High-strength gel profile control and water shutoff agent for middle-temperature high-salinity formation water reservoirs, and preparation method and application thereof

Abstract

The application relates to a high-strength gel profile control water plugging agent for a medium-temperature high-mineralization stratum water reservoir and a preparation method and application thereof. The high-strength gel profile control water plugging agent for the medium-temperature high-mineralization stratum water reservoir is composed of the following components in percentage by weight: 98.4-99.2 wt% of high-mineralization stratum water, 0.5-1.0 wt% of a salt-resistant polymer, 0.1-0.25 wt% of a first crosslinking agent, 0.1-0.25 wt% of a second crosslinking agent, 0.02-0.04 wt% of a first stabilizing agent and 0.05-0.1 wt% of a second stabilizing agent. The technical problem to be solved by the application is effectively solved through formula innovation and performance optimization, and the high-strength profile control water plugging problem in the deep part of a sandstone or fractured carbonate reservoir with high-permeability dominant seepage flow channels developed in a medium-temperature high-mineralization stratum is solved.

Description

Technical Field

[0001] This invention relates to the fields of water injection well profile control and oil well water shut-off in oilfield development, specifically to a high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, its preparation method, and its application. Background Technology

[0002] In water injection development reservoirs, water injection wells often exhibit high-permeability layers or fractured / large-pore layers in the profile, or high-permeability or fractured / large-pore dominant seepage channels exist between oil and water wells in the plane. Injected water flows along these high-permeability channels, resulting in low injection pressure and difficulty in effectively activating relatively low-permeability layers or regions outside of these channels. This leads to small water drive sweep volume, low water drive efficiency, and poor water injection development effects. Therefore, deep profile control measures are necessary, including injecting profile control agents to block high-permeability channels, controlling the flow of subsequent injected water within these channels, increasing injection pressure, activating water drive in relatively low-permeability layers or regions, increasing water drive sweep volume, and improving water injection development effects. Oil wells may also experience severe reservoir heterogeneity leading to water flooding of dominant water flow channels. In such cases, it is necessary to block these dominant water flow channels from the wellhead to reduce bottomhole flowing pressure and achieve the goal of water shut-off and oil production enhancement.

[0003] Some special reservoirs (such as carbonate reservoirs in the Middle East) have exceptionally high permeability through high-permeability channels, coupled with well-developed natural fractures, resulting in exceptionally strong seepage capacity. Effective permeability can reach 2000–4000 mD, and the formation temperature is intermediate (75–95℃). Formation water salinity can reach up to 30 × 10⁻⁶ mD. 4 mg / l, for the above special reservoir conditions, profile control and water shut-off need to have the following characteristics:

[0004] (1) It has high strength and can effectively block and control the flow of water in high-permeability channels or cracked high-permeability channels;

[0005] (2) It has the characteristic of delayed cross-linking and gelation under medium temperature (75-95℃) formation conditions, so as to realize the flow diversion of deep profile adjustment and improve the subsequent water drive sweep volume; to realize the deep sealing of the high permeability water flow channel of oil well and improve the water shut-off effectiveness of oil well;

[0006] (3) It has good stability under high-mineralization formation water conditions, and improves the effectiveness of water shut-off and profile control measures.

[0007] Traditional profile control and water shut-off agents have significant limitations when dealing with such complex reservoir conditions. For example, conventional polymer-based water shut-off agents exhibit poor water shut-off performance in high-salinity environments due to the ion shielding effect causing polymer molecular chain coiling and a significant decrease in viscosity. While some high-temperature resistant water shut-off agents can withstand high temperatures, they lack stability in high-salinity environments, making it difficult to control gelation time and strength, and prone to premature dehydration or strength decay. Furthermore, existing water shut-off agents developed for medium-temperature, high-salinity reservoirs generally suffer from the inability to simultaneously achieve gelation performance and long-term stability, failing to meet the requirements for long-term, efficient reservoir development.

