Composition, plugging control agent containing the same, and plugging control method

Abstract

The present invention provides a composition, a plugging agent containing the same, and a plugging method. The composition provided by the present invention comprises gypsum, sepiolite, and fly ash, and is a composite coagulant. The plugging agent provided by the present invention first comprises the composition, a suspending agent, a stabilizer, a coagulant, and water; and secondly, a particle size regulator. The plugging method provided by the present invention first utilizes the plugging agent to block a channeling layer or a high water retention zone, and then utilizes the plugging agent to block a close channeling layer and a high permeability layer or a secondary high water retention zone.

Description

Technical Field

[0001] The invention belongs to the technical field of heavy oil extraction, and in particular relates to a composition, a plugging control agent containing the composition, and a plugging control method. Background Art

[0002] Due to reservoir heterogeneity in heavy oil wells, uneven steam absorption and the advancing steam front during steam injection lead to increasingly severe steam channeling in the later stages of most thermal recovery wells. Furthermore, after multiple cycles of steam stimulation, water reservoirs form in high-permeability zones. The water in these water reservoirs occupies a dominant position as a steam channel, preferentially absorbing heat during steam injection while simultaneously blocking its diffusion. During oil production, the water preferentially flows to the bottom of the well, resulting in ineffective circulation of injected steam heat and a significant reduction in the oil-to-gas ratio. Therefore, blocking late-stage steam channeling and high water reservoirs in thermal recovery wells is a key measure to improve the oil-to-gas ratio in these wells.

[0003] At present, the main needs are reasonable plugging agents and supporting processes. The current cement particle plugging agents have good temperature resistance, but poor injectability, cannot penetrate deep into the formation, have a short plugging distance, and cause great damage to the oil reservoir; foam plugging agents have poor stability, require a large injection dose, and have high operating costs, which greatly limits their on-site application; gel plugging agents and resin plugging agents are expensive and have complex processes. They cannot deeply plug steam channeling and are prone to blocking the oil layer when plugging high water storage zones. At the same time, their effective period is short at high temperatures and cannot be widely used. Summary of the Invention

[0004] In order to solve the problem that the plugging agent in the prior art has an unsatisfactory plugging effect on steam channeling and high water storage zones in the late stage of thermal recovery, the purpose of the present invention is to provide a composition, a plugging agent containing the same, and a plugging method.

[0005] One aspect of the present invention provides a composition comprising gypsum, sepiolite and fly ash.

[0006] According to a specific embodiment of the present invention, taking the mass of the composition as 100%, the composition comprises 6 wt % to 12 wt % of the gypsum, 6.5 wt % to 19.5 wt % of the sepiolite, and 74 wt % to 83.5 wt % of the fly ash;

[0007] Preferably, the composition comprises 6.5 wt% to 10 wt% of the gypsum, 7 wt% to 10 wt% of the sepiolite, and 80 wt% to 83.5 wt% of the fly ash.

[0008] According to a specific embodiment of the present invention, the particle size of the gypsum is 40 μm to 200 μm; and / or

[0009] The sepiolite fiber length is 1 mm to 6 mm; and / or

[0010] The particle size of the fly ash is 40 μm to 220 μm;

[0011] Preferably, the particle size of the gypsum is 40 μm to 100 μm; and / or

[0012] The particle size of the fly ash is 40 μm to 180 μm; and / or

[0013] The fiber length of the sepiolite is 5 mm.

[0014] The second aspect of the present invention provides a plugging agent, which includes a composition, a suspending agent, a stabilizer, a coagulant and water;

[0015] The composition is the composition described in one of the present invention.

[0016] In the plugging agent provided by the present invention, the coagulant is stored separately.

[0017] According to a specific embodiment of the present invention, the suspending agent is sodium bentonite; and / or

[0018] The stabilizer is tartrate; and / or

[0019] The coagulant is potassium hydroxide and / or sodium hydroxide;

[0020] Preferably, the stabilizer is sodium tartrate; and / or

[0021] The coagulant is sodium hydroxide.

