A single horizontal well SAGD development method

Abstract

The application provides a single horizontal well SAGD development method and relates to the technical field of oil exploitation, and comprises the following steps: selecting a heavy oil reservoir; constructing a single horizontal well; repeatedly injecting a clean water slug for heating; repeatedly injecting a light hydrocarbon solvent slug for heating; electric heating solvent extraction production, long pipe continuous injection of gasified solvent and steam, and short pipe liquid production; repeatedly performing the above production process; when the recovery rate reaches 30%, a non-condensable gas slug is injected; and when the recovery rate is more than 40%, the non-condensable gas is injected until production is stopped. Through a staged progressive development mode, the synergistic effect of thermal viscosity reduction, solvent extraction and gas displacement is fully exerted, the recovery rate is increased from 33.7% to 51.7%, the steam usage amount is reduced by more than 59%, and efficient and low-carbon development of thin-layer super-heavy oil is realized.

Description

Technical Field

[0001] This invention relates to the field of oil extraction technology, specifically to a single horizontal well SAGD development method. Background Technology

[0002] Due to its high viscosity and poor fluidity, heavy oil is difficult to extract effectively using conventional methods. Currently, for heavy oil reservoirs with a surface degassed crude oil viscosity of less than 20,000 mPa·s at 50℃, conventional thermal recovery methods such as steam huff and puff, steam drive, hot water drive, and reservoir combustion can be used. For heavy oil reservoirs with a surface degassed crude oil viscosity greater than 20,000 mPa·s at 50℃ and a continuous reservoir thickness of more than 10m, Steam Assisted Gravity Drainage (SAGD) is typically used. SAGD technology involves deploying horizontal well pairs stacked vertically within the same reservoir. High-dryness steam is injected into the upper injection well. Because the steam density is much lower than that of the crude oil, it rises and forms a steam cavity. As steam is continuously injected, the steam cavity expands upwards and laterally, exchanging heat with the crude oil in the reservoir. The viscosity of the heated crude oil decreases, and it flows downwards with condensate under gravity, being extracted from the horizontal production wells in the lower reservoir.

[0003] However, for heavy oil reservoirs with a crude oil viscosity greater than 50,000 mPa·s after surface degassing at 50℃ and a continuous oil layer thickness of 5-10 m, especially those with poor lateral continuity, strong reservoir heterogeneity, rapid changes in physical properties, and small EUR per well, current technologies cannot achieve profitable development. These reservoirs typically account for 30%-40% of total heavy oil resources, but conventional thermal recovery methods generally result in a final recovery rate of less than 20%, an oil-to-gas ratio of less than 0.08, and carbon emissions exceeding 2.0 tons of carbon per ton of oil, leading to unsatisfactory economic and environmental benefits.

[0004] While existing solvent-assisted SAGD technology can improve extraction efficiency to some extent, it has significant limitations. For example, Chinese patent document CN104453816A discloses a method for solvent-assisted SAGD extraction of heavy oil reservoirs. This method involves injecting steam, dimethyl ether, and dimethyl ether additives into the injection well at the center of the SAGD horizontal well. However, this method can only be used in dual-horizontal-well SAGD well groups and cannot be applied to single-horizontal-well SAGD wells. It requires an oil layer thickness of 10m-15m and cannot effectively utilize thin oil layers below 10m. Furthermore, it is only suitable for injection before the steam chamber descends, after which conventional SAGD production is switched, resulting in high production costs.

[0005] Chinese patent document CN119062295A discloses a circulating thermal solvent extraction method for heavy oil reservoirs. It discloses a technical solution for solvent circulation extraction of heavy oil using a dual horizontal well system in conjunction with an electric heater. This method achieves the technical effect of significantly reducing carbon emissions and improving recovery rate through solvent recycling and electric heating assistance. However, it still does not solve the problem of economic development of single wells in thin-layer ultra-heavy oil reservoirs. This method still requires a dual horizontal well system, and requires a continuous oil layer thickness of ≥10m and a horizontal permeability of ≥1000mD. Its applicability to thin oil layers of 5-10m and ultra-heavy oil reservoirs with relatively low permeability is limited. In addition, the solvent circulation system is complex and the investment in surface equipment is large.

[0006] In addition, existing SAGD technology faces the following technical challenges in developing extra-heavy oil: First, it requires the continuous injection of a large amount of high-temperature steam, resulting in high energy consumption and carbon emissions; second, for thin oil layers, the heat transfer efficiency is low, making it difficult to develop steam chambers; third, extra-heavy oil has extremely high viscosity, making it difficult to flow effectively even under high-temperature conditions; and fourth, existing dual-horizontal well systems have high investment costs and poor economic viability for thin oil reservoirs with relatively small reserves. Summary of the Invention

[0007] The purpose of this invention is to provide a technical solution that can effectively solve the development problems of thin-layer ultra-heavy oil reservoirs, significantly improve the recovery rate and development benefits, and at the same time greatly reduce steam consumption and carbon emissions, thus having good economic and environmental benefits.