[0008] Existing profile control and water shut-off agents cannot achieve efficient plugging and long-term stability in medium-temperature, high-salinity formation water reservoirs, resulting in low reservoir water injection development efficiency, and a large amount of crude oil cannot be effectively displaced, leading to resource waste. Therefore, there is an urgent need to develop a new type of water shut-off agent to overcome technical bottlenecks such as polymer performance degradation and gelation instability under high-salt environments, thereby improving reservoir recovery.

[0009] With the expansion of the development scale of medium-temperature, high-salinity oil reservoirs, higher requirements are placed on the adaptability, controllability, and durability of water-blocking agents. Traditional water-blocking agents can no longer meet the needs of profile control and water shut-off under the complex geological conditions of such reservoirs. Developing new water-blocking agents is a necessary means to ensure the continuous and efficient development of oil reservoirs and improve economic benefits. Summary of the Invention

[0010] In view of this, the main objective of the present invention is to provide a high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, its preparation method and application. The technical problem to be solved is to effectively address the challenge of high-strength profile control and water shut-off in deep medium-temperature, high-salinity formations, sandstone or fractured carbonate reservoirs with well-developed high-permeability seepage channels, through formula innovation and performance optimization.

[0011] The objective of this invention and the technical problem it solves are achieved by the following technical solution. A high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, proposed according to this invention, is composed of the following components by weight percentage: high-salinity formation water 98.4–99.2 wt%, salt-resistant polymer 0.5–1.0 wt%, first crosslinking agent 0.1–0.25 wt%, second crosslinking agent 0.1–0.25 wt%, first stabilizer 0.04 wt%, and second stabilizer 0.05–0.1 wt%.

[0012] The objectives of this invention and the technical problems it addresses can be further achieved by the following technical measures.

[0013] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for intermediate-temperature formation water reservoirs, the intermediate temperature is 75–95°C; and the salinity is 10–30 × 10⁻⁶. 4mg / L, Na + The proportion of Cl- is ≥85%.

[0014] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the molecular weight of the salt-resistant polymer is 9 million to 15 million.

[0015] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the first crosslinking agent is a polyphenol.

[0016] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the first crosslinking agent is selected from at least one of phenol, resorcinol, hydroquinone, and catechol.

[0017] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the second crosslinking agent is hexamethylenetetramine.

[0018] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the first stabilizer is a thiourea compound.

[0019] Preferably, in the aforementioned high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs, the second stabilizer is sulfite.

[0020] The objective of this invention and the technical problem it solves are further achieved by the following technical solution. A method for preparing a high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, according to this invention, includes the following steps:

[0021] Under stirring conditions, the salt-resistant polymer is uniformly dispersed in high-salinity formation water, and then the first crosslinking agent, the second crosslinking agent, the first stabilizer, and the second stabilizer are mixed uniformly to obtain the high-strength gel profile control and water shut-off agent for medium-temperature high-salinity formation water reservoirs.

[0022] The objective of this invention and the technical problem it solves are also achieved by the following technical solution: The application of a high-strength gel profile control and water shut-off agent proposed in this invention in medium-temperature formation water-oil reservoirs.

[0023] By utilizing the above technical solution, the present invention provides a high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, its preparation method, and its application, which has at least the following advantages:

[0024] The high-strength gel profile control and water shut-off agent provided by this invention is designed for medium-temperature formations at 75-95℃ and high-salinity formation water. It has good tolerance to the extreme environment of high-salinity formation water and its applicable range is significantly better than similar products.

[0025] The high-strength gel profile control and water shut-off agent provided by this invention has a gelation time of 2 to 5 days, a gel strength of E to H grade, and a viscosity of 20 to 50 Pa·S (shear rate 2S-1), which can be flexibly adjusted according to reservoir requirements.

[0026] The high-strength gel profile control and water shut-off agent provided by this invention exhibits a water separation rate of <1% and a strength retention rate of >90% over 3 months under simulated reservoir conditions. During long-term reservoir development, the gel structure remains stable, with low water separation and minimal strength decay, significantly extending the effective period of profile control and water shut-off, reducing operating costs, and improving oil recovery.