[0022] According to a specific embodiment of the present invention, taking the mass of the plugging agent as 100%, the plugging agent comprises 21 wt% to 35 wt% of the composition, 3 wt% to 8 wt% of a suspending agent, 3 wt% to 6 wt% of a stabilizer, 1 wt% to 5 wt% of a coagulant, and 50 wt% to 60 wt% of water;

[0023] Preferably, the plugging agent comprises 29.5 wt% to 30 wt% of the composition, 7.5 wt% to 8 wt% of a suspending agent, 4 wt% of a stabilizer, 2 wt% of a coagulant, and 56 wt% to 57 wt% of water;

[0024] Preferably, the viscosity of the plugging agent at 30° C. is not higher than 45 mPa.s;

[0025] Preferably, the viscosity of the plugging agent at 30° C. is 30 mPa.s to 45 mPa.s.

[0026] According to a specific embodiment of the present invention, the plugging agent further includes a particle size regulator;

[0027] Preferably, taking the mass of the plugging agent as 100%, the plugging agent comprises 20 wt % to 35 wt % of the composition, 3 wt % to 8 wt % of a suspending agent, 3 wt % to 6 wt % of a stabilizer, 1 wt % to 5 wt % of a coagulant, 1 wt % to 2.5 wt % of a particle size regulator, and 50 wt % to 60 wt % of water;

[0028] Preferably, the plugging agent comprises 31 wt% to 32 wt% of the composition, 6 wt% to 6.5 wt% of a suspending agent, 4 wt% of a stabilizer, 2 wt% of a coagulant, 1 wt% to 1.5 wt% of a particle size regulator, and 55 wt% of water;

[0029] Preferably, the particle size regulator is selected from vermiculite and / or sponge wool;

[0030] Preferably, the vermiculite has a particle size of 1 mm to 6 mm; and / or

[0031] The sponge fleece meets the second-class cotton linter index in the national standard GB / T 20223-2018 "Cotton Linter": the fiber hand-pulled length is less than 13 mm, of which the fiber hand-pulled length is less than 3 mm and accounts for less than 58 wt% of the total fiber mass;

[0032] Preferably, the vermiculite has a particle size of 1 mm;

[0033] Preferably, the viscosity of the plugging agent at 30° C. is 50 mPa.s to 500 mPa.s;

[0034] Preferably, the viscosity of the plugging agent at 30° C. is 300 mPa.s to 380 mPa.s.

[0035] The third aspect of the present invention provides a plugging adjustment method, which includes the following steps:

[0036] 1) Inject the first plugging agent to block the channeling layer or high water storage zone;

[0037] 2) Inject the second plugging agent to block the close-range channeling layer and high-permeability layer or the secondary high-water storage zone;

[0038] The first plugging agent is the plugging agent described in the second aspect of the present invention, comprising a composition, a suspending agent, a stabilizer, a coagulant, a particle size regulator, and water;

[0039] The second plugging agent is the plugging agent described in the second aspect of the present invention, comprising a composition, a suspending agent, a stabilizer, a coagulant and water.

[0040] The plugging control method provided by the present invention can be performed in multiple rounds according to actual application needs; the injection amount of the plugging agent in each round is calculated based on the parameters of the oil well (permeability, wellbore diameter, porosity, predicted diffusion radius and wellbore length) (calculated according to the cylindrical volume calculation formula).

[0041] The crossflow layer referred to in the present invention refers to the layer where steam can flow from the injection well to the production well during steam injection; the close-range crossflow layer refers to the crossflow layer close to the steam injection well; the high permeability layer refers to the layer whose permeability is greater than the average permeability of all layers in the oil well; the high water storage zone refers to the layer where all high permeability layers are injected with water; the second-highest water storage zone refers to the layer where the injected water accounts for more than 80% of the high permeability layer.

[0042] According to a specific embodiment of the present invention, in step 1), the first plugging agent is injected and the solidification is waited for a first time period; and / or

[0043] In step 2), injecting the second plugging agent and waiting for solidification for a second time;

[0044] Preferably, the first duration and the second duration are independently 2 to 3 days.

[0045] The application of any one of the composition according to the first invention, the plugging agent according to the second invention and the plugging method according to the third invention in the technical field of heavy oil recovery, especially in the plugging of steam channeling and high water storage zone in the late stage of thermal recovery.

[0046] In the prior art, conventional plugging agents (such as organic gel, sol plugging agents or inorganic particle plugging agents) are used to block steam crossflow. Figure 1 As can be seen, the plugging area 6 formed by this conventional plugging agent can only block the crossflow layer 5 and part of the high permeability layer 4 near the steam injection well 1. Steam can bypass the plugging area 6 of the high permeability layer 4 along the steam flow direction 7 and return to the crossflow layer 5, but cannot reach the low permeability potential area 3, resulting in plugging failure.