[0008] To achieve the above objectives, the present invention provides the following technical solution: a single horizontal well SAGD development method, comprising the following steps:

[0009] S1: Select a heavy oil reservoir, wherein the heavy oil reservoir is a heavy oil reservoir that meets the preset continuous oil layer thickness, the preset surface degassed crude oil viscosity, and the preset permeability.

[0010] S2: Construct a single horizontal well, and run a long pipe, a short pipe and an electric heater into the horizontal well. The long pipe includes a temperature monitoring system and the temperature monitoring system is electrically connected to the electric heater.

[0011] S3: Repeatedly inject clean water slug heating, inject clean water from the long tube, drain the fluid from the short tube or the annulus of the oil casing, turn on the electric heater to maintain the preset well perimeter temperature, heat for the preset number of days, then circulate the fluid replacement, after the circulation and fluid replacement is completed, start the next round of clean water slug, repeat multiple rounds of clean water slug until the crude oil viscosity drops to the preset level.

[0012] S4: Repeatedly inject solvent slug heating. First inject light hydrocarbon solvent and then inject clean water to squeeze the solvent into the deep formation. Turn on the electric heater to maintain the ambient temperature around the well at the preset temperature. After heating for the preset number of days, circulate the fluid. After the circulation is completed, start the next round of solvent slug. Repeat the solvent slug multiple times until the crude oil viscosity drops to the preset level.

[0013] S5: Sequentially inject the gasification solvent slug and the steam slug, turn on the electric heater, and shut down the well for the preset number of days. The gasification solvent is a light hydrocarbon solvent in a gasified state.

[0014] S6: Electric heating solvent extraction production, with continuous injection of vaporized solvent and steam in the long tube, and liquid collection in the short tube to start production;

[0015] S7: Repeat S5-S6; when the well recovery rate reaches the preset percentage, inject non-condensable gas into the slug, and after the well is shut down for the preset number of days, continue to inject gasification solvent and steam to start electric heating solvent extraction production; when the well recovery rate exceeds the preset percentage, inject non-condensable gas as well, and stop production when the daily oil production is less than the preset daily production.

[0016] Furthermore, the light hydrocarbon solvent is a single-phase light hydrocarbon or a multi-phase mixed light hydrocarbon between C3 and C7.

[0017] Further: In step S1, the preset continuous oil layer thickness of the heavy oil reservoir is 5m-10m, the preset surface degassed crude oil viscosity at 50℃ is 20000mPa·s-500000mPa·s, the preset horizontal permeability of the heavy oil reservoir is above 500mD, and the preset vertical permeability is greater than 300mD.

[0018] Furthermore: In step S2, the length of the horizontal section of the horizontal well ranges from 300m to 800m, and the toe of the horizontal well is more than 5m higher than the heel of the horizontal well.

[0019] Furthermore, step S2 also includes cleaning the horizontal wellbore by injecting clean water into the annulus of the long pipe and draining the fluid through the short pipe until the wellbore is clean.

[0020] Furthermore: In step S3, the preset wellbore temperature is 280℃-350℃, the preset number of days is 20-30 days, the preset crude oil viscosity is 500mPa·s for the crude oil viscosity of the formation 3m-4m around the well in 80% of the entire horizontal section, the heating time of the clear water slug is extended by 10%-15%, and the maximum wellbore ambient temperature reaches 350℃ under conditions lower than the crude oil coking temperature.

[0021] Further: In step S4, the preset temperature is 350℃, the preset number of days is 20-30 days, and the preset crude oil viscosity is that the crude oil viscosity of the formation 3m-4m around the well in the entire horizontal section drops below 50mPa·s. The injection volume of the light hydrocarbon solvent is determined by numerical simulation. Under the condition that the bottom hole injection pressure is lower than the oil layer fracture pressure by 0.5MPa-1.0MPa, the light hydrocarbon solvent is injected first, followed by 30t-35t of clean water.

[0022] Furthermore: When repeating steps S5-S6, in step S5, the injection volume of the vaporized solvent slug and the vapor slug is increased by 10-15% per round.

[0023] Furthermore: In step S7, the production time of the electrothermal solvent extraction is extended by 50-60 days per round, with a maximum of 330 days.

[0024] Furthermore: In step S6, the mass ratio of vaporized solvent to steam is controlled between 0.7 and 1.4, and the injection-production ratio is controlled between 1.2 and 1.4.

