Method for improving oil and gas recovery ratio through PEG and acidification plug removal

Abstract

The invention discloses a method for improving oil and gas recovery efficiency through PEG and acidification plug removal, and belongs to the technical field of oil and gas field development. The method for improving the oil and gas recovery ratio through PEG + acidification plug removal comprises the steps that after oil and gas recovery is conducted on an oil field, acid liquor is injected from an injection end for acidification plug removal, currently prepared aqueous dispersion containing PEG gel particles with the molecular weight of 800-1000 is injected from a recovery section, and after the PEG gel particles expand to the maximum, water is injected from the injection end for oil and gas recovery. According to the method disclosed by the invention, the research on improving the oil and gas recovery efficiency by using the PEG + acidification blockage removal composite method is developed by using the manufactured rock core blockage models with different permeability levels, and the feasibility of improving the oil and gas recovery efficiency by using the PEG + acidification blockage removal composite method is verified by taking the pressure, permeability, split flow rate, recovery degree effect and the like as comprehensive evaluation indexes.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas field development, and particularly relates to a method for improving oil and gas recovery rate by removing plugging with PEG+acidification. Background Art

[0002] Domestic and foreign studies have shown that as the mining time increases, oil fields face a series of problems such as reduced permeability and wellbore blockage. These problems have led to obstructed oil and gas flow and a significant decrease in recovery rate, posing challenges to the economic benefits of oil fields. Although traditional acidizing treatment methods can effectively improve the fluidity of oil wells, they often have an adverse effect on rock structure and are prone to rock fracture and collapse. Relying solely on acid for treatment may also lead to secondary pollution and increase environmental risks. With the deepening of development, the mineralization of formation water is affected by changes in temperature, pressure, pH environment and incompatibility of injected water. The near-wellbore area of ​​the oil well is prone to scaling and blockage, resulting in reduced production and affecting development efficiency. Although traditional acidizing deblocking methods can effectively remove formation blockages, they have problems such as a single deblocking object, severe corrosion to equipment, and a short effective period for deblocking.

[0003] The disadvantage of the existing technology is that the conventional plugging removal measures are mainly hydrochloric acid, hydrofluoric acid, etc., and the problems are that the amount and strength of the injected acid are high, which increases the drainage time, and the dissolution ability is too strong, which destroys the integrity of the bottom rock of the well; the acid fluid's filtration and reaction speed determine its action distance; the low viscosity of the residual acid affects the backflow of acid insolubles; there is no pretreatment fluid, and generally no chromium compound is added. If the backflow is not timely, it is easy to cause secondary precipitation; the residual acid after the backflow is easy to cause environmental pollution; the large backflow pressure difference is easy to cause clay particles to migrate to the near-well area, and only a small part of it is achieved by adding organic acid (formic acid or acetic acid) to reduce corrosion and slow down deep acidification. Judging from the implementation of the plugging removal measures in recent years, with the deterioration of the material basis of the plugged well, the efficiency of the measures and the increase in oil production have both shown a downward trend. Summary of the invention

[0004] In order to overcome the shortcomings of the prior art, the present invention proposes a method for improving oil and gas recovery rate by using PEG+acidizing to remove plugging: (1) Expanding the scope of objects to be removed: The PEG+acidizing method can remove various types of plugging substances, including calcium carbonate scale, sulfate scale, long carbon chain organic matter, etc. (2) Improving the efficiency of unblocking: The thickening and stabilizing effects of PEG help to slow down the reaction rate of the acid solution and prolong the reaction time, thereby improving the efficiency of unblocking. (3) Prolonging the effective period of unblocking: The addition of PEG can improve the fluidity of the unblocking liquid in the formation, allowing the unblocking liquid to better penetrate into the formation, thereby prolonging the effective period of unblocking. (4) Reducing corrosion to equipment: The addition of corrosion inhibitors can significantly reduce the corrosion of the acid solution to the equipment and extend the service life of the equipment. (5) Improving oil and gas recovery rate: By removing formation blockage and restoring formation permeability, the method provided by the present invention can significantly improve the oil and gas recovery rate.

[0005] To achieve the above object, the present invention provides the following technical solutions:

[0006] One of the technical solutions of the present invention is to provide a method for improving oil and gas recovery by removing plugging with PEG+acidification, comprising the following steps:

[0007] After oil and gas are recovered from the oil field, acid is injected from the injection end to dissolve the blockage, and a freshly prepared aqueous dispersion of PEG gel particles with a molecular weight of 800-1000 is injected from the production section. After the PEG gel particles expand to their maximum, water is injected from the injection end to recover oil and gas.