[0047] The process of the plugging method provided by the present invention to plug steam crossflow is as follows: first, inject the first plugging agent to plug the crossflow layer, specifically see Figure 2 : The first plugging agent forms a plugging area 8 at a position slightly away from the steam injection well 1, plugging the crossflow layer 5; then the second plugging agent is injected to plug the close crossflow layer and high permeability layer, see Figure 3 The second plugging agent forms a plugging area 9 near the steam injection well 1, plugging the close-range crossflow layer 5 and the high-permeability layer 4, allowing the steam to reach the low-permeability potential area 3 along the steam flow direction 10, and the plugging is successful.

[0048] In the prior art, conventional plugging agents (such as organic gel, sol plugging agents or inorganic particle plugging agents) are used to plug high water storage belts. Figure 4 As shown. Figure 4 As can be seen in the figure, the plugging area 14 formed by this conventional plugging agent can only block the high water storage zone 13 and a small part of the secondary high water storage zone 12 near the steam injection well 11. After the steam enters the secondary high water storage zone 12 from the high water storage zone 13 along the steam flow direction 15, it can bypass the plugging area 14 and return to the high water storage zone 13 but cannot enter the low permeability potential zone 3, resulting in plugging failure.

[0049] The process of plugging the high water storage belt by the plugging method provided by the present invention is as follows: first, inject the first plugging agent to plug the high water storage belt, see Figure 5 : The first plugging agent forms a plugging area 16, plugging the high water storage belt 13; then the second plugging agent is injected to plug the second high water storage belt, see Figure 6 : The second plugging agent forms a blocking area 17 in the secondary high water storage belt 12 above the first plugging agent blocking area 16, thereby blocking the high water storage belt and the secondary high water storage belt, so that the steam reaches the low permeability potential area 3 along the steam flow direction 18, and the blocking is successful.

[0050] Beneficial effects of the present invention:

[0051] To address the problems of existing plugging agents, such as poor high-temperature resistance, easy clogging of oil channels, low strength, poor long-term stability, insufficient fluidity, insufficient controllability of setting time, high cost, and unsatisfactory plugging effects on steam channeling and high water retention zones in the late stage of thermal recovery, the present invention provides a composition, a plugging agent containing the same, and a plugging method. The composition provided by the present invention comprises gypsum, sepiolite, and fly ash, and is a composite coagulant. The plugging agent provided by the present invention first comprises the composition, a suspending agent, a stabilizer, a coagulant, and water; and secondly, a particle size regulator. Without the addition of a coagulant, the plugging agent will not solidify. In actual application, no plug will be left in the wellbore, and there is no need to drill the plug again, which greatly reduces the operating cost in actual application. The composition and the plugging agent both have good high temperature resistance and are sufficient to withstand the high temperature of 380°C generated by subsequent gas injection after injection into the formation. The plugging method provided by the present invention first injects a first plugging agent (i.e., a plugging agent provided by the present invention comprising the composition, suspending agent, stabilizer, coagulant, particle size regulator and water) to block the channeling layer or high water retention zone; then injects a second plugging agent (i.e., a plugging agent provided by the present invention comprising the composition, suspending agent, stabilizer, coagulant and water) to block the close-range channeling layer and high permeability layer or the secondary high water retention zone. The first plugging agent and the second plugging agent can be used to perform multiple rounds of plugging according to actual needs to achieve permanent plugging of steam channeling and high water retention zones. More than 20 wells have been successfully plugged with good plugging effect and significant economic benefits. Using the plugging agent containing the composition provided by the present invention and implementing the plugging method provided by the present invention to plug two heavy oil horizontal wells in an eastern oil field, within 180 days after the first round of steam injection: the cumulative gas injection volume and the cumulative liquid production of the two heavy oil horizontal wells decreased by 300 tons and 690 tons respectively compared with those before plugging; the daily liquid production decreased by 3.8 tons compared with that before plugging; the cumulative oil production increased by 712 tons compared with that before plugging; the daily oil production increased by 4 tons compared with that before plugging; the oil-gas ratio increased from 0.11 before plugging to 0.32, the pressure of the first round of steam injection increased by 2 MPa compared with that before plugging, the average water plugging cost was saved by 40% compared with the water plugging cost of other wells using conventional gel, the input-to-output ratio was 1:6, and the economic benefits were significant. The plugging agent containing the composition provided by the present invention is used to implement the plugging method provided by the present invention to plug two steam channeling wells, LX001 and LX002, in a heavy oil reservoir in a certain oil field in Henan Province. Steam is then injected into the LX001 and LX002 vertical wells, respectively. After the steam injection, the bottom hole temperature of the two wells reaches 380°C, no steam channeling occurs, and the steam injection pressure increases by 2.5 MPa compared with that before plugging. After plugging, statistics show that within three months after the steam injection, the LX001 and LX002 vertical wells have increased oil production by more than 150 tons. The average water plugging cost is saved by 45% compared with the water plugging cost of other wells using conventional gels. The input-to-output ratio is 1:7, and the economic benefits are significant. BRIEF DESCRIPTION OF THE DRAWINGS