[0025] Furthermore: In step S7, the well group recovery rate reaches a preset percentage of 30% and a preset number of days of 3-5 days. The non-condensable gas is nitrogen or methane, and the non-condensable gas is replenished every 4-6 months during the slug injection process.

[0026] Further: In step S7, the well group recovery rate exceeds the preset percentage of 40%, the preset daily production is 4 tons, and the method of injecting non-condensable gas is to continuously inject non-condensable gas, increase the daily injection of non-condensable gas by 70%-100% every year, and reduce the injection of solvent and steam by 15%-20% until the injection of solvent and steam is completely stopped.

[0027] Further: In step S1, the heavy oil reservoir is located more than 50m away from edge water and bottom water, or is not affected by edge water and bottom water, is more than 70m away from the fault, and has an oil saturation greater than 50%.

[0028] Further: In step S2, in the single horizontal well design, the horizontal section is 1m-1.5m away from the bottom of the oil layer, the horizontal well is drilled obliquely or vertically along the structural line, and screen pipe completion is adopted.

[0029] Furthermore, in steps S3-S4, the power of the electric heater is controlled in real time by a temperature monitoring system to maintain the wellbore temperature within a preset range.

[0030] Further: In step S6, injection and fluid extraction are stopped when the daily oil production is less than 4 tons.

[0031] Compared with the prior art, the present invention has the following advantages:

[0032] I. This invention employs a single-horizontal-well SAGD system to replace the traditional dual-horizontal-well system, significantly reducing investment costs and operational complexity. The single-horizontal-well design simplifies surface engineering and downhole operations, making the economical development of thin-layer extra-heavy oil reservoirs possible. By optimizing wellbore design and production schemes, the applicable oil layer thickness is reduced from the existing technical requirement of over 10m to 5-10m, greatly expanding the scope of application and enabling the effective utilization of thin-layer extra-heavy oil resources, which account for 30%-40% of the total heavy oil resources.

[0033] II. This invention achieves refined control and maximizes the effectiveness of different development stages through a phased, progressive development model. The water slug heating stage, using high-temperature treatment at 280℃-350℃, reduces the viscosity of the formation crude oil from 20,000-500,000 mPa·s to 500 mPa·s. The solvent slug heating stage, through the extraction of C3-C7 light hydrocarbon solvents, further reduces the crude oil viscosity to below 50 mPa·s, laying the foundation for subsequent efficient extraction. The electrically heated solvent extraction production stage achieves continuous and efficient extraction. The non-condensate gas-assisted stage maintains formation pressure and improves the final recovery rate. This progressive process design increases the recovery rate from 33.7% using conventional methods to 51.7%, and the oil production rate from 2.5% to 4.0%.

[0034] Third, this invention significantly reduces the environmental burden and operating costs. Through the synergistic effect of the electric heater and the light hydrocarbon solvent, steam consumption is drastically reduced by 56.1%-59.1%, correspondingly reducing carbon emissions from high-temperature steam. Simultaneously, the volume of the produced liquid is reduced by 34.2%-37.0%, and the water content decreases from 90.7%-95.2% to 57.5%-58.7%, significantly lowering the processing costs of the produced liquid.

[0035] Fourth, this invention achieves precise temperature control through the electrical connection between a temperature monitoring system and an electric heater. The temperature monitoring system monitors the temperature distribution within the wellbore in real time and adjusts the power of the electric heater through a feedback control system to ensure that the temperature around the well is precisely controlled within a preset range. This intelligent control method not only improves heating efficiency but also avoids the problem of crude oil coking that may be caused by overheating, ensuring the safety and stability of the process.

[0036] V. The technical solution of this invention has good engineering adaptability and economic benefits. The single-horizontal well design is adapted to the geological characteristics of thin-layer reservoirs, and the phased development mode allows for flexible adjustment of process parameters according to the actual formation response. The phased application of non-condensable gas maintains formation pressure while achieving efficient solvent utilization and cost control. The overall technical solution is mature and reliable, with good prospects for industrial application and significant economic value. Attached Figure Description

[0037] Figure 1 This is a flowchart illustrating a single-horizontal-well SAGD development method according to an embodiment of the present invention. Detailed Implementation

[0038] The technical solution of the present invention will now be clearly and completely described with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0039] Example 1

[0040] like Figure 1 As shown, this invention provides a single-horizontal-well SAGD development method, primarily targeting thin-layer extra-heavy oil reservoirs with continuous oil layer thickness of 5m-10m and surface degassed crude oil viscosity of 20000mPa·s-500000mPa·s at 50℃. This method achieves efficient and economical development of thin-layer extra-heavy oil reservoirs through a single-horizontal-well system combined with a phased, progressive development process.