[0027] The high-strength gel profile control and water shut-off agent provided by this invention allows for flexible adjustment of gel time, gel strength, and viscosity according to reservoir and process requirements. Compared with water shut-off agents with fixed properties, it can better match different reservoir geological conditions and construction processes, thereby improving the water shut-off and profile control effect.

[0028] The high-strength gel profile control and water shut-off agent provided by this invention is suitable for sealing the dominant water flow channels in medium-temperature, high-salinity, severely heterogeneous water-injection development reservoirs, and can achieve the purpose of high-strength, deep sealing of dominant water flow channels.

[0029] The above description is merely an overview of the technical solution of the present invention. In order to better understand the technical means of the present invention and to implement it in accordance with the contents of the specification, the preferred embodiments of the present invention are described in detail below with reference to the accompanying drawings. Attached Figure Description

[0030] Figure 1 This is a schematic diagram of the preparation method of the high-strength gel profile control and water-blocking agent according to some embodiments of the present invention;

[0031] Figure 2 Well location map for the development of drainage water injection in the Kh2 reservoir of the Al-Ahdab oilfield;

[0032] Figure 3 A map showing the development status of the Kh2 reservoir in the Al-Ahdab oilfield;

[0033] Figure 4 Well location diagrams for profile control and water shut-off of AD1-10-3H and AD1-11-3H;

[0034] Figure 5 The curve for the interprofiling (IPC) construction of well AD1-10-3H;

[0035] Figure 6 Curves for water shut-off (WSO) construction of well AD1-11-3H;

[0036] Figure 7 Curves showing water injection production before and after profile control of well AD1-10-3H;

[0037] Figure 8 The curves show the production of oil wells in the AD1-10-3H well group before and after profile adjustment. Detailed Implementation

[0038] To further illustrate the technical means and effects adopted by the present invention to achieve the intended purpose, the following describes in detail, in conjunction with preferred embodiments, a high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, its preparation method and application, its specific implementation method, structure, features and effects.

[0039] Unless otherwise specified, all percentages below are by weight or volume. In the following embodiments of the present invention, unless otherwise specified, all components involved are commercially available products well known to those skilled in the art.

[0040] Some embodiments of the present invention provide a method for use with medium-temperature (75–95°C) formation water with a salinity range of 10–30 × 10⁻⁶. 4 mg / L, Na + This high-strength gel profile control and water shut-off agent for reservoirs with Cl- content ≥85% is composed of the following components by weight percentage: 98.4–99.2 wt% high-salinity formation water, 0.5–1.0 wt% salt-resistant polymer, 0.1–0.25 wt% first crosslinking agent, 0.1–0.25 wt% second crosslinking agent, 0.02–0.04 wt% first stabilizer, and 0.05–0.1 wt% second stabilizer. If the salt-resistant polymer concentration is below 0.5 wt%, the gel strength is low or it fails to gel, failing to achieve the purpose and effect of sealing high-permeability layers. If the salt-resistant polymer concentration is above 1.0 wt%, the base liquid viscosity is high, making it difficult to prepare on-site, resulting in poor injectability in low-permeability formations, high injection pressure, and difficult construction. A salt-resistant polymer concentration of 0.5–1.0 wt% within this range can effectively adjust the gel strength, with a wide range of applications and broad technical adaptability. The reaction equivalents of the two crosslinking agents within this range are close, ensuring a complete and sufficient reaction. When the concentrations of the two crosslinking agents are below 0.1 wt%, the gel strength is low, or even fails to form a gel. When both are present, the transaction speed is fast, which cannot meet the purpose of delayed crosslinking, resulting in a small sealing distance and difficulty in meeting the technical requirements of deep sealing. When the concentrations of the two crosslinking agents are above 0.10–25 wt%, the gel formation time and strength can be effectively adjusted within this range, offering a wide range of applications and broad technical adaptability.

[0041] In some alternative embodiments, the salt-resistant polymer is a commercially available product manufactured by Aisen (China) Flocculant Co., Ltd., for example, AN125VHM (product code), with a molecular weight of 9 million to 15 million.