[0052] Figure 1 Schematic diagram of the prior art for plugging steam crossflow, where 1 is the steam injection well, 2 is the well affected by steam crossflow, 3 is the low permeability potential zone, 4 is the high permeability layer, 5 is the crossflow layer, 6 is the plugging area of ​​the conventional plugging agent, and 7 is the steam flow direction;

[0053] Figure 2 Schematic diagram of the first step (blocking the cross-flow layer) in the plugging method provided by the present invention for blocking steam cross-flow, wherein 1 is the steam injection well, 2 is the well affected by steam cross-flow, 3 is the low permeability potential area, 4 is the high permeability layer, 5 is the cross-flow layer, and 8 is the plugging area of ​​the first plugging agent;

[0054] Figure 3 Schematic diagram of the overall plugging after the second step (plugging the close-range crossflow layer and the high-permeability layer) of the plugging method for plugging steam crossflow provided by the present invention is completed, wherein 1 is the steam injection well, 2 is the well affected by steam crossflow, 3 is the low-permeability potential area, 4 is the high-permeability layer, 5 is the crossflow layer, 8 is the plugging area of ​​the first plugging agent, 9 is the plugging area of ​​the second plugging agent, and 10 is the steam flow direction;

[0055] Figure 4 Schematic diagram of the prior art for plugging a high water retention zone, wherein 11 is a steam injection well, 3 is a low permeability potential zone, 12 is a sub-high water retention zone, 13 is a high water retention zone, 14 is the plugging area of ​​a conventional plugging agent, and 15 is the steam flow direction;

[0056] Figure 5 Schematic diagram of the first step (plugging the high water retention zone) in the plugging method provided by the present invention, wherein 11 is a steam injection well, 3 is a low permeability potential area, 12 is a secondary high water retention zone, 13 is a high water retention zone, and 16 is the plugging area of ​​the first plugging agent;

[0057] Figure 6 This is a schematic diagram of the overall plugging after completing the second step of plugging (plugging the second-highest water storage zone) in plugging the high water storage zone in the plugging method provided by the present invention, wherein 11 is a steam injection well, 3 is a low-permeability potential area, 12 is a second-highest water storage zone, 13 is a high water storage zone, 16 is the plugging area of ​​the first plugging agent, 17 is the plugging area of ​​the second plugging agent, and 18 is the steam flow direction. DETAILED DESCRIPTION

[0058] The present invention will be further described below with reference to examples. However, the examples are merely illustrative and do not limit the present invention in any way.

[0059] Example 1

[0060] Field test: Using the composition and plugging agent provided by the present invention and applying the plugging method provided by the present invention, two heavy oil horizontal wells in an eastern oil field were plugged:

[0061] The composition used in this example:

[0062] Composition A: Based on the mass of composition A, composition A includes 10 wt% of gypsum having an average particle size of 40 μm, 6.67 wt% of sepiolite having an average fiber length of 5 mm, and 83.33 wt% of fly ash having an average particle size of 40 μm;

[0063] Composition B: Based on the mass of composition B, composition B includes 6.25 wt% of gypsum with an average particle size of 100 μm, 15.625 wt% of sepiolite with an average fiber length of 5 mm, and 78.125 wt% of fly ash with an average particle size of 180 μm;