[0008] The present invention adopts PEG+acidification to remove blockage and improve oil and gas recovery rate, wherein PEG particles absorb water and swell, have certain elasticity, strength and water retention performance, are resistant to high temperature and high salt and have good injection performance, can enter high permeability zones to bridge and seal, and force the acid solution to turn to enter the blocked area to play a role in removing blockage.

[0009] Preferably, the acid solution is an aqueous solution containing HCl, HF and acetic acid.

[0010] The investigation found that calcium carbonate and magnesium carbonate are the main blockages in the near-well area, and the main reason is the incompatibility between the injected water and the formation water.

[0011] The mechanism of blockage formation is as follows:

[0012] Ca 2+ +CO 3 2- →CaCO 3 ↓

[0013] Mg 2+ +CO 3 2- →MgCO 3 ↓

[0014] Ca2+ +2HCO 3 - →CaCO 3 ↓+CO 2 ↑+H 2 O

[0015] Mg 2+ +2HCO 3 - →MgCO 3 ↓+CO 2 ↑+H 2 O;

[0016] The mechanism of acidizing system plugging removal is as follows:

[0017] SiO 2 +4HF→SiF 4 +2H 2 O

[0018] CaCO 3 +2HCl→CaCl 2 +CO 2 +H 2 O

[0019] CaCO 3 +2CH 3 COOH→(CH 3 COO 2 Ca+H 2 O+CO 2

[0020] MgCO 3 +2HCl→MgCl 2 +CO 2 +H 2 O

[0021] MgCO 3 +2CH 3 COOH→(CH 3 COO 2 Mg+H 2 O+CO 2 ;

[0022] The acid concentration depends on the composition of the rock formation at the site.

[0023] The second technical solution of the present invention is to provide an application of the above-mentioned PEG+acidification plugging removal method for improving oil and gas recovery in oil and gas recovery.

[0024] The beneficial technical effects of the present invention are as follows:

[0025] According to reservoir physical properties, the present invention designs and manufactures PEG core plugging models with different permeability differences, studies the plugging performance of PEG, and clarifies key technical policies such as PEG injection concentration and injection volume.

[0026] The present invention uses a manufactured microscopic visualized heterogeneous porous medium plugging model to reveal the synergistic interaction mechanism of the PEG+acidification system in the heterogeneous porous medium.

[0027] The present invention uses the core plugging model with different permeability differences to carry out research on improving oil and gas recovery by using the PEG+acid plugging removal composite method, and uses pressure, permeability, diversion rate, recovery effect, etc. as comprehensive evaluation indicators to verify the feasibility of using the PEG+acid plugging removal composite method to improve oil and gas recovery in oil fields. The present invention uses microscopic visualization experiments to show that PEG particles can aggregate and swell in high-permeability channels, increase the seepage resistance of high-permeability channels, force secondary injection water to enter low-permeability areas, start the residual oil in low-permeability areas, and significantly improve the recovery degree after PEG particle plugging. BRIEF DESCRIPTION OF THE DRAWINGS

[0028] Figure 1 The expansion of PEG particles dispersed in clear water in Example 1, wherein (a) is the SEM image at the initial stage, (b) is the SEM image after 2 hours, and (c) is the SEM image after 4 hours.

[0029] Figure 2 The expansion of PEG particles dispersed in the formation water of the Wangyao operating area in Example 1, wherein (a) is the SEM image at the initial time, (b) is the SEM image after 2 hours, and (c) is the SEM image after 4 hours.

[0030] Figure 3 This is a diagram showing the effect of different concentrations of HCl aqueous solution dissolving rock cuttings in Example 2.

[0031] Figure 4 This is a diagram showing the effect of different concentrations of HF aqueous solution dissolving rock cuttings in Example 2.

[0032] Figure 5 This is a diagram showing the effect of different concentrations of acetic acid aqueous solution dissolving rock cuttings in Example 2.

[0033] Figure 6 This is a diagram showing the effect of dissolving rock cuttings by the composite acidification system of 11wt% HCl+4wt% HF+6wt% acetic acid in Example 3.

[0034] Figure 7 This is a SEM image of the surface of the rock cuttings before dissolution in Example 3.

[0035] Figure 8These are SEM images of the surface of rock fragments during the dissolution process of Example 3, wherein (a) is the SEM image after 15 minutes of dissolution, and (b) is the SEM image after 30 minutes of dissolution.