[0042] In some optional embodiments, the first crosslinking agent may be a polyphenol selected from at least one of phenol, resorcinol, hydroquinone, and catechol, with different composition and proportions depending on the requirements for salt and temperature resistance.

[0043] In some alternative embodiments, the second crosslinking agent can be hexamethylenetetramine, which slowly releases formaldehyde under formation temperature conditions. An equivalent amount of industrial formaldehyde can be used instead, but industrial formaldehyde is highly volatile and toxic, posing significant safety risks during on-site construction.

[0044] In some alternative embodiments, the first stabilizer may be a thiourea compound, primarily used to increase the temperature resistance and long-term stability of the gel.

[0045] In some optional embodiments, the second stabilizer may be a sulfite, which is mainly used to remove dissolved oxygen from the oilfield water used for preparing the solution, reduce the oxidative degradation of the salt-resistant polymer, and improve the stability and gel strength of the gel.

[0046] In the above technical solution, the present invention effectively solves the problem of deep profile control and water shut-off in medium-temperature, high-mineralization strata, sandstone and fractured carbonate reservoirs with well-developed high-permeability seepage channels. Through formula innovation and performance optimization, the present invention effectively solves the problem of deep profile control and water shut-off in medium-temperature, high-mineralization strata, sandstone and fractured carbonate reservoirs.

[0047] Some embodiments of the present invention also provide a method for preparing a high-strength gel profile control and water shut-off agent for intermediate-temperature formation water reservoirs, comprising the following steps:

[0048] Under stirring conditions, the salt-resistant polymer is uniformly dispersed in high-salinity formation water, and then the first crosslinking agent, the second crosslinking agent, the first stabilizer, and the second stabilizer are mixed uniformly to obtain the high-strength gel profile control and water shut-off agent for medium-temperature high-salinity formation water reservoirs.

[0049] Specifically, the preparation method may include the following steps:

[0050] 1) The preparation equipment process consists of two water storage tanks, one (50m³) and the other (50m³). 3 Centrifugal dispensing pump 2 (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks 7 (equipped with a stirrer, 50m 3 It consists of 3 agitators, 5 valves, 4 connecting pipelines, etc., and the liquid preparation process is as follows: Figure 1 As shown.

[0051] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, then treated by a water treatment system, pressurized by an injection pump, and transported via a high-pressure pipeline to the OGM station. High-salinity formation water is then mixed with this water and injected into the injection wells, and finally introduced into a storage tank for fluid preparation. The salinity of the high-salinity formation water is 10-20 × 10⁻⁶.4 mg / l.

[0052] 3) Start the centrifugal mixing pump 2 and pump the oilfield water from the storage tank 1 into a mixing tank 7. At the same time, use the mixing suction gun 3 to suck up the salt-resistant polymer powder from the polymer material bucket 6 and evenly disperse it in the high-mineralization formation water of the mixing tank 7. Turn on the agitator 5 of the mixing tank 7 and stir while sucking in the water. The amount of salt-resistant polymer added is 0.5 to 1.0 wt%. The specific amount added is adjusted according to the needs of the design and construction process.

[0053] 4) During the mixing process in the mixing tank, add the first crosslinking agent (0.1-0.25 wt%), the second crosslinking agent (0.1-0.25 wt%), the first stabilizer (0.02-0.04 wt%), and the second stabilizer (0.05-0.1 wt%) respectively. The specific amounts added shall be adjusted according to the needs of the design and construction process.

[0054] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thus completing the preparation of the gel profile control and water shut-off agent base liquid.

[0055] Embodiments of the present invention also provide an application of a high-strength gel profile control and water shut-off agent in medium-temperature formation water reservoirs.

[0056] The high-strength gel profile control and water shut-off agent provided by this invention is suitable for sealing the dominant water flow channels in severely heterogeneous water injection development reservoirs, and can achieve the purpose of high-strength deep sealing of dominant water flow channels.

[0057] The present invention will be further described below with reference to specific embodiments.