[0064] The plugging agent used in this embodiment is:

[0065] First plugging agent: Taking the mass of the first plugging agent as 100%, the first plugging agent comprises 32 wt% of composition B prepared in this example, 6 wt% of sodium bentonite, 4 wt% of sodium tartrate, 2 wt% of sodium hydroxide, 1 wt% of vermiculite with an average particle size of 1 mm, and 55 wt% of water, wherein the sodium hydroxide is stored separately; the viscosity of the first plugging agent after mixing all the above components at 30°C is 300 mPa.s;

[0066] Second plugging agent: Taking the mass of the second plugging agent as 100%, the second plugging agent comprises 30 wt% of composition A prepared in this example, 8 wt% of sodium bentonite, 4 wt% of sodium tartrate, 2 wt% of sodium hydroxide, and 56 wt% of water, wherein the sodium hydroxide is stored separately. The viscosity of the second plugging agent after mixing all the above components at 30°C is 45 mPa.s.

[0067] The parameters of the two heavy oil horizontal wells are as follows: well depth of 450 meters, effective thickness of 4.5 meters, permeability of 1500 to 6000 md, strong heterogeneity, and horizontal well section length of 200 meters. During this test, steam stimulation was performed for 11 cycles. The oil-gas ratio of the two wells gradually decreased from the original 0.55 to about 0.11 during this test. The bottomhole temperature of the two wells was measured to be as high as 380°C during steam injection.

[0068] Implement the plugging adjustment method provided by the present invention:

[0069] 1) The first round of injection of the first plugging agent totaling 180m 3 , wherein, all the components of the first plugging agent including composition B, sodium bentonite, sodium tartrate, vermiculite with an average particle size of 1 mm, sodium hydroxide and water are mixed and injected, and the mixture is allowed to solidify for 2 days to seal the high water storage belt;

[0070] 2) The second round of injection of the second plugging agent, a total of 90m 3Among them, all the components of the second plugging agent including composition A, sodium bentonite, sodium tartaric acid, sodium hydroxide and water are mixed and injected, and then solidified for 2 days to seal the second highest water storage belt.

[0071] Two heavy oil horizontal wells (i.e., heavy oil horizontal well 1 and heavy oil horizontal well 2) were plugged according to the above method. The liquid production, oil production, oil-gas ratio, etc. of the two heavy oil horizontal wells 180 days after the first round of steam injection before plugging by the plugging method provided by the present invention, as well as the liquid production, oil production, oil-gas ratio, etc. 180 days after the first round of steam injection after plugging by the method provided by the present invention are shown in Table 1. The liquid production refers to the sum of the oil production and water production.

[0072] Table 1. Production of two heavy oil horizontal wells within 180 days before and after plugging the high water storage zone

[0073]

[0074]

[0075] As can be seen from the data in Table 1, within 180 days after the first round of steam injection in plugging two heavy oil horizontal wells using the composition and plugging agent provided by the present invention and implementing the plugging method provided by the present invention: the cumulative gas injection volume and the cumulative liquid production decreased by 300 tons and 690 tons, respectively, compared with those before plugging; the daily liquid production decreased by 3.8 tons compared with that before plugging; the cumulative oil production increased by 712 tons compared with that before plugging; and the daily oil production increased by 4 tons compared with that before plugging; the oil-gas ratio increased from 0.11 before plugging to 0.32, and the pressure of the first round of steam injection increased by 2 MPa compared with that before plugging; the decrease in cumulative liquid production and daily liquid production, and the increase in cumulative oil production and daily oil production, indicate that the cumulative water production and daily water production of the two heavy oil horizontal wells have decreased significantly, while the oil production has increased significantly. The increase in the oil-gas ratio and the first round of steam injection pressure indicates that the composition, the first plugging agent and the second plugging agent provided by the present invention are used to implement the plugging method provided by the present invention to achieve good plugging effect on the high water storage zone of the two heavy oil horizontal wells.

