of the polymer solution is usually less than the concentration of the main displacing agent solution;

[0029] The acidic system can be a hydrochloric acid solution, a hydrofluoric acid solution, etc.

[0030] In the above method, in step S4, during the chemical flooding process, the dynamic performance characteristics between the injection well and the production well are monitored. When the following phenomena occur, a system with a higher viscosity needs to be injected;

[0031] 1) The seepage resistance is less than 1.2 after 3 months of chemical flooding injection;

[0032] 2) The pressure index calculated by the pressure drop test is less than the block average value, and the degree of fullness is less than 65%;

[0033] 3) The relative water absorption of a single layer is greater than 60%;

[0034] 4) The concentration of the agent produced by the production well suddenly increases, or the concentration of the agent produced reaches 20% of the injection concentration;

[0035] 5) The monthly rising rate of the water cut is greater than 2%;

[0036] 6) The enhanced oil recovery effect is lower than 85% of the design of the plan.

[0037] In step S4, the system with a higher viscosity is a high-concentration main displacing agent or a weak gel system.

[0038] The method for improving the oil recovery rate of the present invention can dynamically adjust the injection system of the injection well throughout the chemical flooding process. The judgment indexes for adjustment are quantitatively characterized, and timely adjustment can be made according to the changes of each index. It has strong timeliness, can achieve one well, one strategy, achieve the purpose of fine chemical flooding, ensure the long-term and high efficiency of the whole chemical flooding process, and effectively improve the utilization rate of the agent and economic benefits. Description of the Drawings

[0039] Figure 1 It is a schematic diagram of the overall process of the method of the present invention.

[0040] Figure 2 It is a well location distribution map of the pilot test area in the specific implementation manner of the present invention.

[0041] Figure 3 It is the calculation result of the inter-well connectivity before chemical flooding in the pilot test area in the specific implementation manner of the present invention.

[0042] Figure 4 It is the injection dynamic change diagram of the multi-stage combined synergistic method in Well A3H in the specific implementation manner of the present invention.

[0043] Figure 5 It is the effect diagram of the implementation of the multi-stage combined synergistic method in the specific implementation manner of the present invention. Specific implementation manner

[0044] Unless otherwise specified, the experimental methods used in the following examples are all conventional methods.

[0045] Unless otherwise specified, the materials, reagents, etc. used in the following examples can all be obtained from commercial channels.

[0046] The adsorption reducer JX-1 used in the following examples is a quaternary ammonium salt surfactant CTAB, and JX-2 is a silane coupling agent. It is a chemical injection enhancement system disclosed in Chinese Patent Application No. 202011108146.X. Among them, the organosilicon sacrificial agent is triethoxyoctylsilane, and the auxiliary agent is a mixture of N-methyldiethanolamine and petroleum sulfonate. In the auxiliary agent, the mass percentage concentration of N-methyldiethanolamine is 90%, and the mass percentage concentration of petroleum sulfonate is 10%. The organosilicon sacrificial agent and the auxiliary agent are compounded according to a mass ratio of 70:30. The specific steps are as follows: First, prepare an aqueous solution of the auxiliary agent, in which the mass fraction of N-methyldiethanolamine is 9% and the mass fraction of petroleum sulfonate is 1%, and then add triethoxyoctylsilane to the above aqueous solution to obtain the chemical injection enhancement system.

[0047] The multi-stage combined synergistic effect is carried out on the A sand body of the Bohai B Oilfield by using the method of the present invention, and the process schematic diagram is as Figure 1 shown.

[0048] The well location map of the A sand body is as Figure 2 shown. There are a total of 7 wells in the area, including 3 injection wells and 4 production wells. The pilot test was started in January 2020. The specific steps are as follows:

[0049] 1) Screening and evaluation of adsorption reducers

[0050] Based on indoor static adsorption experiments, the adsorption reduction effects of two kinds of adsorption reducers, JX-1 and JX-2, were tested and compared. The results showed that after adding the adsorption reducers, the adsorption amount of the polymer (polyacrylamide) decreased significantly. Among them, JX-1 could reduce the polymer adsorption amount from 580 μg / g to 161 μg / g, a decrease of 72%, while the effect of JX-2 was more significant, which could reduce the polymer adsorption amount to 52 μg / g, a decrease of 91%.

[0051] Using a flat sand sandwich model, the injection pressure of the polymer in untreated quartz sand and quartz sand treated with JX-1 and JX-2 respectively was carried out.

[0052] After pretreatment with JX-1, the injection equilibrium pressure decreased by 11%; after treatment with JX-2, the injection equilibrium pressure decreased by 24%. Therefore, JX-2 adsorption reducer was selected and the injection concentration was further optimized.