[0058] Example 1

[0059] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶. 4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 99.16wt% high-salinity formation water, 0.5wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.1wt% catechol and phenol in a mass ratio of 2:1, 0.1wt% hexamethylenetetramine, 0.04wt% thiourea, and 0.1wt% sodium bisulfite.

[0060] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0061] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0062] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (99.16 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0063] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-salinity formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.5wt%.

[0064] 4) During the stirring process in the mixing tank, add catechol and phenol (0.1 wt%) in a mass ratio of 2:1, hexamethylenetetramine (0.1 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0065] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0066] Example 2

[0067] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶. 4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 99.12wt% high-salinity formation water, 0.5wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.12wt% catechol and phenol in a mass ratio of 2:1, 0.12wt% hexamethylenetetramine, 0.04wt% thiourea, and 0.1wt% sodium bisulfite.

[0068] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0069] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0070] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (99.12 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0071] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-salinity formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.5wt%.

[0072] 4) During the stirring process in the mixing tank, add catechol and phenol (0.12 wt%), hexamethylenetetramine (0.12 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%) in a mass ratio of 2:1.

[0073] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0074] Example 3

[0075] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶. 4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 98.96wt% high-salinity formation water, 0.6wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.15wt% catechol and phenol in a mass ratio of 2:1, 0.15wt% hexamethylenetetramine, 0.04wt% thiourea, and 0.1wt% sodium bisulfite.

[0076] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0077] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0078] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (98.96 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0079] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-salinity formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.6wt%.

[0080] 4) During the stirring process in the mixing tank, add catechol and phenol (0.15 wt%) in a mass ratio of 2:1, hexamethylenetetramine (0.15 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0081] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0082] Example 4

[0083] This embodiment provides a method for using medium-temperature (80℃) formation water with a salinity range of 14.3 × 10⁻⁶. 4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 98.76 wt% high-salinity formation water, 0.7 wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.2 wt% catechol and phenol in a mass ratio of 2:1, 0.2 wt% hexamethylenetetramine, 0.04 wt% thiourea, and 0.1 wt% sodium bisulfite.

[0084] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0085] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0086] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via a high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (98.76 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0087] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-salinity formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.7wt%.

[0088] 4) During the stirring process in the mixing tank, add catechol and phenol (0.2 wt%) in a mass ratio of 2:1, hexamethylenetetramine (0.2 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0089] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0090] Example 5

[0091] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶. 4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 98.56wt% high-salinity formation water, 0.8wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.25wt% catechol and phenol in a mass ratio of 2:1, 0.25wt% hexamethylenetetramine, 0.04wt% thiourea, and 0.1wt% sodium bisulfite.

[0092] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0093] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0094] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (98.56 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0095] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-saltification formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.8wt%.

[0096] 4) During the stirring process in the mixing tank, add catechol and phenol (0.25 wt%) in a mass ratio of 2:1, hexamethylenetetramine (0.25 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0097] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0098] Example 6

[0099] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶. 4The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 98.66 wt% high-salinity formation water, 0.8 wt% salt-resistant polymer AN125VHM, 0.2 wt% catechol and phenol in a mass ratio of 2:1, 0.2 wt% hexamethylenetetramine, 0.04 wt% thiourea, and 0.1 wt% sodium bisulfite.

[0100] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0101] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0102] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into the storage tank (98.66 wt%) for fluid preparation. The oilfield water used for fluid preparation has a salinity of 14.3 × 10⁻⁶. 4 mg / l.

[0103] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-saltification formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 0.8wt%.

[0104] 4) During the stirring process in the mixing tank, add catechol and phenol in a mass ratio of 2:1 (0.2 wt%), hexamethylenetetramine (0.2 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0105] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0106] Example 7

[0107] This embodiment provides a method for using medium-temperature (80℃) formation water with a mineralization of 14.3 × 10⁻⁶.4 The high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) is composed of the following components by weight percentage: 98.36 wt% high-salinity formation water, 1.0 wt% salt-resistant polymer AN125VHM (molecular weight of 12 million), 0.25 wt% catechol and phenol in a mass ratio of 2:1, 0.25 wt% hexamethylenetetramine, 0.04 wt% thiourea, and 0.1 wt% sodium bisulfite.