[0076] As of 16 months after this experiment, the two heavy oil horizontal wells completed the second round of steam injection after plugging. The pressure of the second round of steam injection still reached 11MPa, which is 2MPa higher than before plugging. It can be seen that the plugging effect and long-term stability of the plugging method provided by the present invention using the composition and plugging agent provided by the present invention are good. In addition, the temperature at the bottom of the well during steam injection after plugging is as high as 380°C, which also proves that the temperature resistance of the composition and plugging agent provided by the present invention is good and can meet the needs of plugging high water storage belts before steam injection. In addition, in terms of economic cost, it has been calculated that the average water plugging cost of the two heavy oil horizontal wells is 40% lower than the water plugging cost of other wells using conventional gels, and the input-to-output ratio is 1:6, with significant economic benefits.

[0077] Example 2

[0078] Field test: Using the composition and plugging agent provided by the present invention and the plugging method provided by the present invention, plugging was carried out on two steam channeling wells, LX001 and LX002, in a heavy oil reservoir in an oil field in Henan Province:

[0079] The composition used in this example:

[0080] Composition C: Based on the mass of composition C, composition C includes 11.86 wt% gypsum having an average particle size of 40 μm, 6.78 wt% sepiolite having an average fiber length of 5 mm, and 81.36 wt% fly ash having an average particle size of 40 μm;

[0081] Composition D: Based on the mass of composition D, composition D includes 6.452 wt% gypsum having an average particle size of 100 μm, 19.355 wt% sepiolite having an average fiber length of 5 mm, and 74.193 wt% fly ash having an average particle size of 180 μm;

[0082] The plugging agent used in this embodiment is:

[0083] First plugging agent: Taking the mass of the first plugging agent as 100%, the first plugging agent comprises 31 wt% of composition D prepared in this example, 6.5 wt% of sodium bentonite, 4 wt% of sodium tartrate, 2 wt% of sodium hydroxide, 1.5 wt% of vermiculite with an average particle size of 1 mm, and 55 wt% of water, wherein the sodium hydroxide is stored separately. The viscosity of the first plugging agent after mixing all the above components at 30°C is 380 mPa.s;

[0084] Second plugging agent: Taking the mass of the second plugging agent as 100%, the second plugging agent comprises 29.5 wt% of composition C prepared in this example, 7.5 wt% of sodium bentonite, 4 wt% of sodium tartrate, 2 wt% of sodium hydroxide, and 57 wt% of water, wherein the sodium hydroxide is stored separately. The viscosity of the second plugging agent after mixing all the above components at 30°C is 30 mPa.s;

[0085] Details of the two steam breakthrough wells:

[0086] The vertical well LX001 is 309.0 meters, with an effective thickness of 4 meters, a cumulative huff-and-puff cycle of 3, 17 heat treatments, and an oil-gas ratio of 0.48;

[0087] The LX002 vertical well is 420 meters long, with an effective thickness of 4.7 meters, a total of 8 huff-and-puff cycles, 2 heat treatments, and an oil-gas ratio of 0.26. The adjacent wells at a distance of 100 meters all have extra-heavy oil.

[0088] Both steam channeling wells experienced edge water and steam channeling issues. One year prior to this test, vertical well LX002 was producing after steam injection. Eleven months prior to this test, vertical well LX001 was shut down after steam channeling to well LX002. Both wells were subsequently reopened for production, with poor results.

[0089] The plugging method provided by the present invention was implemented to plug two steam channeling wells, LX001 and LX002.

[0090] 1) The first round of injection of the first plugging agent in the LX002 vertical well was 80m 3 , wherein all the components of the first plugging agent including composition D, sodium bentonite, sodium tartrate, vermiculite with an average particle size of 1 mm, sodium hydroxide and water are mixed and injected, and then allowed to solidify for two days to block the channeling layer;

[0091] 2) The second round of injection of the second plugging agent in the LX002 vertical well totaled 40m 3 , wherein all the components of the second plugging agent including composition C, sodium bentonite, sodium tartaric acid, sodium hydroxide and water are mixed and injected, and allowed to solidify for two days to block the close-range channeling layer and the high-permeability layer;

[0092] 3) Injection of the second plugging agent into the LX001 well for a total of 80m 3 Among them, all the components of the second plugging agent including composition C, sodium bentonite, sodium tartaric acid, sodium hydroxide and water are mixed and injected, and then waited for two days to solidify to block the close-range channeling layer and the high-permeability layer.