[0053] Quartz sand was pretreated with JX-2 solutions of different concentrations, and the wettability of the surface of the adsorbed quartz sand was tested. The test results are shown in Table 1. It can be seen from Table 1 that as the concentration of JX-2 increases, the contact angle increases and basically stabilizes at 120° when the concentration is greater than 5%, that is, at this time the porous medium presents an oil-wet state. In order to ensure the adsorption effect of JX-2 on the surface of quartz sand, it is recommended that the concentration of JX-2 is not less than 5%.

[0054] Table 1 Influence of JX-2 solutions with different concentrations on the contact angle

[0055] Adsorbent concentration (%) 0.5 1％ 3％ 5％ 6％ 8％ Contact angle (°) 94 99 107 123 125 128

[0056] 2) Identification of pre-channeling channels before chemical flooding

[0057] The wellbore connectivity calculation method and the pressure drop test method were used to identify the flow direction between injection and production wells and the necessity of profile improvement. The results of the pressure drop test and wellbore connectivity analysis of wells A3H and A9H showed ( Figure 3 and Table 2) that both wells need to be injected with profile control agents first.

[0058] Table 2 Calculation results of pressure drop test

[0059] Well number Pressure coefficient (MPa) Degree of filling (%) A3H 3.3 55 A9H 5.6 51

[0060] Among them, the formulation of the gel system is: (2000 - 2500) mg / L polymer + 1800 mg / L crosslinking agent + 1800 mg / L co-crosslinking agent. The gelation time is 6 days, and the gelation viscosity is 4000 - 7000 mPa·s. Among them, the polymer is polyacrylamide, the crosslinking agent is phenol plus resorcinol, and the co-crosslinking agent is hexamethylenetetramine plus acetic acid. The dispersion system selects micron-sized pre-crosslinked particles (dry solid polymer gel substances, which are granular gels formed through complex chemical reactions of polymer monomers, crosslinking agents, initiators, etc. and then processed through drying, granulation, screening, etc. They can absorb water and swell, and the swollen particles have certain elasticity, strength, and water retention function. After bridging in formation pores and throats, they can change the flow direction of fluids in the formation). The following index parameters of the dispersion system are evaluated through laboratory experiments: the solid content is 30%, the initial particle size D50 is 7.5 μm, and the swelling multiple is 3.5 times.

[0061] The residual resistance coefficients at different concentrations are tested (Table 3). It can be seen from the table that the residual resistance coefficient increases with the increase of concentration and tends to be stable when it is greater than 0.3%. Therefore, the injection concentration of the dispersion system is optimized to 0.3%.

[0062] Table 3 Residual resistance coefficients corresponding to dispersion systems with different concentrations

[0063]

[0064] 3) Screening and evaluation of the main displacing agent

[0065] Based on the reservoir physical properties and fluid physical properties of Sand Body A, the main displacing agent used is screened and evaluated.

[0066] During the screening of the main slug agent, since the crude oil quality of Sand Body A is good and the formation water salinity is not high, the main displacing agent is recommended as a linear polymer based on comprehensive economic considerations. Ten polymer samples of this type are collected. First, their physical and chemical properties and solution properties are tested and evaluated, and then the agents with qualified solution properties are tested for reservoir adaptability.

[0067] Table 4 shows the test results of the 10 samples. It can be seen from the table that the apparent viscosity of PZ1 does not meet the standard, the static adsorption properties of PZ1, PZ9, and PZ10 are unqualified, and the viscosities of PZ1, PZ4, PZ8, PZ9, and PZ10 after 90 days of thermal stability do not meet the evaluation index (greater than 12 mPa·s). The reservoir adaptabilities of the five agents PZ2, PZ3, PZ5, PZ6, and PZ7 all meet the requirements. The fuzzy mathematics method is used to comprehensively score the five qualified agents, and the evaluation result is: PZ6 > PZ3 > PZ2 > PZ5 > PZ7.

[0068] In this embodiment, PZ1 - PZ10 are respectively 10 partially hydrolyzed polyacrylamide samples collected from the market.

[0069] Table 4 Evaluation results of performance parameters of 10 samples

[0070]

[0071] 4) Optimization of injection parameters of the main displacing agent

[0072] Using numerical simulation software, on the basis of historical matching of the numerical simulation model of the water flooding stage of Sand Body A in Oilfield B, the discontinuous chemical flooding reservoir scheme is optimized and designed. Taking the comprehensive index as the evaluation standard, based on the results of numerical simulation calculations, the slug volume, injection concentration and / or injection rate of the main displacing agent corresponding to the maximum comprehensive index or the inflection point when the comprehensive index is rising are the optimal values. Based on the calculation results of the injection parameter optimization, it is recommended that the injection rate be 0.07 PV / a, the cumulative injection slug volume be 0.49 PV, and the injection concentration be 1250 mg / L.