[0041] The first step is reservoir selection. Suitable heavy oil reservoirs must meet the following geological conditions: continuous oil layer thickness of 5m-10m, surface degassed crude oil viscosity of 20000mPa·s-500000mPa·s at 50℃, horizontal permeability of 500mD or higher, vertical permeability of 300mD or higher, and oil saturation of 50% or higher. The reservoir should be at least 50m away from edge water and bottom water or free from their influence, and more than 70m away from faults to ensure the stability of the development process.

[0042] During the construction phase of a single horizontal well, the length of the horizontal section is set at 300-800m, with the specific length determined based on the reservoir size and reserve distribution. The toe of the horizontal well is at least 5m higher than the heel, a design that facilitates gravity drainage and fluid flow. The horizontal section is 1m-1.5m from the bottom of the oil layer. The horizontal well is drilled obliquely or perpendicularly to the structural line, using a screen pipe completion method. Long tubing, short tubing, and an electric heater are run into the horizontal well. The long tubing contains a temperature monitoring system electrically connected to the electric heater, used to monitor the temperature distribution within the wellbore in real time and control the heating power. The power of the electric heater is controlled in real time by the temperature monitoring system to maintain the wellbore temperature within a preset range, achieving precise temperature management.

[0043] After the wellbore is constructed, it needs to be cleaned. Clean water is injected into the annulus through the long pipe, and the fluid is drained through the short pipe until the wellbore is clean. This step ensures the cleanliness of the wellbore, creating favorable conditions for subsequent heat treatment and solvent injection.

[0044] Water slug heating is a crucial pretreatment step in this method. Water is injected through the long tubing up to the wellhead, and then drained through the short tubing or annulus. An electric heater is activated to maintain a wellbore temperature of 280℃-350℃. Heating is continued for 20-30 days, followed by fluid circulation until no fluid is produced or the crude oil content in the produced fluid is less than 5%. Circulation is then stopped, and the next round of water slug heating begins after circulation. The heating time for each round of water slug heating is extended by 10%-15%, achieving a maximum wellbore ambient temperature of 350℃ while remaining below the crude oil coking temperature. A temperature monitoring system monitors the temperature distribution within the wellbore in real time, and the electric heater power is adjusted via a feedback control system to ensure accurate temperature control. Multiple rounds of water slug heating are repeated until the crude oil viscosity in the 3-4m wellbore perimeter of 80% of the horizontal section decreases to 500 mPa·s. After multiple rounds of water slug treatment, the formation temperature within the 3-4m wellbore perimeter significantly increases, and the viscosity of the extra-heavy oil decreases substantially, creating favorable conditions for subsequent solvent treatment.

[0045] In the solvent slug heating stage, single-phase light hydrocarbons or multi-phase mixed light hydrocarbons between C3 and C7 are used as solvents. The optimal light hydrocarbon solvent slug injection rate is determined through numerical simulation. Under the condition that the bottomhole injection pressure is 0.5-1.0 MPa lower than the formation fracturing pressure, light hydrocarbon solvent is injected first, followed by 30-35 tons of clean water, forcing the solvent into the deep formation. An electric heater is turned on to maintain the wellbore ambient temperature at 350℃. After heating for 20-30 days, heating is stopped and fluid circulation begins. After fluid circulation is completed, the next round of solvent slugging is performed. The number of slugging cycles is determined by temperature monitoring or numerical simulation. Solvent molecules bind to the heavy components in the crude oil through intermolecular forces, disrupting the association structure between crude oil molecules and significantly reducing crude oil viscosity. Simultaneously, the solvent's extraction effect preferentially dissolves the light components in the crude oil, increasing its fluidity. Multiple rounds of solvent slugging are repeated until the crude oil viscosity in the formation at a depth of 3-4 meters around the entire horizontal section of the well drops below 50 mPa·s, laying the foundation for subsequent continuous production.

[0046] During the slug injection stage, under the condition that the bottomhole injection pressure is 0.5MPa-1.0MPa lower than the formation fracturing pressure, vaporized solvent and steam are injected sequentially via the slug injection system, and the electric heater is turned on, allowing the well to be shut in for 3-5 days. This process prepares the well for subsequent continuous production, allowing the solvent and steam in the formation to fully exert their viscosity-reducing and extraction effects.

[0047] Electrically heated solvent extraction is the main production stage. Gasified solvent and steam are continuously injected through the long tube, while production begins through the short tube. The mass ratio of gasified solvent to steam is controlled between 0.7 and 1.4, and the production-injection ratio is controlled between 1.2 and 1.4. During production, if the formation pressure rises or falls rapidly, the production-injection ratio can be appropriately increased or decreased. Gasified solvent has stronger diffusion and extraction capabilities under high-temperature conditions, allowing it to penetrate deep into formation pores and mix thoroughly with the crude oil. Steam provides additional heat energy to maintain formation temperature and prevent the crude oil viscosity from rising again. Injection and production cease when daily oil production is less than 4 tons.