[0036] Fig. 9 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.3wt% and the depth is 1 / 10 of the core length.

[0037] Fig.10 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.3wt% and the depth is 1 / 8 of the core length.

[0038] Fig.11 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.3wt% and the depth is 1 / 6 of the core length.

[0039] Fig.12 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.3wt% and the depth is 1 / 5 of the core length.

[0040] Fig.13 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.6wt% and the depth is 1 / 15 of the core length.

[0041] Fig.14 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.6wt% and the depth is 1 / 10 of the core length.

[0042] Fig.15 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.6wt% and the depth is 1 / 8 of the core length.

[0043] Fig.16 This is the production dynamic curve when the PEG particle concentration in Example 4 is 0.6wt% and the depth is 1 / 6 of the core length.

[0044] Fig.17 The recovery degree after PEG particle plugging at different depths when the PEG particle concentration in Example 4 is 0.3wt%, 0.4wt%, 0.5wt% and 0.6wt%.

[0045] Fig.18 The blocking rates of PEG particles at different depths when the PEG particle concentrations in Example 4 are 0.3wt%, 0.4wt%, 0.5wt% and 0.6wt%.

[0046] Fig.19 It is a high and low osmotic rhythm heterogeneous model.

[0047] Fig. 20 Schematic diagram of PEG particle blocking in the high and low osmotic rhythm heterogeneous model. DETAILED DESCRIPTION

[0048] Now, various exemplary embodiments of the present invention are described in detail, and this detailed description should not be considered as a limitation of the present invention, but should be understood as a more detailed description of certain aspects, characteristics and embodiments of the present invention. It should be understood that the terms described in the present invention are only for describing specific embodiments and are not used to limit the present invention.

[0049] In addition, for the numerical range in the present invention, it is understood that each intermediate value between the upper and lower limits of the range is also specifically disclosed. The intermediate value in any stated value or stated range, and each smaller range between any other stated value or intermediate value in the range is also included in the present invention. The upper and lower limits of these smaller ranges can be independently included or excluded in the scope.

[0050] Unless otherwise specified, all technical and scientific terms used herein have the same meaning as commonly understood by those skilled in the art to which the invention pertains. Although only preferred methods and materials are described herein, any methods and materials similar or equivalent to those described herein may also be used in the practice or testing of the present invention.

[0051] The words “include,” “including,” “have,” “contain,” etc. used in this document are open-ended terms, meaning including but not limited to.

[0052] The PEG particles used in the embodiments of the present invention are PEG gel particles with a molecular weight of 1000.

[0053] The rock cuttings used in the embodiments of the present invention were taken from the Wangyao operating area of ​​Ansai Oilfield.

[0054] Example 1

[0055] Observe the expansion of water-dispersible PEG particles:

[0056] Clean water and formation water were used to disperse PEG particles (the proportion of PEG gel particles was 3 wt %), and the expansion of PEG particles was observed just after preparation, 2 h after preparation, and 4 h after preparation.

[0057] The formation water used in this example is the formation water from the Wangyao operation area, with a mineralization of 53697 mg / L (CO 3 2- 0. HCO 3 - 108mg / L, Cl - 33797mg / L, SO 4 2- 0.Ba 2+ 0. Ca 2+ 12706mg / L, Mg2+ 336mg / L, K + +Na + 6750mg / L).

[0058] The swelling of PEG particles dispersed in water is shown in Figure 1 , where (a) is the initial SEM image, (b) is the SEM image after 2 hours, and (c) is the SEM image after 4 hours; the expansion of PEG particles dispersed in formation water in the Wangyao operation area is shown in Figure 2 , where (a) is the SEM image at the initial stage, (b) is the SEM image after 2 h, and (c) is the SEM image after 4 h.

[0059] from Figure 1 and Figure 2 It can be seen that when PEG particles are dispersed with clean water, at the beginning of the observation, the PEG particles are in a state where they have not yet expanded. They are evenly dispersed in clean water without forming aggregations or lumps, showing good dispersibility and stability. As time goes by, after 2 hours of observation, the PEG particles gradually show signs of expansion and the size begins to change significantly, showing a certain degree of increase compared to the initial state. After 4 hours of observation, the PEG particles reach the maximum expansion. At this time, their size no longer changes significantly, showing a stable expansion state. This state is then maintained, and the expansion multiple does not change in the following time. In addition, by averaging the size of the PEG particles, the average size is about 30μm. When PEG particles are dispersed with formation water from the Wangyao operating area, the PEG particles do not expand significantly at the beginning, and the expanded PEG particles are almost not observed under a microscope, but the dispersibility is good under the mineralization of Wangyao water. After 2 hours, the PEG particles are observed to begin to expand under a microscope, and the size of the PEG particles has changed significantly compared to the initial state. After 4 hours, the PEG particles expand to the maximum, and the expansion multiple does not change in the following time. The average size of the PEG particles observed by microscope is 25μm.