[0073] 5) Injection capacity evaluation and injection improvement

[0074] During the implementation process, the injection volume, injection pressure and apparent water absorption index are calculated and analyzed. When the injection pressure rises by more than 3 MPa, the apparent water absorption index drops by more than 20%, or the injection volume fails to reach the allocated injection volume, the corresponding system is injected according to the plugging reason. Well A3H had a reduced injection volume around November 2021 and could not reach the allocated injection volume, so it was switched to inject a water slug to scour the wellbore, and the subsequent injection volume recovered. The injection dynamics are as shown in the attached Figure 4 figure (the upper curve represents the wellhead pressure and the lower curve represents the injection volume).

[0075] 6) Dynamic monitoring between injection and production wells during the chemical flooding stage

[0076] During the injection process, the injection dynamics of the injection wells are continuously monitored. In April 2021, an upward trend in the produced agent concentration was detected in production well A4H. Therefore, the viscosity of the injection system of injection well A3H was promptly adjusted, and a weak gel system was selected. After laboratory experiment evaluation, the formula is: (1500 - 1800) mg / L polymer + 1500 mg / L crosslinking agent + 1500 mg / L co - crosslinking agent.

[0077] After using the method of the present invention, obvious effects of reducing water cut and increasing oil production have been achieved in the pilot test area. The production dynamic curve of Sand Body A is as shown in Figure 5 the figure, the peak daily oil increment is 95 m 3 / d, the increase rate is 56%, the water cut drops by 10%. After 2 years and 6 months of chemical flooding implementation, compared with the basic water flooding, the cumulative increased oil production has reached 66,000 cubic meters, and the increased oil production accounts for 41% of the total production in this stage.

Claims

1. A method for enhancing oil recovery in a multistage combined horizontal well with dynamic monitoring throughout the process, comprising the following steps: S1. Inject an adsorption reducer into the formation and then perform water flooding; S2. During the water flooding process, determine whether to inject a profile modifier based on whether there is a channeling path between the injection well and the production well, where When there is such a channeling channel, inject the profile modifier; when there is no such channeling channel, do not inject the profile modifier; Judge whether there is such a channeling channel according to the following analysis and test results: At least one of the results of inter-well connectivity analysis, tracer test, pressure drop test, and water absorption profile test; The profile modifier is a gel-type modifier or a dispersion-type modifier; The profile adjustment rate of the gel-type modifier is greater than 85%. Calculate the profile adjustment rate of the gel-type modifier according to Equation (1): （1） where: D w represents the profile adjustment rate, %; k1 represents the initial aqueous permeability measured in the core displacement experiment, μm 2 ; k2 represents the aqueous permeability measured after injecting the gel-type modifier, μm 2 ; The profile adjustment rate of the dispersion-type modifier is greater than 60%; S3. After the water flooding is completed, inject the main displacing agent for chemical flooding; The main displacing agent is a polyacrylamide polymer; Based on the numerical simulation model of the target reservoir, set the parameter value range, and take the comprehensive index as the evaluation standard to optimize the slug volume, injection concentration, and / or injection rate of the main displacing agent through the results of numerical simulation calculation; Comprehensive index = increase in oil recovery rate × cumulative incremental oil volume / dry powder consumption of the main displacing agent; S4. During the chemical flooding process, determine whether to inject an injection enhancer according to the injection pressure and apparent water absorption index of the injection well, so as to achieve the purpose of increasing oil recovery.

2. The method according to claim 1, wherein: In step S4, when the increase in the injection pressure is greater than 3 MPa, the decrease in the apparent water absorption index is greater than 20%, or the injection volume fails to reach the allocated injection volume, then inject the injection enhancer.

3. The method according to claim 1 or 2, wherein: In step S4, the injection enhancer is a polymer solution, compatible injection water, or an acidic system; The concentration of the polymer solution is lower than the concentration of the main displacing agent solution.

4. The method according to claim 1 or 2, wherein: In step S4, during the chemical flooding process, monitor the dynamic performance characteristics between the injection well and the production well. When any of the following phenomena occurs, a system with a higher viscosity needs to be injected; 1) The pressure index calculated by the pressure drop test is less than the block average value, and the fullness is less than 65%; 2) The relative water absorption of a single layer is greater than 60%; 3) The produced agent concentration of the production well suddenly increases, or the produced agent concentration reaches 20% of the injection concentration; 4) The monthly increase rate of the water cut is greater than 2%; 5) The oil-increasing effect is lower than 85% of the project design.

5. The method according to claim 4, wherein: In step S4, the system with a higher viscosity is a high-concentration main displacing agent or a weak gel system.

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