[0048] The above-described slug injection and electrothermal solvent extraction processes are repeated, with the injection volume of gasified solvent slugs and steam slugs increased by 10-15% per round, and the electrothermal solvent extraction production time extended by 50-60 days per round, with a maximum of 330 days. This incremental operation mode achieves a progressive increase in mining efficiency.

[0049] When the well recovery rate reaches 30%, the formation pressure begins to decrease. At this point, the slug injects non-condensable gases such as nitrogen or methane, and the well is kept steam-bound for 3-5 days. After this, gasification solvent and steam are continuously injected to initiate electrically heated solvent extraction production. Non-condensable gases do not condense in the formation and can maintain a gaseous state for a long time, thus helping to maintain formation pressure. Non-condensable gases are replenished every 4-6 months to ensure stable formation pressure.

[0050] When the well group's recovery rate exceeds 40% and it enters the later stages of development, the injection of non-condensable gas becomes the primary driving mechanism. The injection method involves continuous injection of non-condensable gas, increasing the daily injection volume by 70%-100% annually while reducing the injection of solvent and steam by 15%-20%, until solvent and steam injection are completely stopped. Production ceases when daily oil production falls below 4 tons. By gradually increasing the non-condensable gas injection volume while simultaneously reducing solvent and steam injection volumes, operating costs are lowered, and the final recovery rate is maximized through gas displacement.

[0051] The entire process operates on the synergistic effect of thermal viscosity reduction, solvent extraction, and gravity drainage. In the water slug heating stage, heat exchange between high-temperature water and the surrounding formation raises the temperature of the near-wellbore extra-heavy oil, causing its viscosity to decrease. In the solvent slug heating stage, the good miscibility of light hydrocarbon solvents with crude oil further reduces viscosity; the solvent partially vaporizes in the high-temperature environment, enhancing diffusion and penetration. In the electrically heated solvent extraction stage, the synergistic effect of vaporized solvent and steam forms a dynamic viscosity reduction and extraction system. Under gravity, the viscosity-reduced and extracted crude oil flows downwards and is extracted. In the non-condensate gas-assisted stage, the energy from gas expansion propels the remaining crude oil into the wellbore while maintaining formation pressure, extending the well's economic production life.

[0052] The working principle of this invention is as follows:

[0053] This invention provides a single-horizontal-well SAGD development method based on the synergistic effect of thermal viscosity reduction, solvent extraction, and gravity drainage. This method uses a phased, progressive process to gradually reduce the viscosity of extra-heavy oil, improve its fluidity, and ultimately achieve efficient extraction.

[0054] During the water slug heating stage, clean water is injected into the wellbore through a long pipe, and an electric heater heats the water to a high temperature of 280℃-350℃. A temperature monitoring system, electrically connected to the electric heater, monitors the temperature distribution within the wellbore in real time. A feedback control system precisely adjusts the electric heater power to ensure the temperature remains within a preset range. The high-temperature clean water exchanges heat with the surrounding formation, causing the extra-heavy oil in the near-wellbore zone to heat up, intensifying molecular thermal motion, weakening intermolecular forces, and decreasing viscosity. During the fluid circulation process, the heated oil-containing liquid is discharged from the short pipe or annulus, and fresh clean water is continuously injected, forming a thermal cycle. The heating time of each water slug cycle increases by 10%-15%, and under conditions below the crude oil coking temperature, the highest wellbore ambient temperature reaches 350℃, ensuring continuous optimization of the heating effect. After multiple rounds of water slugging treatment, the formation temperature within 3-4m around the well increased significantly, and the viscosity of the extra-heavy oil decreased from the initial 20,000-500,000 mPa·s to about 500 mPa·s, creating favorable conditions for subsequent solvent treatment.

[0055] In the solvent slug heating stage, the good miscibility of single-phase or multi-phase light hydrocarbon solvents (C3-C7) with crude oil further reduces viscosity. The injection volume of light hydrocarbon solvent is determined through numerical simulation. Under the condition that the bottomhole injection pressure is 0.5-1.0 MPa lower than the formation fracture pressure, light hydrocarbon solvent is injected first, followed by 30-35 tons of clean water to force the solvent into the deep formation, ensuring sufficient contact between the solvent and the extra-heavy oil in the formation. Under the continuous heating of the electric heater, the light hydrocarbon solvent partially vaporizes in the high-temperature environment, enhancing diffusion and penetration capabilities, enabling it to penetrate deeper into the formation. Solvent molecules bind to the heavy components in crude oil through intermolecular forces, disrupting the association structure between crude oil molecules and significantly reducing crude oil viscosity. Simultaneously, the solvent's extraction effect preferentially dissolves the light components in the crude oil, improving its flow properties. The mixture formed by the light hydrocarbon solvent and crude oil has lower viscosity and better flowability, facilitating subsequent extraction operations. After multiple rounds of solvent slugging treatment, the viscosity of the formation crude oil was further reduced to below 50 mPa·s, laying the foundation for subsequent continuous mining.