[0060] The above experimental results show that PEG particles have a certain size and morphological stability, and their expansion process has a certain predictability and regularity, which further reveals the complexity of the surface structure of PEG particles, as well as their stability and plasticity in aqueous solution.

[0061] Example 2

[0062] Optimization of acid solution for plugging removal:

[0063] Different concentrations of HCl aqueous solution, HF aqueous solution and acetic acid aqueous solution were used to dissolve the cuttings for 120 minutes. The relationship between the cuttings dissolution rate and the acid concentration was observed, and the concentration and dissolution rate were balanced to obtain the best deblocking acid.

[0064] The effect of different concentrations of HCl aqueous solution on the dissolution of rock cuttings is shown in the figure. Figure 3 ; The effect of different concentrations of HF aqueous solution on the dissolution of rock cuttings is shown in Figure 4 ; The effect of different concentrations of acetic acid aqueous solution on the dissolution of rock cuttings is shown in Figure 5 . Figure 3 to Figure 5 The percentage concentration of acid solution is mass percentage.

[0065] from Figure 3 to Figure 5 It can be seen that with the gradual increase of acid concentration, the dissolution rate and dissolution rate of HCl, HF and acetic acid on the cuttings all show an increasing trend. Compared with HCl and HF, the dissolution rate and dissolution rate of acetic acid increase more slowly. In the case of 11wt% HCl, the dissolution rate reached 26%, which is the optimal dissolution concentration; in the case of 4wt% HF, the dissolution rate reached 19%, which also reached the optimal dissolution concentration. In addition, even if the acid concentration is increased, the increase in the dissolution rate becomes relatively slow. The dissolution rate of 6wt% acetic acid is only 7.51%. Even if the acetic acid concentration is further increased, the increase in the dissolution rate and dissolution rate also shows a slow trend. Based on this, the composite acidification system with better dissolution effect is selected: 11wt% HCl+4wt% HF+6wt% acetic acid.

[0066] Example 3

[0067] Investigation on the optimal concentration of acid solution for plugging removal:

[0068] The composite acidizing system of 11wt% HCl+4wt% HF+6wt% acetic acid was used to dissolve the cuttings, and the relationship between the cuttings dissolution rate and time was observed to obtain the optimal deblocking time.

[0069] The effect of the composite acidizing system of 11wt% HCl+4wt% HF+6wt% acetic acid on the dissolution of rock cuttings is shown in the figure. Figure 6 . Figure 6 The results show that the maximum dissolution rate of the composite acidizing system of 11wt% HCl+4wt% HF+6wt% acetic acid can reach 36.4% for dissolving rock cuttings. When the dissolution time reaches 60min, the rate of increase in the dissolution rate gradually slows down, and the optimal deblocking time is 60min.

[0070] The SEM image of the surface of the cuttings before dissolution is shown in Figure 7 The SEM images of the cuttings surface during the dissolution process are shown in Figure 8 , where (a) is the SEM image after 15 min of dissolution, and (b) is the SEM image after 30 min of dissolution.

[0071] Figure 7 and Figure 8The results show that the surface of the cuttings before dissolution was smooth and flawless, with no obvious scratches or bumps. After acid dissolution, the surface of the cuttings showed significant scratches and a large number of uneven dissolution pits, presenting an irregular state. This shows that the acid has a high efficiency in dissolving the cuttings, and as the acid stays on the cuttings surface for an increased time, the dissolution becomes more intense, resulting in more dissolution pits.

[0072] Example 4

[0073] PEG particle dosage optimization plan in the laboratory:

[0074] Prepare 16 core samples of homogeneous rock with a permeability of 5mD, each core has a diameter of 2.5cm and a length of 30cm.