[0093] The composition and plugging agent provided by the present invention and the method provided by the present invention were used to plug two steam channeling wells, LX001 and LX002, in a heavy oil reservoir in an oil field in Henan Province, to achieve the following plugging effects:

[0094] After plugging, steam was injected into Well LX001 and Well LX002. Bottomhole temperatures in both wells reached 380°C, with no steam channeling occurring. The steam injection pressure increased by 2.5 MPa compared to the pre-plugging pressure (10 MPa). Statistics show that within three months of steam injection, Well LX001 and Well LX002 increased oil production by over 150 tons, demonstrating the heat resistance of the composition and plugging agent provided by the present invention. Combined with the plugging method provided by the present invention, the plugging effect on steam channeling was effective and the plugging was stable over the long term. The average plugging cost for Well LX001 and Well LX002 was 45% lower than that of other wells using conventional gels, resulting in a 1:7 input-to-return ratio and significant economic benefits.

[0095] Although the present invention has been described with reference to specific embodiments, those skilled in the art will appreciate that various modifications may be made without departing from the true spirit and scope of the invention. Furthermore, the subject matter, spirit, and scope of the invention may be modified in various ways to adapt to specific circumstances, materials, combinations of materials, and methods. All such modifications are intended to be within the scope of the claims.

Claims

1. A plugging agent comprising gypsum, sepiolite, fly ash, a suspending agent, a stabilizer, a coagulant and water.

2. The plugging agent according to claim 1, characterized in that Taking the total mass of the gypsum, sepiolite and fly ash as 100%, the mass of the gypsum is 6 wt % to 12 wt %, the mass of the sepiolite is 6.5 wt % to 19.5 wt % and the mass of the fly ash is 74 wt % to 83.5 wt %.

3. The plugging agent according to claim 1, characterized in that Taking the total mass of the gypsum, sepiolite and fly ash as 100%, the mass of the gypsum is 6.5 wt % to 10 wt %, the mass of the sepiolite is 7 wt % to 10 wt %, and the mass of the fly ash is 80 wt % to 83.5 wt %.

4. The plugging agent according to claim 1, characterized in that The gypsum has a particle size of 40µm to 200µm; and / or The sepiolite fiber length is 1 mm to 6 mm; and / or The particle size of the fly ash is 40µm to 220µm.

5. The plugging agent according to claim 1, characterized in that The suspending agent is sodium bentonite; and / or The stabilizer is tartrate; and / or The coagulant is potassium hydroxide and / or sodium hydroxide.

6. The plugging agent according to any one of claims 1 to 5, characterized in that Taking the mass of the plugging agent as 100%, the total mass of the gypsum, sepiolite and fly ash is 21wt% to 35wt%, the mass of the suspending agent is 3wt% to 8wt%, the mass of the stabilizer is 3wt% to 6wt%, the mass of the coagulant is 1wt% to 5wt% and the mass of the water is 50wt% to 60wt%.

7. The plugging agent according to claim 1, characterized in that The plugging agent also includes a particle size regulator.

8. The plugging agent according to claim 7, characterized in that: Taking the mass of the plugging agent as 100%, the total mass of the gypsum, sepiolite and fly ash is 20wt% to 35wt%, the mass of the suspending agent is 3wt% to 8wt%, the mass of the stabilizer is 3wt% to 6wt%, the mass of the coagulant is 1wt% to 5wt%, the mass of the particle size regulator is 1wt% to 2.5wt% and the mass of the water is 50wt% to 60wt%.

9. The plugging agent according to claim 7 or 8, characterized in that: The particle size regulator is selected from vermiculite and / or sponge wool.

10. A method for adjusting blockage, comprising the following steps: 1) Inject the first plugging agent to block the channeling layer or high water storage zone; 2) Inject the second plugging agent to block the close-range channeling layer and high-permeability layer or the secondary high-water storage zone; The first plugging agent is the plugging agent according to any one of claims 7 to 9; The second plugging agent is the plugging agent according to any one of claims 1 to 6.

11. The plugging adjustment method according to claim 10, characterized in that: In step 1), injecting the first plugging agent and waiting for solidification for a first time; and / or In step 2), injecting the second plugging agent and waiting for solidification for a second time; The first duration and the second duration are independently 2 to 3 days.

12. Use of the plugging control agent according to any one of claims 1 to 9 or the plugging control method according to claim 10 or 11 in the technical field of heavy oil extraction.

13. The use according to claim 12, characterized in that The application is in the steam channeling and high water storage zone blocking in the late stage of thermal recovery.

Images