[0056] In the slug injection and electrically heated solvent extraction production stages, a mixture of vaporized solvent and steam is injected through a long tube, while the short tube produces the fluid. It should be noted that the vaporized solvent is a light hydrocarbon solvent in a vaporized state. Under high-temperature conditions, the vaporized solvent has stronger diffusion and extraction capabilities, allowing it to penetrate deep into the formation pores and mix thoroughly with the crude oil. Steam provides additional heat energy to maintain formation temperature, prevent crude oil viscosity from rising again, and its expansion energy provides driving force for crude oil flow. The synergistic effect of solvent and steam forms a dynamic viscosity reduction and extraction system. The solvent is responsible for chemical viscosity reduction and extraction of light components, while the steam is responsible for thermal viscosity reduction and providing driving pressure. By controlling the mass ratio of vaporized solvent to steam between 0.7 and 1.4, and the production-injection ratio between 1.2 and 1.4, a balance between injection and production rates is achieved, maintaining stable formation pressure. Under gravity, the viscosity-reduced and extracted crude oil flows downwards and is extracted from the short tube. When this process is repeated, the injection volume of the vaporized solvent slug and the steam slug is increased by 10-15% per round, and the production time of the electrically heated solvent extraction is extended by 50-60 days per round, with a maximum of 330 days, thus achieving progressive optimization of the development effect.

[0057] When the recovery rate reaches 30%, the formation pressure begins to decrease. At this point, the slug injects non-condensable gases such as nitrogen or methane. Non-condensable gases do not condense under the required formation temperature and pressure conditions, maintaining their gaseous state for an extended period and thus helping to maintain formation pressure. After injection, a gas cap forms at the top of the formation, and the expansion energy of the gas propels the remaining crude oil into the wellbore. Simultaneously, the non-condensable gas occupies pore spaces previously occupied by solvents and vapors, improving oil removal efficiency and displacing previously stagnant remaining oil. Non-condensable gas is replenished every 4-6 months to ensure continuous and stable formation pressure.

[0058] When the recovery rate exceeds 40% and the well enters the later stages of development, the injection of non-condensable gas becomes the primary driving mechanism. At this point, the readily flowing crude oil in the formation has been largely extracted, with the remaining oil mainly consisting of bound and residual oil. By continuously injecting non-condensable gas, increasing the daily injection volume by 70%-100% annually while simultaneously reducing the injection of solvent and steam by 15%-20%, until solvent and steam injection are completely stopped, operating costs are significantly reduced, and the final recovery rate is maximized through gas displacement. The small molecular size of non-condensable gas allows it to penetrate micropores, displacing the bound crude oil while maintaining formation pressure and extending the well's economic production life. When daily oil production falls below 4 tons, it indicates that the well's economic value has reached a critical point, at which point production is ceased.

[0059] Throughout the entire process, the structural design of the single horizontal well played a crucial role. The design of the horizontal well's toe being more than 5 meters higher than its heel utilizes gravitational potential energy, facilitating natural fluid flow within the wellbore. The horizontal section's distance from the bottom of the oil layer is 1-1.5 meters, ensuring effective utilization of the oil layer while avoiding the risk of water channeling that might arise from excessive proximity to the oil layer bottom. Drilling the horizontal well obliquely or perpendicularly to the structural line, along with the screen completion method, ensures good oil layer connectivity. The dual-string system of long and short tubing separates injection and production, preventing interference between the injected and produced fluids and improving operational precision. The electrical connection between the temperature monitoring system and the electric heater provides real-time temperature data and power control, making the entire heating process controllable and adjustable, ensuring precise execution and safe operation of the process.

[0060] Through this phased and progressive working principle, this invention fully leverages the respective advantages of thermal viscosity reduction, solvent extraction, and gas displacement, and achieves their organic combination and synergistic effect through a reasonable timing arrangement. Water slug heating lays the foundation for solvent processing, solvent slug heating creates conditions for efficient production, electrically heated solvent extraction contributes the main output, and non-condensable gas assistance ensures maximum final recovery. The entire process achieves efficient development of thin-layer extra-heavy oil, increasing the recovery rate from 33.7% in conventional methods to over 51.7%, while significantly reducing steam consumption and carbon emissions, providing an effective technical means for the economical development of thin-layer extra-heavy oil.