[0108] The above is used for formation water with a medium temperature (80℃) and a mineralization of 14.3 × 10⁻⁶. 4 The preparation method of a high-strength gel profile control and water shut-off agent for oil reservoirs (mg / L) includes the following steps:

[0109] 1) The preparation equipment process consists of two water storage tanks (50m³ each). 3 Centrifugal dispensing pump (head 35m, displacement 50m³ / h) 3 / h), 3 mixing tanks (equipped with agitators, 50m³ / h) 3 It consists of components such as connecting pipelines, and the solution preparation process is as follows: Figure 1 As shown.

[0110] 2) The water used for fluid preparation is produced fluid from the oilfield, demulsified by a three-phase separator, treated by a water treatment system, pressurized by an injection pump, and transported via high-pressure pipeline to the OGM station. High-salinity formation water is then added to the injection wells and subsequently injected into a storage tank (98.36 wt%) for fluid preparation. The salinity of this high-salinity formation water is 14.3 × 10⁻⁶. 4 mg / l.

[0111] 3) Turn on the centrifugal pump to pump the oilfield water from the storage tank into a mixing tank. At the same time, use the mixing suction gun to suck up the powder of salt-resistant polymer AN125VHM and evenly disperse it in the high-salinity formation water in the mixing tank. Turn on the mixing tank agitator and stir while sucking up the powder. The amount of salt-resistant polymer AN125VHM added is 1.0wt%.

[0112] 4) During the stirring process in the mixing tank, add catechol and phenol (0.25 wt%) in a mass ratio of 2:1, hexamethylenetetramine (0.25 wt%), thiourea (0.04 wt%), and sodium bisulfite (0.1 wt%).

[0113] 5) Add high-mineralization formation water to the designed liquid volume and continue stirring for 2 hours to allow the agent to fully swell, dissolve, and mature in the high-mineralization formation water, thereby obtaining the high-strength gel profile control and water shut-off agent. Its gel performance evaluation is shown in Table 1.

[0114] The high-strength gel profile control and water plugging agents of Examples 1-7 were subjected to gel performance tests. The test results are summarized in Table 1, and the gel strength rating evaluation criteria are shown in Table 2. As can be seen from the data in Table 1, the gel strength of the high-strength gel profile control and water plugging agents of Examples 1-7 is between EH grade, and the gelation time is between 3-5 days.

[0115] Table 1. Statistical evaluation of the gel performance of the high-strength gel profile control and water-blocking agents in Examples 1-7.

[0116] Table 2. Gel Strength Rating Evaluation Method Using GSC Codes

[0117]

[0118]

[0119] The application of the high-strength gel profile control and water shut-off agent of the present invention in a medium-temperature, high-salinity formation water reservoir in a certain oilfield in the Middle East is as follows.

[0120] An oil field in the Middle East is located in the relatively stable central Mesopotamian Basin, an area with the deepest deposits and thickest sediments. The oil field's structure is a broad, gently sloping, long-axis anticline trending northwest to southeast, with a major axis of approximately 50 km, a minor axis width of 15-20 km, and a closed area of ​​nearly 150 km². 2 The dip angles of both flanks of the anticline are less than 2°. Four oil-bearing strata are developed from top to bottom in the Cretaceous: the Khasib, Mishrif, Rumaila, and Mauddud formations. Among them, the Khasib formation has the widest oil distribution and the largest reserves, making it the main development strata of the oil field.

[0121] The main reservoir in this block, Kh2, was put into development in 2011, using a linear horizontal well network with a row of injection and production wells and water injection. The well spacing was 100m, and the row spacing was 300m, employing a bottom-injection, top-production water injection development method. The projected recovery rate was 28.4%, and initial production results were good. After subsequent injections in 2012, the corresponding wells quickly produced water. By 2018, the reservoir had entered the early stage of high water-cut development, with a comprehensive water cut reaching 65.1% and a recovery rate of only 14.28%. Figure 2 , Figure 3 .