[0075] Using formation water from the Wangyao operating area as water for dispersing PEG particles, four different PEG particle concentrations were designed: 0.3wt%, 0.4wt%, 0.5wt% and 0.6wt%. For PEG particle dispersions with concentrations of 0.3wt% and 0.4wt%, different PEG particle depth settings were used, with four gradients of 1 / 10, 1 / 8, 1 / 6 and 1 / 5 of the entire core length. For PEG particle dispersions with concentrations of 0.5wt% and 0.6wt%, similar PEG particle depth settings were used, with four gradients of 1 / 15, 1 / 10, 1 / 8 and 1 / 6 of the entire core length.

[0076] The experimental steps of each group were as follows: (1) the core size was 2.5 cm in diameter and 30 cm in length; (2) vacuum was drawn, the core was saturated with clean water, and the pore volume of the core was calculated; (3) formation water was injected from the injection end at 0.1 mL / min, and the permeability was calculated based on the steady-state pressure; (4) crude oil was injected from the injection end at 0.1 mL / min, the oil drove the water, the core was saturated with crude oil, the oil saturation was calculated, and the core was aged at 50 °C for 7 days; (5) clean water was injected from the injection end at 0.1 mL / min, and a water drive was performed until the water content exceeded 98%. Complete a water drive; (6) Inject a composite acidification system of 11wt% HCl+4wt% HF+6wt% acetic acid from the injection end and dissolve for 1h; (7) Prepare PEG particle systems of different concentrations, and inject different amounts (according to the depth of PEG particles injected into the core) of PEG particle systems from the production end (the injection end is open during this process), then close the valves at both ends and let stand at 50°C for 2 hours; (8) Open the valves at both ends, inject clean water from the injection end for secondary water drive, and calculate the changes in pressure difference and production degree.

[0077] The production dynamic data of 0.3 wt% PEG particles blocking the hyperosmotic channel from the production end under different depth settings are shown in Table 1.

[0078] Table 1 Displacement effect at different plugging depths

[0079]

[0080] The production dynamic data of 0.6 wt% PEG particles blocking the hyperosmotic channel from the production end under different depth settings are shown in Table 2.

[0081] Table 2 Displacement effect of different plugging depths

[0082]

[0083] The production performance curve when the particle concentration is 0.3wt% and the depth is 1 / 10 of the core length is shown in Fig. 9 .

[0084] Fig. 9 It shows that during the primary water flooding process, as the PV number of injected water increases, the water content increases sharply, and the crude oil recovery rate also increases gradually accordingly. When the PV number of injected water reaches 1.4, the water content is 99.55%, the crude oil recovery rate is 20.82%, and the displacement pressure difference at both ends of the core is stable at around 208.39KPa after water channeling. After injecting PEG particles with set concentration and injection amount from the core production end, it is left to stand for 2 hours to wait for the PEG particles to play a plugging role in the core porous medium. After 2 hours, the secondary water flooding was started from the injection end. It was observed that the displacement pressure difference at both ends of the core began to rise sharply from 19.37KPa. When the PV number of injected water reached 3, the displacement pressure difference rose to 435.53KPa. The plugging rate of PEG particles can be calculated to be 52.15% from the change in the pressure difference before and after the PEG particles are plugged. During the secondary water flooding process, due to the plugging effect of PEG particles, the crude oil recovery rate can be further increased by 3.15%, and the water content can be reduced by up to 3.68%.

[0085] Fig.10 This is the production dynamic curve when the PEG particle concentration is 0.3wt% and the depth is 1 / 8 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be further increased by 4.96%, and the water content can be reduced by up to 2.84%.

[0086] Fig.11 This is the production dynamic curve when the PEG particle concentration is 0.3wt% and the depth is 1 / 6 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be further increased by 6.23%, and the water content can be reduced by up to 2.84%.

[0087] Fig.12This is the production dynamic curve when the PEG particle concentration is 0.3wt% and the depth is 1 / 5 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be increased by another 6.55%, and the water content can be reduced by up to 2.84%.

[0088] The production performance curve when the particle concentration is 0.6wt% and the depth is 1 / 15 of the core length is shown in Fig.13 .

[0089] Fig.13 It shows that, firstly, during the primary water flooding process, as the PV number of the injected water increases, the water content increases sharply, and the crude oil recovery rate also increases gradually accordingly. When the PV number of the injected water reaches 1.4, the water content is 99.56%, the crude oil recovery rate is 20.22%, and the displacement pressure difference at both ends of the core is stable at around 212.39KPa after water channeling. After injecting PEG particles with set concentration and injection amount from the core production end, it is left to stand for 2 hours to wait for the PEG particles to play a plugging role in the core porous medium. After 2 hours, the secondary water flooding starts from the injection end. It can be observed that the displacement pressure difference at both ends of the core starts to rise sharply from 59.71KPa. When the PV number of the injected water reaches 3, the displacement pressure difference rises to 669.44KPa. The plugging rate of PEG particles can be calculated to be 68.27% from the change of the pressure difference before and after the PEG particles are plugged. Of course, during the secondary water flooding process, due to the plugging effect of PEG particles, the crude oil recovery rate can be further increased by 3.28%, and the water content can be reduced by up to 3.58%.