[0061] Example 2

[0062] This method was implemented in an oil reservoir with a continuous oil layer thickness of 9m, a crude oil viscosity of 200,000 mPa·s after degassing at 50℃, a horizontal permeability of 1300 mD, an original oil saturation of 65%, and a minimum fracture pressure of 7.5 MPa. The horizontal section was 500m long and drilled at 91°. The tail end of the horizontal well was 6m higher than the tail end.

[0063] During the start-up phase, four rounds of clean water slugging are performed, with 20-30 tons of clean water added per round. After heating for 40 days, the liquid is replaced by circulation. Then, four rounds of solvent slugging are performed, with 10-20 tons of solvent and 30-35 tons of clean water added per round. After heating for 30 days, the liquid is replaced by circulation.

[0064] During the production phase, electrically heated solvent extraction was used for 8 years, with the solvent-to-steam mass ratio controlled at 0.7, the production-injection ratio controlled at 1.2, and the steam injection rate at 60 t / d. Once the recovery rate reached 30%, the slug injection nitrogen stage began, lasting 3 years, followed by a 3-year continuous nitrogen injection stage before production ceased. Ultimately, the recovery rate increased from 33.7% with conventional steam extraction to 52.8%, oil production increased by 12,500 tons, the oil recovery rate increased from 3.0% to 4.2%, steam usage decreased by 56.1%, liquid production decreased by 36.8%, and water cut decreased from 93.2% to 57.7%.

[0065] Example 3

[0066] This method was implemented in an oil reservoir with a continuous oil layer thickness of 8m, a crude oil viscosity of 150000mPa·s after degassing at 50℃, a horizontal permeability of 1000mD, an original oil saturation of 65%, and a minimum fracture pressure of 7.5MPa. The horizontal section was 400m long and drilled at 91°. The tail end of the horizontal well was 5m higher than the tail end.

[0067] During the start-up phase, four rounds of clean water slugging are performed, with 20-30 tons of clean water added per round. After heating for 40 days, the liquid is circulated and replaced. Then, three rounds of solvent slugging are performed, with 10-20 tons of solvent and 30-35 tons of clean water added per round. After heating for 30 days, the liquid is replaced.

[0068] During the production phase, electrically heated solvent extraction was used for 9 years, with the solvent-to-steam mass ratio controlled at 0.9, the production-injection ratio controlled at 1.2, and the steam injection rate at 50 t / d. Once the recovery rate reached 30%, the slug injection nitrogen stage began, lasting 2 years, followed by a 3-year continuous nitrogen injection stage before production ceased. Ultimately, the recovery rate increased from 32.1% with conventional steam extraction to 51.2%, oil production increased by 11,300 tons, the oil recovery rate increased from 2.8% to 4.0%, steam usage decreased by 55.9%, liquid production decreased by 34.2%, and water cut decreased from 95.2% to 58.7%.

[0069] As can be seen from Examples 2 and 3 above, the technical solution of the present invention can effectively solve the development problems of thin-layer extra-heavy oil reservoirs, significantly improve the recovery rate and development benefits, and at the same time greatly reduce steam consumption and carbon emissions, thus having good economic and environmental benefits. The phased and progressive development mode of the present invention makes the entire development process highly controllable and adaptable, providing an effective technical means for the efficient development of thin-layer extra-heavy oil.

[0070] The above embodiments are only for illustrating the technical concept and features of the present invention, and are intended to enable those skilled in the art to understand the content of the present invention and implement it accordingly. They should not be construed as limiting the scope of protection of the present invention. All equivalent transformations or modifications made in accordance with the spirit and essence of the present invention should be covered within the scope of protection of the present invention.