[0122] The Kh2 reservoir exhibits three microfacies: calcic shoals, bioclastic shoals, and intershoal depressions. The lithology is dominated by various types of grainy limestone, with bioclastic micritic limestone, micritic limestone, and marl developing in the upper and lower sections. This carbonate reservoir has a porosity of 22.2%, a permeability of 4.6 millidarcy, a reservoir temperature of 79℃, and a formation water salinity of 24 × 10⁻⁶. 4ppm, see Table 3. The Kh2 reservoir is a medium-temperature (80℃) formation with an oilfield water salinity of 14.3 × 10⁻⁶. 4 mg / L.

[0123] A high-permeability layer, Kh2-1-2L, is widely developed in the upper part of the Kh2 reservoir, with an average thickness of 1.2 m and a permeability as high as 230-1042 mD. The strong heterogeneity of the reservoir is the main reason for the rapid increase in water cut in the Kh2 reservoir.

[0124] Table 3 Geological parameters of the Kh2 reservoir sub-layer

[0125]

[0126] The high-permeability layer of Kh2-1-2L is characterized by: cavities created by biological disturbance passively filling the upper coarse-grained sediments, mimicking early cementation as the rock fabric changes, resulting in well-developed intergranular porosity and good physical properties; later diagenesis and dissolution occurred, allowing fluids to preferentially enter the cavities and dissolve the cement, further increasing the permeability of the cavities. This high-permeability layer is stably developed throughout the region, with permeability ranging from 230-1042 mD, averaging 760 mD. Other reservoirs have permeability less than 40 mD, representing a permeability difference of tens to hundreds of times, making it a veritable "thief layer."

[0127] Therefore, the presence of high-permeability layers exacerbates the vertical heterogeneity of the reservoir. During development, injected water flows through high-permeability layers, and the injection pressure of injection wells is low (most injection wells have a pressure of 0), making it difficult to effectively initiate water drive in other low-permeability sections, thereby reducing the volume of injected water sweep and causing ineffective circulation of injected water.

[0128] Therefore, this invention forms the technical approach of water shut-off and profile control in oil and water wells:

[0129] Implement profile control measures for injection wells: use profile control agents to block high-permeability layers (dominant seepage channels), and later establish effective water drive by increasing water pressure during water injection, thereby increasing the swept volume and improving the water injection development effect.

[0130] Water shut-off measures are implemented in oil wells: water shut-off agents are used to seal high-permeability layers, control the flooding of the main water flow channel, and allow the injected water to flow around the well, thereby achieving the purpose of reducing water and increasing oil production.

[0131] A technical route for water shut-off and profile control in oil and water wells was developed:

[0132] Targeting the characteristics of high-permeability layers as dominant seepage channels, a high-strength, salt-resistant gel profile control and water-stopping agent is used to achieve high-strength, deep sealing of high-permeability layers. High-permeability layers have high permeability and strong seepage capacity, requiring a higher strength profile control and water-stopping agent; this allows the injected water to flow around the deeper layers, achieving deep sealing, increasing the water-driven sweep volume, and improving oil yield and shelf life.

[0133] Based on demonstration and screening evaluation, it was decided to perform chemical profile control on the water injection well AD1-10-3H (see Tables 4 and 5), and to implement water shut-off measures on the corresponding oil well AD1-11-3H. Figure 4 .

[0134] Table 4. Profile Adjustment Construction Design for Well AD1-10-3H

[0135]

[0136]

[0137] Table 5 Design for Water Plugging Construction of Well AD1-11-3H

[0138]

[0139]

[0140] Profile adjustment and water plugging construction status:

[0141] Profile control (IPC) of well AD1-10-3H: Continuous profile control was carried out from September 19 to October 30, 2024, lasting 41 days. A total of 5130m³ of fluid was injected. 3 The construction pressure increased from 0 MPa to a maximum of 6.5 MPa. Figure 5 .

[0142] Water shut-off (WSO) operation for well AD1-11-3H: Water shut-off operations were carried out from November 10th to November 15th, 2024. A total of 1170m³ of fluid was injected. 3 The construction pressure increased from 0 MPa to a maximum of 0.5 MPa. Figure 6 .