[0090] Fig.14 This is the production dynamic curve when the PEG particle concentration is 0.6wt% and the depth is 1 / 10 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be further increased by 5.49% and the water content can be reduced by up to 3.96%.

[0091] Fig.15 This is the production dynamic curve when the PEG particle concentration is 0.6wt% and the depth is 1 / 8 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be increased by another 6.66%, and the water content can be reduced by up to 2.96%.

[0092] Fig.16 This is the production dynamic curve when the PEG particle concentration is 0.6wt% and the depth is 1 / 6 of the core length. During the secondary water flooding process, due to the plugging effect of the PEG particles, the crude oil recovery rate can be further increased by 7.19% and the water content can be reduced by up to 3.64%.

[0093] When the PEG particle concentration is 0.3wt%, 0.4wt%, 0.5wt% and 0.6wt%, the recovery degree after PEG particle plugging at different depths is shown in Figure 2. Fig.17The plugging rate of PEG particles at different depths is shown in Fig.18 .

[0094] from Fig.17 and Fig.18 It can be seen that after PEG particle plugging, the recovery degree gradually increases with the increase of plugging depth and PEG particle concentration. Specifically, when the PEG particle concentration is low (≤0.4wt%), there is a turning point in the recovery degree when the plugging depth is 1 / 6; when the PEG particle concentration is high (≥0.5wt%), there is another turning point in the recovery degree when the plugging depth is 1 / 8. In addition, the changing trend of the plugging rate is consistent with the changing trend and phenomenon of the recovery degree. These observations show that there is a complex relationship between the recovery degree and the plugging rate at different PEG particle concentrations and plugging depths.

[0095] Using the high and low osmotic rhythm heterogeneous model ( Fig.19 , one side is a hypertonic area, and the other side is a hypotonic area, forming a high- and low-tonic heterogeneous microscopic model) indicating the blocking effect of PEG particles.

[0096] Schematic diagram of PEG particle plugging in high and low osmotic rhythm heterogeneous model Fig. 20 . In the primary water flooding stage of oil field development, the main purpose of water injection is to drive the saturated oil in the high permeability area to achieve effective reservoir development. In this stage, water will mainly enter the high permeability area, which has a higher permeability and can more effectively promote the movement of the oil phase, thereby realizing the exploitation of the reservoir. The oil phase in the low permeability area is often not swept and mobilized, because it is difficult for water to form sufficient displacement pressure in these areas and cannot effectively promote the movement of the oil phase. In order to start the remaining oil in the low permeability area, PEG particles are used for plugging. By reversely injecting PEG particles, they flow along the high permeability area. After the PEG particles are left to swell, the high permeability area can be effectively plugged. The PEG particles form a plugging layer in the high permeability area, preventing water from penetrating and improving the water drive sweep efficiency to a certain extent. During the secondary water flooding, the plugging of the high permeability area allows the secondary injected water to enter the low permeability area, thereby effectively mobilizing the remaining oil in the low permeability area.

[0097] The embodiments described above are only descriptions of the preferred modes of the present invention, and are not intended to limit the scope of the present invention. Without departing from the design spirit of the present invention, various modifications and improvements made to the technical solutions of the present invention by ordinary technicians in this field should all fall within the protection scope determined by the claims of the present invention.

Claims

1. A method for improving oil and gas recovery by removing plugging with PEG+acidification, characterized in that: The following steps are involved: After oil and gas are recovered from the oil field, acid is injected from the injection end to dissolve the blockage, and a freshly prepared aqueous dispersion of PEG gel particles with a molecular weight of 800-1000 is injected from the production section. After the PEG gel particles expand to their maximum, water is injected from the injection end to recover oil and gas.

2. The method for improving oil and gas recovery by PEG+acidification plugging removal according to claim 1, characterized in that: The acid solution is an aqueous solution containing HCl, HF and acetic acid.

3. Use of the method for improving oil and gas recovery rate by removing plugging with PEG+acidification as claimed in any one of claims 1 to 2 in oil and gas recovery.

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