Claims

1. A single-horizontal-well SAGD development method, characterized in that, Includes the following steps: S1: Select a heavy oil reservoir, wherein the heavy oil reservoir is a heavy oil reservoir that meets the preset continuous oil layer thickness, the preset surface degassed crude oil viscosity, and the preset permeability. In step S1, the thickness of the continuous oil layer in the heavy oil reservoir is 5m-10m, the viscosity of the degassed crude oil at the surface under 50℃ is 20000mPa·s-500000mPa·s, the horizontal permeability of the heavy oil reservoir is above 500mD, and the vertical permeability is greater than 300mD. S2: Construct a single horizontal well, and run a long pipe, a short pipe and an electric heater into the horizontal well. The long pipe includes a temperature monitoring system and the temperature monitoring system is electrically connected to the electric heater. In step S2, the length of the horizontal section of the horizontal well ranges from 300m to 800m, and the toe of the horizontal well is more than 5m higher than the heel of the horizontal well. S3: Repeatedly inject clean water slug heating, inject clean water from the long tube, drain the fluid from the short tube or the annulus of the oil casing, turn on the electric heater to maintain the preset well perimeter temperature, heat for the preset number of days, then circulate the fluid replacement, after the circulation and fluid replacement is completed, start the next round of clean water slug, repeat multiple rounds of clean water slug until the crude oil viscosity drops to the preset level. In step S3, the preset wellbore temperature is 280℃-350℃, the preset number of days is 20-30 days, the preset crude oil viscosity is 500mPa·s for the formation crude oil viscosity 3m-4m around the well in 80% of the entire horizontal section, the heating time of the clear water slug is extended by 10%-15%, and the maximum wellbore ambient temperature reaches 350℃ under the condition of being lower than the crude oil coking temperature. S4: Repeatedly inject solvent slug heating. First inject light hydrocarbon solvent and then inject clean water to squeeze the solvent into the deep formation. Turn on the electric heater to maintain the ambient temperature around the well at the preset temperature. After heating for the preset number of days, circulate the fluid. After the circulation is completed, start the next round of solvent slug. Repeat the solvent slug multiple times until the crude oil viscosity drops to the preset level. In step S4, the preset temperature is 350℃, the preset number of days is 20-30 days, and the preset crude oil viscosity is that the crude oil viscosity of the formation 3m-4m around the well in the entire horizontal section drops below 50mPa·s. The injection volume of the light hydrocarbon solvent is determined by numerical simulation. Under the condition that the bottom hole injection pressure is lower than the oil layer fracture pressure by 0.5MPa-1.0MPa, the light hydrocarbon solvent is injected first, followed by 30t-35t of clean water. S5: Sequentially inject the gasification solvent slug and the steam slug, turn on the electric heater, and shut down the well for the preset number of days. The gasification solvent is a light hydrocarbon solvent in a gasified state. S6: Electric heating solvent extraction production, with continuous injection of vaporized solvent and steam in the long tube, and liquid collection in the short tube to start production; S7: Repeat S5-S6; when the well recovery rate reaches the preset percentage, inject non-condensable gas into the slug, and after the well is shut down for the preset number of days, continue to inject gasification solvent and steam to start electric heating solvent extraction production; when the well recovery rate exceeds the preset percentage, inject non-condensable gas as well, and stop production when the daily oil production is less than the preset daily production. In step S7, the well recovery rate reaches a preset percentage of 30% and the preset number of days is 3-5 days. The non-condensable gas is nitrogen or methane. During the slug injection of non-condensable gas, non-condensable gas is replenished every 4-6 months. In step S7, the well group recovery rate exceeds the preset percentage of 40%, the preset daily production is 4 tons, and the method of injecting non-condensable gas is to continuously inject non-condensable gas, increase the daily injection of non-condensable gas by 70%-100% every year, and reduce the injection of solvent and steam by 15%-20% until the injection of solvent and steam is completely stopped.

2. The single-horizontal-well SAGD development method according to claim 1, characterized in that: The light hydrocarbon solvent is a single-phase light hydrocarbon or a multi-phase mixed light hydrocarbon between C3 and C7.

3. The single-horizontal-well SAGD development method according to claim 1, characterized in that: Step S2 also includes cleaning the horizontal wellbore by injecting clean water into the annulus of the long pipe and draining the fluid through the short pipe until the wellbore is clean.

4. The SAGD development method for a single horizontal well according to claim 1, characterized in that: When repeating steps S5-S6, in step S5, the injection volume of the vaporized solvent slug and the vapor slug is increased by 10-15% per round.

5. The single-horizontal-well SAGD development method according to claim 1, characterized in that: In step S7, the production time for electrothermal solvent extraction is extended by 50-60 days per round, with a maximum of 330 days.

6. The single-horizontal-well SAGD development method according to claim 1, characterized in that: In step S6, the mass ratio of vaporized solvent to steam is controlled between 0.7 and 1.4, and the injection-production ratio is controlled between 1.2 and 1.

4.

7. The single-horizontal-well SAGD development method according to claim 1, characterized in that: In step S1, the heavy oil reservoir is located more than 50m away from the edge water and bottom water, more than 70m away from the fault, and has an oil saturation greater than 50%.

8. The SAGD development method for a single horizontal well according to claim 1, characterized in that: In step S2, in the single horizontal well design, the horizontal section is 1m-1.5m away from the bottom of the oil layer, the horizontal well is drilled obliquely or vertically along the structural line, and screen pipe completion is used.

9. The SAGD development method for a single horizontal well according to claim 1, characterized in that: In steps S3-S4, the power of the electric heater is controlled in real time by the temperature monitoring system to keep the wellbore temperature within a preset range.

10. The single-horizontal-well SAGD development method according to claim 1, characterized in that: In step S6, injection and fluid extraction are stopped when the daily oil production is less than 4 tons.

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