[0143] Analysis of the effect of profile control and water plugging:

[0144] Increased Injection-Production Pressure: After profile modification of well AD1-10-3H, with the injection rate remaining constant at 1500 bbl / d, the wellhead pressure increased from 0 psi to 1300 psi, indicating that effective sealing of high-permeability zones or fractures with depth and strength has been achieved. (See...) Figure 7 .

[0145] Following profile control and water shut-off in the AD1-10-3H well group, the water cut at the corresponding oil well end group significantly decreased, and oil production increased markedly: 6.5 months after operation, the overall water cut decreased by 18%, daily oil production increased by over 700 bbl, and cumulative oil production increased by 141,333 bbl, with a return on investment (ROI) greater than 9.0. (See attached data.) Figure 8 .

[0146] The terms "first" and "second" in the above embodiments are used to distinguish between different embodiments, and do not represent the superiority or inferiority of each embodiment.

[0147] Numerous specific details are set forth in the specification provided herein. However, it will be understood that embodiments of the invention may be practiced without these specific details. In some instances, well-known structures and techniques have not been shown in detail so as not to obscure the understanding of this specification.

[0148] The numerical range described in this invention includes all values ​​within this range, and also includes any range value composed of any two values ​​within this range. Different values ​​of the same indicator appearing in all embodiments of this invention can be arbitrarily combined to form a range value.

[0149] The technical features in the claims and / or specification of this invention can be combined, and the combination is not limited to the combinations obtained through reference in the claims. Technical solutions obtained by combining the technical features in the claims and / or specification are also within the scope of protection of this invention.

[0150] The above description is merely a preferred embodiment of the present invention and is not intended to limit the present invention in any way. Any simple modifications, equivalent changes, and alterations made to the above embodiments based on the technical essence of the present invention shall still fall within the scope of the technical solution of the present invention.

Claims

1. A high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs, characterized in that, It is composed of the following components by weight percentage: 98.4–99.2 wt% high-salinity formation water, 0.5–1.0 wt% salt-resistant polymer, 0.1–0.25 wt% first crosslinking agent, 0.1–0.25 wt% second crosslinking agent, 0.02–0.04 wt% first stabilizer, and 0.05–0.1 wt% second stabilizer.

2. The high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs as described in claim 1, characterized in that, The intermediate temperature is 75–95℃; the mineralization degree is 10–30×10⁻⁶. 4 mg / L, Na + The proportion of Cl- is ≥85%.

3. The high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs as described in claim 1, characterized in that, The salt-resistant polymer has a molecular weight of 9 million to 15 million.

4. The high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs as described in claim 1, characterized in that, The first crosslinking agent is a polyphenol.

5. The high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs as described in claim 4, characterized in that, The first crosslinking agent is selected from at least one of phenol, resorcinol, hydroquinone, and catechol.

6. The high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs as described in claim 1, characterized in that, The second crosslinking agent is hexamethylenetetramine.

7. The high-strength gel profile control and water shut-off agent for medium-temperature, high-salinity formation water reservoirs as described in claim 1, characterized in that, The first stabilizer is a thiourea compound.

8. The high-strength gel profile control and water shut-off agent for medium-temperature salinity formation water reservoirs as described in claim 1, characterized in that, The second stabilizer is sulfite.

9. A method for preparing a high-strength gel profile control and water shut-off agent for intermediate-temperature, high-salinity formation water reservoirs as described in any one of claims 1-8, characterized in that, Includes the following steps: Under stirring conditions, the salt-resistant polymer is uniformly dispersed in high-salinity formation water, and then the first crosslinking agent, the second crosslinking agent, the first stabilizer, and the second stabilizer are mixed uniformly to obtain the high-strength gel profile control and water shut-off agent for medium-temperature high-salinity formation water reservoirs.

10. The application of the high-strength gel profile control and water shut-off agent according to any one of claims 1-8 in medium-temperature, high-salinity formation water reservoirs.

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